MARATHON OIL CORP - Quarter Report: 2023 September (Form 10-Q)
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, 2023 | ||||||||||
OR
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||
| For the transition period from _____ to _____ | ||||||||
Commission file number 1-1513
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
| Delaware | 25-0996816 | |||||||
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
990 Town and Country Boulevard, Houston, Texas
77024-2217
(Address of principal executive offices)
(713) 629-6600
(Registrant’s telephone number, including area code)
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 $1.00 | MRO | 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 þ No o
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes þ No o
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 | þ | Accelerated filer | o | Non-accelerated filer | o | ||||||||||||||||||||||||
| 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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No þ
There were 585,247,358 shares of Marathon Oil Corporation common stock outstanding as of October 31, 2023.
MARATHON OIL CORPORATION
Unless the context otherwise indicates, references to “Marathon Oil,” “we,” “our,” or “us” in this Form 10-Q are references to Marathon Oil Corporation, including its wholly owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon Oil exerts significant influence by virtue of its ownership interest).
For certain industry specific terms used in this Form 10-Q, please see “Definitions” in our 2022 Annual Report on Form 10-K.
| Table of Contents | ||||||||
| Page | ||||||||
1
Part I – FINANCIAL INFORMATION
Item 1. Financial Statements
MARATHON OIL CORPORATION
Consolidated Statements of Income (Unaudited)
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
| September 30, | September 30, | ||||||||||||||||||||||
| (In millions, except per share data) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||
| Revenues from contracts with customers | $ | 1,771 | $ | 2,008 | $ | 4,822 | $ | 5,937 | |||||||||||||||
| Net gain (loss) on commodity derivatives | 1 | 41 | 19 | (129) | |||||||||||||||||||
| Income from equity method investments | 38 | 190 | 140 | 469 | |||||||||||||||||||
| Net gain on disposal of assets | 1 | 2 | 6 | 1 | |||||||||||||||||||
| Other income | 2 | 6 | 19 | 25 | |||||||||||||||||||
| Total revenues and other income | 1,813 | 2,247 | 5,006 | 6,303 | |||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Production | 192 | 193 | 607 | 509 | |||||||||||||||||||
| Shipping, handling and other operating | 164 | 199 | 487 | 575 | |||||||||||||||||||
| Exploration | 20 | 73 | 46 | 92 | |||||||||||||||||||
| Depreciation, depletion and amortization | 583 | 460 | 1,662 | 1,319 | |||||||||||||||||||
| Impairments | — | 2 | — | 4 | |||||||||||||||||||
| Taxes other than income | 113 | 137 | 251 | 381 | |||||||||||||||||||
| General and administrative | 72 | 79 | 225 | 220 | |||||||||||||||||||
| Total costs and expenses | 1,144 | 1,143 | 3,278 | 3,100 | |||||||||||||||||||
| Income from operations | 669 | 1,104 | 1,728 | 3,203 | |||||||||||||||||||
| Net interest and other | (94) | (52) | (268) | (128) | |||||||||||||||||||
| Other net periodic benefit credits | 5 | 5 | 11 | 14 | |||||||||||||||||||
| Income before income taxes | 580 | 1,057 | 1,471 | 3,089 | |||||||||||||||||||
| Provision for income taxes | 127 | 240 | 314 | 2 | |||||||||||||||||||
| Net income | $ | 453 | $ | 817 | $ | 1,157 | $ | 3,087 | |||||||||||||||
| Net income per share: | |||||||||||||||||||||||
| Basic | $ | 0.75 | $ | 1.22 | $ | 1.88 | $ | 4.40 | |||||||||||||||
| Diluted | $ | 0.75 | $ | 1.22 | $ | 1.88 | $ | 4.39 | |||||||||||||||
| Weighted average common shares outstanding: | |||||||||||||||||||||||
| Basic | 603 | 670 | 615 | 701 | |||||||||||||||||||
| Diluted | 604 | 672 | 616 | 703 | |||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
2
MARATHON OIL CORPORATION
Consolidated Statements of Comprehensive Income (Unaudited)
| Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
| September 30, | September 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net income | $ | 453 | $ | 817 | $ | 1,157 | $ | 3,087 | |||||||||||||||
| Other comprehensive income (loss), net of tax | |||||||||||||||||||||||
| Change in actuarial gain (loss) and other for postretirement and postemployment plans | (4) | (3) | (17) | (6) | |||||||||||||||||||
| Change in derivative hedges unrecognized gain | — | 7 | 1 | 23 | |||||||||||||||||||
| Other | — | — | — | (1) | |||||||||||||||||||
| Other comprehensive income (loss) | (4) | 4 | (16) | 16 | |||||||||||||||||||
| Comprehensive income | $ | 449 | $ | 821 | $ | 1,141 | $ | 3,103 | |||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
3
MARATHON OIL CORPORATION
Consolidated Balance Sheets (Unaudited)
| September 30, | December 31, | ||||||||||
| (In millions, except par value and share amounts) | 2023 | 2022 | |||||||||
| Assets | |||||||||||
| Current assets: | |||||||||||
| Cash and cash equivalents | $ | 174 | $ | 334 | |||||||
| Receivables, net | 1,434 | 1,146 | |||||||||
| Inventories | 174 | 125 | |||||||||
| Other current assets | 66 | 66 | |||||||||
| Total current assets | 1,848 | 1,671 | |||||||||
| Equity method investments | 421 | 577 | |||||||||
Property, plant and equipment, net of accumulated depreciation, depletion and amortization of $25,377 and $23,876 | 17,411 | 17,377 | |||||||||
| Other noncurrent assets | 239 | 315 | |||||||||
| Total assets | $ | 19,919 | $ | 19,940 | |||||||
| Liabilities | |||||||||||
| Current liabilities: | |||||||||||
| Accounts payable | $ | 1,582 | $ | 1,279 | |||||||
| Commercial paper | 450 | — | |||||||||
| Payroll and benefits payable | 67 | 90 | |||||||||
| Accrued taxes | 128 | 171 | |||||||||
| Other current liabilities | 279 | 364 | |||||||||
| Long-term debt due within one year | 400 | 402 | |||||||||
| Total current liabilities | 2,906 | 2,306 | |||||||||
| Long-term debt | 4,876 | 5,521 | |||||||||
| Deferred tax liabilities | 386 | 167 | |||||||||
| Defined benefit postretirement plan obligations | 94 | 100 | |||||||||
| Asset retirement obligations | 308 | 295 | |||||||||
| Deferred credits and other liabilities | 123 | 154 | |||||||||
| Total liabilities | 8,693 | 8,543 | |||||||||
Commitments and contingencies (Note 21) | |||||||||||
| Stockholders’ Equity | |||||||||||
Preferred stock – no shares issued or outstanding (no par value, 26 million shares authorized) | — | — | |||||||||
| Common stock: | |||||||||||
Issued – 937 million shares (par value $1 per share, 1.925 billion shares authorized at September 30, 2023 and December 31, 2022) | 937 | 937 | |||||||||
Held in treasury, at cost – 347 million shares and 304 million shares | (8,598) | (7,512) | |||||||||
| Additional paid-in capital | 7,163 | 7,203 | |||||||||
| Retained earnings | 11,634 | 10,663 | |||||||||
| Accumulated other comprehensive income | 90 | 106 | |||||||||
| Total stockholders’ equity | 11,226 | 11,397 | |||||||||
| Total liabilities and stockholders’ equity | $ | 19,919 | $ | 19,940 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
4
MARATHON OIL CORPORATION
Consolidated Statements of Cash Flows (Unaudited)
| Nine Months Ended | |||||||||||
| September 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| Increase (decrease) in cash and cash equivalents | |||||||||||
| Operating activities: | |||||||||||
| Net income | $ | 1,157 | $ | 3,087 | |||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Depreciation, depletion and amortization | 1,662 | 1,319 | |||||||||
| Impairments | — | 4 | |||||||||
| Exploratory dry well costs and unproved property impairments | 41 | 85 | |||||||||
| Net gain on disposal of assets | (6) | (1) | |||||||||
| Deferred income taxes | 264 | (137) | |||||||||
| Unrealized loss on derivative instruments, net | 8 | 4 | |||||||||
| Pension and other post retirement benefits, net | (27) | (28) | |||||||||
| Stock-based compensation | 32 | 28 | |||||||||
| Equity method investments, net | 99 | (130) | |||||||||
| Changes in: | |||||||||||
| Current receivables | (298) | (221) | |||||||||
| Inventories | (51) | (27) | |||||||||
| Current accounts payable and accrued liabilities | 166 | 300 | |||||||||
| Other current assets and liabilities | (17) | (57) | |||||||||
| All other operating, net | (23) | 75 | |||||||||
| Net cash provided by operating activities | 3,007 | 4,301 | |||||||||
| Investing activities: | |||||||||||
| Additions to property, plant and equipment | (1,659) | (1,117) | |||||||||
| Acquisitions, net of cash acquired | (15) | 2 | |||||||||
| Disposal of assets, net of cash transferred to the buyer | (7) | 8 | |||||||||
| Equity method investments - return of capital | 57 | 12 | |||||||||
| Net cash used in investing activities | (1,624) | (1,095) | |||||||||
| Financing activities: | |||||||||||
| Proceeds from revolving credit facility | 1,018 | — | |||||||||
| Repayments of revolving credit facility | (1,468) | — | |||||||||
| Proceeds from commercial paper borrowings, net | 450 | — | |||||||||
| Borrowings | 200 | — | |||||||||
| Debt repayments | (401) | (35) | |||||||||
| Shares repurchased under buyback programs | (1,121) | (2,474) | |||||||||
| Dividends paid | (186) | (162) | |||||||||
| Purchases of shares for tax withholding obligations | (31) | (21) | |||||||||
| All other financing, net | (4) | 15 | |||||||||
| Net cash used in financing activities | (1,543) | (2,677) | |||||||||
| Net increase (decrease) in cash and cash equivalents | (160) | 529 | |||||||||
| Cash and cash equivalents at beginning of period | 334 | 580 | |||||||||
| Cash and cash equivalents at end of period | $ | 174 | $ | 1,109 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
5
MARATHON OIL CORPORATION
Consolidated Statements of Stockholders’ Equity (Unaudited)
| Total Equity of Marathon Oil Stockholders | ||||||||||||||||||||||||||||||||||||||||||||
| (In millions) | Preferred Stock | Common Stock | Treasury Stock | Additional Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income | Total Equity | |||||||||||||||||||||||||||||||||||||
| Nine Months Ended September 30, 2022 | ||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2021 Balance | $ | — | $ | 937 | $ | (4,825) | $ | 7,221 | $ | 7,271 | $ | 82 | $ | 10,686 | ||||||||||||||||||||||||||||||
| Shares repurchased under buyback programs | — | — | (592) | — | — | — | (592) | |||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 55 | (43) | — | — | 12 | |||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 1,304 | — | 1,304 | |||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | 8 | 8 | |||||||||||||||||||||||||||||||||||||
Dividends paid (per share amount of $0.07) | — | — | — | — | (52) | — | (52) | |||||||||||||||||||||||||||||||||||||
| March 31, 2022 Balance | $ | — | $ | 937 | $ | (5,362) | $ | 7,178 | $ | 8,523 | $ | 90 | $ | 11,366 | ||||||||||||||||||||||||||||||
| Shares repurchased under buyback programs | — | — | (760) | — | — | — | (760) | |||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 4 | 8 | — | — | 12 | |||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 966 | — | 966 | |||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | 4 | 4 | |||||||||||||||||||||||||||||||||||||
Dividends paid (per share amount of $0.08) | — | — | — | — | (56) | — | (56) | |||||||||||||||||||||||||||||||||||||
| June 30, 2022 Balance | $ | — | $ | 937 | $ | (6,118) | $ | 7,186 | $ | 9,433 | $ | 94 | $ | 11,532 | ||||||||||||||||||||||||||||||
| Shares repurchased under buyback programs | — | — | (1,122) | — | — | — | (1,122) | |||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | 10 | — | — | 10 | |||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 817 | — | 817 | |||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | — | 4 | 4 | |||||||||||||||||||||||||||||||||||||
Dividends paid (per share amount of $0.08) | — | — | — | — | (54) | — | (54) | |||||||||||||||||||||||||||||||||||||
| September 30, 2022 Balance | $ | — | $ | 937 | $ | (7,240) | $ | 7,196 | $ | 10,196 | $ | 98 | $ | 11,187 | ||||||||||||||||||||||||||||||
| Nine Months Ended September 30, 2023 | ||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2022 Balance | $ | — | $ | 937 | $ | (7,512) | $ | 7,203 | $ | 10,663 | $ | 106 | $ | 11,397 | ||||||||||||||||||||||||||||||
| Shares repurchased under buyback programs | — | — | (334) | — | — | — | (334) | |||||||||||||||||||||||||||||||||||||
| Excise tax on shares repurchased | — | — | (3) | — | — | — | (3) | |||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 35 | (54) | — | — | (19) | |||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 417 | — | 417 | |||||||||||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | — | — | (7) | (7) | |||||||||||||||||||||||||||||||||||||
Dividends paid (per share amount of $0.10) | — | — | — | — | (63) | — | (63) | |||||||||||||||||||||||||||||||||||||
| March 31, 2023 Balance | $ | — | $ | 937 | $ | (7,814) | $ | 7,149 | $ | 11,017 | $ | 99 | $ | 11,388 | ||||||||||||||||||||||||||||||
| Shares repurchased under buyback programs | — | — | (372) | — | — | — | (372) | |||||||||||||||||||||||||||||||||||||
| Excise tax on shares repurchased | — | — | (3) | — | — | — | (3) | |||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 1 | 10 | — | — | 11 | |||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 287 | — | 287 | |||||||||||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | — | — | (5) | (5) | |||||||||||||||||||||||||||||||||||||
Dividends paid (per share amount of $0.10) | — | — | — | — | (62) | — | (62) | |||||||||||||||||||||||||||||||||||||
| June 30, 2023 Balance | $ | — | $ | 937 | $ | (8,188) | $ | 7,159 | $ | 11,242 | $ | 94 | $ | 11,244 | ||||||||||||||||||||||||||||||
| Shares repurchased under buyback programs | — | — | (415) | — | — | — | (415) | |||||||||||||||||||||||||||||||||||||
| Excise tax on shares repurchased | — | — | (4) | — | — | — | (4) | |||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | 9 | 4 | — | — | 13 | |||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | 453 | — | 453 | |||||||||||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | — | — | (4) | (4) | |||||||||||||||||||||||||||||||||||||
Dividends paid (per share amount of $0.10) | — | — | — | — | (61) | — | (61) | |||||||||||||||||||||||||||||||||||||
| September 30, 2023 Balance | $ | — | $ | 937 | $ | (8,598) | $ | 7,163 | $ | 11,634 | $ | 90 | $ | 11,226 | ||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
6
1. Basis of Presentation
These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the SEC and do not include all of the information and disclosures required by U.S. GAAP for complete financial statements.
