Notes to Consolidated Financial Statements (Unaudited)
1. Organization and Basis of Presentation
We are an independent oil and gas exploration and production company with a focus on U.S. resource plays: Eagle Ford in Texas, Bakken in North Dakota, Permian in New Mexico and Texas and STACK and SCOOP in Oklahoma. Our U.S. assets are complemented by our international operations in E.G.
Proposed Merger with ConocoPhillips
On May 28, 2024, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with ConocoPhillips, a Delaware corporation (“ConocoPhillips”), and Puma Merger Sub Corp., a wholly owned subsidiary of ConocoPhillips (“Merger Sub”). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Sub be merged with and into Marathon Oil (the “Merger”), with Marathon Oil surviving and continuing as the surviving corporation in the Merger as a direct, wholly owned subsidiary of ConocoPhillips. Under the terms of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each of our outstanding shares of common stock (other than certain Excluded Shares and Converted Shares, each as defined in the Merger Agreement) will be converted to the right to receive 0.2550 (the “Exchange Ratio”) shares of ConocoPhillips common stock (the “Merger Consideration”). The Merger Agreement also contains certain customary termination rights of each of Marathon Oil and ConocoPhillips, and under certain circumstances, a termination fee would be payable by us. On August 29, 2024, the Company’s stockholders approved and adopted the Merger Agreement at a special meeting of stockholders. Completion of the Merger remains subject to certain conditions, including certain governmental and regulatory approvals. The Merger is currently expected to close late in the fourth quarter of 2024; however, no assurance can be given as to when, or if, the Merger will occur. See Item 1A. Risk Factors for a discussion of the risks related to the Merger and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional details relating to the Merger.
In association with the Merger, for the three and nine months ended September 30, 2024, we have incurred transaction costs of $6 million and $16 million, respectively, which are recorded as general and administrative expense in the consolidated statements of income. We expect to incur additional costs as the Merger progresses. Transaction costs consist primarily of third party legal and banking fees.
The above description of the Merger Agreement and the transactions contemplated thereby, including certain referenced terms, is a summary of certain principal terms and conditions contained in the Merger Agreement.
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 2023 Annual Report on Form 10-K. The results of operations for the third quarter and first nine months of 2024 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 during the first nine months of 2024 that had a material impact on our consolidated financial statements.
Notes to Consolidated Financial Statements (Unaudited)
Accounting Standards Updates Not Yet Adopted
In November 2023, the FASB issued a new accounting standards update to improve the disclosures around a public entity’s reportable segments. The standard requires disclosure of significant segment expenses included within each reported measure of segment profit or loss. This standard is effective for annual reporting periods beginning after December 15, 2023, and interim reporting periods within annual reporting periods beginning after December 15, 2024, with early adoption permitted. The standard is effective for us in the 2024 annual reporting period and will be applied retrospectively to all prior periods presented in the financial statements. This standard only modifies disclosure requirements; as such, there will be no impact on our consolidated results of operations, financial position or cash flows.
In December 2023, the FASB issued a new accounting standards update to improve income tax disclosures primarily related to the rate reconciliation and income taxes paid. The standard requires consistent categories and greater disaggregation of information in the rate reconciliation and income taxes paid by jurisdiction. The standard is effective for annual periods beginning after December 15, 2024, with early adoption permitted. This standard is effective for us in the 2025 annual reporting period and will be applied retrospectively to all prior periods presented in the financial statements. The standard only modifies disclosure requirements; as such, there will be no impact on our consolidated results of operations, financial position or cash flows.
There were no other 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 an immaterial number of antidilutive stock options and performance units for the three and nine months ended September 30, 2024. In addition, 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:
Three Months Ended September 30,
Nine Months Ended September 30,
(In millions, except per share data)
2024
2023
2024
2023
Net income
$
287
$
453
$
933
$
1,157
Weighted average common shares outstanding
563
603
570
615
Effect of dilutive securities
1
1
—
1
Weighted average common shares, diluted
564
604
570
616
Net income per share:
Basic
$
0.51
$
0.75
$
1.64
$
1.88
Diluted
$
0.51
$
0.75
$
1.64
$
1.88
Dividends per share
$
0.11
$
0.10
$
0.33
$
0.30
Under the Merger Agreement, we are subject to restrictions that prevent us from increasing our quarterly dividend in excess of $0.11 per share.
4. Revenues
The majority of our revenues are derived from the sale of crude oil and condensate, NGLs and natural gas, including LNG, under spot and term agreements with our customers in the United States and Equatorial Guinea.
As of September 30, 2024 and December 31, 2023, receivables from contracts with customers, included in receivables, net, were $905 million and $886 million, respectively.
Notes to Consolidated Financial Statements (Unaudited)
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:
Notes to Consolidated Financial Statements (Unaudited)
International (E.G.)
Three Months Ended September 30,
Nine Months Ended September 30,
(In millions)
2024
2023
2024
2023
Crude oil and condensate
$
53
$
64
$
142
$
160
NGLs
—
1
1
2
Natural gas, sold as gas
1
5
5
14
Natural gas, sold as LNG
72
—
207
—
Natural gas, total
73
5
212
14
Other
—
1
2
3
Revenues from contracts with customers
$
126
$
71
$
357
$
179
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.
Notes to Consolidated Financial Statements (Unaudited)
Nine Months Ended September 30, 2023
(In millions)
U.S.
Int’l
Not Allocated to Segments
Total
Revenue 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, including related party
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 credits
—
—
(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.
(c)Unrealized loss on commodity derivative instruments (SeeNote 8).
(d)Includes $10 million of dry well expense associated with wells in Permian and $11 million of unproved impairments related to Permian exploration leases.
Notes to Consolidated Financial Statements (Unaudited)
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, 2024 and 2023, our effective income tax rates were as follows:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
2024
2023
Effective income tax rate
38
%
22
%
28
%
21
%
•2024— Our effective income tax rate was different from our U.S. statutory tax rate of 21% for the three and nine months ended September 30, 2024 due to a deferred tax valuation allowance recorded in the quarter against foreign tax credits expiring in future periods. As a result of continued volatility in commodity prices and corresponding impacts to projections of future taxable income, we believe it is more likely than not that we will not utilize $75 million of foreign tax credits before they expire. We continue to assess whether the balance of the valuation allowance is appropriate on a quarterly basis particularly given the expiring nature of foreign tax credits in years 2025 through 2026. If we experience sustained lower commodity prices that impact the performance of future earnings, it is reasonably possible that within the next 12 months sufficient negative evidence may exist that will require us to establish additional valuation allowance on our deferred tax assets that we do not expect to realize.
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 are subject to the corporate book minimum tax in 2024. In September 2024, the IRS issued proposed regulations on the corporate book minimum tax. We have reviewed the proposed regulations and do not expect any material changes to our calculation for 2024. In addition, in September 2024, estimated tax payment relief for the 2024 corporate book minimum tax was granted through the end of the year. As further guidance is issued, we will continue to evaluate and assess the impact the IRA may have on our current and future period income taxes.
7. 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. During the fourth quarter of 2023, we repaid $300 million of outstanding borrowings. On March 28, 2024, we fully repaid the $1.2 billion outstanding balance under our Term Loan Facility by utilizing the net proceeds received from the senior notes issued during the first quarter of 2024 plus cash on hand (see Debt Issuance below).
Revolving Credit Facility and Commercial Paper Program
We have an unsecured revolving credit facility (“Revolving Credit Facility”) with a borrowing capacity of $2.6 billion. 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 matures on July 28, 2027. At September 30, 2024, we had nooutstanding borrowings under our Revolving Credit Facility.
