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, 2023
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 26, 2023, 641.7 million shares of common stock were outstanding.
DEVON ENERGY CORPORATION
FORM 10-Q
Part I. Financial Information | |||
Item 1. | 6 | ||
Consolidated | 6 | ||
7 | |||
| |||
| |||
9 | |||
10 | |||
| 10 | ||
11 | |||
11 | |||
13 | |||
14 | |||
14 | |||
15 | |||
15 | |||
16 | |||
Note 10 – Supplemental Information to Statements of Cash Flows | 16 | ||
16 | |||
17 | |||
17 | |||
18 | |||
18 | |||
19 | |||
19 | |||
21 | |||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
| |
| 22 | ||
23 | |||
30 | |||
33 | |||
33 | |||
Item 3. |
| ||
Item 4. |
| ||
Part II. Other Information | |||
Item 1. |
| ||
Item 1A. |
| ||
Item 2. |
| ||
Item 3. |
| ||
Item 4. |
| ||
Item 5. |
| ||
Item 6. |
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| |||
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”"2022 Plan" means the Devon Energy Corporation 20152022 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”Catalyst” means the division of Devon encompassing oil and gas properties located in Canada. All dollar amounts associated with Canada are in U.S. dollars, unless stated otherwise.Catalyst Midstream Partners, LLC.
“Canadian Plan”CDM” means Devon Canada Corporation Incentive Savings Plan.Cotton Draw Midstream, L.L.C.
“DD&A” means depreciation, depletion and amortization expenses.
“Devon Plan”"EPA" means Devon Energy Corporation Incentive Savings Plan.the United States Environmental Protection Agency.
“E&P”ESG” means explorationenvironmental, social and production activities.governance.
“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."IRA" refers to the Inflation Reduction Act of 2022.
“LOE” means lease operating expenses.
"Matterhorn" refers to Matterhorn Express Pipeline, LLC and, as applicable, its direct parent, MXP Parent, LLC.
“MBbls” means thousand barrels.
“MBoe” means thousand Boe.
“Mcf” means thousand cubic feet.
"Merger" means the merger of East Merger Sub, Inc., a wholly-owned subsidiary of the Company ("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 that certain Agreement and Plan of Merger, dated September 26, 2020, by and among the Company, Merger Sub and WPX.
“MMBoe” means million Boe.
3
“MMcf” means million cubic feet.
“N/M” means not meaningful.
3
"NCI" means noncontrolling interests.
“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.
“2018 Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit.credit, effective as of October 5, 2018.
“2023 Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of March 24, 2023.
“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;
uncertainties inherent in estimating oil, gas and NGL reserves;
the extent to which we are successful in acquiring and discovering additional reserves;
the uncertainties, costs and risks involved in exploration and development activities;
risks related to our hedging activities;
counterparty credit risks;
midstream capacity constraints and potential interruptions in production, including from limits to the build out of midstream infrastructure;
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 constraintsour ability to successfully complete mergers, acquisitions and potential interruptions in production;
competition for leases, materials, peopleour ability to pay dividends and capital;
cyberattacks targeting our systems and infrastructure; and
any of the other risks and uncertainties discussed in this report, our 20162022 Annual Report on Form 10-K and our other filings with the SEC.
The forward-looking statements included in this filing speak only as of the date of this report, represent management’s current reasonable expectations as of the date of this filing and are subject to the risks and uncertainties identified above as well as those described elsewhere in this report and in other documents we file from time to time with the SEC. We cannot guarantee the accuracy of our forward-looking statements, and readers are urged to carefully review and consider the various disclosures made in this report and in other documents we file from time to time with the SEC. All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume nodo not undertake, and expressly disclaim, any 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, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
|
| (Unaudited) |
| |||||
Oil, gas and NGL sales |
| $ | 2,679 |
|
| $ | 3,175 |
|
Oil, gas and NGL derivatives |
|
| 64 |
|
|
| (683 | ) |
Marketing and midstream revenues |
|
| 1,080 |
|
|
| 1,320 |
|
Total revenues |
|
| 3,823 |
|
|
| 3,812 |
|
Production expenses |
|
| 693 |
|
|
| 618 |
|
Exploration expenses |
|
| 3 |
|
|
| 2 |
|
Marketing and midstream expenses |
|
| 1,105 |
|
|
| 1,324 |
|
Depreciation, depletion and amortization |
|
| 615 |
|
|
| 489 |
|
Asset dispositions |
|
| — |
|
|
| (1 | ) |
General and administrative expenses |
|
| 106 |
|
|
| 94 |
|
Financing costs, net |
|
| 72 |
|
|
| 85 |
|
Other, net |
|
| 5 |
|
|
| (61 | ) |
Total expenses |
|
| 2,599 |
|
|
| 2,550 |
|
Earnings before income taxes |
|
| 1,224 |
|
|
| 1,262 |
|
Income tax expense |
|
| 221 |
|
|
| 267 |
|
Net earnings |
|
| 1,003 |
|
|
| 995 |
|
Net earnings attributable to noncontrolling interests |
|
| 8 |
|
|
| 6 |
|
Net earnings attributable to Devon |
| $ | 995 |
|
| $ | 989 |
|
Net earnings per share: |
|
|
|
|
|
| ||
Basic net earnings per share |
| $ | 1.53 |
|
| $ | 1.48 |
|
Diluted net earnings per share |
| $ | 1.53 |
|
| $ | 1.48 |
|
Comprehensive earnings: |
|
|
|
|
|
| ||
Net earnings |
| $ | 1,003 |
|
| $ | 995 |
|
Other comprehensive earnings, net of tax: |
|
|
|
|
|
| ||
Pension and postretirement plans |
|
| 1 |
|
|
| 1 |
|
Other comprehensive earnings, net of tax |
|
| 1 |
|
|
| 1 |
|
Comprehensive earnings: |
| $ | 1,004 |
|
| $ | 996 |
|
Comprehensive earnings attributable to noncontrolling interests |
|
| 8 |
|
|
| 6 |
|
Comprehensive earnings attributable to Devon |
| $ | 996 |
|
| $ | 990 |
|
See accompanying notes to consolidated financial statements
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWSBALANCE SHEETS
|
|
|
|
|
|
| ||||||||||
|
| 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 |
|
|
| March 31, 2023 |
|
| December 31, 2022 |
| ||
|
| (Unaudited) |
|
|
|
| ||
ASSETS |
|
|
|
|
|
| ||
Current assets: |
|
|
|
|
|
| ||
Cash, cash equivalents and restricted cash |
| $ | 887 |
|
| $ | 1,454 |
|
Accounts receivable |
|
| 1,615 |
|
|
| 1,767 |
|
Inventory |
|
| 212 |
|
|
| 201 |
|
Other current assets |
|
| 475 |
|
|
| 469 |
|
Total current assets |
|
| 3,189 |
|
|
| 3,891 |
|
Oil and gas property and equipment, based on successful efforts |
|
| 16,932 |
|
|
| 16,567 |
|
Other property and equipment, net ($112 million and $109 million related to CDM in 2023 and 2022, respectively) |
|
| 1,583 |
|
|
| 1,539 |
|
Total property and equipment, net |
|
| 18,515 |
|
|
| 18,106 |
|
Goodwill |
|
| 753 |
|
|
| 753 |
|
Right-of-use assets |
|
| 219 |
|
|
| 224 |
|
Investments |
|
| 469 |
|
|
| 440 |
|
Other long-term assets |
|
| 275 |
|
|
| 307 |
|
Total assets |
| $ | 23,420 |
|
| $ | 23,721 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
| ||
Current liabilities: |
|
|
|
|
|
| ||
Accounts payable |
| $ | 935 |
|
| $ | 859 |
|
Revenues and royalties payable |
|
| 1,266 |
|
|
| 1,506 |
|
Short-term debt |
|
| 247 |
|
|
| 251 |
|
Other current liabilities |
|
| 483 |
|
|
| 489 |
|
Total current liabilities |
|
| 2,931 |
|
|
| 3,105 |
|
Long-term debt |
|
| 6,175 |
|
|
| 6,189 |
|
Lease liabilities |
|
| 256 |
|
|
| 257 |
|
Asset retirement obligations |
|
| 546 |
|
|
| 511 |
|
Other long-term liabilities |
|
| 866 |
|
|
| 900 |
|
Deferred income taxes |
|
| 1,543 |
|
|
| 1,463 |
|
Stockholders' equity: |
|
|
|
|
|
| ||
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued |
|
| 64 |
|
|
| 65 |
|
Additional paid-in capital |
|
| 6,344 |
|
|
| 6,921 |
|
Retained earnings |
|
| 4,712 |
|
|
| 4,297 |
|
Accumulated other comprehensive loss |
|
| (115 | ) |
|
| (116 | ) |
Treasury stock, at cost, 0.6 million shares in 2023 |
|
| (28 | ) |
|
| — |
|
Total stockholders’ equity attributable to Devon |
|
| 10,977 |
|
|
| 11,167 |
|
Noncontrolling interests |
|
| 126 |
|
|
| 129 |
|
Total equity |
|
| 11,103 |
|
|
| 11,296 |
|
Total liabilities and equity |
| $ | 23,420 |
|
| $ | 23,721 |
|
See accompanying notes to consolidated financial statements
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETSSTATEMENTS OF CASH FLOWS
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
|
| (Unaudited) |
|
|
|
|
| |
|
| (Millions, except share data) |
| |||||
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 2,781 |
|
| $ | 1,959 |
|
Accounts receivable |
|
| 1,462 |
|
|
| 1,356 |
|
Assets held for sale |
|
| — |
|
|
| 193 |
|
Other current assets |
|
| 379 |
|
|
| 264 |
|
Total current assets |
|
| 4,622 |
|
|
| 3,772 |
|
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 |
|
Goodwill |
|
| 3,964 |
|
|
| 3,964 |
|
Other long-term assets |
|
| 1,891 |
|
|
| 1,987 |
|
Total assets |
| $ | 27,559 |
|
| $ | 25,913 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
| $ | 797 |
|
| $ | 642 |
|
Revenues and royalties payable |
|
| 1,012 |
|
|
| 908 |
|
Short-term debt |
|
| 20 |
|
|
| — |
|
Other current liabilities |
|
| 1,003 |
|
|
| 1,066 |
|
Total current liabilities |
|
| 2,832 |
|
|
| 2,616 |
|
Long-term debt |
|
| 10,383 |
|
|
| 10,154 |
|
Asset retirement obligations |
|
| 1,100 |
|
|
| 1,226 |
|
Other long-term liabilities |
|
| 645 |
|
|
| 894 |
|
Deferred income taxes |
|
| 665 |
|
|
| 648 |
|
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 |
|
Additional paid-in capital |
|
| 7,207 |
|
|
| 7,237 |
|
Accumulated deficit |
|
| (428 | ) |
|
| (1,646 | ) |
Accumulated other comprehensive earnings |
|
| 297 |
|
|
| 284 |
|
Total stockholders’ equity attributable to Devon |
|
| 7,129 |
|
|
| 5,927 |
|
Noncontrolling interests |
|
| 4,805 |
|
|
| 4,448 |
|
Total equity |
|
| 11,934 |
|
|
| 10,375 |
|
Total liabilities and equity |
| $ | 27,559 |
|
| $ | 25,913 |
|
|
| Three Months Ended March 31, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
|
| (Unaudited) |
| |||||
Cash flows from operating activities: |
|
|
|
|
|
| ||
Net earnings |
| $ | 1,003 |
|
| $ | 995 |
|
Adjustments to reconcile net earnings to net cash from operating activities: |
|
|
|
|
|
| ||
Depreciation, depletion and amortization |
|
| 615 |
|
|
| 489 |
|
Leasehold impairments |
|
| — |
|
|
| 1 |
|
Amortization of liabilities |
|
| (7 | ) |
|
| (6 | ) |
Total (gains) losses on commodity derivatives |
|
| (64 | ) |
|
| 683 |
|
Cash settlements on commodity derivatives |
|
| 13 |
|
|
| (344 | ) |
Gains on asset dispositions |
|
| — |
|
|
| (1 | ) |
Deferred income tax expense |
|
| 80 |
|
|
| 164 |
|
Share-based compensation |
|
| 23 |
|
|
| 20 |
|
Other |
|
| 2 |
|
|
| (21 | ) |
Changes in assets and liabilities, net |
|
| 12 |
|
|
| (143 | ) |
Net cash from operating activities |
|
| 1,677 |
|
|
| 1,837 |
|
Cash flows from investing activities: |
|
|
|
|
|
| ||
Capital expenditures |
|
| (1,012 | ) |
|
| (537 | ) |
Acquisitions of property and equipment |
|
| (13 | ) |
|
| (1 | ) |
Divestitures of property and equipment |
|
| 21 |
|
|
| 26 |
|
Distributions from investments |
|
| 8 |
|
|
| 8 |
|
Contributions to investments |
|
| (37 | ) |
|
| (22 | ) |
Net cash from investing activities |
|
| (1,033 | ) |
|
| (526 | ) |
Cash flows from financing activities: |
|
|
|
|
|
| ||
Repurchases of common stock |
|
| (517 | ) |
|
| (211 | ) |
Dividends paid on common stock |
|
| (596 | ) |
|
| (667 | ) |
Distributions to noncontrolling interests |
|
| (11 | ) |
|
| (8 | ) |
Shares exchanged for tax withholdings and other |
|
| (87 | ) |
|
| (73 | ) |
Net cash from financing activities |
|
| (1,211 | ) |
|
| (959 | ) |
Effect of exchange rate changes on cash |
|
| — |
|
|
| 2 |
|
Net change in cash, cash equivalents and restricted cash |
|
| (567 | ) |
|
| 354 |
|
Cash, cash equivalents and restricted cash at beginning of period |
|
| 1,454 |
|
|
| 2,271 |
|
Cash, cash equivalents and restricted cash at end of period |
| $ | 887 |
|
| $ | 2,625 |
|
|
|
|
|
|
|
| ||
Reconciliation of cash, cash equivalents and restricted cash: |
|
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 761 |
|
| $ | 2,459 |
|
Restricted cash |
|
| 126 |
|
|
| 166 |
|
Total cash, cash equivalents and restricted cash |
| $ | 887 |
|
| $ | 2,625 |
|
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, 2023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2022 |
|
| 653 |
|
| $ | 65 |
|
| $ | 6,921 |
|
| $ | 4,297 |
|
| $ | (116 | ) |
| $ | — |
|
| $ | 129 |
|
| $ | 11,296 |
| ||||||||||||||||||||||||||||||||
Net earnings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,218 |
|
|
| — |
|
|
| — |
|
|
| 59 |
|
|
| 1,277 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 995 |
|
|
| — |
|
|
| — |
|
|
| 8 |
|
|
| 1,003 |
|
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Restricted stock grants, net of cancellations |
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (43 | ) |