These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2022 Annual Report on Form 10-K. The results of operations for the third quarter and first nine months of 2023 are not necessarily indicative of the results to be expected for the full year.
2. Accounting Standards
Accounting Standards Updates Adopted
No accounting standards were adopted in the third quarter of 2023 that had a material impact on our consolidated financial statements.
Accounting Standards Updates Not Yet Adopted
There were no issued but pending accounting standards expected to have a material impact on our consolidated financial statements.
3. Income and Dividends per Common Share
Basic income per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options and performance units in all periods, provided the effect is not antidilutive. The per share calculations below exclude 1 million of antidilutive stock options and performance units for the three and nine months ended September 30, 2023, and 1 million and 2 million of antidilutive stock options and performance units for the three and nine months ended September 30, 2022, respectively.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (In millions, except per share data) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net income | $ | 453 | $ | 817 | $ | 1,157 | $ | 3,087 | |||||||||||||||
| Weighted average common shares outstanding | 603 | 670 | 615 | 701 | |||||||||||||||||||
| Effect of dilutive securities | 1 | 2 | 1 | 2 | |||||||||||||||||||
| Weighted average common shares, diluted | 604 | 672 | 616 | 703 | |||||||||||||||||||
| Net income per share: | |||||||||||||||||||||||
| Basic | $ | 0.75 | $ | 1.22 | $ | 1.88 | $ | 4.40 | |||||||||||||||
| Diluted | $ | 0.75 | $ | 1.22 | $ | 1.88 | $ | 4.39 | |||||||||||||||
| Dividends per share | $ | 0.10 | $ | 0.08 | $ | 0.30 | $ | 0.23 | |||||||||||||||
4. Revenues
The majority of our revenues are derived from the sale of crude oil and condensate, NGLs and natural gas under spot and term agreements with our customers in the United States and Equatorial Guinea.
As of September 30, 2023 and December 31, 2022, receivables from contracts with customers, included in receivables, less reserves for credit losses, were $1.1 billion and $875 million, respectively.
7
The following tables present our revenues from contracts with customers disaggregated by product type and geographic areas for the three and nine months ended September 30:
United States
| Three Months Ended September 30, 2023 | |||||||||||||||||||||||||||||||||||
| (In millions) | Eagle Ford | Bakken | Oklahoma | Permian | Other U.S. | Total | |||||||||||||||||||||||||||||
| Crude oil and condensate | $ | 587 | $ | 580 | $ | 64 | $ | 164 | $ | 13 | $ | 1,408 | |||||||||||||||||||||||
| Natural gas liquids | 80 | 47 | 30 | 20 | — | 177 | |||||||||||||||||||||||||||||
| Natural gas | 48 | 20 | 31 | 12 | 1 | 112 | |||||||||||||||||||||||||||||
| Other | 2 | — | — | — | 1 | 3 | |||||||||||||||||||||||||||||
| Revenues from contracts with customers | $ | 717 | $ | 647 | $ | 125 | $ | 196 | $ | 15 | $ | 1,700 | |||||||||||||||||||||||
| Three Months Ended September 30, 2022 | |||||||||||||||||||||||||||||||||||
| (In millions) | Eagle Ford | Bakken | Oklahoma | Permian | Other U.S. | Total | |||||||||||||||||||||||||||||
| Crude oil and condensate | $ | 523 | $ | 648 | $ | 104 | $ | 114 | $ | 39 | $ | 1,428 | |||||||||||||||||||||||
| Natural gas liquids | 49 | 82 | 63 | 16 | 6 | 216 | |||||||||||||||||||||||||||||
| Natural gas | 56 | 67 | 105 | 22 | 11 | 261 | |||||||||||||||||||||||||||||
| Other | 3 | — | — | — | 19 | 22 | |||||||||||||||||||||||||||||
| Revenues from contracts with customers | $ | 631 | $ | 797 | $ | 272 | $ | 152 | $ | 75 | $ | 1,927 | |||||||||||||||||||||||
| Nine Months Ended September 30, 2023 | |||||||||||||||||||||||||||||||||||
| (In millions) | Eagle Ford | Bakken | Oklahoma | Permian | Other U.S. | Total | |||||||||||||||||||||||||||||
| Crude oil and condensate | $ | 1,606 | $ | 1,467 | $ | 205 | $ | 475 | $ | 35 | $ | 3,788 | |||||||||||||||||||||||
| Natural gas liquids | 215 | 125 | 102 | 60 | — | 502 | |||||||||||||||||||||||||||||
| Natural gas | 141 | 69 | 95 | 30 | 2 | 337 | |||||||||||||||||||||||||||||
| Other | 5 | — | — | — | 11 | 16 | |||||||||||||||||||||||||||||
| Revenues from contracts with customers | $ | 1,967 | $ | 1,661 | $ | 402 | $ | 565 | $ | 48 | $ | 4,643 | |||||||||||||||||||||||
| Nine Months Ended September 30, 2022 | |||||||||||||||||||||||||||||||||||
| (In millions) | Eagle Ford | Bakken | Oklahoma | Permian | Other U.S. | Total | |||||||||||||||||||||||||||||
| Crude oil and condensate | $ | 1,526 | $ | 2,049 | $ | 341 | $ | 302 | $ | 124 | $ | 4,342 | |||||||||||||||||||||||
| Natural gas liquids | 148 | 263 | 191 | 46 | 23 | 671 | |||||||||||||||||||||||||||||
| Natural gas | 145 | 156 | 256 | 55 | 28 | 640 | |||||||||||||||||||||||||||||
| Other | 6 | — | — | — | 71 | 77 | |||||||||||||||||||||||||||||
| Revenues from contracts with customers | $ | 1,825 | $ | 2,468 | $ | 788 | $ | 403 | $ | 246 | $ | 5,730 | |||||||||||||||||||||||
8
International (E.G.)
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Crude oil and condensate | $ | 64 | $ | 75 | $ | 160 | $ | 186 | |||||||||||||||
| Natural gas liquids | 1 | 1 | 2 | 2 | |||||||||||||||||||
| Natural gas | 5 | 5 | 14 | 17 | |||||||||||||||||||
| Other | 1 | — | 3 | 2 | |||||||||||||||||||
| Revenues from contracts with customers | $ | 71 | $ | 81 | $ | 179 | $ | 207 | |||||||||||||||
5. Segment Information
We have two reportable operating segments. Both of these segments are organized and managed based upon geographic location and the nature of the products and services offered.
•United States (“U.S.”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas in the United States; and
•International (“Int’l”) – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of the United States as well as produces and markets products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea (“E.G.”)
Segment income represents income that excludes certain items not allocated to our operating segments, net of income taxes. A portion of our corporate and operations general and administrative support costs are not allocated to the operating segments. These unallocated costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities. Additionally, items which affect comparability such as: gains or losses on dispositions, impairments of proved and certain unproved properties, dry wells, changes in our valuation allowance, unrealized gains or losses on commodity and interest rate derivative instruments, effects of pension settlements and curtailments, expensed transaction costs for business combinations or other items (as determined by the chief operating decision maker (“CODM”)) are not allocated to operating segments.
9
| Three Months Ended September 30, 2023 | |||||||||||||||||||||||
| (In millions) | U.S. | Int’l | Not Allocated to Segments | Total | |||||||||||||||||||
| Revenues from contracts with customers | $ | 1,700 | $ | 71 | $ | — | $ | 1,771 | |||||||||||||||
| Net gain (loss) on commodity derivatives | 7 | — | (6) | (b) | 1 | ||||||||||||||||||
| Income from equity method investments | — | 38 | — | 38 | |||||||||||||||||||
| Net gain on disposal of assets | — | — | 1 | 1 | |||||||||||||||||||
| Other income | — | 1 | 1 | 2 | |||||||||||||||||||
| Less costs and expenses: | |||||||||||||||||||||||
| Production | 173 | 19 | — | 192 | |||||||||||||||||||
| Shipping, handling and other operating | 162 | 2 | — | 164 | |||||||||||||||||||
| Exploration | 8 | 1 | 11 | (c) | 20 | ||||||||||||||||||
| Depreciation, depletion and amortization | 570 | 12 | 1 | 583 | |||||||||||||||||||
| Taxes other than income | 112 | — | 1 | 113 | |||||||||||||||||||
| General and administrative | 32 | 3 | 37 | 72 | |||||||||||||||||||
| Net interest and other | — | — | 94 | 94 | |||||||||||||||||||
| Other net periodic benefit costs | — | — | (5) | (5) | |||||||||||||||||||
| Income tax provision (benefit) | 145 | 11 | (29) | 127 | |||||||||||||||||||
| Segment income (loss) | $ | 505 | $ | 62 | $ | (114) | $ | 453 | |||||||||||||||
| Total assets | $ | 18,503 | $ | 1,072 | $ | 344 | $ | 19,919 | |||||||||||||||
Capital expenditures(a) | $ | 444 | $ | 1 | $ | 4 | $ | 449 | |||||||||||||||
(a)Includes accruals and excludes acquisitions.
(c)Includes $11 million of unproved impairments related to Permian exploration leases.
10
| Three Months Ended September 30, 2022 | |||||||||||||||||||||||
| (In millions) | U.S. | Int’l | Not Allocated to Segments | Total | |||||||||||||||||||
| Revenues from contracts with customers | $ | 1,927 | $ | 81 | $ | — | $ | 2,008 | |||||||||||||||
| Net gain (loss) on commodity derivatives | (26) | — | 67 | (b) | 41 | ||||||||||||||||||
| Income from equity method investments | — | 190 | — | 190 | |||||||||||||||||||
| Net gain on disposal of assets | — | — | 2 | 2 | |||||||||||||||||||
| Other income | 4 | 1 | 1 | 6 | |||||||||||||||||||
| Less costs and expenses: | |||||||||||||||||||||||
| Production | 173 | 20 | — | 193 | |||||||||||||||||||
| Shipping, handling and other operating | 171 | 5 | 23 | 199 | |||||||||||||||||||
| Exploration | 11 | — | 62 | (c) | 73 | ||||||||||||||||||
| Depreciation, depletion and amortization | 441 | 14 | 5 | 460 | |||||||||||||||||||
| Impairments | — | — | 2 | 2 | |||||||||||||||||||
| Taxes other than income | 136 | — | 1 | 137 | |||||||||||||||||||
| General and administrative | 37 | 4 | 38 | 79 | |||||||||||||||||||
| Net interest and other | — | — | 52 | 52 | |||||||||||||||||||
| Other net periodic benefit costs | — | — | (5) | (5) | |||||||||||||||||||
| Income tax provision (benefit) | 213 | 48 | (21) | 240 | |||||||||||||||||||
| Segment income (loss) | $ | 723 | $ | 181 | $ | (87) | $ | 817 | |||||||||||||||
| Total assets | $ | 15,487 | $ | 1,294 | $ | 1,077 | $ | 17,858 | |||||||||||||||
Capital expenditures(a) | $ | 406 | $ | 1 | $ | 6 | $ | 413 | |||||||||||||||
(a)Includes accruals and excludes acquisitions.
(c)Includes dry well costs and unproved property impairments of $48 million for Louisiana Austin Chalk exploration leases and $14 million for Permian unproved property leases.
11
| Nine Months Ended September 30, 2023 | |||||||||||||||||||||||
| (In millions) | U.S. | Int’l | Not Allocated to Segments | Total | |||||||||||||||||||
| Revenues from contracts with customers | $ | 4,643 | $ | 179 | $ | — | $ | 4,822 | |||||||||||||||
| Net gain (loss) on commodity derivatives | 27 | — | (8) | (c) | 19 | ||||||||||||||||||
| Income from equity method investments | — | 140 | — | 140 | |||||||||||||||||||
| Net gain on disposal of assets | — | — | 6 | 6 | |||||||||||||||||||
| Other income | 12 | 5 | 2 | 19 | |||||||||||||||||||
| Less costs and expenses: | |||||||||||||||||||||||
| Production | 542 | 65 | — | 607 | |||||||||||||||||||
| Shipping, handling and other operating | 482 | 5 | — | 487 | |||||||||||||||||||
| Exploration | 19 | 1 | 26 | (d) | 46 | ||||||||||||||||||
| Depreciation, depletion and amortization | 1,622 | 34 | 6 | 1,662 | |||||||||||||||||||
| Taxes other than income | 252 | (b) | — | (1) | 251 | ||||||||||||||||||
| General and administrative | 98 | 9 | 118 | 225 | |||||||||||||||||||
| Net interest and other | — | — | 268 | 268 | |||||||||||||||||||
| Other net periodic benefit costs | — | — | (11) | (11) | |||||||||||||||||||
| Income tax provision (benefit) | 372 | 29 | (87) | 314 | |||||||||||||||||||
| Segment income (loss) | $ | 1,295 | $ | 181 | $ | (319) | $ | 1,157 | |||||||||||||||
| Total assets | $ | 18,503 | $ | 1,072 | $ | 344 | $ | 19,919 | |||||||||||||||
Capital expenditures(a) | $ | 1,661 | $ | 3 | $ | 9 | $ | 1,673 | |||||||||||||||
(a)Includes accruals and excludes acquisitions.
(b)Includes a nonrecurring Eagle Ford severance tax refund of $47 million related to prior years.
(d)Includes $10 million of dry well expense associated with wells in Permian (See Note 9) and $11 million of unproved impairments related to Permian exploration leases.
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| Nine Months Ended September 30, 2022 | |||||||||||||||||||||||
| (In millions) | U.S. | Int’l | Not Allocated to Segments | Total | |||||||||||||||||||
| Revenue from contracts with customers | $ | 5,730 | $ | 207 | $ | — | $ | 5,937 | |||||||||||||||
| Net loss on commodity derivatives | (125) | — | (4) | (b) | (129) | ||||||||||||||||||
| Income from equity method investments | — | 469 | — | 469 | |||||||||||||||||||
| Net gain on disposal of assets | — | — | 1 | 1 | |||||||||||||||||||
| Other income | 10 | 5 | 10 | 25 | |||||||||||||||||||
| Less costs and expenses: | |||||||||||||||||||||||
| Production | 464 | 45 | — | 509 | |||||||||||||||||||
| Shipping, handling and other operating | 508 | 15 | 52 | 575 | |||||||||||||||||||
| Exploration | 30 | — | 62 | (c) | 92 | ||||||||||||||||||
| Depreciation, depletion and amortization | 1,260 | 45 | 14 | 1,319 | |||||||||||||||||||
| Impairments | — | — | 4 | 4 | |||||||||||||||||||
| Taxes other than income | 374 | — | 7 | 381 | |||||||||||||||||||
| General and administrative | 94 | 10 | 116 | 220 | |||||||||||||||||||
| Net interest and other | — | — | 128 | (d) | 128 | ||||||||||||||||||
| Other net periodic benefit credit | — | — | (14) | (14) | |||||||||||||||||||
| Income tax provision (benefit) | 655 | 110 | (763) | (e) | 2 | ||||||||||||||||||
| Segment income | $ | 2,230 | $ | 456 | $ | 401 | $ | 3,087 | |||||||||||||||
| Total assets | $ | 15,487 | $ | 1,294 | $ | 1,077 | $ | 17,858 | |||||||||||||||
Capital expenditures(a) | $ | 1,124 | $ | 1 | $ | 11 | $ | 1,136 | |||||||||||||||
(a)Includes accruals and excludes acquisitions.