The Revolving Credit Facility includes a covenant requiring our total debt to total capitalization ratio, as defined in the credit agreement, 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, 2024, we were in compliance with this covenant.
Notes to Consolidated Financial Statements (Unaudited)
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.
We utilize our commercial paper program to fund various short-term working capital requirements. As of September 30, 2024, we had $180 million of outstanding commercial paper maturing at various dates with a weighted average interest rate of 5.27%.
Under the Merger Agreement, we are permitted to borrow under our commercial paper program or Revolving Credit Facility, an aggregate amount not to exceed $1.5 billion outstanding.
Long-term debt
At September 30, 2024, we had $4.6 billion of total long-term debt outstanding. Refer to our 2023 Annual Report on Form 10-K for a listing of our long-term debt maturities. Under the Merger Agreement, we are subject to restrictions and limitations that prevent us from incurring additional debt, or redeeming all or a portion of our existing outstanding debt, except for permitted borrowings under our commercial paper program or Revolving Credit Facility (see Revolving Credit Facility and Commercial Paper Program above).
Debt issuance
On March 28, 2024, we completed a public offering of $1.2 billion aggregate principal amount of unsecured senior notes consisting of $600 million aggregate principal amount of 5.30% senior notes due April 1, 2029 (“2029 Notes”) and $600 million aggregate principal amount of 5.70% senior notes due April 1, 2034 (“2034 Notes”). Interest on the senior notes is payable semi-annually beginning October 1, 2024. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. Net proceeds received totaled approximately $1.2 billion. Debt issuance costs of $12 millionwere recorded as deferred financing costs within long-term debt in our consolidated balance sheets and are being amortized to interest expense in our consolidated statement of income over the term of each note. The net proceeds, together with cash on hand, were used to repay $1.2 billion of outstanding borrowings under our Term Loan Facility.
Debt redemption
On July 1, 2024, using short-term borrowings, we purchased $200 million of our outstanding sub-series 2017 A-2 bonds and $200 million of our outstanding sub-series 2017 B-1 bonds that are part of the $1.0 billion Parish of St. John The Baptist, State of Louisiana Revenue Refunding Bonds (Marathon Oil Corporation Project) Series 2017. The $400 million of bonds due 2037 were purchased on their mandatory put date of July 1, 2024, for our own account and are subject to an interest rate of 4.125%. We have the right, subject to the consent of ConocoPhillips, to convert and remarket these bonds to the public at any time up to their June 1, 2037 maturity date.
In July 2023, we redeemed the $131 million 8.125% Senior Notes in connection with their maturity date.
In March 2023, we redeemed the $70 million 8.5% Senior Notes in connection with their maturity date.
Debt Remarketing
In April 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 repayment and new borrowing associated with the remarketed bonds are presented separately within Debt repayments and Borrowings, respectively, within the Consolidated Statements of Cash Flows.
8. 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 9. 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. Under the Merger Agreement, we are subject to limitations on our ability to enter into new derivative transactions.
Notes to Consolidated Financial Statements (Unaudited)
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, 2024
(In millions)
Asset
Liability
Net Asset
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
$
7
$
—
$
7
Other current assets
Interest Rate
4
—
4
Other noncurrent assets
Total Designated Hedges
$
11
$
—
$
11
Total
$
21
$
—
$
21
December 31, 2023
(In millions)
Asset
Liability
Net Asset
Balance Sheet Location
Not Designated as Hedges
Commodity
$
24
$
—
$
24
Other current assets
Total Not Designated as Hedges
$
24
$
—
$
24
Cash Flow Hedges
Interest Rate
$
9
$
—
$
9
Other current assets
Interest Rate
9
—
9
Other noncurrent assets
Total Designated Hedges
$
18
$
—
$
18
Total
$
42
$
—
$
42
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 2025. These derivatives are three-way collars and two-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 plus the difference between the floor and the sold put price. Two-way collars only consists of a sold call (ceiling) and a purchased put (floor). These crude oil and natural gas derivatives were not designated as hedges.
Notes to Consolidated Financial Statements (Unaudited)
The following table sets forth outstanding derivative contracts as of September 30, 2024, and the weighted average prices for those contracts:
2024
2025
Fourth Quarter
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Crude Oil
NYMEX WTI Three-Way Collars
Volume (Bbls/day)
50,000
—
—
—
—
Weighted average price per Bbl:
Ceiling
$
95.95
$
—
$
—
$
—
$
—
Floor
$
65.00
$
—
$
—
$
—
$
—
Sold put
$
50.00
$
—
$
—
$
—
$
—
Natural Gas
Henry Hub Two-Way Collars
Volume (MMBtu/day)
—
150,000
150,000
150,000
150,000
Weighted average price per MMBtu:
Ceiling
$
—
$
5.85
$
5.85
$
5.85
$
5.85
Floor
$
—
$
2.50
$
2.50
$
2.50
$
2.50
The unrealized gain (loss) and realized gain 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)
2024
2023
2024
2023
Unrealized gain (loss) on derivative instruments, net
$
9
$
(6)
$
(14)
$
(8)
Realized gain on derivative instruments, net(a)
$
—
$
7
$
—
$
27
(a)During the third quarter and first nine months of 2024, we had no settled derivative positions. During the third quarter and first nine months of 2023, net cash received for settled derivative positions was $6 million and $23 million, respectively.
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, 2024 and December 31, 2023, 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, 2024 and December 31, 2023.
During the nine months ended September 30, 2024, net cash received for the settled interest rate swap positions was $9 million. As of September 30, 2024, we expect to reclassify a $7 million gain from accumulated other comprehensive income into our consolidated statements of income over the next twelve months.
Notes to Consolidated Financial Statements (Unaudited)
9. 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, 2024 and December 31, 2023 by hierarchy level:
September 30, 2024
(In millions)
Level 1
Level 2
Level 3
Total
Derivative instruments, assets
Commodity(a)
$
—
$
10
$
—
$
10
Interest rate - designated as cash flow hedges
—
11
—
11
Derivative instruments, assets
$
—
$
21
$
—
$
21
December 31, 2023
(In millions)
Level 1
Level 2
Level 3
Total
Derivative instruments, assets
Commodity(a)
$
—
$
24
$
—
$
24
Interest rate - designated as cash flow hedges
—
18
—
18
Derivative instruments, assets
$
—
$
42
$
—
$
42
(a)Derivative instruments are recorded on a net basis in our consolidated balance sheet. See Note 8.
As of September 30, 2024, our commodity derivatives include three-way collars and two-way collars. These instruments are measured at fair value using either a Black-Scholes or a modified Black-Scholes Model. For three-way collars and two-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 8 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.
Notes to Consolidated Financial Statements (Unaudited)
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, 2024 and December 31, 2023:
September 30, 2024
December 31, 2023
(In millions)
Fair Value
Carrying Amount
Fair Value
Carrying Amount
Financial assets
Other noncurrent assets
$
10
$
32
$
9
$
27
Total financial assets
$
10
$
32
$
9
$
27
Financial liabilities
Other current liabilities
$
80
$
123
$
80
$
126
Long-term debt, including current portion(a)
4,824
4,596
4,961
4,997
Deferred credits and other liabilities
58
60
70
71
Total financial liabilities
$
4,962
$
4,779
$
5,111
$
5,194
(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 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.
10. Property, Plant and Equipment
(In millions)
September 30, 2024
December 31, 2023
United States
$
16,941
$
16,905
International
229
252
Corporate
50
56
Net property, plant and equipment
$
17,220
$
17,213
As of September 30, 2024 and December 31, 2023, we had no exploratory well costs capitalized greater than one year related to suspended wells.