|
| — |
|
|
| (43 | ) |
|
| — |
|
|
| — |
|
|
| (4 | ) |
|
| — |
|
|
| — |
|
|
| (625 | ) |
|
| — |
|
|
| (629 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (43 | ) |
|
| — |
|
|
| — |
|
|
| 43 |
|
|
| — |
|
|
| — |
|
|
| (11 | ) |
|
| (1 | ) |
|
| (596 | ) |
|
| — |
|
|
| — |
|
|
| 597 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| (95 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (95 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (580 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (580 | ) |
Share-based compensation |
|
| 1 |
|
|
| — |
|
|
| 96 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 96 |
|
|
| 1 |
|
|
| — |
|
|
| 23 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 23 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 12 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 545 |
|
|
| 557 |
| ||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (247 | ) |
|
| (247 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (11 | ) |
|
| (11 | ) |
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, 2023 |
|
| 645 |
|
| $ | 64 |
|
| $ | 6,344 |
|
| $ | 4,712 |
|
| $ | (115 | ) |
| $ | (28 | ) |
| $ | 126 |
|
| $ | 11,103 |
| ||||||||||||||||||||||||||||||||
Three Months Ended March 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2021 |
|
| 663 |
|
| $ | 66 |
|
| $ | 7,636 |
|
| $ | 1,692 |
|
| $ | (132 | ) |
| $ | — |
|
| $ | 137 |
|
| $ | 9,399 |
| ||||||||||||||||||||||||||||||||
Net earnings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 989 |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
|
| 995 |
| ||||||||||||||||||||||||||||||||
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 48 |
|
|
| — |
|
|
| — |
|
|
| 48 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Restricted stock grants, net of cancellations |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (23 | ) |
|
| — |
|
|
| (23 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (305 | ) |
|
| — |
|
|
| (305 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (23 | ) |
|
| — |
|
|
| — |
|
|
| 23 |
|
|
| — |
|
|
| — |
|
|
| (5 | ) |
|
| — |
|
|
| (286 | ) |
|
| — |
|
|
| — |
|
|
| 286 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| (65 | ) |
|
| (125 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (190 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (668 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (668 | ) |
Common stock issued |
|
| 103 |
|
|
| 10 |
|
|
| 2,117 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2,127 |
| ||||||||||||||||||||||||||||||||
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 142 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 142 |
|
|
| 1 |
|
|
| — |
|
|
| 20 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 20 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 320 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 896 |
|
|
| 1,216 |
| ||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (224 | ) |
|
| (224 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (8 | ) |
|
| (8 | ) |
Balance as of September 30, 2016 |
|
| 524 |
|
| $ | 52 |
|
| $ | 7,487 |
|
| $ | (1,977 | ) |
| $ | 278 |
|
| $ | — |
|
| $ | 4,221 |
|
| $ | 10,061 |
| ||||||||||||||||||||||||||||||||
Balance as of March 31, 2022 |
|
| 661 |
|
| $ | 66 |
|
| $ | 7,371 |
|
| $ | 2,013 |
|
| $ | (131 | ) |
| $ | (19 | ) |
| $ | 135 |
|
| $ | 9,435 |
| ||||||||||||||||||||||||||||||||
See accompanying notes to consolidated financial statements
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 20162022 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, 2023 and 20162022 and Devon’s financial position as of September 30, 2017.March 31, 2023.
Restricted Cash
Recently Adopted Accounting StandardsAs of March 31, 2023, approximately $126 million of cash on the consolidated balance sheets is presented as restricted cash. These obligations primarily relate to an abandoned Canadian firm transportation agreement.
Variable Interest Entity
In January 2017,CDM is a joint venture entity formed by Devon adopted ASU 2016-09, Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting. Its objective is to simplify several aspectsand an affiliate of QL Capital Partners, LP. CDM provides gathering, compression and dehydration services for natural gas production in the Cotton Draw area of the accounting for share-based payments, including income taxes when awards vest orDelaware 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 settled, statutory withholding and forfeitures. As the result of adoption, Devon made certain income tax presentation changes, most notably prospectively presenting excess tax benefits and deficienciesshown separately as noncontrolling interests in the consolidated comprehensive statements of earnings and as operating cash flows in theaccompanying 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
The following table presents Devon's investments.
|
|
|
| Carrying Amount |
| |||||
Investments |
| % Interest |
| March 31, 2023 |
|
| December 31, 2022 |
| ||
Catalyst |
| 50% |
| $ | 332 |
|
| $ | 339 |
|
Matterhorn |
| 12.5% |
|
| 90 |
|
|
| 54 |
|
Other |
| Various |
|
| 47 |
|
|
| 47 |
|
Total |
|
|
| $ | 469 |
|
| $ | 440 |
|
Devon has an interest in Catalyst, which is a joint venture with an affiliate of Howard Energy Partners, LLC (“HEP”) and certain other investors, to develop oil gathering and natural gas processing infrastructure in the new cash flow statement guidance dictating the presentation of shares exchanged for tax-withholding purposes as a financing activity. The adoptionStateline area of the new guidance did not materially impactDelaware Basin. Under the consolidated financial statementsterms 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. 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,comprehensive earnings.
During 2023 and 2022, Devon continuesmade investments in Matterhorn. Matterhorn is a joint venture entity and was formed for the purpose of constructing a natural gas pipeline that will transport natural gas from the Permian Basin to evaluate the “gross versus net” presentation of certain revenues and associated expensesKaty, Texas area. Devon's investment in its consolidated statements of earnings. Any presentation changes would have no impact on operating income, earnings or cash flows. DevonMatterhorn does not expectgive it the ability to exercise 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.influence over Matterhorn.
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Disaggregation of Revenue
The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersedefollowing table presents revenue from contracts with customers that are disaggregated based on the lease requirements in Topic 840, Leases. Its objective is to increase transparencytype of good or service.
|
| Three Months Ended March 31, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
Oil |
| $ | 2,143 |
|
| $ | 2,406 |
|
Gas |
|
| 213 |
|
|
| 307 |
|
NGL |
|
| 323 |
|
|
| 462 |
|
Oil, gas and NGL sales |
|
| 2,679 |
|
|
| 3,175 |
|
|
|
|
|
|
|
| ||
Oil |
|
| 730 |
|
|
| 776 |
|
Gas |
|
| 152 |
|
|
| 209 |
|
NGL |
|
| 198 |
|
|
| 335 |
|
Marketing and midstream revenues |
|
| 1,080 |
|
|
| 1,320 |
|
Total revenues from contracts with customers |
| $ | 3,759 |
|
| $ | 4,495 |
|
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 align with new revenue recognition requirements. This ASU is effective forDivestitures
Acquisitions
In September 2022, Devon beginning January 1, 2019completed its acquisition of producing properties 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 periodleasehold interests located in the financial statements. Early adoption is permitted, but Devon does not plan to early adopt. Devon is in the processEagle Ford for cash consideration of evaluating contracts and gathering the necessary terms and data elements for purposesapproximately $1.7 billion, net 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 play for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash, after adjustments, and $659 million of common equity shares. The purchase price allocation was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.
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. EstimatedAdditionally, in July 2022, Devon completed its acquisition of producing properties and leasehold interests located in the Williston Basin for cash consideration of approximately $830 million, net of purchase price adjustments. The total estimated proved reserves associated with these Eagle Ford and Williston Basin assets is approximately 87 MMBoe and 66 MMBoe, respectively. Each of these acquisitions were less than 1%accounted for as asset acquisitions as substantially all of total U.S. proved reserves.the fair value was concentrated in a group of similar assets. Each of the acquisitions resulted in the purchase of producing properties and leasehold interests in a defined geographical and geological area and substantially all of the assets have similar risk characteristics.
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 interest2023 and 2022 and could receive up to an additional $130 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, 2023 consolidated balance sheet was approximately $190 million.$53 million and $35 million, respectively. These values were derived utilizing a Monte Carlo valuation model and qualify as a level 3 fair value measurement.
Devon also received $4 million in contingent earnout payments related to the sale of non-core assets in the Rockies in the first quarter of 2023 and 2022.
|
|
Objectives and Strategies
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon and EnLink periodically enterenters into derivative financial instruments with respect to a portion of theirits oil, gas and NGL marketing activities. These commodity derivative financial instruments include financial price swaps, basis swaps and costless price collars. Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of September 30, 2017, Devon did not have any open foreign exchange contracts.
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Devon does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
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, 2023, Devon neither held cash collateral of its counterparties nor 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, 2023, 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 Collars |
|
| |||||||||
Period |
| Volume |
|
| Weighted |
|
| Weighted |
|
| |||
Q2-Q4 2023 |
|
| 83,329 |
|
| $ | 69.48 |
|
| $ | 94.66 |
|
|
Q1-Q4 2024 |
|
| 7,486 |
|
| $ | 60.00 |
|
| $ | 86.17 |
|
|
|
| Oil Basis Swaps |
| |||||||
Period |
| Index |
| Volume |
|
| Weighted Average |
| ||
Q2-Q4 2023 |
| Midland Sweet |
|
| 50,091 |
|
| $ | 1.09 |
|
Q1-Q4 2024 |
| Midland Sweet |
|
| 48,500 |
|
| $ | 1.19 |
|
Q1-Q4 2025 |
| Midland Sweet |
|
| 36,000 |
|
| $ | 0.94 |
|
As of September 30, 2017,March 31, 2023, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.
|
| Price Swaps |
|
| Price Collars |
| ||||||||||||||
Period |
| Volume (MMBtu/d) |
|
| Weighted Average Price ($/MMBtu) |
|
| Volume (MMBtu/d) |
|
| Weighted Average Floor Price ($/MMBtu) |
|
| Weighted Average Ceiling Price ($/MMBtu) |
| |||||
Q4 2017 |
|
| 331,196 |
|
| $ | 3.21 |
|
|
| 455,000 |
|
| $ | 3.03 |
|
| $ | 3.41 |
|
Q1-Q4 2018 |
|
| 261,888 |
|
| $ | 3.09 |
|
|
| 149,982 |
|
| $ | 2.99 |
|
| $ | 3.30 |
|
Q1-Q4 2019 |
|
| 6,164 |
|
| $ | 3.08 |
|
|
| 8,630 |
|
| $ | 2.92 |
|
| $ | 3.22 |
|
|
| Price Swaps |
|
| Price Collars |
| ||||||||||||||
Period |
| Volume (MMBtu/d) |
|
| Weighted Average Price ($/MMBtu) |
|
| Volume (MMBtu/d) |
|
| Weighted Average Floor Price ($/MMBtu) |
|
| Weighted Average |
| |||||
Q2-Q4 2023 |
|
| 57,309 |
|
| $ | 3.32 |
|
|
| 187,215 |
|
| $ | 3.62 |
|
| $ | 7.27 |
|
Q1-Q4 2024 |
|
| 40,426 |
|
| $ | 3.30 |
|
|
| 40,527 |
|
| $ | 3.78 |
|
| $ | 7.05 |
|
|
| Natural Gas Basis Swaps |
| |||||||
Period |
| Index |
| Volume |
|
| Weighted Average |
| ||
Q2-Q4 2023 |
| El Paso Natural Gas |
|
| 141,691 |
|
| $ | (1.58 | ) |
Q2-Q4 2023 |
| Houston Ship Channel |
|
| 140,000 |
|
| $ | (0.19 | ) |
Q2-Q4 2023 |
| WAHA |
|
| 70,000 |
|
| $ | (0.51 | ) |
Q1-Q4 2024 |
| El Paso Natural Gas |
|
| 19,945 |
|
| $ | (0.92 | ) |
Q1-Q4 2024 |
| Houston Ship Channel |
|
| 30,000 |
|
| $ | (0.32 | ) |
Q1-Q4 2024 |
| WAHA |
|
| 44,973 |
|
| $ | (0.58 | ) |
13
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
|
| Natural Gas Basis Swaps |
| |||||||
Period |
| Index |
| Volume (MMBtu/d) |
|
| Weighted Average Differential to Henry Hub ($/MMBtu) |
| ||
Q4 2017 |
| Panhandle Eastern Pipe Line |
|
| 150,000 |
|
| $ | (0.34 | ) |
Q4 2017 |
| El Paso Natural Gas |
|
| 80,000 |
|
| $ | (0.13 | ) |
Q4 2017 |
| Houston Ship Channel |
|
| 35,000 |
|
| $ | 0.06 |
|
Q4 2017 |
| Transco Zone 4 |
|
| 205,000 |
|
| $ | 0.03 |
|
Q1-Q4 2018 |
| Panhandle Eastern Pipe Line |
|
| 50,000 |
|
| $ | (0.29 | ) |
As of September 30, 2017,March 31, 2023, 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, 2023 and December 31, 2022.