(c)Includes dry well costs and unproved property impairments of $48 million for Louisiana exploration leases and $14 million for Permian exploration leases.
(e)Includes a $685 million benefit related to the partial release of our valuation allowance (See Note 6).
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6. Income Taxes
Effective Tax Rate
The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The difference between the total provision and the sum of the amounts allocated to segments is reported in the “Not Allocated to Segments” column of the tables in Note 5.
For the three and nine months ended September 30, 2023 and 2022, our effective income tax rates were as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Effective income tax rate | 22 | % | 23 | % | 21 | % | — | % | |||||||||||||||
•2022 — Our effective income tax rate was different from our U.S. statutory tax rate of 21% for the nine months ended September 30, 2022, due to the first quarter 2022 release of the valuation allowance on certain U.S. and state deferred tax assets resulting in a non-cash deferred tax benefit of $685 million.
In August 2022, the President signed the Inflation Reduction Act of 2022 (“IRA”) into law. The IRA enacted various income tax provisions, including a 15% corporate book minimum tax. The corporate book minimum tax, which became effective on January 1, 2023, applies to corporations with an average annual adjusted financial statement income that exceeds $1 billion for the preceding three years. Under current law and guidance, we do not anticipate being subject to the corporate book minimum tax in 2023 but anticipate that the corporate book minimum tax will apply in 2024. The U.S. Treasury is expected to publish further guidance and regulations that will be relevant to scoping considerations and the calculation of minimum income tax liabilities. As this guidance is issued, we will continue to evaluate and assess the impact the IRA may have on our current and future period income taxes. We have made an accounting policy election to consider the effects of the corporate book minimum tax on the realizability of our deferred tax assets, carryforwards and tax credits as a period cost when they arise.
7. Credit Losses
The majority of our receivables are from purchasers of commodities or joint interest owners in properties we operate, both of which are recorded at estimated or invoiced amounts and do not bear interest. The majority of these receivables have payment terms of 30 days or less. At the end of each reporting period, we assess the collectability of our receivables and estimate the expected credit losses using historical data, current market conditions, reasonable and supportable forecasts of future economic conditions and other data as deemed appropriate.
Changes in the allowance for credit losses were as follows:
| (In millions) | September 30, 2023 | December 31, 2022 | |||||||||
| Beginning balance as of January 1 | $ | 10 | $ | 15 | |||||||
| Current period provision | 3 | (3) | |||||||||
| Current period write offs | (2) | (2) | |||||||||
| Recoveries of amounts previously reserved | (1) | — | |||||||||
| Ending balance | $ | 10 | $ | 10 | |||||||
14
8. Inventories
Crude oil and natural gas liquids are recorded at weighted average cost and carried at the lower of cost or net realizable value. Supplies and other items consist principally of tubular goods and equipment which are valued at weighted average cost and reviewed periodically for obsolescence or impairment when market conditions indicate.
| (In millions) | September 30, 2023 | December 31, 2022 | |||||||||
| Crude oil and natural gas liquids | $ | 9 | $ | 15 | |||||||
| Supplies and other items | 165 | 110 | |||||||||
| Inventories | $ | 174 | $ | 125 | |||||||
9. Property, Plant and Equipment
| (In millions) | September 30, 2023 | December 31, 2022 | |||||||||
| United States | $ | 17,098 | $ | 17,034 | |||||||
| International | 260 | 288 | |||||||||
| Corporate | 53 | 55 | |||||||||
| Net property, plant and equipment | $ | 17,411 | $ | 17,377 | |||||||
As of September 30, 2023 and December 31, 2022, we had $10 million and $20 million, respectively, of exploratory well costs capitalized greater than one year related to suspended wells. Management believes these wells exhibit sufficient quantities of hydrocarbons to justify potential development. All of the suspended wells require completion activities in order to classify the reserves as proved. The decrease during the nine months ended September 30, 2023 included a reduction in suspended well costs as we recorded $10 million of dry well expense associated with drilled and uncompleted exploratory wells in Permian.
10. Asset Retirement Obligations
Asset retirement obligations primarily consist of estimated costs to remove, dismantle and restore land or seabed at the end of oil and gas production operations. Changes in asset retirement obligations were as follows:
| September 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| Beginning balance as of January 1 | $ | 340 | $ | 316 | |||||||
| Incurred liabilities, including acquisitions | 4 | 10 | |||||||||
| Settled liabilities, including dispositions | (27) | (8) | |||||||||
| Accretion expense (included in depreciation, depletion and amortization) | 11 | 11 | |||||||||
| Revisions of estimates | 12 | (1) | |||||||||
Ending balance as of September 30, total | $ | 340 | $ | 328 | |||||||
Ending balance as of September 30, short-term | $ | 32 | $ | 45 | |||||||
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11. Leases
Lessee
Balance sheet information related to right-of-use (“ROU”) assets and lease liabilities was as follows:
| (In millions) | Balance Sheet Location: | September 30, 2023 | December 31, 2022 | |||||||||||
| ROU assets: | ||||||||||||||
| Operating leases | $ | 93 | $ | 123 | ||||||||||
| Finance leases | 20 | 24 | ||||||||||||
| Total ROU assets | $ | 113 | $ | 147 | ||||||||||
| Lease liabilities: | ||||||||||||||
| Current liabilities | ||||||||||||||
| Operating leases | $ | 63 | $ | 94 | ||||||||||
| Finance leases | 7 | 6 | ||||||||||||
| Noncurrent liabilities | ||||||||||||||
| Operating leases | 35 | 32 | ||||||||||||
| Finance leases | 13 | 18 | ||||||||||||
| Total lease liabilities | $ | 118 | $ | 150 | ||||||||||
Operating Leases
We enter into various lease agreements to support our operations including drilling rigs, compressors, buildings, vessels, vehicles and miscellaneous field equipment. We primarily act as a lessee in these transactions and the majority of our existing leases are classified as either short-term or long-term operating leases.
Finance Leases
In 2018, we signed an agreement with an owner/lessor to construct and lease a new build-to-suit office building in Houston, Texas. The initial lease term is five years and commenced in late September 2021 after the new Houston office was ready for occupancy. In March 2022, we made our first cash lease payment. During the nine months ended September 30, 2023 and 2022, we have made cash lease payments totaling approximately $16 million and $6 million, respectively. At the end of the initial lease term, we can negotiate to extend the lease term for an additional five years, subject to the approval of the participants; purchase the property subject to certain terms and conditions; or remarket the property to an unrelated third party. The lease contains a residual value guarantee of 100% of the total acquisition and construction costs.
Lessor
Our wholly owned subsidiary, Marathon E.G. Production Limited, is a lessor for residential housing in E.G., which is occupied by EGHoldings, a related party equity method investee – see Note 20. The lease was classified as an operating lease and expires in 2024, with a lessee option to extend through 2034. Lease payments are fixed for the entire duration of the agreement at approximately $6 million per year. Our lease income is reported in other income in our consolidated statements of income for all periods presented. The undiscounted cash flows to be received under this lease agreement are summarized below.
| (In millions) | Operating Lease Future Cash Receipts | ||||
| 2023 | $ | 2 | |||
| 2024 | 6 | ||||
| 2025 | 6 | ||||
| 2026 | 6 | ||||
| 2027 | 6 | ||||
| Thereafter | 42 | ||||
| Total undiscounted cash flows | $ | 68 | |||
16
12. Derivatives
We may use derivatives to manage a portion of our exposure to commodity price risk, commodity locational risk and interest rate risk. For further information regarding the fair value measurement of derivative instruments, see Note 13. All of our commodity derivatives and interest rate derivatives are subject to enforceable master netting arrangements or similar agreements under which we report net amounts.
The following tables present the gross fair values of our open derivative instruments and the reported net amounts along with their locations in our consolidated balance sheets.
| September 30, 2023 | |||||||||||||||||||||||
| (In millions) | Asset | Liability | Net Asset (Liability) | Balance Sheet Location | |||||||||||||||||||
| Not Designated as Hedges | |||||||||||||||||||||||
| Commodity | $ | 3 | $ | — | $ | 3 | Other current assets | ||||||||||||||||
| Total Not Designated as Hedges | $ | 3 | $ | — | $ | 3 | |||||||||||||||||
| Cash Flow Hedges | |||||||||||||||||||||||
| Interest Rate | $ | 10 | $ | — | $ | 10 | Other current assets | ||||||||||||||||
| Interest Rate | 15 | — | 15 | Other noncurrent assets | |||||||||||||||||||
| Total Designated Hedges | $ | 25 | $ | — | $ | 25 | |||||||||||||||||
| Total | $ | 28 | $ | — | $ | 28 | |||||||||||||||||
| December 31, 2022 | |||||||||||||||||||||||
| (In millions) | Asset | Liability | Net Asset (Liability) | Balance Sheet Location | |||||||||||||||||||
| Not Designated as Hedges | |||||||||||||||||||||||
| Commodity | $ | 10 | $ | — | $ | 10 | Other current assets | ||||||||||||||||
| Total Not Designated as Hedges | $ | 10 | $ | — | $ | 10 | |||||||||||||||||
| Cash Flow Hedges | |||||||||||||||||||||||
| Interest Rate | $ | 9 | $ | — | $ | 9 | Other current assets | ||||||||||||||||
| Interest Rate | 15 | — | 15 | Other noncurrent assets | |||||||||||||||||||
| Total Designated Hedges | $ | 24 | $ | — | $ | 24 | |||||||||||||||||
| Total | $ | 34 | $ | — | $ | 34 | |||||||||||||||||
Derivatives Not Designated as Hedges
Commodity Derivatives
We have entered into crude oil and natural gas derivatives indexed to their respective indices as noted in the table below, related to a portion of our forecasted U.S. sales through 2023 and 2024. These derivatives are three-way collars. Three-way collars consist of a sold call (ceiling), a purchased put (floor) and a sold put. The ceiling price is the maximum we will receive for the contract volumes; the floor is the minimum price we will receive, unless the market price falls below the sold put strike price. In this case, we receive the NYMEX WTI price or the Henry Hub price plus the difference between the floor and the sold put price. These crude oil and natural gas derivatives were not designated as hedges.
17
The following table sets forth outstanding derivative contracts as of September 30, 2023, and the weighted average prices for those contracts:
| 2023 | 2024 | |||||||||||||||||||||||||||||||
| Fourth Quarter | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||||||||||||||
| Crude Oil | ||||||||||||||||||||||||||||||||
| NYMEX WTI Three-Way Collars | ||||||||||||||||||||||||||||||||
| Volume (Bbls/day) | 10,000 | 20,000 | 20,000 | — | — | |||||||||||||||||||||||||||
| Weighted average price per Bbl: | ||||||||||||||||||||||||||||||||
| Ceiling | $ | 97.59 | $ | 100.06 | $ | 100.06 | $ | — | $ | — | ||||||||||||||||||||||
| Floor | $ | 60.00 | $ | 67.50 | $ | 67.50 | $ | — | $ | — | ||||||||||||||||||||||
| Sold put | $ | 45.00 | $ | 52.50 | $ | 52.50 | $ | — | $ | — | ||||||||||||||||||||||
| Natural Gas | ||||||||||||||||||||||||||||||||
| Henry Hub Three-Way Collars | ||||||||||||||||||||||||||||||||
| Volume (MMBtu/day) | 50,000 | — | — | $ | — | — | ||||||||||||||||||||||||||
| Weighted average price per MMBtu: | ||||||||||||||||||||||||||||||||
| Ceiling | $ | 11.14 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||
| Floor | $ | 4.00 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||
| Sold Put | $ | 2.50 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||
The following table sets forth outstanding derivative contracts as of October 31, 2023, with their weighted average prices, and is inclusive of activities that occurred subsequent to September 30, 2023:
| 2023 | 2024 | |||||||||||||||||||||||||||||||
| Fourth Quarter | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||||||||||||||
| Crude Oil | ||||||||||||||||||||||||||||||||
| NYMEX WTI Three-Way Collars | ||||||||||||||||||||||||||||||||
| Volume (Bbls/day) | 10,000 | 40,000 | 40,000 | 20,000 | 20,000 | |||||||||||||||||||||||||||
| Weighted average price per Bbl: | ||||||||||||||||||||||||||||||||
| Ceiling | $ | 97.59 | $ | 101.01 | $ | 101.01 | $ | 101.95 | $ | 101.95 | ||||||||||||||||||||||
| Floor | $ | 60.00 | $ | 66.25 | $ | 66.25 | $ | 65.00 | $ | 65.00 | ||||||||||||||||||||||
| Sold put | $ | 45.00 | $ | 51.25 | $ | 51.25 | $ | 50.00 | $ | 50.00 | ||||||||||||||||||||||
| Natural Gas | ||||||||||||||||||||||||||||||||
| Henry Hub Three-Way Collars | ||||||||||||||||||||||||||||||||
| Volume (MMBtu/day) | 50,000 | — | — | $ | — | — | ||||||||||||||||||||||||||
| Weighted average price per MMBtu: | ||||||||||||||||||||||||||||||||
| Ceiling | $ | 11.14 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||
| Floor | $ | 4.00 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||
| Sold Put | $ | 2.50 | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||||
18
The unrealized and realized gain (loss) impact of our commodity derivative instruments appears in the table below and is reflected in net gain (loss) on commodity derivatives in the consolidated statements of income.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Unrealized gain (loss) on derivative instruments, net | $ | (6) | $ | 67 | $ | (8) | $ | (4) | |||||||||||||||
Realized gain (loss) on derivative instruments, net(a) | $ | 7 | $ | (26) | $ | 27 | $ | (125) | |||||||||||||||
(a)During the third quarter and first nine months of 2023, net cash received for settled derivative positions was $6 million and $23 million, respectively. During the third quarter and first nine months of 2022, net cash paid for settled derivative positions was $56 million and $145 million, respectively.