Notes to Consolidated Financial Statements (Unaudited)
11. 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)
2024
2023
Beginning balance as of January 1
$
340
$
340
Incurred liabilities, including acquisitions
8
4
Settled liabilities, including dispositions
(9)
(27)
Accretion expense (included in depreciation, depletion and amortization)
12
11
Revisions of estimates
3
12
Ending balance as of September 30, total
$
354
$
340
Ending balance as of September 30, short-term
$
13
$
32
12. Equity Method Investments
During the periods ended September 30, 2024 and December 31, 2023, our equity method investees were considered related parties. Our investments in our equity method investees are summarized in the following table:
(In millions)
Ownership as of September 30, 2024
September 30, 2024
December 31, 2023
EG LNG (a)
56%
$
108
$
118
Alba Plant LLC (b)
52%
155
153
AMPCO (c)
45%
169
162
Total
$
432
$
433
(a)EG LNG 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)
2024
2023
2024
2023
Income data:
Revenues and other income
$
194
$
200
$
588
$
689
Income from operations
73
77
232
279
Net income
$
63
$
63
$
193
$
227
Revenues from related parties were $2 million and $7 million for the three and nine months ended September 30, 2024, respectively, which primarily related to Alba Plant LLC and AMPCO. Revenues from related parties were $6 million and $17 million for the three and nine months ended September 30, 2023, respectively, with the majority related to EG LNG. As a result of the agreement that took effect on January 1, 2024, related party shipping, handling and other operating expense presented on the face of the consolidated statements of income represents compensation to EG LNG for liquefaction, storage and product handling services.
Notes to Consolidated Financial Statements (Unaudited)
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 $29 million and $106 million during the three and nine months ended September 30, 2024 and $47 million and $296 million during the three and nine months ended September 30, 2023, respectively.
Current receivables from related parties were $34 million at September 30, 2024, which primarily related to EG LNG. Current receivables from related parties were $24 million at December 31, 2023, which primarily related to EG LNG and Alba Plant LLC. Payables to related parties were $15 million and $6 million at September 30, 2024 and December 31, 2023, respectively, with the majority related to EG LNG in both periods.
Related Party Lease Transaction
Our wholly owned subsidiary, MEGPL, is a lessor for residential housing in E.G., which is occupied by EG LNG. The lease was classified as an operating lease with an initial term expiring in 2024. On June 30, 2024, the lessee exercised an option to extend the lease 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
2024
$
2
2025
6
2026
6
2027
6
2028
6
Thereafter
35
Total undiscounted cash flows
$
61
13. Stockholders’ Equity
Our Board of Directors has authorized a share repurchase program. During the first nine months of 2024, we repurchased approximately 19 million shares of our common stock pursuant to the share repurchase program at a cost of $516 million. Our remaining share repurchase authorization was approximately $1.8 billion at September 30, 2024. Purchases under our repurchase 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.
Upon the announcement of the Merger Agreement, we suspended our stock repurchase activity as we are subject to certain restrictions to our ability to repurchase, redeem or otherwise acquire our capital stock.
Notes to Consolidated Financial Statements (Unaudited)
14. Incentive Based Compensation
Stock options and restricted stock units
The following table presents a summary of activity for the first nine months of 2024:
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, 2023
1,004,304
$
31.38
3,514,405
$
22.07
Granted
—
—
2,100,923
24.67
Exercised/Vested
(13,889)
10.47
(1,787,035)
19.40
Canceled
(649,764)
33.78
(153,072)
24.22
Outstanding at September 30, 2024
340,651
$
27.64
3,675,221
$
24.76
In accordance with the Merger Agreement, each outstanding and vested Marathon Oil option award granted pursuant to the Marathon Oil stock plan will be canceled and converted into the right to receive a number of shares of ConocoPhillips common stock (rounded down to the nearest whole share) equal to the quotient of (i) the product of (A) the excess, if any, of the Merger Consideration Value (as defined below) over the per share exercise price, multiplied by (B) the number of shares of Marathon Oil common stock subject to such Marathon Oil option award immediately prior to the Effective Time, divided by (ii) the volume-weighted average price of the ConocoPhillips common stock for the five consecutive trading days ending two trading days prior to the closing date (the “Parent Closing Price”). Any Marathon Oil option award that has an exercise price per share that is equal to or greater than the Merger Consideration Value will be canceled for no consideration. The term “Merger Consideration Value” means the product of (x) the Exchange Ratio multiplied by (y) the Parent Closing Price.
At closing, restricted stock units will be canceled and converted into an award of ConocoPhillips common stock at the Exchange Ratio and will be subject to the same vesting conditions that existed prior to the closing of the Merger Agreement. Any restricted stock units held by non-employee directors of Marathon Oil will fully vest at closing and be converted, at the Exchange Ratio, into the right to receive ConocoPhillips common stock. Additionally, consummation of the Merger constitutes a change in control as defined under our 2019 Incentive Compensation Plan. After a change in control has occurred, restricted stock units granted to employees who are involuntarily separated, under certain conditions, will immediately vest as ConocoPhillips common stock.
Stock-based performance unit awards
During the first nine months of 2024, we granted 261,459 stock-based performance units to eligible officers, which are settled in shares. The weighted average grant date fair value per unit was $28.45. During the first nine months of 2024, we stock settled the units related to the 2021 grant. At September 30, 2024, there were 650,966 outstanding stock-based performance units to be settled in shares to officers.
During the first nine months of 2024, we also granted 261,459 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 $26.96 as of September 30, 2024. During the first nine months of 2024, we also cash settled the units related to the 2022 grant. At September 30, 2024, there were 483,923 units outstanding of the stock-based performance unit awards to be settled in cash to officers.
In accordance with the Merger Agreement, each stock-based performance unit that is outstanding immediately prior to closing will vest. Outstanding performance units were initially granted assuming a target payout; however, at closing, all outstanding performance units will vest at the maximum payout percentage of 200% of target.
Notes to Consolidated Financial Statements (Unaudited)
15. Inventories
Crude oil, NGLs and natural gas, including LNG, 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, 2024
December 31, 2023
Crude oil, NGLs and natural gas, including LNG
$
13
$
14
Supplies and other items
153
172
Inventories
$
166
$
186
16. Supplemental Cash Flow Information
Nine Months Ended September 30,
(In millions)
2024
2023
Included in operating activities:
Interest paid (a)
$
181
$
251
Income taxes paid, net of refunds
$
67
$
103
Noncash investing activities:
Increase in asset retirement costs
$
11
$
16
(a)The decrease in interest paid during the nine months ended September 30, 2024, compared to the same period in 2023, was primarily due to reductions in interest paid on borrowings under both the Term Loan Facility and Revolving Credit Facility.
Other noncash investing activities include accrued capital expenditures for the nine months ended September 30, 2024 and 2023 of $130 million and $125 million, respectively.
17. 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, 2024, we have a $125 million current liability in suspended royalty and working interest revenue, including interest, of which $104 million was included within accounts payable and $21 million related to accrued interest was included within other current liabilities on our consolidated balance sheet. Additionally, we have a long-term receivable of $30 million for capital and expenses. 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 (“M-Opinion”) concluding that the Disputed Land is held in trust for the Three Affiliated Tribes. While the 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.