| March 31, 2023 |
|
| December 31, 2022 |
|
|
| ||||||||||||||||||
| 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 | $ | 176 |
|
| $ | (5 | ) |
| $ | 171 |
|
| $ | 138 |
|
| $ | (19 | ) |
| $ | 119 |
|
| Other current assets |
Long-term derivative asset |
| 14 |
|
|
| (3 | ) |
|
| 11 |
|
|
| 12 |
|
|
| — |
|
|
| 12 |
|
| Other long-term assets |
Short-term derivative liability |
| (6 | ) |
|
| 5 |
|
|
| (1 | ) |
|
| (22 | ) |
|
| 19 |
|
|
| (3 | ) |
| Other current liabilities |
Long-term derivative liability |
| (4 | ) |
|
| 3 |
|
|
| (1 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
| Other long-term liabilities |
Total derivative asset (liability) | $ | 180 |
|
| $ | — |
|
| $ | 180 |
|
| $ | 128 |
|
| $ | — |
|
| $ | 128 |
|
|
|
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 2016 in conjunction with the reduction of workforce described in Note 6. For the nine months ended September 30, 2016, approximately $60 million of associated expense for these accelerated awards is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings.
|
| Three Months Ended March 31, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
G&A |
| $ | 23 |
|
| $ | 20 |
|
Related income tax benefit |
| $ | 20 |
|
| $ | 17 |
|
|
| 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 12/31/22 |
|
| 5,788 |
|
| $ | 29.11 |
|
|
| 1,841 |
|
| $ | 31.33 |
|
|
Granted |
|
| 1,174 |
|
| $ | 63.51 |
|
|
| 743 |
|
| $ | 51.38 |
|
|
Vested |
|
| (2,378 | ) |
| $ | 25.15 |
|
|
| (1,037 | ) |
| $ | 27.89 |
|
|
Forfeited |
|
| (32 | ) |
| $ | 42.04 |
|
|
| — |
|
| $ | — |
|
|
Unvested at 3/31/23 |
|
| 4,552 |
|
| $ | 39.95 |
|
|
| 1,547 |
| (1) | $ | 43.25 |
|
|
|
| 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 2017,2023, as indicated in the previous summary table. The grants in the previous summary table also include the impacts of performance share units granted in a prior year that vested higher than 100% of target due to Devon's TSR performance compared to our peers.
|
| 2017 |
|
| 2023 |
| ||||||||
Grant-date fair value |
| $ | 51.05 |
| — |
| $ | 53.12 |
|
| $ | 81.70 |
| |
Risk-free interest rate |
| 1.50% |
|
|
| 4.15 | % | |||||||
Volatility factor |
| 45.8% |
|
|
| 61.43 | % | |||||||
Contractual term (years) |
| 2.89 |
|
|
| 2.89 |
| |||||||
16
13
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, 2023.
|
| Restricted Stock |
|
| Performance |
| ||
|
| Awards/Units |
|
| Share Units |
| ||
Unrecognized compensation cost |
| $ | 132 |
|
| $ | 37 |
|
Weighted average period for recognition (years) |
|
| 3.0 |
|
|
| 2.0 |
|
|
|
|
|
|
| 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 |
|
5. Restructuring
The following table summarizes Devon’s restructuring liabilities. The remaining liabilities primarily relate to an abandoned Canadian firm transportation agreement.
|
| Other |
|
| Other |
|
|
|
| |||
|
| Current |
|
| Long-term |
|
|
|
| |||
|
| Liabilities |
|
| Liabilities |
|
| Total |
| |||
Balance as of December 31, 2022 |
| $ | 34 |
|
| $ | 81 |
|
| $ | 115 |
|
Changes related to prior years' restructurings |
|
| (11 | ) |
|
| (3 | ) |
|
| (14 | ) |
Balance as of March 31, 2023 |
| $ | 23 |
|
| $ | 78 |
|
| $ | 101 |
|
|
|
|
|
|
|
|
|
|
| |||
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 |
|
EnLink Share-Based Awards
6. Other, Net
The following table summarizes Devon's other expenses (income) presented in the accompanying consolidated comprehensive statements of earnings.
In March 2017,
|
| Three Months Ended March 31, |
| |||||
| 2023 |
|
| 2022 |
| |||
Estimated future obligation under a performance guarantee |
| $ | — |
|
| $ | (96 | ) |
Ukraine charitable pledge |
|
| — |
|
|
| 20 |
|
Asset retirement obligation accretion |
|
| 7 |
|
|
| 7 |
|
Other |
|
| (2 | ) |
|
| 8 |
|
Total |
| $ | 5 |
|
| $ | (61 | ) |
Devon has guaranteed performance through 2026 for a minimum volume commitment associated with assets divested in 2018. Due to improved commodity prices, market conditions, and performance by the General Partner and EnLink issued restricted incentive units as bonus paymentspurchaser of the assets, the purchaser was able to officers and certain employees. The combined grant fair value was $10 million, andfully satisfy the total cost was recognizedperformance obligation due in the first quarter of 2017 due to2023 and 2022. Additionally, at March 31, 2022, Devon reduced the awards vesting immediately.
The following table presents a summaryestimated future exposure of the unrecognized compensation costperformance guarantee. The effect of these cash collections and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units as of September 30, 2017.
|
| 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 pricesliability revisions resulted in effect on the first day of each of the previous 12 months.
The oil and gas impairmentsa $96 million benefit 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 122022.
The first quarter of 2022 includes a $20 million pledge for additional details.humanitarian relief for the Ukrainian people and surrounding countries supporting refugees.
1714
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
6.Restructuring and Transaction Costs
The following table summarizes restructuring and transaction costs presented in the accompanying consolidated comprehensive statement of earnings.
|
| September 30, 2016 |
| |||||
|
| Three Months Ended |
|
| Nine Months Ended |
| ||
|
| (Millions) |
| |||||
2016 reduction in workforce: |
|
|
|
|
|
|
|
|
Employee related costs |
| $ | (7 | ) |
| $ | 229 |
|
Lease obligations |
|
| — |
|
|
| 17 |
|
Asset impairments |
|
| — |
|
|
| 3 |
|
Transaction costs |
|
| 2 |
|
|
| 17 |
|
Restructuring and transaction costs |
| $ | (5 | ) |
| $ | 266 |
|
The following table summarizes Devon’s restructuring liabilities.7. Income Taxes
|
| Other |
|
| Other |
|
|
|
|
| ||
|
| Current |
|
| Long-term |
|
|
|
|
| ||
|
| Liabilities |
|
| Liabilities |
|
| Total |
| |||
|
| (Millions) |
| |||||||||
Balance as of December 31, 2016 |
| $ | 48 |
|
| $ | 62 |
|
| $ | 110 |
|
Changes due to 2016 workforce reductions |
|
| (25 | ) |
|
| (2 | ) |
|
| (27 | ) |
Changes related to prior years' restructurings |
|
| (3 | ) |
|
| (24 | ) |
|
| (27 | ) |
Balance as of September 30, 2017 |
| $ | 20 |
|
| $ | 36 |
|
| $ | 56 |
|
Balance as of December 31, 2015 |
| $ | 13 |
|
| $ | 63 |
|
| $ | 76 |
|
Changes due to 2016 workforce reductions |
|
| 58 |
|
|
| 13 |
|
|
| 71 |
|
Changes related to prior years' restructurings |
|
| 5 |
|
|
| (8 | ) |
|
| (3 | ) |
Balance as of September 30, 2016 |
| $ | 76 |
|
| $ | 68 |
|
| $ | 144 |
|
Reduction in Workforce
In the first nine months of 2016, Devon recognized $229 million in employee-related costs associated with a reduction in workforce. Of these employee-related costs, approximately $60 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, approximately $30 million resulted from estimated settlements of defined retirement benefits.
As a result of the reduction of workforce, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Devon recognized restructuring costs that represent the present value of its future obligations under the leases and impairment charges for leasehold improvements and furniture associated with the office space it ceased using.
Transaction Costs
In the first nine months of 2016, Devon and EnLink recognized transaction costs primarily associated with the closing of the acquisitions discussed in Note 2.
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents Devon’s total income tax expense (benefit) and a reconciliation of its effective income tax rate to the U.S. statutory income tax rate.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
| (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 | % |
|
| Three Months Ended March 31, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
Earnings before income taxes |
| $ | 1,224 |
|
| $ | 1,262 |
|
|
|
|
|
|
|
| ||
Current income tax expense |
| $ | 141 |
|
| $ | 103 |
|
Deferred income tax expense |
|
| 80 |
|
|
| 164 |
|
Total income tax expense |
| $ | 221 |
|
| $ | 267 |
|
|
|
|
|
|
|
| ||
U.S. statutory income tax rate |
|
| 21 | % |
|
| 21 | % |
State income taxes |
|
| 1 | % |
|
| 1 | % |
Other |
|
| (4 | %) |
|
| (1 | %) |
Effective income tax rate |
|
| 18 | % |
|
| 21 | % |
Devon estimates its annual effectiveOn August 16, 2022 the IRA was signed into law and included various income tax raterelated provisions with effective dates generally beginning in recording its quarterly provision for income taxes in2023. Among the various jurisdictions in whichenacted provisions are a 15% corporate alternative minimum tax ("CAMT") and several new and expanded clean energy credits and incentives. Dependent upon future regulations, Devon believes 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 maintain a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses largely due to full cost impairments. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets.
Devon provided an additional $796 millionis subject to the U.S. segment valuation allowance inCAMT as Devon has an average annual adjusted financial statement income that exceeds $1 billion for the first nine months of 2016 based on the financial loss recorded during the period. Also, during the third quarter of 2016, Devon’s Canadian segment recorded a $71 million partial valuation allowance. Devon reduced its U.S. segment valuation allowance by $348 million in the first nine months of 2017 based on the financial income recorded during the period.three-year period ended December 31, 2022.
Also in the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate 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 calculating2023, Devon recognized income tax and, therefore, have ancredits associated with its qualified research activities performed during the 2018 to 2021 tax years. The impact on the effective tax rate.
Devonof these credits is under auditincluded within Other 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.table above.