Interest Rate Swaps
During 2020, we entered into forward starting interest rate swaps with a notional amount of $350 million to hedge variations in cash flows arising from fluctuations in the LIBOR benchmark interest rate related to forecasted interest payments of a future debt issuance in 2025. The expected proceeds of the future debt issuance were intended to refinance our $900 million 3.85% Senior Notes due 2025 (“2025 Notes”). In September 2021, we fully redeemed these 2025 Notes. In March 2022, we closed these positions and settled the interest rate swaps for proceeds of $44 million. During the nine months ended September 30, 2022, we recorded a cumulative $17 million gain within net interest and other within our consolidated statements of income related to these swaps.
Derivatives Designated as Cash Flow Hedges
During 2019, we entered into forward starting interest rate swaps with a maturity date of September 9, 2026 to hedge variations in cash flows related to the interest rate component of future lease payments of our Houston office. As of September 30, 2023 and December 31, 2022, the notional amount of open interest rate swaps for the Houston office was $295 million. The weighted average secured overnight financing rate (“SOFR”) for the swaps was 1.43% as of both September 30, 2023 and December 31, 2022.
The Houston office lease commenced in September 2021, however, our first cash lease payment for February 2022 rent was paid in March 2022. The first settlement date for the interest rate swaps was in January 2022. During the nine months ended September 30, 2023, net cash received for the settled interest rate swap positions was $8 million. As of September 30, 2023, we expect to reclassify a $11 million gain from accumulated other comprehensive income into our consolidated statements of income over the next twelve months. See Note 11 for further details regarding Houston office lease.
13. Fair Value Measurements
Fair Values – Recurring
The following tables present assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2023 and December 31, 2022 by hierarchy level.
| September 30, 2023 | |||||||||||||||||||||||
| (In millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||
| Derivative instruments, assets | |||||||||||||||||||||||
Commodity(a) | $ | — | $ | 3 | $ | — | $ | 3 | |||||||||||||||
| Interest rate - designated as cash flow hedges | — | 25 | — | 25 | |||||||||||||||||||
| Derivative instruments, assets | $ | — | $ | 28 | $ | — | $ | 28 | |||||||||||||||
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| December 31, 2022 | |||||||||||||||||||||||
| (In millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||
| Derivative instruments, assets | |||||||||||||||||||||||
Commodity(a) | $ | — | $ | 10 | $ | — | $ | 10 | |||||||||||||||
| Interest rate - designated as cash flow hedges | — | 24 | — | 24 | |||||||||||||||||||
| Derivative instruments, assets | $ | — | $ | 34 | $ | — | $ | 34 | |||||||||||||||
(a)Commodity derivative instruments are recorded on a net basis in our consolidated balance sheet. See Note 12.
As of September 30, 2023, our commodity derivatives include three-way collars. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For three-way collars, inputs to the models include commodity prices and implied volatility and are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.
The forward starting interest rate swaps are measured at fair value with a market approach using actionable broker quotes, which are Level 2 inputs. See Note 12 for details on the forward starting interest rate swaps.
Fair Values – Financial Instruments
Our current assets and liabilities include financial instruments, the most significant of which are receivables, commercial paper borrowings, the current portion of our long-term debt and payables. We believe the carrying values of our receivables, commercial paper borrowings and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our credit rating and (3) our historical incurrence of and expected future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.
The following table summarizes financial instruments, excluding receivables, commercial paper borrowings, payables and derivative financial instruments, and their reported fair values by individual balance sheet line item at September 30, 2023 and December 31, 2022.
| September 30, 2023 | December 31, 2022 | ||||||||||||||||||||||
| (In millions) | Fair Value | Carrying Amount | Fair Value | Carrying Amount | |||||||||||||||||||
| Financial assets | |||||||||||||||||||||||
| Other noncurrent assets | $ | 9 | $ | 27 | $ | 10 | $ | 28 | |||||||||||||||
| Total financial assets | $ | 9 | $ | 27 | $ | 10 | $ | 28 | |||||||||||||||
| Financial liabilities | |||||||||||||||||||||||
| Other current liabilities | $ | 132 | $ | 198 | $ | 140 | $ | 204 | |||||||||||||||
Long-term debt, including current portion(a) | 5,126 | 5,297 | 5,806 | 5,948 | |||||||||||||||||||
| Deferred credits and other liabilities | 45 | 45 | 73 | 73 | |||||||||||||||||||
| Total financial liabilities | $ | 5,303 | $ | 5,540 | $ | 6,019 | $ | 6,225 | |||||||||||||||
(a)Excludes debt issuance costs.
Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities, are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.
Our fixed rate debt instruments are publicly traded. The fair value of our fixed rate debt is measured using a market approach, based upon quotes from major financial institutions, which are Level 2 inputs. Our floating rate debt is non-public and consists of borrowings under our Term Loan Facility and Revolving Credit Facility. The fair value of our floating rate debt approximates the carrying value and is estimated based on observable market-based inputs, which results in a Level 2 classification.
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14. Debt
Term Loan Facility
In November 2022, we entered into a term credit agreement, which provides for a two-year $1.5 billion term loan facility (“Term Loan Facility”) and we borrowed the full amount thereunder in December 2022. Borrowings under the Term Loan Facility can be prepaid without penalty. As of September 30, 2023, we had $1.5 billion in borrowings under our Term Loan Facility. The third quarter weighted average interest rate on borrowings under the Term Loan Facility was 7.10%.
The Term Loan Facility includes a covenant requiring our total debt to total capitalization ratio not to exceed 65% as of the last day of each fiscal quarter. In the event of a default, the lenders holding more than half of the commitments may terminate all of the commitments under the Term Loan Facility and require the immediate repayment of all outstanding borrowings under the Term Loan Facility. As of September 30, 2023, we were in compliance with this covenant with a ratio of 26%.
Subsequent to the quarter, we repaid $250 million of outstanding borrowings on October 31, 2023. We have $1.3 billion in borrowings remaining under our Term Loan Facility.
Revolving Credit Facility
In September 2023, we increased our $2.5 billion unsecured Revolving Credit Facility by $61 million to a total of $2.6 billion. Fees on the unused commitment of each lender, as well as the borrowing options under the Revolving Credit Facility, remain unaffected by the increase. We have the option to increase the commitment amount by up to an additional $939 million, subject to the consent of any increasing lenders. The Revolving Credit Facility maturity remains July 28, 2027.
During the third quarter of 2023, we utilized commercial paper borrowings to fully repay our outstanding borrowings against our $2.6 billion unsecured Revolving Credit Facility. The third quarter weighted average interest rate on borrowings under the Revolving Credit Facility was 6.82%.
The Revolving Credit Facility includes a covenant requiring our total debt to total capitalization ratio not to exceed 65% as of the last day of each fiscal quarter. In the event of a default, the lenders holding more than half of the commitments may terminate the commitments under the Revolving Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Revolving Credit Facility. As of September 30, 2023, we were in compliance with this covenant with a ratio of 26%.
Commercial Paper Program
During the second quarter of 2023, we obtained ratings for our commercial paper from Moody’s, Standard & Poor’s and Fitch. Pursuant to our commercial paper program, we may issue unsecured notes in a maximum aggregate face amount of $2.5 billion outstanding at any time, with maturities up to 365 days from the date of issuance. Our $2.5 billion commercial paper program is backed by our $2.6 billion Revolving Credit Facility.
During the third quarter of 2023, we utilized our recently established commercial paper program to fund various short-term working capital requirements. As of September 30, 2023, we had $450 million of outstanding commercial paper maturing at various dates. The third quarter weighted average interest rate for commercial paper borrowings was 6.19%.
Debt Redemption
On July 17, 2023, we repaid the $131 million 8.125% Senior Notes in connection with their maturity date.
On March 1, 2023, we repaid the $70 million 8.5% Senior Notes in connection with their maturity date.
Long-term debt
At September 30, 2023, we had $5.3 billion of total long-term debt outstanding. Long-term debt due within one year consists of $200 million 2.1% Bonds and $200 million 2.125% Bonds which feature a mandatory put on July 1, 2024. Refer to our 2022 Annual Report on Form 10-K for a listing of our long-term debt maturities.
Debt Remarketing
On April 3, 2023, we closed a $200 million remarketing to investors of sub-series 2017A-1 bonds that are part of the $1 billion St. John the Baptist Parish, State of Louisiana revenue refunding bonds Series 2017. The bonds are subject to an interest rate of 4.05% and a mandatory purchase date of July 1, 2026. The repayments and new borrowings associated with the remarketed bonds are presented separately within Debt repayments and Borrowings, respectively, within the Consolidated Statements of Cash Flows.
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15. Stockholders’ Equity
Our Board of Directors has authorized a share repurchase program. During the first nine months of 2023, we repurchased approximately 45 million shares of our common stock pursuant to the share repurchase program at a cost of $1.1 billion. Our remaining share repurchase authorization was approximately $1.4 billion at September 30, 2023. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations or proceeds from potential asset sales. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion.
Additionally, during the first nine months of 2023 we repurchased $31 million of shares related to our tax withholding obligation associated with the vesting of stock-based compensation awards; these repurchases do not impact our share repurchase program authorization.
Subsequent to the quarter, we repurchased approximately $145 million of shares of our common stock through November 1, 2023. Effective November 1, 2023, our Board of Directors increased our remaining share repurchase program authorization to $2.5 billion.
16. Incentive Based Compensation
Stock options, restricted stock and restricted stock units
The following table presents a summary of activity for the first nine months of 2023:
| Stock Options | Restricted Stock & Units | ||||||||||||||||||||||
| Number of Shares | Weighted Average Exercise Price | Number of Shares & Units | Weighted Average Grant Date Fair Value | ||||||||||||||||||||
| Outstanding at December 31, 2022 | 1,678,524 | $ | 28.86 | 4,651,196 | $ | 14.89 | |||||||||||||||||
| Granted | — | $ | — | 1,845,409 | $ | 25.77 | |||||||||||||||||
| Exercised/Vested | (184,028) | $ | 10.47 | (2,729,366) | $ | 12.49 | |||||||||||||||||
| Canceled | (374,431) | $ | 34.41 | (159,450) | $ | 21.05 | |||||||||||||||||
| Outstanding at September 30, 2023 | 1,120,065 | $ | 30.03 | 3,607,789 | $ | 21.99 | |||||||||||||||||
Stock-based performance unit awards
During the first nine months of 2023, we granted 222,464 stock-based performance units to eligible officers, which are settled in shares. The grant date fair value per unit was $32.97. During the first nine months of 2023, we stock settled the units related to the 2020 grant. At September 30, 2023, there were 686,266 outstanding stock-based performance units to be settled in shares to officers.
During the first nine months of 2023, we also granted 222,464 stock-based performance units to eligible officers, which are settled in cash. At the grant date for these performance units, each unit represents the value of one share of our common stock. The fair value of each cash-settled performance unit was $27.05 as of September 30, 2023. During the first nine months of 2023, we also cash settled the units related to the 2021 grant. At September 30, 2023, there were 389,507 units outstanding of the stock-based performance unit awards to be settled in cash to officers.
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17. Defined Benefit Postretirement Plans
The following table summarizes the components of net periodic benefit costs (credits):
| Three Months Ended September 30, | |||||||||||||||||||||||
| Pension Benefits | Other Benefits | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Service cost | $ | 4 | $ | 4 | $ | — | $ | — | |||||||||||||||
| Interest cost | 2 | 1 | 1 | 1 | |||||||||||||||||||
| Expected return on plan assets | (3) | (2) | — | — | |||||||||||||||||||
| Amortization: | |||||||||||||||||||||||
| – prior service credit | (1) | (1) | (4) | (4) | |||||||||||||||||||
| – actuarial loss | — | — | — | — | |||||||||||||||||||
Net settlement loss(a) | — | — | — | — | |||||||||||||||||||
Net periodic benefit costs (credits)(b) | $ | 2 | $ | 2 | $ | (3) | $ | (3) | |||||||||||||||
| Nine Months Ended September 30, | |||||||||||||||||||||||
| Pension Benefits | Other Benefits | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Service cost | $ | 11 | $ | 11 | $ | — | $ | — | |||||||||||||||
| Interest cost | 8 | 5 | 2 | 2 | |||||||||||||||||||
| Expected return on plan assets | (7) | (7) | — | — | |||||||||||||||||||
| Amortization: | |||||||||||||||||||||||
| – prior service credit | (4) | (4) | (12) | (12) | |||||||||||||||||||
| – actuarial loss | — | 1 | 1 | 1 | |||||||||||||||||||
Net settlement loss(a) | 1 | — | — | — | |||||||||||||||||||
Net periodic benefit costs (credits)(b) | $ | 9 | $ | 6 | $ | (9) | $ | (9) | |||||||||||||||
(a)Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan’s total service and interest cost for that year.
(b)Net periodic benefit costs (credits) reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
During the first nine months of 2023, we made contributions of $19 million to our funded pension plan and we expect to make additional contributions of $4 million this year. We also made payments of $3 million and $5 million to our unfunded pension plan and other postretirement benefit plans, respectively.
18. Reclassifications Out of Accumulated Other Comprehensive Income (Loss)
The following table presents a summary of amounts reclassified from accumulated other comprehensive income (loss):
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | Income Statement Line | ||||||||||||||||||||||||
| Postretirement and postemployment plans | |||||||||||||||||||||||||||||
| Amortization of prior service credit | $ | 5 | $ | 5 | $ | 16 | $ | 16 | Other net periodic benefit credits | ||||||||||||||||||||
| Amortization of actuarial loss | — | — | (1) | (2) | Other net periodic benefit credits | ||||||||||||||||||||||||
| Net settlement loss | — | — | (1) | — | Other net periodic benefit credits | ||||||||||||||||||||||||
| Income Tax | (1) | (1) | (3) | (3) | Provision (benefit) for income taxes | ||||||||||||||||||||||||
| Total reclassifications of expense, net of tax | $ | 4 | $ | 4 | $ | 11 | $ | 11 | Net income | ||||||||||||||||||||
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19. Supplemental Cash Flow Information
| Nine Months Ended September 30, | ||||||||||||||
| (In millions) | 2023 | 2022 | ||||||||||||
| Included in operating activities: | ||||||||||||||
Interest paid(a) | $ | 251 | $ | 153 | ||||||||||
| Income taxes paid, net of refunds | $ | 103 | $ | 128 | ||||||||||
| Noncash investing activities: | ||||||||||||||
| Increase in asset retirement costs | $ | 16 | $ | 9 | ||||||||||
(a)The increase during the nine months ended September 30, 2023 compared to the same period in 2022 was primarily related to interest paid on borrowings under the Term Loan Facility and Revolving Credit Facility.
Other noncash investing activities include accrued capital expenditures for the nine months ended September 30, 2023 and 2022 of $125 million and $99 million, respectively.