Notes to Consolidated Financial Statements (Unaudited)
We received Notices of Violation (“NOVs”) from the EPA related to alleged violations of the Clean Air Act with respect to our operations on the Fort Berthold Indian Reservation between 2015 and 2019. To fully resolve this matter, on July 10, 2024, we entered into a consent decree with the EPA and Department of Justice, which was entered by the court on September 17, 2024. The consent decree requires the completion of mitigation projects, implementation of specific injunctive relief and payment of a $65 million civil penalty, with substantially all of that civil penalty accrued in our quarterly report for the period ending March 31, 2024. In October 2024, we paid the $65 million civil penalty in full. In 2022, we began early implementation of the injunctive requirements, which are scheduled to be completed in 2025 for a total cost of approximately $177 million, over 70% of which has been incurred or included in the 2024 capital budget with the remaining amount to be spent by the end of 2025. The consent decree contains a detailed compliance schedule with deadlines for achievement of milestones through at least 2026 and requirements for ongoing permitting, inspection and monitoring, maintenance, auditing, and reporting. We do not admit liability regarding any of the allegations in the complaint associated with the consent decree and elected to resolve the allegations in a negotiated settlement rather than litigation.
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, 2024, 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 costs 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 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, 2024. 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.
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, Permian in New Mexico and Texas and STACK and SCOOP in Oklahoma. Our U.S. assets are complemented by our international operations in E.G. As shown in our 2023 Annual Report on Form 10-K, our Vision and Mission are supported by our Foundation and Values. We expect to achieve our Vision by adherence to a capital allocation framework that limits our capital expenditures relative to our expected cash flow from operations. We allocate capital to prioritize shareholder returns and per share growth, exercise discipline in reinvestment, retire outstanding debt and replenish inventory.
Proposed Merger
On May 28, 2024, we entered into the Merger Agreement with ConocoPhillips and Merger Sub. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Sub will be merged with and into Marathon Oil, with Marathon Oil surviving and continuing as the surviving corporation in the Merger as a direct, wholly owned subsidiary of ConocoPhillips. Under the terms of the Merger Agreement, at the Effective Time, each of our outstanding shares of common stock (other than certain Excluded Shares and Converted Shares) will be converted to the right to receive the Merger Consideration. The Merger Agreement also contains certain customary termination rights of each of Marathon Oil and ConocoPhillips, and under certain circumstances, a termination fee would be payable by us.
On July 11, 2024, Marathon Oil and ConocoPhillips each received a request for additional information and documentary materials (together, the “Second Request”) from the Federal Trade Commission (the “FTC”) in connection with the FTC’s review of the Merger. Issuance of the Second Request extends the waiting period imposed by the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended until 30 days after Marathon Oil and ConocoPhillips have substantially complied with the Second Request, unless that period is terminated sooner by the FTC. Marathon Oil and ConocoPhillips will continue to work cooperatively with the FTC in its review of the Merger.
On August 29, 2024, the Company’s stockholders approved and adopted the Merger Agreement at a special meeting of stockholders. Completion of the Merger remains subject to certain conditions, including certain governmental and regulatory approvals. The Merger is currently expected to close late in the fourth quarter of 2024; however, no assurance can be given as to when, or if, the Merger will occur.
In association with the Merger, for the three and nine months ended September 30, 2024, we have incurred transaction costs of $6 million and $16 million, respectively, which are recorded as general and administrative expense in the consolidated statements of income. We expect to incur additional costs as the Merger progresses. Transaction costs consist primarily of third party legal and banking fees.
If the Merger is consummated, Marathon Oil’s common stock will be delisted from the New York Stock Exchange and deregistered under the Exchange Act, and Marathon Oil will cease to be a publicly traded company.
Additionally, the Merger Agreement imposes restrictions on our business and operations during the pendency of the Merger. While we do not believe those restrictions are unduly burdensome, they may delay or prevent us from taking actions we could otherwise take. Accordingly, our results of operations from before the Merger Agreement may not be comparable to results of operations since we entered into the Merger Agreement. See Note 1 to the consolidated financial statements for additional information on the Merger and Part II, Item 1A. Risk Factors for a discussion of risks related to the Merger.
Financial and operational results
•Our net income was $287 million in the third quarter of 2024 as compared to net income of $453 million in the same period last year. Included in our financial results for the current quarter:
◦Revenue from contracts with customers in our US segment decreased $85 million in the third quarter of 2024 compared to the same period in 2023. The primary drivers of the decrease were lower crude and natural gas price realizations, partially offset by increased crude sales volumes.
◦In our International segment we realized revenue of $72 million in the third quarter of 2024 from shipments of LNG with global pricing linkage that began in 2024. Refer to Operations below for additional information.
◦Received EG dividend distribution and return of capital totaling $29 million.
◦Shipping, and handling and other operating, including related party expense and depreciation, depletion and amortization expense increased by $40 million and $44 million, respectively, in the third quarter of 2024 compared to the same period in 2023. The increase in shipping, handling and other operating, including related party expense was driven primarily by EG LNG processing LNG for a tolling fee and profit share, and an increase in purchases of commodity volumes for resale to satisfy transportation commitments. The increase in DD&A was driven by increased net sales volumes in our US segment during the quarter.
◦Provision for income taxes increased $52 million compared to the same quarter last year. The primary driver of the increase was a $75 million deferred tax valuation allowance recorded against foreign tax credits expiring in future periods, partially offset by lower income before income taxes. See Critical Accounting Estimatessection below and Note 6 to the consolidated financial statements for additional information.
•We reduced our long-term debt and commercial paper outstanding. During the third quarter of 2024, we redeemed $400 million of bonds outstanding. In addition, for the nine months ended September 30, 2024, we had $270 million in net repayments of commercial paper and as of September 30, 2024, we have $180 million in remaining outstanding commercial paper borrowings. See Cash Flows section below and Note 7to the consolidated financial statementsfor further information.
Outlook
Capital Budget
In February 2024, we announced a 2024 capital budget of $1.9 billion to $2.1 billion. The terms of the Merger Agreement restrict us from certain expansions to our capital budget.
Due to an increase in our production during the third quarter of 2024, we are raising the midpoint of our annual oil production guidance to 192 mbopd from our previously announced midpoint oil production guidance of 190 mbopd. In addition, we are raising the midpoint of our annual oil equivalent production guidance to 393 mboed from our previously announced midpoint oil equivalent production guidance of 390 mboed.
Operations
The following table presents a summary of our sales volumes for each of our segments. Refer toResults of Operationsfor a price-volume analysis for each of the segments:
The following tables provide additional details regarding net sales volumes, sales mix and operational drilling activity for our significant operations within this segment:
Three Months Ended September 30,
Nine Months Ended September 30,
Net Sales Volumes
2024
2023
Increase (Decrease)
2024
2023
Increase (Decrease)
Equivalent Barrels (mboed)
Eagle Ford
166
158
5
%
149
153
(3)
%
Bakken
115
121
(5)
%
109
108
1
%
Permian
56
42
33
%
50
43
16
%
Oklahoma
40
46
(13)
%
43
50
(14)
%
Other United States
2
2
—
%
2
2
—
%
Total United States
379
369
3
%
353
356
(1)
%
Three Months Ended September 30, 2024
Sales Mix - U.S. Resource Plays
Eagle Ford
Bakken
Permian
Oklahoma
Total
Crude oil and condensate
52
%
62
%
55
%
18
%
52
%
NGLs
25
%
23
%
24
%
32
%
25
%
Natural gas
23
%
15
%
21
%
50
%
23
%
Three Months Ended September 30,
Nine Months Ended September 30,
Drilling Activity - U.S. Resource Plays (a)
2024
2023
2024
2023
Gross Operated
Eagle Ford:
Wells drilled to total depth
23
18
105
83
Wells brought to sales
34
38
124
123
Bakken:
Wells drilled to total depth
22
19
66
64
Wells brought to sales
27
25
62
65
Permian:
Wells drilled to total depth
6
5
24
19
Wells brought to sales
9
9
34
25
Oklahoma:
Wells drilled to total depth
—
7
5
11
Wells brought to sales
13
4
13
9
(a)Includes drilling activity operated under joint development agreements where we have a working interest in the well.