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) |
|
| 2023 |
|
| 2022 |
| |||||||||||||||
Net earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Net earnings (loss) attributable to Devon |
| $ | 228 |
|
| $ | 993 |
|
| $ | 1,218 |
|
| $ | (3,633 | ) | ||||||||
Net earnings: |
|
|
|
|
| |||||||||||||||||||
Net earnings |
| $ | 995 |
|
| $ | 989 |
| ||||||||||||||||
Attributable to participating securities |
|
| (2 | ) |
|
| (11 | ) |
|
| (13 | ) |
|
| (1 | ) |
|
| (8 | ) |
|
| (16 | ) |
Basic and diluted earnings (loss) |
| $ | 226 |
|
| $ | 982 |
|
| $ | 1,205 |
|
| $ | (3,634 | ) | ||||||||
Basic and diluted earnings |
| $ | 987 |
|
| $ | 973 |
| ||||||||||||||||
Common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Common shares outstanding - total |
|
| 526 |
|
|
| 524 |
|
|
| 525 |
|
|
| 509 |
|
|
| 651 |
|
|
| 663 |
|
Attributable to participating securities |
|
| (6 | ) |
|
| (6 | ) |
|
| (6 | ) |
|
| (6 | ) |
|
| (6 | ) |
|
| (7 | ) |
Common shares outstanding - basic |
|
| 520 |
|
|
| 518 |
|
|
| 519 |
|
|
| 503 |
|
|
| 645 |
|
|
| 656 |
|
Dilutive effect of potential common shares issuable |
|
| 3 |
|
|
| 3 |
|
|
| 3 |
|
|
| — |
|
|
| 2 |
|
|
| 2 |
|
Common shares outstanding - diluted |
|
| 523 |
|
|
| 521 |
|
|
| 522 |
|
|
| 503 |
|
|
| 647 |
|
|
| 658 |
|
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Net earnings per share: |
|
|
|
|
|
| ||||||||||||||||||
Basic |
| $ | 0.43 |
|
| $ | 1.90 |
|
| $ | 2.32 |
|
| $ | (7.22 | ) |
| $ | 1.53 |
|
| $ | 1.48 |
|
Diluted |
| $ | 0.43 |
|
| $ | 1.89 |
|
| $ | 2.31 |
|
| $ | (7.22 | ) |
| $ | 1.53 |
|
| $ | 1.48 |
|
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 |
|
|
|
2015
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, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
Pension and postretirement benefit plans: |
|
|
|
|
|
| ||
Beginning accumulated pension and postretirement benefits |
| $ | (116 | ) |
| $ | (132 | ) |
Recognition of net actuarial loss and prior service cost in earnings (1) |
|
| 1 |
|
|
| 1 |
|
Accumulated other comprehensive loss, net of tax |
| $ | (115 | ) |
| $ | (131 | ) |
|
| 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, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
Changes in assets and liabilities, net: |
|
|
|
|
|
| ||
Accounts receivable |
| $ | 150 |
|
| $ | (457 | ) |
Other current assets |
|
| 16 |
|
|
| 64 |
|
Other long-term assets |
|
| 31 |
|
|
| 66 |
|
Accounts payable and revenues and royalties payable |
|
| (165 | ) |
|
| 247 |
|
Other current liabilities |
|
| (3 | ) |
|
| 8 |
|
Other long-term liabilities |
|
| (17 | ) |
|
| (71 | ) |
Total |
| $ | 12 |
|
| $ | (143 | ) |
Supplementary cash flow data: |
|
|
|
|
|
| ||
Interest paid |
| $ | 101 |
|
| $ | 100 |
|
Income taxes refunded |
| $ | — |
|
| $ | (23 | ) |
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, 2023 |
|
| December 31, 2022 |
| |||||||
Oil, gas and NGL sales |
| $ | 528 |
|
| $ | 487 |
|
| $ | 1,025 |
|
| $ | 1,153 |
|
Joint interest billings |
|
| 111 |
|
|
| 110 |
|
|
| 238 |
|
|
| 162 |
|
Marketing and midstream revenues |
|
| 792 |
|
|
| 708 |
|
|
| 325 |
|
|
| 428 |
|
Other |
|
| 44 |
|
|
| 69 |
|
|
| 36 |
|
|
| 33 |
|
Gross accounts receivable |
|
| 1,475 |
|
|
| 1,374 |
|
|
| 1,624 |
|
|
| 1,776 |
|
Allowance for doubtful accounts |
|
| (13 | ) |
|
| (18 | ) |
|
| (9 | ) |
|
| (9 | ) |
Net accounts receivable |
| $ | 1,462 |
|
| $ | 1,356 |
|
| $ | 1,615 |
|
| $ | 1,767 |
|
|
|
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.
2116
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
12. 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, 2023 |
|
| December 31, 2022 |
| ||
Property and equipment: |
|
|
|
|
|
| ||
Proved |
| $ | 43,584 |
|
| $ | 42,734 |
|
Unproved and properties under development |
|
| 1,654 |
|
|
| 1,548 |
|
Total oil and gas |
|
| 45,238 |
|
|
| 44,282 |
|
Less accumulated DD&A |
|
| (28,306 | ) |
|
| (27,715 | ) |
Oil and gas property and equipment, net |
|
| 16,932 |
|
|
| 16,567 |
|
Other property and equipment |
|
| 2,340 |
|
|
| 2,280 |
|
Less accumulated DD&A |
|
| (757 | ) |
|
| (741 | ) |
Other property and equipment, net (1) |
|
| 1,583 |
|
|
| 1,539 |
|
Property and equipment, net |
| $ | 18,515 |
|
| $ | 18,106 |
|
|
| 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 is as follows:instruments and balances. The notes and debentures are senior, unsecured obligations of Devon.
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
|
| (Millions) |
| |||||
Devon debt: |
|
|
|
|
|
|
|
|
Debentures and notes |
| $ | 6,933 |
|
| $ | 6,933 |
|
Net discount on debentures and notes |
|
| (30 | ) |
|
| (30 | ) |
Debt issuance costs |
|
| (41 | ) |
|
| (44 | ) |
Total Devon debt |
|
| 6,862 |
|
|
| 6,859 |
|
EnLink debt: |
|
|
|
|
|
|
|
|
Credit facilities |
|
| 74 |
|
|
| 148 |
|
Debentures and notes |
|
| 3,500 |
|
|
| 3,163 |
|
Net premium (discount) on debentures and notes |
|
| (6 | ) |
|
| 9 |
|
Debt issuance costs |
|
| (27 | ) |
|
| (25 | ) |
Total EnLink debt |
|
| 3,541 |
|
|
| 3,295 |
|
Total debt |
|
| 10,403 |
|
|
| 10,154 |
|
Less amount classified as short-term debt (1) |
|
| 20 |
|
|
| — |
|
Total long-term debt |
| $ | 10,383 |
|
| $ | 10,154 |
|
|
| March 31, 2023 |
|
| December 31, 2022 |
| ||
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 on debentures and notes |
|
| 92 |
|
|
| 103 |
|
Debt issuance costs |
|
| (33 | ) |
|
| (26 | ) |
Total debt |
| $ | 6,422 |
|
| $ | 6,440 |
|
Less amount classified as short-term debt |
|
| 247 |
|
|
| 251 |
|
Total long-term debt |
| $ | 6,175 |
|
| $ | 6,189 |
|
|
|
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
On March 24, 2023, Devon hasamended and restated its 2018 Senior Credit Facility to provide for a $3.0new $3.0 billion revolving 2023 Senior Credit Facility with a financial covenant and other terms similar to the 2018 Senior Credit Facility. The 2023 Senior Credit Facility matures on March 24, 2028, with the option to extend the maturity date by three additional one-year periods, subject to lender consent. As of September 30, 2017,March 31, 2023, Devon had $59no outstanding borrowings under the 2023 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 2023 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 noncashnon-cash financial write-downs such as full cost ceiling impairments or goodwill impairments. As of September 30, 2017,March 31, 2023, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 18.9%23.2%.
Retirement17
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.DEVON ENERGY CORPORATION AND SUBSIDIARIES
EnLink DebtNOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
All of EnLink’s and the General Partner’s debt is non-recourse to Devon.(Unaudited)
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, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
Interest based on debt outstanding |
| $ | 93 |
|
| $ | 92 |
|
Interest income |
|
| (17 | ) |
|
| (1 | ) |
Other |
|
| (4 | ) |
|
| (6 | ) |
Total net financing costs |
| $ | 72 |
|
| $ | 85 |
|
Interest income increased from 2022 to 2023 primarily due to higher interest rates on cash balances.
|
| 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, 2023 and December 31, 2022.
|
| March 31, 2023 |
|
| December 31, 2022 |
| ||||||||||||||||||
|
| Finance |
|
| Operating |
|
| Total |
|
| Finance |
|
| Operating |
|
| Total |
| ||||||
Right-of-use assets |
| $ | 201 |
|
| $ | 18 |
|
| $ | 219 |
|
| $ | 203 |
|
| $ | 21 |
|
| $ | 224 |
|
Lease liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Current lease liabilities (1) |
| $ | 8 |
|
| $ | 12 |
|
| $ | 20 |
|
| $ | 8 |
|
| $ | 13 |
|
| $ | 21 |
|
Long-term lease liabilities |
|
| 250 |
|
|
| 6 |
|
|
| 256 |
|
|
| 249 |
|
|
| 8 |
|
|
| 257 |
|
Total lease liabilities |
| $ | 258 |
|
| $ | 18 |
|
| $ | 276 |
|
| $ | 257 |
|
| $ | 21 |
|
| $ | 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) |
|
| 2023 |
|
| 2022 |
| |||||||
Asset retirement obligations as of beginning of period |
| $ | 1,272 |
|
| $ | 1,414 |
|
| $ | 529 |
|
| $ | 485 |
|
Liabilities incurred and assumed through acquisitions |
|
| 30 |
|
|
| 18 |
| ||||||||
Liabilities incurred |
|
| 6 |
|
|
| 8 |
| ||||||||
Liabilities settled and divested |
|
| (53 | ) |
|
| (310 | ) |
|
| (6 | ) |
|
| (3 | ) |
Revision of estimated obligation |
|
| (184 | ) |
|
| 70 |
|
|
| 27 |
|
|
| (35 | ) |
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 |
|
|
| 563 |
|
|
| 462 |
|
Less current portion |
|
| 41 |
|
|
| 46 |
|
|
| 17 |
|
|
| 19 |
|
Asset retirement obligations, long-term |
| $ | 1,100 |
|
| $ | 1,230 |
|
| $ | 546 |
|
| $ | 443 |
|
During the first quarter of 2017,2023, Devon reducedincreased its estimated asset retirement obligations by $184approximately $27 million primarily due to changesinflation-driven increases in the assumed inflation rate and retirement dates for its oil and gas assets.
current cost estimates. During the first nine monthsquarter 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.
2418
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 2022, the Board of Directors authorized expansions of the share repurchase program ultimately to $2.0 billion and extended the expiration date to May 4, 2023. In May 2023, the Board of Directors authorized a further expansion to $3.0 billion and extended the expiration date to December 31, 2024. The table below summarizesprovides information regarding purchases of Devon’s common stock under the dividends $3.0 billion share repurchase program (shares in thousands).
|
| Total Number of |
|
| Dollar Value of |
|
| Average Price Paid |
| |||
$3.0 Billion Plan |
|
|
|
|
|
|
|
|
| |||
2021: |
|
|
|
|
|
|
|
|
| |||
Fourth quarter |
|
| 13,983 |
|
| $ | 589 |
|
| $ | 42.15 |
|
2022: |
|
|
|
|
|
|
|
|
| |||
First quarter |
|
| 3,979 |
|
|
| 230 |
|
| $ | 57.74 |
|
Second quarter |
|
| 5,052 |
|
|
| 318 |
|
| $ | 63.07 |
|
Third quarter |
|
| 1,875 |
|
|
| 113 |
|
| $ | 59.99 |
|
Fourth quarter |
|
| 802 |
|
|
| 57 |
|
| $ | 71.69 |
|
2023: |
|
|
|
|
|
|
|
|
| |||
First quarter |
|
| 10,090 |
|
|
| 545 |
|
| $ | 53.96 |
|
Total plan |
|
| 35,781 |
|
| $ | 1,852 |
|
| $ | 51.77 |
|
Dividends
Devon paid on its common stock.
| Amounts |
|
| Rate |
| ||
| (Millions) |
|
| (Per Share) |
| ||
Quarter Ended 2017: |
|
|
|
|
|
|
|
First quarter 2017 | $ | 32 |
|
| $ | 0.06 |
|
Second quarter 2017 |
| 33 |
|
| $ | 0.06 |
|
Third quarter 2017 |
| 30 |
|
| $ | 0.06 |
|
Total year-to-date | $ | 95 |
|
|
|
|
|
Quarter Ended 2016: |
|
|
|
|
|
|
|
First quarter 2016 | $ | 125 |
|
| $ | 0.24 |
|
Second quarter 2016 |
| 33 |
|
| $ | 0.06 |
|
Third quarter 2016 |
| 32 |
|
| $ | 0.06 |
|
Total year-to-date | $ | 190 |
|
|
|
|
|
In response to the depressed commodity price environment, Devon reduced itspays a quarterly dividend to $0.06which is comprised of a fixed dividend and a variable dividend. The variable dividend is dependent on quarterly cash flows, among other factors. Devon raised its fixed dividend multiple times over the past year from $0.16 per share in the first quarter of 2022 to $0.20 per share beginning in the first quarter of 2023. The following table summarizes Devon’s fixed and variable dividends for the first quarter of 2023 and 2022, respectively.
| Fixed |
|
| Variable |
|
| Total |
|
| Rate Per Share |
| ||||
2023: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 133 |
|
| $ | 463 |
|
| $ | 596 |
|
| $ | 0.89 |
|
2022: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 109 |
|
| $ | 558 |
|
| $ | 667 |
|
| $ | 1.00 |
|
In May 2023, Devon announced a cash dividend in the amount of $0.72 per share payable in the second quarter of 2016.
|
|
Subsidiary Equity Transactions
EnLink has the ability to sell common units through its “at the market” equity offering programs. In the third quarter of 2017, EnLink entered into additional equity distribution agreements to sell up to $600 million in common units through its programs. Future common units that EnLink issues will be issued under the new equity distribution agreement. During the first nine months of 2017, EnLink issued and sold 5 million common units through its programs and generated $92 million in net proceeds.
In September 2017, EnLink issued 400,000 preferred units through an underwritten public offering for net proceeds of approximately $394 million.
During the first nine months of 2016, EnLink issued and sold 7 million common units for net proceeds of $110 million. In conjunction with its acquisition of Anadarko Basin gathering and processing midstream assets during the first quarter of 2016, EnLink issued preferred units as discussed in Note 2.
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 interest in the General Partner as of September 30, 2017 was 64%2023. The net gainsdividend consists of a $0.20 per share fixed quarterly dividend and lossesa $0.52 per share variable quarterly dividend 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.will total approximately $461 million.