20. Equity Method Investments
During the periods ended September 30, 2023 and December 31, 2022 our equity method investees were considered related parties. Our investment in our equity method investees are summarized in the following table:
| (In millions) | Ownership as of September 30, 2023 | September 30, 2023 | December 31, 2022 | ||||||||||||||
EGHoldings (a) | 56% | $ | 108 | $ | 287 | ||||||||||||
Alba Plant LLC (b) | 52% | 160 | 155 | ||||||||||||||
AMPCO (c) | 45% | 153 | 135 | ||||||||||||||
| Total | $ | 421 | $ | 577 | |||||||||||||
(a)EGHoldings is engaged in LNG production activity.
(b)Alba Plant LLC processes LPG.
(c)AMPCO is engaged in methanol production activity.
Summarized, 100% combined financial information for equity method investees is as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Income data: | |||||||||||||||||||||||
| Revenues and other income | $ | 200 | $ | 499 | $ | 689 | $ | 1,332 | |||||||||||||||
| Income from operations | 77 | 358 | 279 | 893 | |||||||||||||||||||
| Net income | $ | 63 | $ | 335 | $ | 227 | $ | 811 | |||||||||||||||
Revenues from related parties were $6 million and $17 million for the three and nine months ended September 30, 2023 and $7 million and $22 million for the three and nine months ended September 30, 2022, respectively, with the majority related to EGHoldings in both periods.
Cash received from equity investees is classified as dividends or return of capital on the Consolidated Statements of Cash Flows. Dividends from equity method investees are reflected in the Operating activities section in Equity Method Investments, net while return of capital is reflected in the Investing activities section. Dividends and return of capital received by us totaled $47 million and $296 million during the three and nine months ended September 30, 2023 and $150 million and $350 million during the three and nine months ended September 30, 2022, respectively.
Current receivables from related parties at September 30, 2023 were $24 million with the majority related to EGHoldings and $36 million at December 31, 2022 which primarily related to Alba Plant LLC and EGHoldings. Payables to related parties at September 30, 2023 and December 31, 2022 were $17 million and $20 million, respectively, with the majority related to Alba Plant LLC in both periods.
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21. Commitments and Contingencies
Various groups, including the State of North Dakota and the Mandan, Hidatsa and Arikara Nation or MHA Nation, also known as the Three Affiliated Tribes of the Fort Berthold Indian Reservation (the “Three Affiliated Tribes”) represented by the Bureau of Indian Affairs (the “BIA”), have been involved in a dispute regarding the ownership of certain lands underlying the Missouri River and Little Missouri River (the “Disputed Land”) from which we currently produce. As a result, as of September 30, 2023, we have a $168 million current liability in suspended royalty and working interest revenue, including interest, of which $144 million was included within accounts payable and $24 million related to accrued interest was included within other current liabilities on our consolidated balance sheet. Additionally, we have a long-term receivable of $26 million for capital and expenses. To address a potential dispute with the Three Affiliated Tribes over the validity of certain of our leases, Marathon Oil has entered into an agreement pursuant to which we will pay an amount representing $50 million of the suspended royalties (inclusive of interest thereon) to the Three Affiliated Tribes. The agreement allows Marathon to recover all funds paid to the Three Affiliated Tribes (including by offsetting against production from other minerals leased to Marathon by the Three Affiliated Tribes) if a court ultimately determines that the Disputed Land is not held in trust for the Three Affiliated Tribes, but instead is owned by the State of North Dakota. The United States Department of the Interior (“DOI”) has addressed the United States’ position with respect to this dispute several times in recent years with conflicting opinions. In January 2017, the DOI issued an opinion that the Disputed Land is held in trust for the Three Affiliated Tribes, then in June 2018 and May 2020 the DOI issued opinions concluding that the State of North Dakota held title to the Disputed Land. Most recently, on February 4, 2022, the DOI issued an opinion (“2022 M-Opinion”) concluding that the Disputed Land is held in trust for the Three Affiliated Tribes. While the 2022 M-Opinion is binding on all agencies within the DOI, it is not legally binding on third parties, including Marathon Oil, the State of North Dakota, or a court. Given the uncertainty in matters such as these, we are unable to predict the ultimate outcome of this matter at this time; however, we believe the resolution of this matter will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
We are a defendant in a number of legal and administrative proceedings arising in the ordinary course of business including, but not limited to, royalty claims, contract claims, tax disputes and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. In addition, we may also be subject to retained liabilities with respect to certain divested assets by operation of law. For example, we are exposed to the risk that owners and/or operators of assets purchased from us become unable to satisfy plugging or abandonment obligations that attach to those assets. In that event, due to operation of law, we may be required to assume plugging or abandonment obligations for those assets. Although we have established reserves for such liabilities, we could be required to accrue additional amounts in the future and these amounts could be material.
Marathon Oil was named in a lawsuit alleging improper royalty deductions in certain of our Oklahoma operations, and after plaintiffs lost their attempt to certify a class action, a settlement was reached, and in the first quarter of 2023 such settlement was approved by the court and paid.
We have received Notice of Violations (“NOV”)’s from the EPA related to allegations of violations of the Clean Air Act with respect to our operations on the Fort Berthold Indian Reservation between 2015 and 2019. We continue to actively negotiate a draft consent decree with the EPA and Department of Justice. The resolution of the enforcement action will likely include monetary sanctions and implementation of both environmental mitigation projects and injunctive terms, which would increase both our development costs and operating costs. We maintain an accrual for estimated potential monetary sanctions. Through the date of this filing, there exists substantial uncertainty as to the ultimate result of this matter and it is reasonably possible the result could be materially different from our expectations and our accrual.
The Company received NOV’s from the EPA relating to alleged Clean Air Act violations following flyovers conducted in 2020 and 2022 over certain of the Company’s oil and gas facilities in New Mexico. The notices involve alleged emission and permitting violations. We initiated discussions with the EPA to resolve these matters. At this time, we are unable to estimate the potential loss associated with these matters, however, it is reasonably possible that resolution of these matters may result in a fine or penalty in excess of $300,000.
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We have incurred and will continue to incur capital, operating and maintenance and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately offset by the prices we receive for our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.
At September 30, 2023, accrued liabilities for remediation relating to environmental laws and regulations were not material. It is not presently possible to estimate the ultimate amount of all remediation cost that might be incurred or the penalties that may be imposed.
In the second quarter of 2019, Marathon E.G. Production Limited (“MEGPL”), a consolidated and wholly owned subsidiary, signed a series of agreements to process third-party Alen Unit gas through existing infrastructure located in Punta Europa, E.G. Our equity method investee, Alba Plant LLC, is also a party to some of the agreements. These agreements require (subject to certain limitations) MEGPL to indemnify the owners of the Alen Unit against injury to Alba Plant LLC’s personnel and damage to or loss of Alba Plant LLC’s automobiles, as well as third party claims caused by Alba Plant LLC and certain environmental liabilities arising from certain hydrocarbons in the custody of Alba Plant LLC. At this time, we cannot reasonably estimate this obligation as we do not have any history of prior indemnification claims or environmental discharge or contamination. Therefore, we have not recorded a liability with respect to these indemnities since the amount of potential future payments under these indemnification clauses is not determinable.
The agreements to process the third-party Alen Unit gas required the execution of third-party guarantees by Marathon Oil Corporation in favor of the Alen Unit’s owners. Two separate guarantees were executed during the second quarter of 2020; one for a maximum of approximately $91 million pertaining to the payment obligations of Equatorial Guinea LNG Operations, S.A. and another for a maximum of $25 million pertaining to the payment obligations of Alba Plant LLC. Payment by us would be required if any of those entities fails to honor its payment obligations pursuant to the relevant agreements with the owners of the Alen Unit. Certain owners of the Alen Unit, or their affiliates, are also direct or indirect shareholders in Equatorial Guinea LNG Operations, S.A. and Alba Plant LLC. Each guarantee expires no later than December 31, 2027. We measured these guarantees at fair value using the net present value of premium payments we expect to receive from our investees. Our liability for these guarantees was approximately $4 million as of September 30, 2023. Each of Equatorial Guinea LNG Operations, S.A. and Equatorial Guinea LNG Train 1, S.A. provided us with a pledge of its receivables as recourse against any payments we may make under the guaranty of Equatorial Guinea LNG Operations, S.A.’s performance.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the preceding consolidated financial statements and notes in Item 1.
Executive Overview
We are an independent exploration and production company, focused on U.S. resource plays: Eagle Ford in Texas, Bakken in North Dakota, STACK and SCOOP in Oklahoma and Permian in New Mexico and Texas. Our U.S. assets are complemented by our international operations in E.G. Our overall business strategy is to responsibly deliver competitive corporate return levels, free cash flow and cash returns to shareholders, all of which are sustainable and resilient through long-term commodity price cycles. We expect to achieve our business strategy by adherence to a disciplined reinvestment rate capital allocation framework that limits our capital expenditures relative to our expected cash flow from operations. Keeping our workforce safe, maintaining a strong balance sheet, responsibly meeting global energy demand with a focus on continuously improving environmental performance, serving as a trusted partner in our local communities and maintaining best in-class corporate governance standards are foundational to the execution of our strategy.
In December 2022, we closed on a transaction to acquire approximately 130,000 net proved and unproved acres, with an average 97% working interest, in the Eagle Ford resource play from Ensign Natural Resources (“Ensign”) for cash consideration of $3.0 billion.
Below are certain key financial and operational highlights for the quarter:
Financial and operational results
•Our net income was $453 million in the third quarter of 2023 as compared to net income of $817 million in the same period last year. Included in our financial results for the current quarter:
◦Revenues from contracts with customers decreased $237 million compared to the same quarter last year as a result of lower realized commodity prices, partially offset by increased sales. Lower realized commodity prices also resulted in lower income from equity method investments, which decreased $152 million compared to the same quarter last year.
◦Net sales volumes in the U.S. segment increased 25% compared to the same period last year, primarily driven by increased production from the acreage acquired from Ensign.
◦The increase in net sales volumes resulted in higher depreciation, depletion and amortization expense of $123 million as compared to the same quarter last year.
◦Our provision for income taxes decreased $113 million compared to the same quarter last year.
•Upon conclusion of the third quarter, we announced the signing of a 5-year firm LNG sales agreement for a portion of our equity gas from the Alba Field liquefied at EG LNG. The contract is effective January 1, 2024, and features a pricing structure linked to the Dutch Title Transfer Facility (TTF) index, providing us with significant incremental exposure to the European LNG market.
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Prioritized return of capital to investors and maintained investment grade balance sheet
•In the first nine months of 2023, we repurchased $1.1 billion of shares through our share repurchase program. In addition, effective November 1, 2023, our Board increased our remaining share repurchase authorization to $2.5 billion.
•As of September 30, 2023, we have $174 million of cash on hand and $2.3 billion of total liquidity.
•We reduced our long-term debt, including the repayment at maturity of $70 million 8.5% Senior Notes on March 1, 2023 and $131 million 8.125% Senior Notes on July 17, 2023. In addition, subsequent to the quarter, we repaid $250 million of outstanding borrowings on our Term Loan Facility on October 31, 2023.
•During the first nine months of 2023, we paid $186 million of dividends, or $0.30 per share, compared to dividends paid of $0.23 per share during the first nine months of 2022. On October 25, 2023, our Board approved a 10% increase to our dividend payable to shareholders in the fourth quarter of 2023, to $0.11 per share.
•All three primary credit rating agencies continue to rate us as investment grade.
Outlook
Capital Budget
In February 2023, we announced a 2023 capital budget of $1.9 billion to $2.0 billion that prioritizes free cash flow generation over production growth, consistent with our disciplined capital allocation framework. Our expectation is our full year capital expenditures will be at the higher end of our range. Our production targets for 2023 include full year oil-equivalent production of 385 - 405 mboed, of which we are also trending towards the higher end of the range. We continue to monitor inflationary pressures given the labor market, commodity prices, supply chain challenges and geopolitical instability.
Operations
The following table presents a summary of our sales volumes for each of our segments. Refer to Results of Operations for a price-volume analysis for each of the segments.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||
| Net Sales Volumes | 2023 | 2022 | Increase (Decrease) | 2023 | 2022 | Increase (Decrease) | |||||||||||||||||||||||||||||
United States (mboed) | 369 | 295 | 25 | % | 356 | 286 | 24 | % | |||||||||||||||||||||||||||
International (mboed) | 53 | 58 | (9) | % | 51 | 59 | (14) | % | |||||||||||||||||||||||||||
Total (mboed) | 422 | 353 | 20 | % | 407 | 345 | 18 | % | |||||||||||||||||||||||||||
United States
The following tables provide additional details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment. Effective in 2023, the Texas Delaware oil play, which was previously included within Other United States as an exploration property, was integrated into the Permian resource play. The increase in net sales volumes in our U.S. segment compared to the same period in the prior year was primarily a result of our acquisition of the Eagle Ford assets of Ensign in December 2022.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||
| Net Sales Volumes | 2023 | 2022 | Increase (Decrease) | 2023 | 2022 | Increase (Decrease) | |||||||||||||||||||||||||||||
Equivalent Barrels (mboed) | |||||||||||||||||||||||||||||||||||
| Eagle Ford | 158 | 90 | 76 | % | 153 | 85 | 80 | % | |||||||||||||||||||||||||||
| Bakken | 121 | 118 | 3 | % | 108 | 116 | (7) | % | |||||||||||||||||||||||||||
| Oklahoma | 46 | 54 | (15) | % | 50 | 54 | (7) | % | |||||||||||||||||||||||||||
| Permian | 42 | 24 | 75 | % | 43 | 21 | 105 | % | |||||||||||||||||||||||||||
| Other United States | 2 | 9 | (78) | % | 2 | 10 | (80) | % | |||||||||||||||||||||||||||
| Total United States | 369 | 295 | 25 | % | 356 | 286 | 24 | % | |||||||||||||||||||||||||||
28
| Three Months Ended September 30, 2023 | |||||||||||||||||||||||||||||
| Sales Mix - U.S. Resource Plays | Eagle Ford | Bakken | Oklahoma | Permian | Total | ||||||||||||||||||||||||
| Crude oil and condensate | 51 | % | 64 | % | 19 | % | 52 | % | 51 | % | |||||||||||||||||||
| Natural gas liquids | 25 | % | 22 | % | 29 | % | 24 | % | 25 | % | |||||||||||||||||||
| Natural gas | 24 | % | 14 | % | 52 | % | 24 | % | 24 | % | |||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| Drilling Activity - U.S. Resource Plays | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Gross Operated | |||||||||||||||||||||||
| Eagle Ford: | |||||||||||||||||||||||
| Wells drilled to total depth | 18 | 22 | 83 | 86 | |||||||||||||||||||
| Wells brought to sales | 38 | 48 | 123 | 95 | |||||||||||||||||||
| Bakken: | |||||||||||||||||||||||
| Wells drilled to total depth | 19 | 12 | 64 | 36 | |||||||||||||||||||
| Wells brought to sales | 25 | 9 | 65 | 49 | |||||||||||||||||||
| Oklahoma: | |||||||||||||||||||||||
| Wells drilled to total depth | 7 | 4 | 11 | 13 | |||||||||||||||||||
| Wells brought to sales | 4 | — | 9 | 19 | |||||||||||||||||||
| Permian: | |||||||||||||||||||||||
| Wells drilled to total depth | 5 | 6 | 19 | 12 | |||||||||||||||||||
| Wells brought to sales | 9 | 13 | 25 | 13 | |||||||||||||||||||
International
Net sales volumes were lower during the three and nine months ended September 30, 2023 as compared to the same period in the prior year primarily due to natural decline. The following table provides details regarding net sales volumes for our operations within this segment:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||
| Net Sales Volumes | 2023 | 2022 | Increase (Decrease) | 2023 | 2022 | Increase (Decrease) | |||||||||||||||||||||||||||||
Equivalent Barrels (mboed) | |||||||||||||||||||||||||||||||||||
| Equatorial Guinea | 53 | 58 | (9) | % | 51 | 59 | (14) | % | |||||||||||||||||||||||||||
| Equity Method Investees | |||||||||||||||||||||||||||||||||||
LNG (mtd) | 1,670 | 2,536 | (34) | % | 1,831 | 2,872 | (36) | % | |||||||||||||||||||||||||||
Methanol (mtd) | 1,208 | 956 | 26 | % | 1,210 | 967 | 25 | % | |||||||||||||||||||||||||||
Condensate and LPG (boed) | 8,264 | 7,060 | 17 | % | 7,896 | 8,113 | (3) | % | |||||||||||||||||||||||||||
29
Market Conditions
Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows, the amount of capital we invest in our business, redemption of our debt, payment of dividends and funding of share repurchases. Commodity prices experienced significant volatility in 2022 and this has continued into the third quarter of 2023. Russia’s invasion of Ukraine was a geopolitical shock that caused energy prices to spike significantly higher in early to mid-2022. However, Russian oil production has remained at higher levels than expected, European gas shortages were averted as record levels of LNG were imported into that market and an exceptionally warm 2022 / 2023 winter in both the U.S. and Europe has refilled gas inventories to multi year highs causing prices to fall back significantly. Recent events in the Middle East have added a further geopolitical risk premium to oil prices and the outlook for that region remains extremely uncertain. Economic headwinds, caused by elevated interest rates as central banks fight inflation, continue to be a threat to energy demand growth as we move forward. Price volatility was also exacerbated by ongoing OPEC+ petroleum supply limitations and economic sanctions involving producer countries. We continue to expect commodity price volatility given the complex global dynamics of supply and demand that exist in the market. Refer to Item 1A. Risk Factors in our 2022 Annual Report on Form 10-K for further discussion on how volatility in commodity prices could impact us.