International
In our International segment, we own interests in multiple facilities in E.G. This includes a 64% operated working interest in the Alba field, located offshore E.G., which is consolidated in our financial statements on a pro rata basis. We also own interests in several facilities onshore E.G. which are accounted for as equity method investments. This includes a 52% interest in Alba Plant LLC, which operates an LPG processing plant; a 56% interest in EG LNG, which operates a 3.7 mmta LNG production facility; and a 45% interest in AMPCO, which operates a methanol plant. For additional information on our interests and their operations, refer to Items 1. and 2. Business and Properties in our 2023 Annual Report on Form 10-K.
As described in Market Conditions, prior to 2024, we primarily sold natural gas to equity method investees via Gas Sales Agreements (GSA’s) in the form of feedstock for LNG and methanol production at long-term fixed prices. AMPCO markets methanol at market prices, and EG LNG marketed LNG on a market-based contract indexed to Henry Hub pricing. We also sell a certain amount of natural gas for local electricity generation at a long-term fixed price. Whereas the GSA with AMPCO continues into 2026, beginning January 1, 2024, the GSA to sell natural gas to EG LNG, and the contract for EG LNG to sell LNG indexed to Henry Hub pricing, expired and were replaced by a new series of agreements. The Alba field partners no longer sell natural gas under a GSA to EG LNG; instead, EG LNG earns a tolling fee to provide liquefaction, storage and product handling services as well as a profit share, and as an Alba partner, we now market our share of LNG to third parties indexed at global LNG prices. We also assume responsibility for shrink and plant losses during liquefaction, which results in lower reported net production and sales volumes, and we are subject to a lifting schedule for our equity LNG cargos, which may place us in an underlift/overlift position depending on timing. In our consolidated statements of income, our sales of LNG to third parties are included in revenues from contracts with customers. The fees payable to EG LNG are recorded as related party shipping, handling and other operating expense, and our share of this income earned by EG LNG is included in income from equity method investments. In addition to servicing the Alba field, EG LNG processes additional third-party gas from the Alen field under a combination of a tolling fee and profit-sharing arrangement, the benefits of which are also included in our respective share of income from equity method investments.
In 2024, our initial sales of LNG under this new contract occurred. For the three months ended September 30, 2024, our net sales volumes of LNG were 72 mmcfd, at an average realized price of $10.76 per mcf. We recorded $72 million in revenue for these sales, and incurred expense of $18 million to EG LNG for their services. We recorded $39 million in income from equity method investments for the period and International segment income of $95 million. We also held a positive balance of LNG inventory at quarter end, that was included in our October sales.
For the nine months ended September 30, 2024, our net sales volumes of LNG were 86 mmcfd, at the average realized price of $8.76 per mcf. We recorded $207 million in revenue for these sales, and incurred expense of $45 million to EG LNG for their services. We recorded $104 million in income from equity method investments for the period and International segment income of $256 million.
In 2024, due to the expected arbitrage between LNG and methanol pricing, we have chosen to optimize our E.G. integrated gas operations by redirecting a portion of Alba field natural gas from AMPCO to the LNG production facility operated by EG LNG.
The table below 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
2024
2023
Increase (Decrease)
2024
2023
Increase (Decrease)
Crude and oil condensate (mbbld)
9
11
(18)
%
9
10
(10)
%
NGLs (mbbld)
5
6
(17)
%
5
6
(17)
%
Natural gas, sold as gas (mmcfd)
66
217
(70)
%
75
212
(65)
%
Natural gas, sold as LNG (mmcfd)
72
—
—
%
86
—
—
%
Total natural gas (mmcfd)
138
217
(36)
%
161
212
(24)
%
Total International (mboed)
37
53
(30)
%
41
51
(20)
%
Equity Method Investees
LNG (mtd)(a)
—
1,670
(100)
%
129
1,831
(93)
%
Methanol (mtd)
674
1,208
(44)
%
854
1,210
(29)
%
Condensate and LPG (boed)
6,369
8,264
(23)
%
6,665
7,896
(16)
%
(a)LNG sales from equity method investees in 2024 represents final residual volumes sold under the contract terms in place prior to January 1, 2024.
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 and payment of dividends. Commodity prices experienced significant volatility in 2022 after the Russia/Ukraine conflict began and this has continued into 2024. Events in the Middle East have added further volatility to energy prices and the outlook for that region remains extremely uncertain. Further, uncertainty around Chinese demand continues to exacerbate volatility as sluggish demand is countered by reports of fiscal stimulus. Economic headwinds should diminish moving forward as inflation has moderated and interest rates have started to fall. We expect commodity price volatility to continue given the complex global dynamics of supply and demand that exist in the market. Refer to Item 1A. Risk Factors in our 2023 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 2024 and 2023:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Increase (Decrease)
2024
2023
Increase (Decrease)
Average Price Realizations(a)
Crude oil and condensate (per bbl)
$
73.92
$
80.90
(9)
%
$
76.08
$
76.13
—
%
NGLs (per bbl)
20.40
21.37
(5)
%
21.20
21.29
—
%
Natural gas (per mcf)
1.45
2.28
(36)
%
1.61
2.38
(32)
%
Benchmarks
WTI crude oil average of daily prices (per bbl)
$
75.27
$
82.22
(8)
%
$
77.61
$
77.28
—
%
Magellan East Houston (“MEH”) crude oil average of daily prices (per bbl)
77.36
84.00
(8)
%
79.72
76.14
5
%
Mont Belvieu NGLs (per bbl)(b)
21.37
23.13
(8)
%
22.63
22.99
(2)
%
Henry Hub natural gas settlement date average (per mmbtu)
2.16
2.55
(15)
%
2.10
2.69
(22)
%
(a)Excludes gains or losses on commodity derivative instruments.
(b)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.
NGLs – 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.
The following table presents our average price realizations and the related benchmark for crude oil and natural gas for the third quarter and first nine months of 2024 and 2023:
Three Months Ended September 30,
Nine Months Ended September 30,
2024
2023
Increase (Decrease)
2024
2023
Increase (Decrease)
Average Price Realizations
Crude oil and condensate (per bbl)
$
61.68
$
64.30
(4)
%
$
60.83
$
59.33
3
%
NGLs (per bbl)
1.00
1.00
—
%
1.00
1.00
—
%
Natural gas, sold as gas (per mcf)
0.24
0.24
—
%
0.24
0.24
—
%
Natural gas, sold as LNG (per mcf)
10.76
—
—
%
8.76
—
—
%
Average total natural gas (per mcf)
5.75
$
0.24
2,296
%
4.79
0.24
1,896
%
Benchmark
Brent (Europe) crude oil (per bbl) (a)
$
79.84
$
86.66
(8)
%
$
82.05
$
82.05
—
%
TTF (Europe) natural gas (per mmbtu) (b)
11.51
10.80
7
%
10.12
12.93
(22)
%
JKM (East Asia) natural gas (per mmbtu) (c)
13.17
12.57
5
%
11.29
13.85
(18)
%
(a)Average of monthly prices obtained from the United States Energy Information Agency website.
(b)Average of monthly prices obtained from NYMEX Exchange (expressed in $).