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
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
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.
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 does not currently believebelieves 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 denies the allegations in these lawsuits and 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 denies all allegations asserted in these lawsuits and intends to vigorously defend against these claims.
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.
20
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, 2023 and December 31, 2016. 2022, 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, 2023 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cash equivalents |
| $ | 217 |
|
| $ | 217 |
|
| $ | 217 |
|
| $ | — |
|
| $ | — |
|
Commodity derivatives |
| $ | 182 |
|
| $ | 182 |
|
| $ | — |
|
| $ | 182 |
|
| $ | — |
|
Commodity derivatives |
| $ | (2 | ) |
| $ | (2 | ) |
| $ | — |
|
| $ | (2 | ) |
| $ | — |
|
Debt |
| $ | (6,422 | ) |
| $ | (6,278 | ) |
| $ | — |
|
| $ | (6,278 | ) |
| $ | — |
|
Contingent earnout payments |
| $ | 88 |
|
| $ | 88 |
|
| $ | — |
|
| $ | — |
|
| $ | 88 |
|
December 31, 2022 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cash equivalents |
| $ | 708 |
|
| $ | 708 |
|
| $ | 708 |
|
| $ | — |
|
| $ | — |
|
Commodity derivatives |
| $ | 131 |
|
| $ | 131 |
|
| $ | — |
|
| $ | 131 |
|
| $ | — |
|
Commodity derivatives |
| $ | (3 | ) |
| $ | (3 | ) |
| $ | — |
|
| $ | (3 | ) |
| $ | — |
|
Debt |
| $ | (6,440 | ) |
| $ | (6,231 | ) |
| $ | — |
|
| $ | (6,231 | ) |
| $ | — |
|
Contingent earnout payments |
| $ | 157 |
|
| $ | 157 |
|
| $ | — |
|
| $ | — |
|
| $ | 157 |
|
|
|
|
|
|
|
|
|
|
| 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 asset divestiture 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.
2721
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, 2023 compared to the three-month and nine-monthprevious periods, ended September 30, 2016 and in our financial condition and liquidity since December 31, 2016.2022. For information regarding our critical accounting policies and estimates, see our 20162022 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Executive Overview
We are a leading independent oil and natural gas exploration and production company whose operations are focused onshore in the United Sates. Our operations are currently focused in five core areas: the Delaware Basin, Eagle Ford, Anadarko Basin, Williston Basin and Powder River Basin. Our asset base is underpinned by premium acreage in the economic core of 2017 Results
Key components ofthe Delaware Basin and our financial performance are summarized below.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, (3) |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| Change |
|
| 2017 |
|
| 2016 |
|
| Change |
| ||||||
|
| (Millions, except per share amounts) |
| |||||||||||||||||||||
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 months of 2017, we generated solid operating results with our three-fold strategy of operating in North America’s bestdiverse, top-tier resource plays delivering superior execution and maintainingprovide a high degreedeep inventory of financial strength. Led by our development in the STACK, we continuedopportunities for years to improve our 90-day initial production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity performance and improving the performance of our established wells. Even though our 2017 production volumes have declined from 2016 due to reduced capital investment, we estimate our highest-margin U.S. oil production from retained assets will exit 2017 at levels approximately 20% higher than year-end 2016.
Compared to 2016, commodity prices increased significantly and were the primary driver for improvements in Devon’s operating margins, earnings and cash flow during the first nine months of 2017. We exitedcome. In the third quarter of 20172022, we acquired additional producing properties and leasehold interests in both the Williston Basin and Eagle Ford that were complementary to our existing acreage, offered operational synergies and added additional high-quality inventory to our portfolio.
We remain focused on building economic value by executing on our strategic priorities of moderating production growth, emphasizing capital and operational efficiencies, optimizing 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:
We remain committed to capital discipline and delivering the objectives that underpin our Senior Credit Facility. We have no significant debt maturities until 2021. At September 30, 2017, we also had approximately 65%current plan. Those objectives prioritize value creation through moderated capital investment and production growth, particularly with a view of the volatility in commodity prices, supply chain constraints and the economic uncertainty arising from inflation and recent geopolitical events.
22
Results of Operations
The following graphs, discussion and analysis are intended to provide an understanding of our remaining 2017 forecasted oil production hedged at an average floor priceresults of $50/Bbloperations and approximately 66%current financial condition. To facilitate the review, these numbers are being presented before consideration of our remaining 2017 forecasted natural gas production hedged at an average floor pricenoncontrolling interests.
Q1 2023 vs. Q4 2022
Our first quarter 2023 and fourth quarter 2022 net earnings were $1.0 billion and $1.2 billion, respectively. The graph below shows the change in net earnings from the fourth quarter of $3.10/MMBtu. We2022 to the first quarter of 2023. The material changes are building our 2018 and 2019 hedge positions at similar prices.further discussed by category on the following pages.
We expect to further enhance our financial strength with our announced $1 billion asset divestiture program. The planned divestitures include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, we have closed non-core divestitures totaling approximately $400 million under this program.Production Volumes
|
| Q1 2023 |
|
| % of Total |
|
| Q4 2022 |
|
| Change |
| ||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 211 |
|
|
| 66 | % |
|
| 201 |
|
|
| 5 | % |
Eagle Ford |
|
| 40 |
|
|
| 13 | % |
|
| 42 |
|
|
| -4 | % |
Anadarko Basin |
|
| 15 |
|
|
| 5 | % |
|
| 15 |
|
|
| 1 | % |
Williston Basin |
|
| 36 |
|
|
| 11 | % |
|
| 37 |
|
|
| -4 | % |
Powder River Basin |
|
| 14 |
|
|
| 4 | % |
|
| 16 |
|
|
| -9 | % |
Other |
|
| 4 |
|
|
| 1 | % |
|
| 5 |
|
|
| -14 | % |
Total |
|
| 320 |
|
|
| 100 | % |
|
| 316 |
|
|
| 2 | % |
|
| Q1 2023 |
|
| % of Total |
|
| Q4 2022 |
|
| Change |
| ||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 640 |
|
|
| 62 | % |
|
| 626 |
|
|
| 2 | % |
Eagle Ford |
|
| 82 |
|
|
| 8 | % |
|
| 84 |
|
|
| -3 | % |
Anadarko Basin |
|
| 237 |
|
|
| 23 | % |
|
| 238 |
|
|
| 0 | % |
Williston Basin |
|
| 54 |
|
|
| 5 | % |
|
| 64 |
|
|
| -15 | % |
Powder River Basin |
|
| 16 |
|
|
| 2 | % |
|
| 21 |
|
|
| -24 | % |
Other |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| 32 | % |
Total |
|
| 1,030 |
|
|
| 100 | % |
|
| 1,034 |
|
|
| 0 | % |
|
| Q1 2023 |
|
| % of Total |
|
| Q4 2022 |
|
| Change |
| ||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 97 |
|
|
| 65 | % |
|
| 101 |
|
|
| -4 | % |
Eagle Ford |
|
| 15 |
|
|
| 10 | % |
|
| 12 |
|
|
| 24 | % |
Anadarko Basin |
|
| 26 |
|
|
| 18 | % |
|
| 23 |
|
|
| 15 | % |
Williston Basin |
|
| 8 |
|
|
| 6 | % |
|
| 9 |
|
|
| -11 | % |
Powder River Basin |
|
| 2 |
|
|
| 1 | % |
|
| 3 |
|
|
| -23 | % |
Other |
|
| 1 |
|
|
| 0 | % |
|
| — |
|
| N/M |
| |
Total |
|
| 149 |
|
|
| 100 | % |
|
| 148 |
|
|
| 1 | % |
2923
We recently unveiled our “2020 Vision,” which is
|
| Q1 2023 |
|
| % of Total |
|
| Q4 2022 |
|
| Change |
| ||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 415 |
|
|
| 65 | % |
|
| 407 |
|
|
| 2 | % |
Eagle Ford |
|
| 68 |
|
|
| 11 | % |
|
| 68 |
|
|
| 1 | % |
Anadarko Basin |
|
| 81 |
|
|
| 12 | % |
|
| 77 |
|
|
| 5 | % |
Williston Basin |
|
| 53 |
|
|
| 8 | % |
|
| 57 |
|
|
| -7 | % |
Powder River Basin |
|
| 19 |
|
|
| 3 | % |
|
| 22 |
|
|
| -13 | % |
Other |
|
| 5 |
|
|
| 1 | % |
|
| 5 |
|
|
| -7 | % |
Total |
|
| 641 |
|
|
| 100 | % |
|
| 636 |
|
|
| 1 | % |
From the fourth quarter of 2022 to the first quarter of 2023, the change in volumes contributed to a strategic plan through$31 million decrease to earnings as the end of the decade intended to deliver top-tier returns on invested capital, while delivering sustainable, long-term growth for our business. We plan to attain leading returns with our 2020 Visionhigher production per day was offset by pursing the following objectives:
|
|
|
|
|
|
|
|
|
|
30
Oil, Gas and NGL Production
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| Change |
|
| 2017 |
|
| 2016 |
|
| Change |
| ||||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 1 |
|
|
| 1 |
|
|
| - 13 | % |
|
| 1 |
|
|
| 1 |
|
|
| - 22 | % |
Delaware Basin |
|
| 31 |
|
|
| 31 |
|
|
| +0 | % |
|
| 31 |
|
|
| 35 |
|
|
| - 12 | % |
Eagle Ford |
|
| 30 |
|
|
| 33 |
|
|
| - 10 | % |
|
| 38 |
|
|
| 44 |
|
|
| - 15 | % |
Heavy Oil |
|
| 18 |
|
|
| 22 |
|
|
| - 15 | % |
|
| 18 |
|
|
| 23 |
|
|
| - 22 | % |
Rockies Oil |
|
| 12 |
|
|
| 11 |
|
|
| +9 | % |
|
| 13 |
|
|
| 14 |
|
|
| - 9 | % |
STACK |
|
| 27 |
|
|
| 21 |
|
|
| +31 | % |
|
| 24 |
|
|
| 18 |
|
|
| +34 | % |
Other |
|
| 11 |
|
|
| 11 |
|
|
| + 4 | % |
|
| 10 |
|
|
| 12 |
|
|
| - 17 | % |
Retained assets |
|
| 130 |
|
|
| 130 |
|
|
| +0 | % |
|
| 135 |
|
|
| 147 |
|
|
| - 8 | % |
Divested assets |
|
| — |
|
|
| 6 |
|
|
| N/M |
|
|
| — |
|
|
| 13 |
|
|
| N/M |
|
Total |
|
| 130 |
|
|
| 136 |
|
|
| - 5 | % |
|
| 135 |
|
|
| 160 |
|
|
| - 16 | % |
Bitumen (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Heavy Oil |
|
| 103 |
|
|
| 115 |
|
|
| - 11 | % |
|
| 109 |
|
|
| 105 |
|
|
| +4 | % |
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 672 |
|
|
| 730 |
|
|
| - 8 | % |
|
| 677 |
|
|
| 752 |
|
|
| - 10 | % |
Delaware Basin |
|
| 90 |
|
|
| 92 |
|
|
| - 3 | % |
|
| 91 |
|
|
| 92 |
|
|
| - 0 | % |
Eagle Ford |
|
| 88 |
|
|
| 85 |
|
|
| +4 | % |
|
| 101 |
|
|
| 111 |
|
|
| - 9 | % |
Heavy Oil |
|
| 16 |
|
|
| 18 |
|
|
| - 11 | % |
|
| 17 |
|
|
| 20 |
|
|
| - 14 | % |
Rockies Oil |
|
| 11 |
|
|
| 19 |
|
|
| - 39 | % |
|
| 14 |
|
|
| 27 |
|
|
| - 47 | % |
STACK |
|
| 313 |
|
|
| 292 |
|
|
| +7 | % |
|
| 300 |
|
|
| 296 |
|
|
| +1 | % |
Other |
|
| 11 |
|
|
| 13 |
|
|
| - 16 | % |
|
| 12 |
|
|
| 14 |
|
|
| - 16 | % |
Retained assets |
|
| 1,201 |