United States
The following table presents our average price realizations and the related benchmarks for crude oil and condensate, NGLs and natural gas for the third quarter and first nine months of 2023 and 2022.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | Increase (Decrease) | 2023 | 2022 | Increase (Decrease) | ||||||||||||||||||||||||||||||
Average Price Realizations(a) | |||||||||||||||||||||||||||||||||||
Crude oil and condensate (per bbl)(b) | $ | 80.90 | $ | 93.67 | (14) | % | $ | 76.13 | $ | 99.28 | (23) | % | |||||||||||||||||||||||
Natural gas liquids (per bbl) | 21.37 | 34.00 | (37) | % | 21.29 | 37.14 | (43) | % | |||||||||||||||||||||||||||
Natural gas (per mcf)(c) | 2.28 | 7.84 | (71) | % | 2.38 | 6.52 | (63) | % | |||||||||||||||||||||||||||
| Benchmarks | |||||||||||||||||||||||||||||||||||
WTI crude oil average of daily prices (per bbl) | $ | 82.22 | $ | 91.43 | (10) | % | $ | 77.28 | $ | 98.25 | (21) | % | |||||||||||||||||||||||
Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl) | 84.00 | 96.12 | (13) | % | 76.14 | 101.71 | (25) | % | |||||||||||||||||||||||||||
Mont Belvieu NGLs (per bbl)(d) | 23.13 | 36.08 | (36) | % | 22.99 | 38.66 | (41) | % | |||||||||||||||||||||||||||
Henry Hub natural gas settlement date average (per mmbtu) | 2.55 | 8.20 | (69) | % | 2.69 | 6.77 | (60) | % | |||||||||||||||||||||||||||
(a)Excludes gains or losses on commodity derivative instruments.
(b)Inclusion of realized gains (losses) on crude oil derivative instruments would have no impact on average price realizations for the third quarter 2023 and would have decreased average price realizations by $0.85 per bbl for the third quarter 2022. Inclusion of realized gains (losses) on crude oil derivative instruments would have no impact on average price realization for the first nine months of 2023 and would have decreased average price realizations by $2.39 per bbl for the first nine months of 2022.
(c)Inclusion of realized gains (losses) on natural gas derivative instruments would have minimal impact on average price realizations for the third quarter and first nine months of 2023 and 2022.
(d)Bloomberg Finance LLP: Y-grade Mix NGL of 55% ethane, 25% propane, 5% butane, 8% isobutane and 7% natural gasoline.
Crude oil and condensate – Price realizations may differ from benchmarks due to the quality and location of the product.
Natural gas liquids – The majority of our sales volumes are sold at reference to Mont Belvieu prices.
Natural gas – A significant portion of our volumes are sold at bid-week prices, or first-of-month indices relative to our producing areas.
30
International (E.G.)
The following table presents our average price realizations and the related benchmark for crude oil for the third quarter and first nine months of 2023 and 2022.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||
| 2023 | 2022 | Increase (Decrease) | 2023 | 2022 | Increase (Decrease) | ||||||||||||||||||||||||||||||
| Average Price Realizations | |||||||||||||||||||||||||||||||||||
Crude oil and condensate (per bbl) | $ | 64.30 | $ | 74.01 | (13) | % | $ | 59.33 | $ | 72.26 | (18) | % | |||||||||||||||||||||||
Natural gas liquids (per bbl) | 1.00 | 1.00 | — | % | 1.00 | 1.00 | — | % | |||||||||||||||||||||||||||
Natural gas (per mcf) | 0.24 | 0.24 | — | % | 0.24 | 0.24 | — | % | |||||||||||||||||||||||||||
| Benchmark | |||||||||||||||||||||||||||||||||||
Brent (Europe) crude oil (per bbl)(a) | $ | 86.66 | $ | 100.71 | (14) | % | $ | 82.05 | $ | 104.85 | (22) | % | |||||||||||||||||||||||
(a)Average of monthly prices obtained from the United States Energy Information Agency website.
Crude oil and condensate – Alba field liquids production is primarily condensate. We generally sell our share of condensate in relation to the Brent crude benchmark. Alba Plant LLC processes the rich hydrocarbon gas which is supplied by the Alba field under a fixed-price long-term contract. Alba Plant LLC extracts NGLs and condensate which is then sold by Alba Plant LLC at market prices, with our share of the revenue reflected in income from equity method investments on the consolidated statements of income. Alba Plant LLC delivers the processed dry natural gas to the Alba Unit Parties for distribution and sale to AMPCO and EG LNG.
Natural gas liquids – Wet gas is sold to Alba Plant LLC at a fixed-price long-term contract resulting in realized prices not tracking market price. Alba Plant LLC extracts and keeps NGLs, which are sold at market price, with our share of income from Alba Plant LLC being reflected in the income from equity method investments on the consolidated statements of income.
Natural gas – Dry natural gas, processed by Alba Plant LLC on behalf of the Alba Unit Parties, is sold by the Alba field to EG LNG and AMPCO at fixed-price contracts resulting in realized prices not tracking market price. The gas sales contracts between Alba Unit and EG LNG and AMPCO expire on December 31, 2023 and in 2026, respectively. We derive additional value from the equity investment in our downstream gas processing units EG LNG and AMPCO. EG LNG sells LNG on a market-based contract and AMPCO markets methanol at market prices.
In March 2023, we announced the signing of a HOA to progress the development of the Equatorial Guinea Regional Gas Mega Hub. In October 2023, we announced the signing of a 5-year firm LNG sales agreement for a portion of our Alba gas liquefied at EG LNG. The contract is effective January 1, 2024, and features a pricing structure linked to the Dutch Title Transfer Facility (TTF) index, providing us with significant incremental exposure to the European LNG market.
In addition to processing Alba Unit gas, Alba Plant LLC and EG LNG process third-party gas from the Alen field under a combination of a tolling and a market linked profit-sharing arrangement, the benefits of which are included in our respective share of income from equity method investees. This profit-sharing arrangement provides exposure to global LNG market prices.
31
Results of Operations
Three Months Ended September 30, 2023 vs. Three Months Ended September 30, 2022
Revenues from contracts with customers are presented by segment in the table below:
| Three Months Ended September 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| Revenues from contracts with customers | |||||||||||
| United States | $ | 1,700 | $ | 1,927 | |||||||
| International | 71 | 81 | |||||||||
| Segment revenues from contracts with customers | $ | 1,771 | $ | 2,008 | |||||||
Below is a price/volume analysis for each segment. Refer to the preceding Operations and Market Conditions sections for additional detail related to our net sales volumes and average price realizations.
| Increase (Decrease) Related to | ||||||||||||||||||||||||||
| (In millions) | Three Months Ended September 30, 2022 | Price Realizations | Net Sales Volumes | Three Months Ended September 30, 2023 | ||||||||||||||||||||||
| United States Price/Volume Analysis | ||||||||||||||||||||||||||
| Crude oil and condensate | $ | 1,428 | $ | (223) | $ | 203 | $ | 1,408 | ||||||||||||||||||
| Natural gas liquids | 216 | (105) | 66 | 177 | ||||||||||||||||||||||
| Natural gas | 261 | (276) | 127 | 112 | ||||||||||||||||||||||
Other sales(a) | 22 | 3 | ||||||||||||||||||||||||
| Total | $ | 1,927 | $ | 1,700 | ||||||||||||||||||||||
| International Price/Volume Analysis | ||||||||||||||||||||||||||
| Crude oil and condensate | $ | 75 | $ | (10) | $ | (1) | $ | 64 | ||||||||||||||||||
| Natural gas liquids | 1 | — | — | 1 | ||||||||||||||||||||||
| Natural gas | 5 | — | — | 5 | ||||||||||||||||||||||
| Other sales | — | 1 | ||||||||||||||||||||||||
| Total | $ | 81 | $ | 71 | ||||||||||||||||||||||
(a)Includes revenue from commodity volumes purchased for resale.
Net gain on commodity derivatives in the third quarter of 2023 was $1 million, compared to a net gain of $41 million for the same period in 2022. We have commodity derivative contracts which settle against the NYMEX WTI and Henry Hub indexes. We record commodity derivative gains/losses as the index pricing and forward curves change each period. See Note 12 to the consolidated financial statements for further information.
Income from equity method investments decreased $152 million in the third quarter of 2023, when compared to the third quarter of 2022, primarily due to lower prices realized by our equity method investees during the third quarter of 2023.
Production expenses for the third quarter of 2023 decreased by $1 million compared to the same period in 2022. In the Eagle Ford, production expenses increased when compared to the prior year as a result of our acquisition of the Eagle Ford assets of Ensign in December 2022 and inflationary pressures. However, this increase was offset by decreased expenses in other areas as a result of less workover activity and expense projects when compared to the same period in 2022.
The following table provides production expense and production expense rates for each segment:
| Three Months Ended September 30, | |||||||||||||||||||||||
| ($ in millions; rate in $ per boe) | 2023 | 2022 | Increase (Decrease) | 2023 | 2022 | Increase (Decrease) | |||||||||||||||||
| Production Expense and Rate | Expense | Rate | |||||||||||||||||||||
| United States | $ | 173 | $ | 173 | — | % | $ | 5.07 | $ | 6.40 | (21) | % | |||||||||||
| International | $ | 19 | $ | 20 | (5) | % | $ | 3.99 | $ | 3.55 | 12 | % | |||||||||||
32
Shipping, handling and other operating expenses decreased $35 million in the third quarter of 2023 when compared to the same period in 2022, primarily due to lower legal costs and a decrease in purchases of commodity volumes for resale to satisfy transportation commitments as compared to the prior period, partially offset by an increase in shipping and handling costs due to increased volumes from our acquisition of the Eagle Ford assets of Ensign in December 2022.
Exploration expenses include unproved property impairments, dry well costs, geological and geophysical and other costs. The decrease in exploration expenses was primarily driven by lower impairments of unproved property leases and lower dry well costs in the third quarter of 2023 when compared the same period of 2022, primarily due to dry well costs and unproved property impairments in Louisiana Austin Chalk in the third quarter of 2022. See Note 5 to the consolidated financial statements for further information.
The following table summarizes the components of exploration expenses:
| Three Months Ended September 30, | |||||||||||||||||
| (In millions) | 2023 | 2022 | Increase (Decrease) | ||||||||||||||
| Exploration Expenses | |||||||||||||||||
| Unproved property impairments | $ | 16 | $ | 45 | (64) | % | |||||||||||
| Dry well costs | 2 | 26 | (92) | % | |||||||||||||
| Geological, geophysical and other | 2 | 2 | — | % | |||||||||||||
| Total exploration expenses | $ | 20 | $ | 73 | (73) | % | |||||||||||
Depreciation, depletion and amortization increased $123 million in the third quarter of 2023 primarily as a result of higher production volumes.
Our segments apply the units-of-production method to the majority of assets, including capitalized asset retirement costs; therefore, volumes have an impact on DD&A expense. The following table provides DD&A expense and DD&A expense rates for each segment:
| Three Months Ended September 30, | |||||||||||||||||||||||||||||||||||
| ($ in millions; rate in $ per boe) | 2023 | 2022 | Increase (Decrease) | 2023 | 2022 | Increase (Decrease) | |||||||||||||||||||||||||||||
| DD&A Expense and Rate | Expense | Rate | |||||||||||||||||||||||||||||||||
| United States | $ | 570 | $ | 441 | 29 | % | $ | 16.74 | $ | 16.20 | 3 | % | |||||||||||||||||||||||
| International | $ | 12 | $ | 14 | (14) | % | $ | 2.39 | $ | 2.82 | (15) | % | |||||||||||||||||||||||
Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income decreased $24 million in the third quarter of 2023 primarily due to lower sales revenue in the third quarter of 2023, when compared to the same period in 2022.
Net interest and other increased $42 million in the third quarter of 2023 primarily as a result of increased interest expense associated with borrowings on our Term Loan Facility and Revolving Credit Facility.
Provision for income taxes decreased $113 million in the third quarter of 2023 primarily due to a decrease in income before income taxes for the current quarter when compared to the same period in 2022.