(c)Average of monthly prices obtained from Tokyo Commodity Exchange (expressed in $).
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 to AMPCO and EG LNG.
NGLs –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 – Prior to 2024, dry natural gas, processed by Alba Plant LLC on behalf of the Alba Unit Parties, was sold by the Alba field to our equity method investees EG LNG and AMPCO at fixed-price contracts resulting in realized prices not tracking market price. EG LNG marketed LNG on a market-based contract and AMPCO markets methanol at market prices. The gas sales contract between Alba Unit and EG LNG expired on December 31, 2023. The gas sales contract with AMPCO expires in 2026.
In March 2023, we announced the signing of a Heads of Agreement (“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 was 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, we have entered into an agreement to sell the remainder of our 2024 LNG volumes under a contract linked to the Japan/Korea Marker (“JKM”).
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 additional exposure to global LNG market prices.
Three Months Ended September 30, 2024 vs. Three Months Ended September 30, 2023
Revenues from contracts with customersare presented by segment in the table below:
Three Months Ended September 30,
(In millions)
2024
2023
Revenues from contracts with customers
United States
$
1,615
$
1,700
International
126
71
Segment revenues from contracts with customers
$
1,741
$
1,771
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, 2023
Price Realizations
Net Sales Volumes
Three Months Ended September 30, 2024
United States Price/Volume Analysis
Crude oil and condensate
$
1,408
$
(127)
$
69
$
1,350
NGLs
177
(8)
8
177
Natural gas
112
(39)
(4)
69
Other sales(a)
3
19
Total
$
1,700
$
1,615
International Price/Volume Analysis
Crude oil and condensate
$
64
$
(2)
$
(9)
$
53
NGLs
1
(1)
—
—
Natural gas, sold as gas
5
—
(4)
1
Natural gas, sold as LNG
—
72
—
72
Natural gas
5
72
(4)
73
Other sales
1
—
Total
$
71
$
126
(a)Includes revenue from commodity volumes purchased for resale.
Net gain on commodity derivatives in the third quarter of 2024 was $9 million, compared to a net gain of $1 million for the same period in 2023. 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. SeeNote 8 to the consolidated financial statements for further information.
Production expenseincreased $31 million in the third quarter of 2024, when compared to the same period in 2023, primarily due to increased workover activities in our U.S. segment and increased costs associated with higher net sales volumes in our U.S. segment.
The following table provides production expense and production expense rates for each segment:
Shipping, handling and other operating increased $40 million in the third quarter of 2024 when compared to the same period in 2023, due to increases in purchases of commodity volumes for resale to satisfy transportation commitments and increases in related party shipping, handling and other operating expense due to the new agreement that became effective in January 2024, whereby EG LNG processes LNG for a tolling fee and profit share.
Depreciation, depletion and amortization
Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore volumes have an impact on DD&A expense. The following table provides DD&A expense and DD&A expense rates for each segment:
Three Months Ended September 30,
($ in millions; rate in $ per boe)
2024
2023
Increase (Decrease)
2024
2023
Increase (Decrease)
DD&A Expense and Rate
Expense
Rate
United States
$
611
$
570
7
%
$
17.51
$
16.74
5
%
International
$
11
$
12
(8)
%
$
2.82
$
2.39
18
%
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 $14 million in the third quarter of 2024 primarily due to lower sales revenue in our U.S. segment, when compared to the same period in 2023.
General and administrative expensesincreased$16 million in the third quarter of 2024 primarily due to increases in legal service expenses associated with the Merger, and an increase in the annual employee bonus accrual estimated to payout at the maximum percentage as a result of the Merger.
Net interest and other decreased $17 million in the third quarter of 2024 primarily due to the full repayment of the remaining outstanding borrowings of $1.2 billion on the Term Loan Facility in the first quarter of 2024 and the subsequent issuance of our 2029 Notes and 2034 Notes at lower interest rates. See Note 7 to the consolidated financial statements for further information.
Provision for income taxes increased $52 million in the third quarter of 2024 primarily due to a $75 million deferred tax valuation allowance against foreign tax credits expiring in future periods, partially offset by a decrease in income before income taxes for the current quarter when compared to the same period in 2023. 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:
Three Months Ended September 30,
(In millions)
2024
2023
United States
$
362
$
505
International
95
62
Segment income
457
567
Items not allocated to segments, net of income taxes
(170)
(114)
Net income
$
287
$
453
United States segment income in the third quarter of 2024 was$362 million of income versus $505 million of income for the same period in 2023. The decrease in segment income is a result of the variances described above.
International segment income in the third quarter of 2024 was$95 million of income versus $62 million of income for the same period in 2023. The increasewas primarily due to increased revenue from new LNG sales indexed to global prices, partially offset by increased provision for income taxes as a result of increased revenue, and increased shipping and handling costs associated with LNG processing and liquefaction.
Items not allocated to segments, net of income taxes in the third quarter of 2024 was a loss of $170 million versus a loss of $114 million for the same period in 2023. The increase in loss was primarily due to an increased provision for income taxes due to a $75 million valuation allowance booked in the third quarter of 2024 and variances in general and administrative expense described above. The increase in loss was partially offset by decreases in net interest and other, described above, and a net unrealized gain on commodity derivatives in the third quarter of 2024, when compared to the same period in 2023.
Results of Operations
Nine Months Ended September 30, 2024 vs. Nine Months Ended September 30, 2023
Revenues from contracts with customers are presented by segment in the table below:
Nine Months Ended September 30,
(In millions)
2024
2023
Revenues from contracts with customers
United States
$
4,588
$
4,643
International
357
179
Segment revenues from contracts with customers
$
4,945
$
4,822
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, 2023
Price Realizations
Net Sales Volumes
Nine Months Ended September 30, 2024
United States Price/Volume Analysis
Crude oil and condensate
$
3,788
$
(2)
$
60
$
3,846
NGLs
502
(2)
(9)
491
Natural gas
337
(106)
(11)
220
Other sales(a)
16
31
Total
$
4,643
$
4,588
International Price/Volume Analysis
Crude oil and condensate
$
160
$
3
$
(21)
$
142
NGLs
2
—
(1)
1
Natural gas, sold as gas
14
—
(9)
5
Natural gas, sold as LNG
—
207
—
207
Natural gas
14
207
(9)
212
Other sales
3
2
Total
$
179
$
357
(a)Includes revenue from commodity volumes purchased for resale.
Net gain (loss) on commodity derivatives in the first nine months of 2024 was a net loss of $14 million, compared to a net gain of $19 million for the same period in 2023. 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. SeeNote 8 to the consolidated financial statements for further information.
Income from equity method investmentsdecreased $36 million for the first nine months of 2024, primarily due to decreased revenue as EG LNG no longer markets LNG directly as a result of the new agreement that became effective in January 2024, in addition to lower sales volume by our equity method investees during the first nine months of 2024.
Other income for the first nine months of 2024 decreased by $15 million compared to the same period in 2023, primarily due to fair value adjustments on liabilities assumed from acquisitions.
Production expenses for the first nine months of 2024 increased by $53 million compared to the same period in 2023, primarily due to increased workover activities in our U.S segment.
The following table provides production expense and production expense rates for each segment:
Nine Months Ended September 30,
($ in millions; rate in $ per boe)
2024
2023
Increase (Decrease)
2024
2023
Increase (Decrease)
Production Expense and Rate
Expense
Rate
United States
$
608
$
542
12
%
$
6.30
$
5.58
13
%
International
$
52
$
65
(20)
%
$
4.60
$
4.69
(2)
%
Shipping, handling and other operating expenses increased $61 million in the first nine months of 2024, when compared to the same period in 2023, due to increased shipping and handling expenses as a result of the new agreement that became effective in January 2024, whereby EG LNG no longer markets LNG directly but instead processes LNG for a tolling fee and profit share which we record as related party shipping, handling and other operating expense.