|
|
| 1,249 |
|
|
| - 4 | % |
|
| 1,212 |
|
|
| 1,312 |
|
|
| - 8 | % |
Divested assets |
|
| — |
|
|
| 75 |
|
|
| N/M |
|
|
| — |
|
|
| 165 |
|
|
| N/M |
|
Total |
|
| 1,201 |
|
|
| 1,324 |
|
|
| - 9 | % |
|
| 1,212 |
|
|
| 1,477 |
|
|
| - 18 | % |
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 36 |
|
|
| 44 |
|
|
| - 18 | % |
|
| 40 |
|
|
| 45 |
|
|
| - 10 | % |
Delaware Basin |
|
| 11 |
|
|
| 12 |
|
|
| - 14 | % |
|
| 10 |
|
|
| 12 |
|
|
| - 19 | % |
Eagle Ford |
|
| 12 |
|
|
| 13 |
|
|
| - 8 | % |
|
| 13 |
|
|
| 18 |
|
|
| - 29 | % |
Rockies Oil |
|
| 1 |
|
|
| 1 |
|
|
| +9 | % |
|
| 1 |
|
|
| 1 |
|
|
| - 2 | % |
STACK |
|
| 32 |
|
|
| 23 |
|
|
| +37 | % |
|
| 30 |
|
|
| 28 |
|
|
| +7 | % |
Other |
|
| 2 |
|
|
| 3 |
|
|
| - 10 | % |
|
| 2 |
|
|
| 3 |
|
|
| - 13 | % |
Retained assets |
|
| 94 |
|
|
| 96 |
|
|
| - 2 | % |
|
| 96 |
|
|
| 107 |
|
|
| - 10 | % |
Divested assets |
|
| — |
|
|
| 8 |
|
|
| N/M |
|
|
| — |
|
|
| 17 |
|
|
| N/M |
|
Total |
|
| 94 |
|
|
| 104 |
|
|
| - 10 | % |
|
| 96 |
|
|
| 124 |
|
|
| - 22 | % |
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 148 |
|
|
| 166 |
|
|
| - 11 | % |
|
| 154 |
|
|
| 171 |
|
|
| - 10 | % |
Delaware Basin |
|
| 57 |
|
|
| 59 |
|
|
| - 3 | % |
|
| 56 |
|
|
| 62 |
|
|
| - 11 | % |
Eagle Ford |
|
| 57 |
|
|
| 61 |
|
|
| - 7 | % |
|
| 67 |
|
|
| 81 |
|
|
| - 17 | % |
Heavy Oil |
|
| 124 |
|
|
| 140 |
|
|
| - 11 | % |
|
| 130 |
|
|
| 132 |
|
|
| - 1 | % |
Rockies Oil |
|
| 16 |
|
|
| 16 |
|
|
| +0 | % |
|
| 17 |
|
|
| 20 |
|
|
| - 17 | % |
STACK |
|
| 111 |
|
|
| 92 |
|
|
| +20 | % |
|
| 104 |
|
|
| 95 |
|
|
| +9 | % |
Other |
|
| 14 |
|
|
| 16 |
|
|
| - 8 | % |
|
| 14 |
|
|
| 17 |
|
|
| - 17 | % |
Retained assets |
|
| 527 |
|
|
| 550 |
|
|
| - 4 | % |
|
| 542 |
|
|
| 578 |
|
|
| - 6 | % |
Divested assets |
|
| — |
|
|
| 27 |
|
|
| N/M |
|
|
| — |
|
|
| 57 |
|
|
| N/M |
|
Total |
|
| 527 |
|
|
| 577 |
|
|
| - 9 | % |
|
| 542 |
|
|
| 635 |
|
|
| - 15 | % |
31
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
| ||||||||||||||||||
|
| 2017 (1) |
|
| 2016 (1) |
|
| Change |
|
| 2017 (1) |
|
| 2016 (1) |
|
| Change |
|
| ||||||
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 47.12 |
|
| $ | 42.51 |
|
|
| +11 | % |
| $ | 47.84 |
|
| $ | 36.89 |
|
|
| +30 | % |
|
Canada |
| $ | 35.02 |
|
| $ | 27.46 |
|
|
| +28 | % |
| $ | 32.77 |
|
| $ | 22.26 |
|
|
| +47 | % |
|
Total |
| $ | 45.41 |
|
| $ | 40.12 |
|
|
| +13 | % |
| $ | 45.83 |
|
| $ | 34.78 |
|
|
| +32 | % |
|
Bitumen (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
| $ | 31.75 |
|
| $ | 23.00 |
|
|
| +38 | % |
| $ | 28.49 |
|
| $ | 17.77 |
|
|
| +60 | % |
|
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 2.45 |
|
| $ | 2.24 |
|
|
| +10 | % |
| $ | 2.54 |
|
| $ | 1.70 |
|
|
| +50 | % |
|
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 15.15 |
|
| $ | 9.80 |
|
|
| +55 | % |
| $ | 14.62 |
|
| $ | 8.84 |
|
|
| +65 | % |
|
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
| $ | 23.85 |
|
| $ | 20.26 |
|
|
| +18 | % |
| $ | 24.44 |
|
| $ | 17.16 |
|
|
| +42 | % |
|
Canada |
| $ | 31.59 |
|
| $ | 23.23 |
|
|
| +36 | % |
| $ | 28.50 |
|
| $ | 18.15 |
|
|
| +57 | % |
|
Total |
| $ | 25.67 |
|
| $ | 20.98 |
|
|
| +22 | % |
| $ | 25.41 |
|
| $ | 17.37 |
|
|
| +46 | % |
|
|
|
The volume and price changesfewer days 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 sales increased in the third quarter and the first nine months of 2017 due to price increases for all commodities.quarter. The increase in oilvolumes per day was primarily due to new well activity in the Delaware and bitumen sales resulted fromAnadarko Basins which was partially offset by natural declines in the Williston and Powder River Basins.
Realized Prices
|
| Q1 2023 |
|
| Realization |
| Q4 2022 |
|
| Change |
| |||
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
| |||
WTI index |
| $ | 76.17 |
|
|
|
| $ | 82.53 |
|
|
| -8 | % |
Realized price, unhedged |
| $ | 74.32 |
|
| 98% |
| $ | 82.31 |
|
|
| -10 | % |
Cash settlements |
| $ | (0.10 | ) |
|
|
| $ | (4.87 | ) |
|
|
| |
Realized price, with hedges |
| $ | 74.22 |
|
| 97% |
| $ | 77.44 |
|
|
| -4 | % |
|
| Q1 2023 |
|
| Realization |
| Q4 2022 |
|
| Change |
| |||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
| |||
Henry Hub index |
| $ | 3.44 |
|
|
|
| $ | 6.26 |
|
|
| -45 | % |
Realized price, unhedged |
| $ | 2.29 |
|
| 67% |
| $ | 4.39 |
|
|
| -48 | % |
Cash settlements |
| $ | 0.18 |
|
|
|
| $ | (0.38 | ) |
|
|
| |
Realized price, with hedges |
| $ | 2.47 |
|
| 72% |
| $ | 4.01 |
|
|
| -38 | % |
|
| Q1 2023 |
|
| Realization |
| Q4 2022 |
|
| Change |
| |||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
| |||
WTI index |
| $ | 76.17 |
|
|
|
| $ | 82.53 |
|
|
| -8 | % |
Realized price, unhedged |
| $ | 24.12 |
|
| 32% |
| $ | 24.32 |
|
|
| -1 | % |
Cash settlements |
| $ | — |
|
|
|
| $ | — |
|
|
|
| |
Realized price, with hedges |
| $ | 24.12 |
|
| 32% |
| $ | 24.32 |
|
|
| -1 | % |
|
| Q1 2023 |
|
| Q4 2022 |
|
| Change |
| |||
Combined (per Boe) |
|
|
|
|
|
|
|
|
| |||
Realized price, unhedged |
| $ | 46.44 |
|
| $ | 53.66 |
|
|
| -13 | % |
Cash settlements |
| $ | 0.22 |
|
| $ | (3.04 | ) |
|
|
| |
Realized price, with hedges |
| $ | 46.66 |
|
| $ | 50.62 |
|
|
| -8 | % |
From the fourth quarter of 2022 to the first quarter of 2023, realized prices contributed to a higher average WTI crude$429 million decrease in earnings. Unhedged realized oil, index price. Additionally, our bitumen sales benefited from tighter heavy oil differentials. The increases in gas and NGL sales wereprices decreased primarily due to higher North American regional index prices upon which our gas sales are basedlower WTI, Henry Hub and higher NGL prices at the Mont Belvieu Texas hub.
index prices. The increasesdecrease in sales due to the favorable movement in commodityindex prices was partially offset by improved hedge cash settlements related to gas commodities.
We currently have approximately 25% of both our remaining anticipated 2023 oil and gas production hedged.
Hedge Settlements
|
| Q1 2023 |
|
| Q4 2022 |
|
| Change |
| |||
|
| Q |
|
|
|
|
|
|
| |||
Oil |
| $ | (3 | ) |
| $ | (141 | ) |
|
| 98 | % |
Natural gas |
|
| 16 |
|
|
| (36 | ) |
|
| 144 | % |
Total cash settlements (1) |
| $ | 13 |
|
| $ | (177 | ) |
|
| 107 | % |
32
A summary of our open commodity derivative positions is included in Note 3 to the financial statements included in “Part I. Financial Information – Item 1. Financial Statements” of this report. The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presentsderivatives on the cash settlements and fair value gains and losses recognized as componentsconsolidated statements of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of fair value gains and losses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 |
|
|
3324
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 2023 |
|
| Q4 2022 |
|
| Change |
| |||
LOE |
| $ | 327 |
|
| $ | 308 |
|
|
| 6 | % |
Gathering, processing & transportation |
|
| 166 |
|
|
| 178 |
|
|
| -7 | % |
Production taxes |
|
| 175 |
|
|
| 210 |
|
|
| -17 | % |
Property taxes |
|
| 25 |
|
|
| 19 |
|
|
| 32 | % |
Total |
| $ | 693 |
|
| $ | 715 |
|
|
| -3 | % |
Per Boe: |
|
|
|
|
|
|
|
|
| |||
LOE |
| $ | 5.67 |
|
| $ | 5.26 |
|
|
| 8 | % |
Gathering, processing & transportation |
| $ | 2.88 |
|
| $ | 3.05 |
|
|
| -6 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
| |||
Production taxes |
|
| 6.5 | % |
|
| 6.7 | % |
|
| -2 | % |
Production expenses decreased from the fourth quarter of 2022 to the first quarter of 2023 primarily due to a decrease in production taxes which resulted from lower commodity derivatives. In additionprices. This decrease in production expenses was partially offset by an increase in LOE.
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 2023 |
|
| $ per BOE |
|
| Q4 2022 |
|
| $ per BOE |
| ||||
Field-level cash margin (Non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
| $ | 1,334 |
|
| $ | 35.71 |
|
| $ | 1,585 |
|
| $ | 42.38 |
|
Eagle Ford |
|
| 257 |
|
| $ | 41.75 |
|
|
| 321 |
|
| $ | 51.24 |
|
Anadarko Basin |
|
| 154 |
|
| $ | 21.09 |
|
|
| 203 |
|
| $ | 28.53 |
|
Williston Basin |
|
| 156 |
|
| $ | 32.65 |
|
|
| 194 |
|
| $ | 37.02 |
|
Powder River Basin |
|
| 70 |
|
| $ | 41.43 |
|
|
| 99 |
|
| $ | 49.33 |
|
Other |
|
| 15 |
|
| N/M |
|
|
| 22 |
|
| N/M |
| ||
Total |
| $ | 1,986 |
|
| $ | 34.42 |
|
| $ | 2,424 |
|
| $ | 41.44 |
|
DD&A
|
| Q1 2023 |
|
| Q4 2022 |
|
| Change |
| |||
Oil and gas per Boe |
| $ | 10.25 |
|
| $ | 10.14 |
|
|
| 1 | % |
|
|
|
|
|
|
|
|
|
| |||
Oil and gas |
| $ | 591 |
|
| $ | 593 |
|
|
| 0 | % |
Other property and equipment |
|
| 24 |
|
|
| 32 |
|
|
| -27 | % |
Total |
| $ | 615 |
|
| $ | 625 |
|
|
| -2 | % |
General and Administrative Expense
|
| Q1 2023 |
|
| Q4 2022 |
|
| Change |
| |||
G&A per Boe |
| $ | 1.85 |
|
| $ | 2.07 |
|
|
| -11 | % |
|
|
|
|
|
|
|
|
|
| |||
Labor and benefits |
| $ | 56 |
|
| $ | 74 |
|
|
| -24 | % |
Non-labor |
|
| 50 |
|
|
| 48 |
|
|
| 4 | % |
Total |
| $ | 106 |
|
| $ | 122 |
|
|
| -13 | % |
G&A decreased in the first quarter of 2023 primarily due to a decrease in labor and benefit costs.
25
Other Items
|
| Q1 2023 |
|
| Q4 2022 |
|
| Change in earnings |
| |||
Commodity hedge valuation changes (1) |
| $ | 51 |
|
| $ | 124 |
|
| $ | (73 | ) |
Marketing and midstream operations |
|
| (25 | ) |
|
| (18 | ) |
|
| (7 | ) |
Exploration expenses |
|
| 3 |
|
|
| 13 |
|
|
| 10 |
|
Asset dispositions |
|
| — |
|
|
| (29 | ) |
|
| (29 | ) |
Net financing costs |
|
| 72 |
|
|
| 73 |
|
|
| 1 |
|
Other, net |
|
| 5 |
|
|
| (4 | ) |
|
| (9 | ) |
|
|
|
|
|
|
|
| $ | (107 | ) | ||
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 $38Asset dispositions include $28 million resulting from tolls on Canada’s Access Pipeline of $27 million, which commenced in the fourth quarter of 2016 subsequent2022 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 underlyingdivested Barnett Shale 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. 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.Income Taxes
During the first nine months of 2016, we recognized transaction costs of $17 million, primarily associated with the closing of the acquisitions discussed in
|
| Q1 2023 |
|
| Q4 2022 |
| ||
Current expense |
| $ | 141 |
|
| $ | 84 |
|
Deferred expense |
|
| 80 |
|
|
| 265 |
|
Total expense |
| $ | 221 |
|
| $ | 349 |
|
Current tax rate |
|
| 12 | % |
|
| 5 | % |
Deferred tax rate |
|
| 6 | % |
|
| 17 | % |
Effective income tax rate |
|
| 18 | % |
|
| 22 | % |
For discussion on income taxes, see Note 27 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.