33
Segment Income
Segment income represents income that excludes certain items not allocated to our operating segments, net of income taxes. See Note 5 to the consolidated financial statements for further details regarding items not allocated to the operating segments.
The following table reconciles segment income to net income:
| Three Months Ended September 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| United States | $ | 505 | $ | 723 | |||||||
| International | 62 | 181 | |||||||||
| Segment income | 567 | 904 | |||||||||
| Items not allocated to segments, net of income taxes | (114) | (87) | |||||||||
| Net income | $ | 453 | $ | 817 | |||||||
United States segment income in the third quarter of 2023 was $505 million of income versus $723 million of income for the same period in 2022. The decrease in segment income is a result of the variances described above.
International segment income in the third quarter of 2023 was $62 million of income versus $181 million of income for the same period in 2022. The decrease was primarily due to lower prices realized by our equity method investees.
Items not allocated to segments, net of income taxes in the third quarter of 2023 was a loss of $114 million versus a loss of $87 million for the same period in 2022. The increase in loss was primarily due to unrealized net losses on commodity derivatives in the third quarter of 2023 versus unrealized net gains on commodity derivatives in the same period of 2022, partially offset by lower exploration expenses in 2023, as well as higher interest expense as a result of outstanding borrowings on our Term Loan Facility and Revolving Credit Facility.
Results of Operations
Nine Months Ended September 30, 2023 vs. Nine Months Ended September 30, 2022
Revenues from contracts with customers are presented by segment in the table below:
| Nine Months Ended September 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| Revenues from contracts with customers | |||||||||||
| United States | $ | 4,643 | $ | 5,730 | |||||||
| International | 179 | 207 | |||||||||
| Segment revenues from contracts with customers | $ | 4,822 | $ | 5,937 | |||||||
34
Below is a price/volume analysis for each segment. Refer to Operations and Market Conditions for additional detail related to our net sales volumes and average price realizations.
| Increase (Decrease) Related to | ||||||||||||||||||||||||||
| (In millions) | Nine Months Ended September 30, 2022 | Price Realizations | Net Sales Volumes | Nine Months Ended September 30, 2023 | ||||||||||||||||||||||
| United States Price/Volume Analysis | ||||||||||||||||||||||||||
| Crude oil and condensate | $ | 4,342 | $ | (1,152) | $ | 598 | $ | 3,788 | ||||||||||||||||||
| Natural gas liquids | 671 | (374) | 205 | 502 | ||||||||||||||||||||||
| Natural gas | 640 | (591) | 288 | 337 | ||||||||||||||||||||||
Other sales(a) | 77 | 16 | ||||||||||||||||||||||||
| Total | $ | 5,730 | $ | 4,643 | ||||||||||||||||||||||
| International Price/Volume Analysis | ||||||||||||||||||||||||||
| Crude oil and condensate | $ | 186 | $ | (35) | $ | 9 | $ | 160 | ||||||||||||||||||
| Natural gas liquids | 2 | — | — | 2 | ||||||||||||||||||||||
| Natural gas | 17 | — | (3) | 14 | ||||||||||||||||||||||
| Other sales | 2 | 3 | ||||||||||||||||||||||||
| Total | $ | 207 | $ | 179 | ||||||||||||||||||||||
(a)Includes revenue from commodity volumes purchased for resale.
Net gain (loss) on commodity derivatives in the first nine months of 2023 was a net gain of $19 million, compared to a net loss of $129 million for the same period in 2022. We have commodity derivative contracts that settle against the NYMEX WTI and Henry Hub indexes. We record commodity derivative gains/losses as the index pricing and forward curves change each period. See Note 12 to the consolidated financial statements for further information.
Income from equity method investments decreased $329 million for the first nine months of 2023, primarily as a result of lower prices realized by our equity method investees during the first nine months of 2023.
Production expenses for the first nine months of 2023 increased by $98 million compared to the same period in 2022, primarily as a result of our acquisition of the Eagle Ford assets of Ensign in December 2022 and inflationary pressures, when compared to the same period of 2022. In addition, in our International segment, production expenses were higher due to the triennial turnaround in April.
The following table provides production expense and production expense rates for each segment:
| Nine Months Ended September 30, | |||||||||||||||||||||||
| ($ in millions; rate in $ per boe) | 2023 | 2022 | Increase (Decrease) | 2023 | 2022 | Increase (Decrease) | |||||||||||||||||
| Production Expense and Rate | Expense | Rate | |||||||||||||||||||||
| United States | $ | 542 | $ | 464 | 17 | % | $ | 5.58 | $ | 5.94 | (6) | % | |||||||||||
| International | $ | 65 | $ | 45 | 44 | % | $ | 4.69 | $ | 2.76 | 70 | % | |||||||||||
Shipping, handling and other operating expenses decreased $88 million in the first nine months of 2023, when compared to the same period in 2022, primarily due to a decrease in purchases of commodity volumes for resale to satisfy transportation commitments and lower legal costs as compared to the prior period, partially offset by an increase in shipping and handling costs due to increased volumes from our acquisition of the Eagle Ford assets of Ensign in December 2022.
Exploration expenses include unproved property impairments, dry well costs, geological and geophysical and other costs. The decrease in exploration expenses was primarily driven by lower impairments of unproved property leases and lower dry well costs in the first nine months of 2023, when compared to the same period in 2022, primarily due to dry well costs and unproved property impairments in Louisiana Austin Chalk in the first nine months of 2022. See Note 5 to the consolidated financial statements for further information.
35
The following table summarizes the components of exploration expenses:
| Nine Months Ended September 30, | |||||||||||||||||
| (In millions) | 2023 | 2022 | Increase (Decrease) | ||||||||||||||
| Exploration Expenses | |||||||||||||||||
| Unproved property impairments | $ | 29 | $ | 59 | (51) | % | |||||||||||
| Dry well costs | 12 | 26 | (54) | % | |||||||||||||
| Geological, geophysical and other | 5 | 7 | (29) | % | |||||||||||||
| Total exploration expenses | $ | 46 | $ | 92 | (50) | % | |||||||||||
Depreciation, depletion and amortization increased $343 million in the first nine months of 2023 primarily as a result of higher production volumes.
Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore volumes have an impact on DD&A expense. The following table provides DD&A expense and DD&A expense rates for each segment:
| Nine Months Ended September 30, | |||||||||||||||||||||||
| ($ in millions; rate in $ per boe) | 2023 | 2022 | Increase (Decrease) | 2023 | 2022 | Increase (Decrease) | |||||||||||||||||
| DD&A Expense and Rate | Expense | Rate | |||||||||||||||||||||
| United States | $ | 1,622 | $ | 1,260 | 29 | % | $ | 16.70 | $ | 16.11 | 4 | % | |||||||||||
| International | $ | 34 | $ | 45 | (24) | % | $ | 2.40 | $ | 2.80 | (14) | % | |||||||||||
Taxes other than income include production, severance and ad valorem taxes, primarily in the U.S., which tend to increase or decrease in relation to revenue and sales volumes. Taxes other than income decreased $130 million primarily due to lower sales revenue in the first nine months of 2023, as well as a nonrecurring Eagle Ford severance tax refund of $47 million related to prior years recorded in June 2023.
Net interest and other increased $140 million in the first nine months of 2023 primarily as a result of increased interest expense associated with borrowings on our Term Loan Facility and Revolving Credit Facility.
Provision for income taxes reflects an effective income tax rate of 21% in the first nine months of 2023. The provision for income taxes in the first nine months of 2022 included a non-cash tax benefit of $685 million arising from the partial release of a valuation allowance on certain U.S. and state deferred tax assets, which was fully offset by the provision related to income earned by our operations in the first nine months of 2022. See Note 6 to the consolidated financial statements for further information.
Segment Income
Segment income represents income that excludes certain items not allocated to our operating segments, net of income taxes. See Note 5 to the consolidated financial statements for further details regarding items not allocated to the operating segments.
The following table reconciles segment income to net income:
| Nine Months Ended September 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| United States | $ | 1,295 | $ | 2,230 | |||||||
| International | 181 | 456 | |||||||||
| Segment income | 1,476 | 2,686 | |||||||||
| Items not allocated to segments, net of income taxes | (319) | 401 | |||||||||
| Net income | $ | 1,157 | $ | 3,087 | |||||||
United States segment income for the first nine months of 2023 was $1.3 billion of income versus $2.2 billion of income for the same period in 2022. The decrease in segment income is a result of the variances described above.
36
International segment income for the first nine months of 2023 was $181 million of income versus $456 million of income for the same period in 2022. The decrease was primarily due to lower prices realized by our equity method investees.
Items not allocated to segments, net of income taxes for the first nine months of 2023 was a loss of $319 million versus $401 million of income for the same period in 2022. The change from income to loss was primarily due to the partial release of a valuation allowance on certain U.S. and state deferred tax assets in the first six months of 2022, which resulted in a non-cash deferred tax benefit of $685 million. In addition, in first nine months of 2023, our interest expense increased as a result of outstanding borrowings on our Term Loan Facility and Revolving Credit Facility.
Critical Accounting Estimates
There have been no material changes or developments in the evaluation of the accounting estimates and the underlying assumptions or methodologies pertaining to our Critical Accounting Estimates disclosed in our Form 10-K for the year ended December 31, 2022.
Cash Flows
The following table presents sources and uses of cash and cash equivalents:
| Nine Months Ended September 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| Sources of cash and cash equivalents | |||||||||||
| Net cash provided by operating activities | $ | 3,007 | $ | 4,301 | |||||||
| Proceeds from revolving credit facility | 1,018 | — | |||||||||
| Proceeds from commercial paper borrowings, net | 450 | — | |||||||||
Borrowings(a) | 200 | — | |||||||||
| Equity method investments - return of capital | 57 | 12 | |||||||||
| Other | — | 23 | |||||||||
| Total sources of cash and cash equivalents | $ | 4,732 | $ | 4,336 | |||||||
| Uses of cash and cash equivalents | |||||||||||
| Additions to property, plant and equipment | $ | (1,659) | $ | (1,117) | |||||||
| Repayments of revolving credit facility | (1,468) | — | |||||||||
| Shares repurchased under buyback programs | (1,121) | (2,474) | |||||||||
Debt repayments(a) | (401) | (35) | |||||||||
| Dividends paid | (186) | (162) | |||||||||
| Purchases of shares for tax withholding obligations | (31) | (21) | |||||||||
| Acquisitions, net of cash acquired | (15) | 2 | |||||||||
| Other | (11) | — | |||||||||
| Total uses of cash and cash equivalents | $ | (4,892) | $ | (3,807) | |||||||
(a)Includes repayment and new borrowing associated with April 2023 remarketing to investors of $200 million sub-series 2017A-1 bonds. See Note 14 to the consolidated financial statements for further information.
Sources of cash and cash equivalents
Cash flows generated from operating activities during the third quarter of 2023 were 30% lower compared to 2022, primarily as a result of lower realized commodity prices, partially offset by higher volumes resulting from our acquisition of the Eagle Ford assets of Ensign in December 2022.
During the first nine months of 2023, we borrowed $1.0 billion and repaid $1.5 billion under our Revolving Credit Facility. Additionally, we have net outstanding commercial paper borrowings of $450 million as of September 30, 2023. See the Liquidity and Capital Resources section below for further information.
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Uses of cash and cash equivalents
During the first nine months of 2023, we repurchased approximately 45 million shares of our common stock pursuant to the share repurchase program at a cost of $1.1 billion, paid dividends of $186 million and repaid the $70 million 8.5% Senior Notes and $131 million 8.125% Senior Notes. Additionally, we repurchased $31 million of shares during the first nine months of 2023 related to our tax withholding obligations associated with the vesting of stock-based compensation awards; these repurchases do not impact our share repurchase program authorization.
During the third quarter of 2023, we utilized commercial paper borrowings to fully repay our $450 million outstanding borrowings against our $2.6 billion unsecured Revolving Credit Facility. See Note 14 to the consolidated financial statements for further information.
The following table shows capital expenditures by segment and reconciles to additions to property, plant and equipment as presented in the consolidated statements of cash flows:
| Nine Months Ended September 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| United States | $ | 1,661 | $ | 1,124 | |||||||
| International | 3 | 1 | |||||||||
| Not Allocated to Segments (Corporate) | 9 | 11 | |||||||||
| Total capital expenditures (accrued) | 1,673 | 1,136 | |||||||||
| Change in capital expenditure accrual | (14) | (19) | |||||||||
| Total use of cash and cash equivalents for property, plant and equipment | $ | 1,659 | $ | 1,117 | |||||||
The increase in our capital expenditures for the U.S. segment in the first nine months of 2023 compared to the same period in 2022 was largely driven by increased investment and drilling related to the Eagle Ford acreage we acquired from Ensign in December 2022. Additionally, inflationary pressures related to oil field services, labor, drilling materials and equipment in the first nine months of 2023, compared to the same period in 2022, contributed to the increase in capital expenditures.
Liquidity and Capital Resources
Capital Resources and Available Liquidity
Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, capital market transactions and our Revolving Credit Facility. During the second quarter of 2023, we obtained ratings for our commercial paper from Moody’s, Standard & Poor’s and Fitch. Pursuant to our commercial paper program, we may issue unsecured notes in a maximum aggregate face amount of $2.5 billion outstanding at any time, with maturities up to 365 days from the date of issuance. Our $2.5 billion commercial paper program is backed by our $2.6 billion Revolving Credit Facility. At September 30, 2023, we had approximately $2.3 billion of liquidity consisting of $174 million in cash and cash equivalents and $2.1 billion available under our Revolving Credit Facility.
Our working capital requirements are supported by our cash and cash equivalents, commercial paper program and our Revolving Credit Facility. We may issue commercial paper, draw on our Revolving Credit Facility to meet short-term cash requirements or issue debt or equity securities through the shelf registration statement discussed below as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, defined benefit plan contributions, repayment of debt maturities, dividends and other amounts that may ultimately be paid in connection with contingencies. See Note 21 to the consolidated financial statements for further discussion of how our commitments and contingencies could affect our available liquidity. General economic conditions, commodity prices, and financial, business and other factors could affect our operations and our ability to access the capital markets.
We maintain investment grade ratings at all three primary credit rating agencies. A downgrade in our credit ratings could increase our future cost of financing or limit our ability to access capital and could result in additional credit support requirements. We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2022 for a discussion of how a downgrade in our credit ratings could affect us.
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We may incur additional debt in order to fund our working capital requirements, capital expenditures, acquisitions or development activities or for general corporate or other purposes. A higher level of indebtedness could increase the risk that our liquidity and financial flexibility deteriorates. See Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2022 for a further discussion of how our level of indebtedness could affect us.