Exploration expensesinclude unproved property impairments, dry well costs, geological and geophysical and other costs. In the first nine months of 2024, exploration expenses decreased $16 million when compared to the same period in 2023, primarily due to decreases in impairments of unproved leases and decreases in dry well expense in Permian. See Note 5 to the consolidated financial statements for further information.
Depreciation, depletion and amortization
Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs; therefore volumes have an impact on DD&A expense. The following table provides DD&A expense and DD&A expense rates for each segment:
Nine Months Ended September 30,
($ in millions; rate in $ per boe)
2024
2023
Increase (Decrease)
2024
2023
Increase (Decrease)
DD&A Expense and Rate
Expense
Rate
United States
$
1,673
$
1,622
3
%
$
17.32
$
16.70
4
%
International
$
31
$
34
(9)
%
$
2.74
$
2.40
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 increased $47 million in the first nine months of 2024 primarily due to a nonrecurring Eagle Ford severance tax refund of $47 million related to prior years recorded in the first nine months of 2023.
General and administrative expenses increased$48 million in the first nine months of 2024, primarily due to increases in legal service expenses associated with the Merger, and an increase in the annual employee bonus accrual estimated to payout at the maximum percentage as a result of the Merger.
Net interest and other decreased $42 million in the first nine months of 2024 primarily due to the repayment of $300 million of the outstanding borrowings on the Term Loan Facility in the fourth quarter of 2023, the full repayment of the remaining outstanding borrowings of $1.2 billion on the Term Loan Facility in the first quarter of 2024 and the subsequent issuance of our 2029 Notes and 2034 Notes at lower interest rates. Additionally, beginning in the third quarter of 2023, we transitioned our credit facility borrowings to commercial paper borrowings at lower interest rates. See Note 7 to the consolidated financial statements for further information.
Provision for income taxes increased $46 million in the first nine months of 2024 primarily due to a $75 million deferred tax valuation allowance against foreign tax credits expiring in future periods, partially offset by a decrease in income before income taxes for the first nine months of 2024 when compared to the same period in 2023. See Note 6 to the consolidated financial statements for further information.
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)
2024
2023
United States
$
1,075
$
1,295
International
256
181
Segment income
1,331
1,476
Items not allocated to segments, net of income taxes
(398)
(319)
Net income
$
933
$
1,157
United States segment income for the first nine months of 2024 was $1.1 billion of income versus $1.3 billion of income for the same period in 2023. The decrease in segment income is a result of the variances described above.
International segment income for the first nine months of 2024 was $256 million of income versus $181 million of income for the same period in 2023. The increase was primarily due to increased revenue from new LNG sales indexed to global prices, partially offset by increased income tax as a result of increased revenue, and increased shipping and handling costs associated with LNG processing and liquefaction.
Items not allocated to segments, net of income taxes for the first nine months of 2024 was $398 million of loss versus $319 million of loss for the same period in 2023. The increase in loss was primarily due to an increased provision for income taxes due to a $75 million valuation allowance booked in the first nine months of 2024 and variances in general and administrative expense described above. The increase in loss was partially offset by decreases in net interest and other and exploration expense, described above, in the first nine months of 2024 when compared to the same period in 2023.
Critical Accounting Estimates
Other than the item set forth below, there have been no other 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, 2023.
Income Taxes
We have recorded deferred tax assets and liabilities, measured at enacted tax rates, for temporary differences between book basis and tax basis, tax credit carryforwards and operating loss carryforwards. In accordance with U.S. GAAP, we routinely assess the realizability of our deferred tax assets and reduce such assets to the expected realizable amount by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for additional or adjustments to existing valuation allowances, we consider all available positive and negative evidence. Positive evidence includes reversals of temporary differences, forecasts of future taxable income, assessment of future business assumptions and applicable tax planning strategies that are prudent and feasible. Negative evidence includes losses in recent years, as well as the forecasts of future losses in the realizable period. In making our assessment regarding valuation allowances, we weigh the evidence based on objectivity.
We base our future taxable income estimates on projected financial information which we believe to be reasonably likely to occur. Numerous judgments and assumptions are inherent in the estimation of future taxable income, including factors such as future operating conditions and the assessment of the effects of foreign taxes on our U.S. federal income taxes. Future operating conditions can be affected by numerous factors, including (i) future prices for crude oil and condensate, NGLs and natural gas, including LNG, (ii) estimated quantities of crude oil and condensate, NGLs and natural gas, including LNG, (iii) expected timing of production, and (iv) future capital requirements. An estimate of the sensitivity to changes in assumptions resulting in future taxable income calculations is not practicable, given the numerous assumptions that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future taxable income would likely be partially offset by lower capital expenditures.
Based on the assumptions and judgments described above, during the third quarter of 2024, as a result of continued volatility in commodity prices and corresponding impacts to projections of future taxable income, we recorded a $75 million deferred tax valuation allowance against foreign tax credits expiring in future periods. We continue to assess whether the balance of the valuation allowance is appropriate on a quarterly basis particularly given the expiring nature of foreign tax credits in years 2025 through 2026. If we experience sustained lower commodity prices that impact the performance of future earnings, it is reasonably possible that within the next 12 months sufficient negative evidence may exist that will require us to establish additional valuation allowance on our deferred tax assets that we do not expect to realize. See Note 6 to the consolidated financial statements for further detail.
Cash Flows
The following table presents sources and uses of cash and cash equivalents:
Nine Months Ended September 30,
(In millions)
2024
2023
Sources of cash and cash equivalents
Net cash provided by operating activities
$
3,054
$
3,007
Borrowings
1,200
200
Proceeds from commercial paper borrowings, net
—
450
Proceeds from revolving credit facility
450
1,018
Equity method investments - return of capital
10
57
Other
11
—
Total sources of cash and cash equivalents
$
4,725
$
4,732
Uses of cash and cash equivalents
Capital expenditures
$
(1,726)
$
(1,673)
Change in capital accrual
44
14
Debt repayments
(1,600)
(401)
Repayments of revolving credit facility
(450)
(1,468)
Repayments of commercial paper borrowings, net
(270)
—
Shares repurchased under buyback programs
(516)
(1,121)
Dividends paid
(188)
(186)
Withholding tax on stock-based incentive awards
(19)
(31)
Acquisition, net of cash acquired
(4)
(15)
Other
(17)
(11)
Total uses of cash and cash equivalents
$
(4,746)
$
(4,892)
Sources of cash and cash equivalents
Cash flows generated from operating activities during the first nine months of 2024 were 2% higher compared to the same period in 2023, primarily due to a working capital inflow in the first nine months of 2024 compared to a working capital outflow during the same period in 2023, offset by lower net income during the first nine months of 2024 compared to the same period in 2023.
On March 28, 2024, we completed a public offering of $1.2 billion aggregate principal amount of unsecured senior notes (2029 Notes and 2034 Notes). Net proceeds received totaled approximately $1.2 billion and together with cash on hand were used to repay $1.2 billion outstanding borrowings under our Term Loan Facility. See Note 7to the consolidated financial statementsand Liquidity and Capital Resources section below for further information.