Net Financing CostsQ1 2023 vs. Q1 2022
|
| 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’sOur first quarter 2023 and 2022 net financing costs decreased duringearnings were both $1.0 billion. The graph below shows the change in net earnings from the first quarter of 2022 to the first quarter of 2023. The material changes are further discussed by category on the following pages.
26
Production Volumes
|
| Q1 2023 |
|
| % of Total |
|
| Q1 2022 |
|
| Change |
| ||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 211 |
|
|
| 66 | % |
|
| 209 |
|
|
| 1 | % |
Eagle Ford |
|
| 40 |
|
|
| 13 | % |
|
| 17 |
|
|
| 137 | % |
Anadarko Basin |
|
| 15 |
|
|
| 5 | % |
|
| 14 |
|
|
| 6 | % |
Williston Basin |
|
| 36 |
|
|
| 11 | % |
|
| 32 |
|
|
| 12 | % |
Powder River Basin |
|
| 14 |
|
|
| 4 | % |
|
| 12 |
|
|
| 14 | % |
Other |
|
| 4 |
|
|
| 1 | % |
|
| 4 |
|
|
| -2 | % |
Total |
|
| 320 |
|
|
| 100 | % |
|
| 288 |
|
|
| 11 | % |
|
| Q1 2023 |
|
| % of Total |
|
| Q1 2022 |
|
| Change |
| ||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 640 |
|
|
| 62 | % |
|
| 561 |
|
|
| 14 | % |
Eagle Ford |
|
| 82 |
|
|
| 8 | % |
|
| 61 |
|
|
| 33 | % |
Anadarko Basin |
|
| 237 |
|
|
| 23 | % |
|
| 210 |
|
|
| 13 | % |
Williston Basin |
|
| 54 |
|
|
| 5 | % |
|
| 54 |
|
|
| 0 | % |
Powder River Basin |
|
| 16 |
|
|
| 2 | % |
|
| 19 |
|
|
| -14 | % |
Other |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| 37 | % |
Total |
|
| 1,030 |
|
|
| 100 | % |
|
| 906 |
|
|
| 14 | % |
|
| Q1 2023 |
|
| % of Total |
|
| Q1 2022 |
|
| Change |
| ||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 97 |
|
|
| 65 | % |
|
| 92 |
|
|
| 6 | % |
Eagle Ford |
|
| 15 |
|
|
| 10 | % |
|
| 9 |
|
|
| 69 | % |
Anadarko Basin |
|
| 26 |
|
|
| 18 | % |
|
| 25 |
|
|
| 3 | % |
Williston Basin |
|
| 8 |
|
|
| 6 | % |
|
| 8 |
|
|
| 6 | % |
Powder River Basin |
|
| 2 |
|
|
| 1 | % |
|
| 2 |
|
|
| -4 | % |
Other |
|
| 1 |
|
|
| 0 | % |
|
| — |
|
| N/M |
| |
Total |
|
| 149 |
|
|
| 100 | % |
|
| 136 |
|
|
| 10 | % |
|
| Q1 2023 |
|
| % of Total |
|
| Q1 2022 |
|
| Change |
| ||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 415 |
|
|
| 65 | % |
|
| 394 |
|
|
| 5 | % |
Eagle Ford |
|
| 68 |
|
|
| 11 | % |
|
| 36 |
|
|
| 90 | % |
Anadarko Basin |
|
| 81 |
|
|
| 12 | % |
|
| 75 |
|
|
| 8 | % |
Williston Basin |
|
| 53 |
|
|
| 8 | % |
|
| 48 |
|
|
| 10 | % |
Powder River Basin |
|
| 19 |
|
|
| 3 | % |
|
| 18 |
|
|
| 7 | % |
Other |
|
| 5 |
|
|
| 1 | % |
|
| 4 |
|
|
| 6 | % |
Total |
|
| 641 |
|
|
| 100 | % |
|
| 575 |
|
|
| 12 | % |
From the first quarter of 2022 to the first quarter of 2023, the change in volumes contributed to a $359 million increase in earnings. Volumes increased due to acquisitions in the Eagle Ford and Williston Basin that both closed in the third quarter of 2022. Volumes also increased due to continued development of the Delaware Basin and new well activity in the Anadarko Basin.
Realized Prices
|
| Q1 2023 |
|
| Realization |
| Q1 2022 |
|
| Change |
| |||
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
| |||
WTI index |
| $ | 76.17 |
|
|
|
| $ | 94.45 |
|
|
| -19 | % |
Realized price, unhedged |
| $ | 74.32 |
|
| 98% |
| $ | 92.94 |
|
|
| -20 | % |
Cash settlements |
| $ | (0.10 | ) |
|
|
| $ | (11.32 | ) |
|
|
| |
Realized price, with hedges |
| $ | 74.22 |
|
| 97% |
| $ | 81.62 |
|
|
| -9 | % |
|
| Q1 2023 |
|
| Realization |
| Q1 2022 |
|
| Change |
| |||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
| |||
Henry Hub index |
| $ | 3.44 |
|
|
|
| $ | 4.96 |
|
|
| -31 | % |
Realized price, unhedged |
| $ | 2.29 |
|
| 67% |
| $ | 3.77 |
|
|
| -39 | % |
Cash settlements |
| $ | 0.18 |
|
|
|
| $ | (0.62 | ) |
|
|
| |
Realized price, with hedges |
| $ | 2.47 |
|
| 72% |
| $ | 3.15 |
|
|
| -22 | % |
27
|
| Q1 2023 |
|
| Realization |
| Q1 2022 |
|
| Change |
| |||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
| |||
WTI index |
| $ | 76.17 |
|
|
|
| $ | 94.45 |
|
|
| -19 | % |
Realized price, unhedged |
| $ | 24.12 |
|
| 32% |
| $ | 37.76 |
|
|
| -36 | % |
Cash settlements |
| $ | — |
|
|
|
| $ | — |
|
|
|
| |
Realized price, with hedges |
| $ | 24.12 |
|
| 32% |
| $ | 37.76 |
|
|
| -36 | % |
|
| Q1 2023 |
|
| Q1 2022 |
|
| Change |
| |||
Combined (per Boe) |
|
|
|
|
|
|
|
|
| |||
Realized price, unhedged |
| $ | 46.44 |
|
| $ | 61.40 |
|
|
| -24 | % |
Cash settlements |
| $ | 0.22 |
|
| $ | (6.65 | ) |
|
|
| |
Realized price, with hedges |
| $ | 46.66 |
|
| $ | 54.75 |
|
|
| -15 | % |
From the first nine monthsquarter of 20172022 to the first quarter of 2023, realized prices contributed to an $855 million decrease in earnings. Unhedged realized oil, gas and NGL prices decreased primarily due to lower WTI, Henry Hub and Mont Belvieu index prices. The decrease in index prices was partially offset by improved hedge cash settlements related to gas commodities.
Hedge Settlements
|
| Q1 2023 |
|
| Q1 2022 |
|
| Change |
| |||
Oil |
| $ | (3 | ) |
| $ | (293 | ) |
|
| 99 | % |
Natural gas |
|
| 16 |
|
|
| (51 | ) |
|
| 131 | % |
Total cash settlements (1) |
| $ | 13 |
|
| $ | (344 | ) |
|
| 104 | % |
Cash settlements as presented in borrowings, including scheduled maturities and early retirements funded with asset divestiture proceeds.
EnLink’s interest on debt outstanding increased during the third quarter andtables above represent realized gains or losses related to 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 disclosedinstruments described in Note 143 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 | % |
Production Expenses
36
|
| Q1 2023 |
|
| Q1 2022 |
|
| Change |
| |||
LOE |
| $ | 327 |
|
| $ | 224 |
|
|
| 46 | % |
Gathering, processing & transportation |
|
| 166 |
|
|
| 161 |
|
|
| 3 | % |
Production taxes |
|
| 175 |
|
|
| 214 |
|
|
| -18 | % |
Property taxes |
|
| 25 |
|
|
| 19 |
|
|
| 32 | % |
Total |
| $ | 693 |
|
| $ | 618 |
|
|
| 12 | % |
Per Boe: |
|
|
|
|
|
|
|
|
| |||
LOE |
| $ | 5.67 |
|
| $ | 4.33 |
|
|
| 31 | % |
Gathering, processing & transportation |
| $ | 2.88 |
|
| $ | 3.11 |
|
|
| -7 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
| |||
Production taxes |
|
| 6.5 | % |
|
| 6.7 | % |
|
| -3 | % |
LOE expenses and LOE per Boe increased primarily due to acquisitions in the Eagle Ford and Williston Basin and inflation. Production taxes decreased due to lower commodity prices.
28
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 expect low current income tax ratesthe 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 2023 |
|
| $ per BOE |
|
| Q1 2022 |
|
| $ per BOE |
| ||||
Field-level cash margin (Non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
| $ | 1,334 |
|
| $ | 35.71 |
|
| $ | 1,877 |
|
| $ | 52.99 |
|
Eagle Ford |
|
| 257 |
|
| $ | 41.75 |
|
|
| 158 |
|
| $ | 48.92 |
|
Anadarko Basin |
|
| 154 |
|
| $ | 21.09 |
|
|
| 204 |
|
| $ | 30.31 |
|
Williston Basin |
|
| 156 |
|
| $ | 32.65 |
|
|
| 207 |
|
| $ | 47.65 |
|
Powder River Basin |
|
| 70 |
|
| $ | 41.43 |
|
|
| 86 |
|
| $ | 54.32 |
|
Other |
|
| 15 |
|
| N/M |
|
|
| 25 |
|
| N/M |
| ||
Total |
| $ | 1,986 |
|
| $ | 34.42 |
|
| $ | 2,557 |
|
| $ | 49.45 |
|
DD&A
|
| Q1 2023 |
|
| Q1 2022 |
|
| Change |
| |||
Oil and gas per Boe |
| $ | 10.25 |
|
| $ | 8.95 |
|
|
| 14 | % |
|
|
|
|
|
|
|
|
|
| |||
Oil and gas |
| $ | 591 |
|
| $ | 463 |
|
|
| 28 | % |
Other property and equipment |
|
| 24 |
|
|
| 26 |
|
|
| -9 | % |
Total |
| $ | 615 |
|
| $ | 489 |
|
|
| 26 | % |
DD&A and our oil and gas per Boe rate both increased primarily due to acquisitions in the U.S. segment basedEagle Ford and Williston Basin that closed in the third quarter of 2022.
General and Administrative Expense
|
| Q1 2023 |
|
| Q1 2022 |
|
| Change |
| |||
G&A per Boe |
| $ | 1.85 |
|
| $ | 1.82 |
|
|
| 2 | % |
|
|
|
|
|
|
|
|
|
| |||
Labor and benefits |
| $ | 56 |
|
| $ | 58 |
|
|
| -3 | % |
Non-labor |
|
| 50 |
|
|
| 36 |
|
|
| 39 | % |
Total |
| $ | 106 |
|
| $ | 94 |
|
|
| 13 | % |
G&A increased in the first quarter of 2023 primarily due to an increase in non-labor costs.
Other Items
|
| Q1 2023 |
|
| Q1 2022 |
|
| Change in earnings |
| |||
Commodity hedge valuation changes (1) |
| $ | 51 |
|
| $ | (339 | ) |
| $ | 390 |
|
Marketing and midstream operations |
|
| (25 | ) |
|
| (4 | ) |
|
| (21 | ) |
Exploration expenses |
|
| 3 |
|
|
| 2 |
|
|
| (1 | ) |
Asset dispositions |
|
| — |
|
|
| (1 | ) |
|
| (1 | ) |
Net financing costs |
|
| 72 |
|
|
| 85 |
|
|
| 13 |
|
Other, net |
|
| 5 |
|
|
| (61 | ) |
|
| (66 | ) |
|
|
|
|
|
|
|
| $ | 314 |
| ||
We recognize fair value changes on our continuing net operating loss position.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 further discussion on income taxes,additional information, see Note 73 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.