Credit Arrangements and Borrowings
In November 2022, we entered into a two-year $1.5 billion Term Loan Facility and borrowed the full amount thereunder in December 2022. The Term Loan Facility can be prepaid without penalty. Subsequent to the quarter, we repaid $250 million of outstanding borrowings on October 31, 2023. We have $1.3 billion in borrowings remaining under our Term Loan Facility.
As of September 30, 2023, we had $5.3 billion of total long-term debt outstanding. Long-term debt due within one year consists of $200 million 2.1% Bonds and $200 million 2.125% Bonds which feature a mandatory put on July 1, 2024. In addition, as of September 30, 2023, we had outstanding commercial paper borrowings of $450 million.
Both our Term Loan Facility and Revolving Credit Facility include a covenant requiring that our total debt to total capitalization ratio not exceed 65% as of the last day of the fiscal quarter. Our total debt-to-capital ratio was 26% at both September 30, 2023 and December 31, 2022. See Note 14 to the consolidated financial statements for further information.
Refer to our 2022 Annual Report on Form 10-K for a listing of our long-term debt maturities.
On April 3, 2023, we closed a $200 million remarketing to investors of sub-series 2017A-1 bonds that are part of the $1 billion St. John the Baptist, State of Louisiana revenue refunding bonds Series 2017. The bonds are subject to an interest rate of 4.05% and a mandatory purchase date of July 1, 2026.
Other sources of liquidity
We have an effective universal shelf registration statement filed with the SEC pursuant to which we, as a “well-known seasoned issuer” for purposes of SEC rules, subject to market conditions, are permitted to issue and sell an indeterminate amount of various types of debt, equity securities and other capital instruments, if and when necessary or perceived by us to be opportune, in one or more public offerings.
Capital Requirements
Share Repurchase Program
Our Board of Directors has authorized a share repurchase program. Our remaining authorization at September 30, 2023 was approximately $1.4 billion. Subsequent to the quarter, our Board of Directors increased our remaining authorization to $2.5 billion effective on November 1, 2023.
Dividends
On October 25, 2023, our Board of Directors approved a dividend of $0.11 per share payable December 11, 2023 to stockholders of record at the close of business on November 15, 2023.
Income Taxes
As described in Note 6 to the consolidated financial statements, the IRA was signed into law during 2022. Under current law and guidance, we do not anticipate being subject to the corporate book minimum tax in 2023 but anticipate that corporate book minimum tax will apply in 2024. The U.S. Treasury is expected to publish further guidance and regulations that will be relevant to scoping considerations and the calculation of minimum income tax liabilities. As this guidance is issued, we will continue to evaluate and assess the impact the IRA may have on our current and future period income taxes.
Other Contractual Cash Obligations
As of September 30, 2023, material changes to our contractual cash obligations compared to December 31, 2022 include the previously discussed repayment of $450 million outstanding borrowings against our $2.6 billion unsecured Revolving Credit Facility, which was due in 2027, and the addition of commercial paper borrowings of $450 million. In addition, we repaid $250 million of outstanding borrowings against our $1.5 billion Term Loan Facility on October 31, 2023.
Other than the items set forth above, there are no material changes to our consolidated cash obligations to make future payments under existing contracts, as disclosed in our 2022 Annual Report on Form 10-K.
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Environmental Matters and Other Contingencies
We have incurred and will continue to incur capital, operating and maintenance and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately offset by the prices we receive for our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.
Other than the items set forth in Part II - Item 1. Legal Proceedings, there have been no significant changes to the environmental, health and safety matters under Item 1. Business or Item 3. Legal Proceedings in our 2022 Annual Report on Form 10-K. See Note 21 to the consolidated financial statements for a description of other contingencies.
Forward-Looking Statements
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statements of historical fact, including without limitation statements regarding our future performance, business strategy, capital budget and allocations, reserve estimates, asset quality, production guidance, drilling plans, capital plans, future debt retirement, cost and expense estimates, asset acquisitions and dispositions, expected impacts of the IRA, tax assumptions and allowances, future financial position, statements regarding future commodity prices, and statements regarding management’s other plans and objectives for future operations, are forward-looking statements. Words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “outlook,” “plan,” “positioned,” “project,” “seek,” “should,” “target,” “will,” “would” or similar words may be used to identify forward-looking statements; however, the absence of these words does not mean that the statements are not forward-looking. While we believe that our assumptions concerning future events are reasonable, these expectations may not prove to be correct. A number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:
•conditions in the oil and gas industry, including supply and demand levels for crude oil and condensate, NGLs and natural gas and the resulting impact on price;
•changes in expected reserve or production levels;
•changes in political or economic conditions in the U.S. and E.G., including changes in foreign currency exchange rates, interest rates, inflation rates and global and domestic market conditions;
•actions taken by the members of OPEC and Russia affecting the production and pricing of crude oil and other global and domestic political, economic or diplomatic developments;
•capital available for exploration and development;
•risks related to our hedging activities;
•voluntary or involuntary curtailments, delays or cancellations of certain drilling activities;
•well production timing;
•liabilities or corrective actions resulting from litigation, other proceedings and investigations or alleged violations of law or permits;
•drilling and operating risks;
•lack of, or disruption in, access to storage capacity, pipelines or other transportation methods;
•availability of drilling rigs, materials and labor, including the costs associated therewith;
•difficulty in obtaining necessary approvals and permits;
•the availability, cost, terms and timing of issuance or execution of, competition for, and challenges to, mineral licenses and leases and governmental and other permits and rights-of-way, and our ability to retain mineral licenses and leases;
•non-performance by third parties of their contractual obligations, including due to bankruptcy;
•administrative impediments or unexpected events that may impact dividends or other distributions, and the timing thereof, from our equity method investees;
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•unforeseen hazards such as weather conditions, a health pandemic (including COVID-19), acts of war or terrorist acts and the governmental or military response thereto;
•the impacts of supply chain disruptions that began during the COVID-19 pandemic and the resulting inflationary environment;
•security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, or breaches of the information technology systems, facilities and infrastructure of third parties with which we transact business;
•our ability to achieve, reach or otherwise meet initiatives, plans or ambitions with respect to ESG matters;
•our ability to pay dividends and make share repurchases;
•our ability to secure increased exposure to global LNG market prices and progress on the E.G. Gas Mega Hub;
•impacts of the IRA;
•the risk that the Ensign assets do not perform consistent with our expectations, including with respect to future production or drilling inventory;
•other geological, operating and economic considerations; and
•the risk factors, forward-looking statements and challenges and uncertainties described in our 2022 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other filings with the SEC.
All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we undertake no obligation to revise or update any forward-looking statements as a result of new information, future events or otherwise.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks in the normal course of business including commodity price risk and interest rate risk. We employ various strategies, including the use of financial derivatives to manage the risks related to commodity price and interest rate fluctuations. See Note 12 and Note 13 to the consolidated financial statements for detail relating to our open commodity derivative positions, including underlying notional quantities, how they are reported in our consolidated financial statements and how their fair values are measured.
Commodity Price Risk
As of September 30, 2023, we had open commodity derivatives related to crude oil and natural gas. Based on the September 30, 2023 published NYMEX WTI and natural gas futures prices, a hypothetical 10% change (per bbl for crude oil and per MMBtu for natural gas) would change the fair values of our commodity derivative positions to the following:
| (In millions) | Fair Value at September 30, 2023 | Hypothetical Price Increase of 10% | Hypothetical Price Decrease of 10% | ||||||||||||||
| Derivative asset (liability) - Crude Oil | $ | — | $ | (13) | $ | 9 | |||||||||||
| Derivative asset (liability) - Natural Gas | 3 | 2 | 3 | ||||||||||||||
| Total | $ | 3 | $ | (11) | $ | 12 | |||||||||||
Interest Rate Risk
At September 30, 2023, our portfolio of current and long-term debt is comprised of floating rate debt and fixed-rate instruments. Our Term Loan Facility is a floating rate debt instrument, which exposes us to the risk of earnings or cash flow losses as the result of potential increases in market interest rates. At September 30, 2023, we had $1.5 billion outstanding borrowings under floating rate debt instruments. Assuming no change in the amount of floating rate debt outstanding, a hypothetical 100 basis point increase in the average interest rate under these borrowings would increase our annual interest expense by approximately $15 million. Actual results may vary due to changes in the amount of floating rate debt outstanding.
At September 30, 2023, we had $3.8 billion outstanding borrowings under fixed-rate debt instruments. Our sensitivity to interest rate movements and corresponding changes in the fair value of our fixed-rate debt portfolio affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices different than carrying value.
At September 30, 2023, we had forward starting interest rate swap agreements with a total notional amount of $295 million designated as cash flow hedges. We utilize cash flow hedges to manage our exposure to interest rate movements by utilizing interest rate swap agreements to hedge variations in cash flows related to the SOFR interest component of future lease payments on our Houston office. A hypothetical 10% change in interest rates would change the fair values of our cash flow hedges to the following as of September 30, 2023:
| (In millions) | Fair Value at September 30, 2023 | Hypothetical Interest Rate Increase of 10% | Hypothetical Interest Rate Decrease of 10% | ||||||||||||||
| Interest rate asset (liability) - designated as cash flow hedges | $ | 25 | $ | 29 | $ | 22 | |||||||||||
Item 4. Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of September 30, 2023.
During the first nine months of 2023, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.
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Part II – OTHER INFORMATION
Item 1. Legal Proceedings
We have received NOV’s from the EPA related to allegations of violations of the Clean Air Act with respect to our operations on the Fort Berthold Indian Reservation between 2015 and 2019. We continue to actively negotiate a draft consent decree with the EPA and Department of Justice. The resolution of the enforcement action will likely include monetary sanctions and implementation of both environmental mitigation projects and injunctive terms, which would increase both our development costs and operating costs. We maintain an accrual for estimated potential monetary sanctions. While we do not believe resolution of this matter will have a material adverse effect on our business or operations, there exists substantial uncertainty as to the ultimate result of this matter and it is reasonably possible the result could be materially different from our expectations and our accrual.
The Company received NOV’s from the EPA relating to alleged Clean Air Act violations following flyovers conducted in 2020 and 2022 over certain of the Company’s oil and gas facilities in New Mexico. The notices involve alleged emission and permitting violations. The Company has initiated discussions with the EPA to resolve these matters. At this time, we are unable to estimate the potential loss associated with these matters, however, it is reasonably possible that the resolution of these matters may result in a fine or penalty in excess of $300,000.
Marathon Oil was named in a lawsuit alleging improper royalty deductions in certain of our Oklahoma operations, and after plaintiffs lost their attempt to certify a class action, a settlement was reached, and in the first quarter of 2023 such settlement was approved by the court and paid.
Other than the items set forth above, there have been no significant changes to Item 3. Legal Proceedings in our 2022 Annual Report on Form 10-K. See Note 21 to the consolidated financial statements included in Part I, Item I for a description of such legal and administrative proceedings and Item 3. Legal Proceedings in our 2022 Annual Report on Form 10-K.
Item 1A. Risk Factors
We are subject to various risks and uncertainties in the course of our business. In addition to the other information set forth in this Quarterly Report on Form 10-Q, the reader should carefully consider the factors discussed in Item 1A. Risk Factors in our 2022 Annual Report on Form 10-K. There have been no material changes or updates to the risk factors previously disclosed in our 2022 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about purchases by Marathon Oil, during the quarter ended September 30, 2023, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934.
| Period | Total Number of Shares Purchased(a) | Average Price Paid per Share(b) | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(c) | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(b)(c) | |||||||||||||||||||
| 07/01/2023 - 07/31/2023 | — | $ | — | — | $ | 1,764,769,042 | |||||||||||||||||
| 08/01/2023 - 08/31/2023 | 3,840,870 | 25.97 | 3,840,870 | 1,665,019,129 | |||||||||||||||||||
| 09/01/2023 - 09/30/2023 | 11,782,201 | 26.74 | 11,782,201 | 1,350,019,479 | |||||||||||||||||||
| Total | 15,623,071 | $ | 26.55 | 15,623,071 | |||||||||||||||||||
(a)No shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.
(b)Excludes 1% excise tax on share repurchases.
(c)Refer to our 2022 Annual Report on Form 10-K for historical share repurchase program authorizations and repurchase activity through December 31, 2022. As of September 30, 2023, we have approximately $1.4 billion of authorization remaining under the share repurchase program. Purchases under the program are made at our discretion and may be in either open market transactions, including block purchases or in privately negotiated transactions using cash on hand, cash generated from operations or proceeds from potential asset sales. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. Shares repurchased as of September 30, 2023, were held as treasury stock.
Item 5. Other Information
During the three months ended September 30, 2023, no director or officer adopted or terminated a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement, as each term is defined in Item 408(a) of Regulation S-K.
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Item 6. Exhibits
| Incorporated by Reference (File No. 001-05153, unless otherwise indicated) | |||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | Exhibit | Filing Date | |||||||||||||||||||
| 3.1 | 8-K | 3.1 | 6/1/2018 | ||||||||||||||||||||
| 3.2 | 8-K/A | 3.2 | 10/30/2023 | ||||||||||||||||||||
| 3.3 | 10-K | 3.3 | 2/28/2014 | ||||||||||||||||||||
| 4.1 | 10-K | 4.2 | 2/28/2014 | ||||||||||||||||||||
| 10.1* | |||||||||||||||||||||||
| 10.2†* | |||||||||||||||||||||||
| 31.1* | |||||||||||||||||||||||
| 31.2* | |||||||||||||||||||||||
| 32.1** | |||||||||||||||||||||||
| 32.2** | |||||||||||||||||||||||
| 101.INS* | XBRL Instance Document - the XBRL Instance Document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document | ||||||||||||||||||||||
| 101.SCH* | XBRL Taxonomy Extension Schema | ||||||||||||||||||||||
| 101.CAL* | XBRL Taxonomy Extension Calculation Linkbase | ||||||||||||||||||||||
| 101.DEF* | XBRL Taxonomy Extension Definition Linkbase | ||||||||||||||||||||||
| 101.LAB* | XBRL Taxonomy Extension Label Linkbase | ||||||||||||||||||||||
| 101.PRE* | XBRL Taxonomy Extension Presentation Linkbase | ||||||||||||||||||||||
| 104* | Cover Page Interactive Data File, formatted in iXBRL and contained in Exhibit 101 | ||||||||||||||||||||||
| * | Filed herewith. | ||||||||||||||||||||||
| ** | Furnished herewith. This certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act. | ||||||||||||||||||||||
| † | Management contract or compensatory plan or arrangement. | ||||||||||||||||||||||
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| November 2, 2023 | MARATHON OIL CORPORATION | |||||||
By: | /s/ Rob L. White | |||||||
| Rob L. White | ||||||||
| Vice President, Controller and Chief Accounting Officer | ||||||||
| (Duly Authorized Officer) | ||||||||
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