Net financing costs decreased in the first quarter of 2023 due to an increase in interest income resulting from higher interest rates. For additional information, see Note 13 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
29
For discussion on other, net, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Income Taxes
|
| Q1 2023 |
|
| Q1 2022 |
| ||
Current expense |
| $ | 141 |
|
| $ | 103 |
|
Deferred expense |
|
| 80 |
|
|
| 164 |
|
Total expense |
| $ | 221 |
|
| $ | 267 |
|
Current tax rate |
|
| 12 | % |
|
| 8 | % |
Deferred tax rate |
|
| 6 | % |
|
| 13 | % |
Effective income tax rate |
|
| 18 | % |
|
| 21 | % |
For discussion on income taxes, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
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, 2023 and 2016.2022.
|
| 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, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
Operating cash flow |
| $ | 1,677 |
|
| $ | 1,837 |
|
Capital expenditures |
|
| (1,012 | ) |
|
| (537 | ) |
Divestitures of property and equipment |
|
| 21 |
|
|
| 26 |
|
Investment activity, net |
|
| (29 | ) |
|
| (14 | ) |
Repurchases of common stock |
|
| (517 | ) |
|
| (211 | ) |
Common stock dividends |
|
| (596 | ) |
|
| (667 | ) |
Noncontrolling interest activity, net |
|
| (11 | ) |
|
| (8 | ) |
Other |
|
| (100 | ) |
|
| (72 | ) |
Net change in cash, cash equivalents and restricted cash |
| $ | (567 | ) |
| $ | 354 |
|
Cash, cash equivalents and restricted cash at end of period |
| $ | 887 |
|
| $ | 2,625 |
|
Operating Cash Flow
NetAs presented in the table above, net cash provided by operating activities increased 96% primarily duecontinued to significantly higher commodity prices as compared to the first nine monthsbe a significant source of 2016.
Our consolidated operatingcapital and liquidity. Operating cash flow funded 100%all of our capital expenditures during the first nine months of 2017. In 2016, leveragingand we continued to return value to our liquidity, we also usedshareholders by utilizing cash balancesflow for dividends and proceeds from our common stock offering and non-core asset divestitures to fund our acquisitions and capital expenditures.share repurchases.
Divestitures of Property and Equipment
During the first nine months of 2017, as part of our announced divestiture program, we sold non-core U.S. assets for approximately $320 million, net of customary purchase price adjustments. During the first nine months of 2016, we divested certain non-core upstream assets in the U.S. for approximately $1.9 billion. For further discussion, see Note 2 in “Part 1. Financial Information – Item 1. Financial Statements” in this report.
Issuance of Common 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, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
Delaware Basin |
| $ | 584 |
|
| $ | 395 |
|
Eagle Ford |
|
| 192 |
|
|
| 26 |
|
Anadarko Basin |
|
| 62 |
|
|
| 10 |
|
Williston Basin |
|
| 99 |
|
|
| 23 |
|
Powder River Basin |
|
| 38 |
|
|
| 33 |
|
Other |
|
| 1 |
|
|
| 3 |
|
Total oil and gas |
|
| 976 |
|
|
| 490 |
|
Midstream |
|
| 16 |
|
|
| 29 |
|
Other |
|
| 20 |
|
|
| 18 |
|
Total capital expenditures |
| $ | 1,012 |
|
| $ | 537 |
|
30
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 capital expenditures are largely impacted by oil and gas development activities.
Acquisition capital for the first ninequarter of 2023 represent approximately 60% of our operating cash flow. Capital expenditures increased due to capital spend on assets acquired in 2022 and general inflation trends.
Divestitures of Property and Equipment
During the first three months of 2016 primarily consisted of Devon’s acquisition of2023 and 2022, we received contingent earnout payments related to assets in the STACK play for approximately $1.5 billion and EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets for $1.4 billion. Approximately $850 million and $800 million, respectively, was paid in cash at the closings with the remainder funded with equity consideration and debt.previously sold. For additional information, please see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
DebtInvestment Activity Net
During the first ninethree months of 2017, consolidated net debt borrowings increased $252both 2023 and 2022, Devon received distributions from our investments of $8 million. In May 2017, EnLink issued $500Devon contributed $37 million of 5.45% senior notes due in 2047and $22 million 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 millionour equity method investments during the first ninethree months of 2017.2023 and 2022, respectively.
DuringShareholder Distributions and Stock Activity
We repurchased approximately 10.1 million shares of common stock for $545 million and 4.0 million shares of common stock for $230 million under the share repurchase program authorized by our Board of Directors in the first nine monthsquarter of 2016, our consolidated net debt borrowings decreased $1.8 billion. The decrease was primarily due to completed tender offers to purchase2023 and redeem $1.2 billion of debt securities.2022, respectively. For additional information, see Note 1416 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 months of 2017 and 2016. In the second quarter of 2016, we decreased our quarterly cash2023 and 2022. Devon has raised its fixed dividend ratemultiple times over the past year to $0.06$0.20 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.
EnLink and General Partner Distributions
Devon received $199 million2023. In addition to the fixed quarterly dividend, we paid a variable dividend in distributions from EnLink and the General Partner during the first nine monthsquarter of 20172023 and 2016.2022.
Issuance of Subsidiary Units
| Fixed |
|
| Variable |
|
| Total |
|
| Rate Per Share |
| ||||
2023: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 133 |
|
| $ | 463 |
|
| $ | 596 |
|
| $ | 0.89 |
|
2022: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 109 |
|
| $ | 558 |
|
| $ | 667 |
|
| $ | 1.00 |
|
Noncontrolling Interest Activity, net
During the first ninethree months of 2017, EnLink issued2023 and sold 52022, we distributed $10 million common units through its “at the market” programs and generated $92$8 million, respectively, to our noncontrolling interests in net proceeds. In September 2017, EnLink issued preferred units in an underwritten public offering generating net proceedsCDM.
Liquidity
The business of approximately $394 million.exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire operations and properties from other operators or landowners to enhance our existing portfolio of assets.
In January 2016, as part of its acquisition of Anadarko Basin gathering and processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash proceeds of approximately $725 million. General Partner common units were also issued as consideration in the transaction. Additionally, during the first nine months of 2016, EnLink issued and sold 7 million common units for net proceeds of $110 million through its “at the market” programs.
Liquidity
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 2023, we held approximately $0.9 billion of cash. Our operating cash flow isforecasts are sensitive to many variables theand include a measure of uncertainty as actual results may differ from our expectations.
31
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.
39
To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. We target hedging approximately 50%The key terms to our oil, gas and NGL derivative financial instruments as of our productionMarch 31, 2023 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 2023. The currently elevated level of Propertycost inflation could erode our cost efficiencies gained over previous years and Equipmentpressure our margins for the remainder of 2023. Despite this, we expect to continue generating material amounts of free cash flow at current commodity price levels due to our strategy of spending within cash flow.
In May 2017,Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices. We expect to mitigate the impact of cost inflation through efficiencies gained from the scale of our operations as well as by leveraging our long-standing relationships with our suppliers.
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, 2023, 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 billion2023 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, 2023, 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-termthe size and long-term production growth opportunities.scale of our production. 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 Baa2 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. Our Board of Directors increased our quarterly fixed dividend rate by 11% to $0.20 per share beginning in February 2023. In addition to the fixed quarterly dividend, we may pay a variable dividend of 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.
32
In May 2023, Devon announced a cash dividend in the amount of $0.72 per share payable in the second quarter of 2023. The dividend consists of a $0.20 per share fixed quarterly dividend and a $0.52 per share variable quarterly dividend and will total approximately $461 million.
Share Repurchases
In May 2023, our Board of Directors increased our share repurchase program by $1.0 billion to a total authorized amount of $3.0 billion, and extended the expiration date to December 31, 2024. Through April 2023, we had executed $2.0 billion of the authorized program.
Capital Expenditures
Our capital expenditures budget for the remainder of 2023 is expected to range from approximately $2.6 billion to $2.8 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,
Further, in the event we continuedwere to haveundergo 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 100% valuation allowance againstcorporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the U.S. deferredlowest 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 the first quarter of 2023 for Devon, but the Merger did cause an ownership change for WPX and increased the likelihood Devon could experience an ownership change over the next year.
On August 16, 2022, the IRA was signed into law and included various income tax assets that largely resulted from prior year cumulative financial losses primarily due to full cost impairments. Further, we continue to recordrelated provisions with an effective date beginning in 2023. Among the enacted provisions are a partial valuation allowance against certain Canadian deferred tax assets.
The accruals for deferred tax assets15% CAMT and liabilities are often based on assumptions that areseveral new and expanded clean energy credits and incentives. Devon believes it is subject to a significant amountthe CAMT as Devon has an average annual adjusted financial statement income that exceeds $1 billion for the three-year period ended December 31, 2022. Devon continues to assess the potential impact of judgment by management. These assumptionsthe CAMT, and judgments are reviewedmaterial incremental cash tax could be incurred depending on actual operating results as well as future U.S. Treasury guidance.
For additional information regarding our critical accounting policies and adjusted as facts and circumstances change. Material changes toestimates, see our income tax accruals may occur in the future based2022 Annual Report on the progress of ongoing audits, changes in legislation or resolution of other pending matters.Form 10-K.
Non-GAAP Measures
We make reference toutilize “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 2017 Results” in this Item 2. that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings excluding certain 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 changes in derivatives and financial instrument fair values and foreign currency, gains and losses on asset sales, noncash asset impairments, gains associated with early retirement of debt anddispositions, deferred tax asset valuation allowance. Amounts excluded for the third quarterallowance and first nine months of 2016 relate tofair value changes in derivatives andderivative 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. instruments.
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
33
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 NCI |
|
| Per Diluted Share |
| ||||
2023 |
|
|
|
|
|
|
|
|
|
|
| ||||
Earnings attributable to Devon (GAAP) | $ | 1,224 |
|
| $ | 1,003 |
|
| $ | 995 |
|
| $ | 1.53 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
| ||||
Deferred tax asset valuation allowance |
| — |
|
|
| (3 | ) |
|
| (3 | ) |
|
| (0.01 | ) |
Fair value changes in financial instruments |
| (53 | ) |
|
| (40 | ) |
|
| (40 | ) |
|
| (0.06 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 1,171 |
|
| $ | 960 |
|
| $ | 952 |
|
| $ | 1.46 |
|
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 |
|
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.
Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.
|
| Three Months Ended March 31, |
| |||||
|
| 2023 |
|
| 2022 |
| ||
Net earnings (GAAP) |
| $ | 1,003 |
|
| $ | 995 |
|
Financing costs, net |
|
| 72 |
|
|
| 85 |
|
Income tax expense |
|
| 221 |
|
|
| 267 |
|
Exploration expenses |
|
| 3 |
|
|
| 2 |
|
Depreciation, depletion and amortization |
|
| 615 |
|
|
| 489 |
|
Asset dispositions |
|
| — |
|
|
| (1 | ) |
Share-based compensation |
|
| 23 |
|
|
| 20 |
|
Derivative and financial instrument non-cash valuation changes |
|
| (51 | ) |
|
| 339 |
|
Accretion on discounted liabilities and other |
|
| 5 |
|
|
| (61 | ) |
EBITDAX (Non-GAAP) |
|
| 1,891 |
|
|
| 2,135 |
|
Marketing and midstream revenues and expenses, net |
|
| 25 |
|
|
| 4 |
|
Commodity derivative cash settlements |
|
| (13 | ) |
|
| 344 |
|
General and administrative expenses, cash-based |
|
| 83 |
|
|
| 74 |
|
Field-level cash margin (Non-GAAP) |
| $ | 1,986 |
|
| $ | 2,557 |
|
34
Item 3. Quantitative and QualitativeQualitative Disclosures About Market Risk
Commodity Price Risk
As of September 30, 2017,March 31, 2023, we have commodity derivatives that pertain to a portion of our estimated production for the last threenine months of 2017,2023, as well as 2018for 2024 and 2019.2025. 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, 2023, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by approximately $170$115 million.
Interest Rate Risk
As of September 30, 2017,March 31, 2023, we had total debt of $10.4$6.4 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, 2023.
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, 2023 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.
4335
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 below and in Part I, Item 3. Legal Proceedings of our 2022 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. For more information on our legal contingencies, see Note 17 in “Part I. Financial Information – Item 1. Financial Statements” of this report.
On February 1, 2023, we received a notice of violation from the EPA relating to alleged air permit violations by WPX Energy Permian, LLC, a wholly-owned subsidiary of the Company, during 2020 in New Mexico. The Company has been engaging with the EPA to resolve this matter. Although this matter is ongoing and management cannot predict its ultimate outcome, the resolution of this matter may result in a fine or penalty in excess of $300,000.
Please see our 20162022 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 20162022 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 2017.2023 (shares in thousands).
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 |
|
| 161 |
|
| $ | 64.92 |
|
|
| 158 |
|
| $ | 682 |
|
February 1 - February 28 |
|
| 4,671 |
|
| $ | 55.97 |
|
|
| 3,743 |
|
| $ | 479 |
|
March 1 - March 31 |
|
| 6,584 |
|
| $ | 53.68 |
|
|
| 6,189 |
|
| $ | 147 |
|
Total |
|
| 11,416 |
|
| $ | 54.77 |
|
|
| 10,090 |
|
|
|
| |
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 |
|
|
|
UnderIn addition to shares purchased under the Devon Plan, eligibleshare repurchase program described below, these amounts also include approximately 1.3 million shares received by us from employees may purchase sharesfor the payment of our common stock throughpersonal income tax withholdings on vesting transactions.
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.
4436
Exhibit Number | Description | ||
| Amended and Restated Credit Agreement, dated March 24, 2023, among Devon Energy Corporation, as borrower, each lender from time to time party thereto, each letter of credit issuer from time to time party thereto, and Bank of America, N.A., as administrative agent and swing line lender (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed March 28, 2023; File No. 001-32318). | ||
10.2* | |||
10.3* | |||
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. | ||
4537
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 | ||||
38
46