During the first nine months of 2024, we borrowed and repaid $450 million under our Revolving Credit Facility. However, as of September 30, 2024, we had nooutstanding borrowings under our Revolving Credit Facility. In addition, we utilize our commercial paper program to fund our short-term working capital requirements. During the first nine months of 2024, we had $270 million in net repayments of commercial paper and as of September 30, 2024, we have $180 million in remaining outstanding commercial paper borrowings see Note 7to the consolidated financial statements and Liquidity and Capital Resources section below for further information.
During the first nine months of 2024, we repurchased approximately 19 million shares of our common stock pursuant to the share repurchase program at a cost of $516 million and paid dividends of $188 million.
Additionally, during the first nine months of 2024, using short-term borrowings, we redeemed $400 million of our outstanding bonds that are part of the $1.0 billion Parish of St. John The Baptist, State of Louisiana Revenue Refunding Bonds (Marathon Oil Corporation Project) Series 2017. See Note 7to the consolidated financial statements and Liquidity and Capital Resources section below for further information.
The following table shows capital expenditures by segments:
Nine Months Ended September 30,
(In millions)
2024
2023
United States
$
1,712
$
1,661
International
7
3
Not allocated to segments
7
9
Total capital expenditures
$
1,726
$
1,673
Liquidity and Capital Resources
The following liquidity and capital resources discussion is qualified in its entirety by the limitations contained in the Merger Agreement. Under the Merger Agreement, we are subject to restrictions and limitations that, among other things, preclude us from assuming additional debt, issuing additional equity or debt, making certain capital expenditures and executing certain asset transactions, and entering certain merger, liquidation or disposition transactions. Upon completion of the Merger and on the closing date, we will terminate all commitments under our Revolving Credit Facility and repay in full all obligations, if any, with respect to our Revolving Credit Facility and commercial paper program.
Capital Resources and Available Liquidity
Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, capital market transactions, our Revolving Credit Facility and our commercial paper program. At September 30, 2024, we had approximately $2.5 billion of liquidity consisting of $134 million in cash and cash equivalents and $2.4 billion available under our Revolving Credit Facility. Under the Merger Agreement, however, we are not permitted to exceed an aggregate $1.5 billion in outstanding borrowings under our commercial paper program or Revolving Credit Facility except in emergency situations provided that we notify ConocoPhillips of any such borrowings as soon as reasonably practicable.
Our working capital requirements are supported by our cash and cash equivalents, our Revolving Credit Facility and our commercial paper program. Subject to certain restrictions in the Merger Agreement, 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 17 to the consolidated financial statements for further discussion of how our commitments and contingencies could affect our available liquidity. Additionally, we expect our available liquidity to be impacted by a number of non-recurring costs associated with the Merger Agreement including, among others, fees and expenses from financial advisors and other advisors and representatives, certain employment-related costs relating to employees of Marathon Oil and filing fees due in connection with required regulatory filings. Some of these costs have already been incurred or may be incurred regardless of whether the Merger is completed. Further, 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, 2023 for a discussion of how a downgrade in our credit ratings could affect us.
We may incur additional debt 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, 2023 for a further discussion of how our level of indebtedness could affect us.
Credit Arrangements and Borrowing Developments
On March 28, 2024, we completed a public offering of $1.2 billion aggregate principal amount of unsecured senior notes consisting of $600 million aggregate principal amount of 5.30% 2029 Notes and $600 million aggregate principal amount of 5.70% 2034 Notes. Interest on the senior notes is payable semi-annually beginning October 1, 2024. We may redeem some or all of the senior notes at any time at the applicable redemption price, plus accrued interest, if any. Net proceeds received totaled approximately $1.2 billion which were used together with cash on hand to repay $1.2 billion outstanding borrowings under our Term Loan Facility. See Note 7 to the consolidated financial statements for further information.
On July 1, 2024, using short-term borrowings, we purchased $200 million of our outstanding sub-series 2017 A-2 bonds and $200 million of our outstanding sub-series 2017 B-1 bonds that are part of the $1.0 billion Parish of St. John The Baptist, State of Louisiana Revenue Refunding Bonds (Marathon Oil Corporation Project) Series 2017. The $400 million of bonds due 2037 were purchased on their mandatory put date of July 1, 2024, for our own account and are subject to an interest rate of 4.125%. We have the right, subject to the consent of ConocoPhillips, to convert and remarket these bonds to the public at any time up to their June 1, 2037 maturity date.
As of September 30, 2024, we had $4.6 billion of total long-term debt outstanding. In addition, as of September 30, 2024, we had outstanding commercial paper borrowings of $180 million.
As of September 30, 2024, we had no outstanding borrowings under our Revolving Credit Facility. Our Revolving Credit Facility includes 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 22% at September 30, 2024. See Note 7 to the consolidated financial statements for further information.
Refer to our 2023 Annual Report on Form 10-K for a listing of our long-term debt maturities.
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 and certain restrictions in the Merger Agreement, 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, however, upon the announcement of the Merger Agreement, we suspended our stock repurchase activity as we are subject to certain restrictions to our ability to repurchase, redeem or otherwise acquire our capital stock. Our remaining authorization at September 30, 2024 was approximately $1.8 billion.
Dividends
On October 30, 2024, our Board of Directors approved a dividend of $0.11 per share payable December 10, 2024 to stockholders of record at the close of business on November 15, 2024. Pursuant to the terms of the Merger Agreement, we are prevented from increasing our quarterly per share dividend in excess of $0.11 per quarter.
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 are subject to the corporate book minimum tax in 2024. In September 2024, the IRS issued proposed regulations on the corporate book minimum tax. We have reviewed the proposed regulations and do not expect any material changes to our calculation for 2024. In addition, in September 2024, estimated tax payment relief for the 2024 corporate book minimum tax was granted through the end of the year. As further guidance is issued, we will continue to evaluate and assess the impact the IRA may have on our current and future period income taxes.
As of September 30, 2024, material changes to our contractual cash obligations compared to December 31, 2023 include the previously discussed addition of $1.2 billion in senior notes, the full repayment of $1.2 billion outstanding borrowings under our Term Loan Facility and the $400 million purchase of our outstanding bonds. In addition, we repaid $270 million of net outstanding commercial paper borrowings.
As described in Note 17 to the consolidated financial statements, we entered into a consent decree with the EPA and Department of Justice that included a civil penalty of $65 million, which was paid in full in October 2024.
Additionally, future contractual cash obligations may include liabilities in connection with the Merger Agreement. Certain costs may be incurred even if the Merger is not consummated.
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 2023 Annual Report on Form 10-K.
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 of 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 2023 Annual Report on Form 10-K. See Note 17 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, as amended (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, expectations with respect to the consent decree with the EPA and Department of Justice and statements regarding management’s other plans and objectives for future operations, are forward-looking statements. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipates,” “believes,” “continue,” “could,” “estimates,” “expects,” “forecast,” “future,” “guidance,” “intend,” “may,” “outlook,” “plans,” “positioned,” “projects,” “seek,” “should,” “targets,” “will,” “would” or similar words indicating that future outcomes are uncertain. 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, including liquified 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;
•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;
•unforeseen hazards such as weather conditions, a health pandemic, 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;
•changes in safety, health, environmental, tax, currency and other regulations, or requirements or initiatives including those addressing the impact of global climate change, air emissions or water management;
•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 assets we acquire do not perform consistent with our expectations, including with respect to future production or drilling inventory;
•other geological, operating and economic considerations;
•risks and uncertainties associated with the proposed Merger with ConocoPhillips, including the following:
◦ConocoPhillips’ ability to successfully integrate Marathon Oil’s businesses and technologies, which may result in the combined company not operating as effectively and efficiently as expected; the risk that the expected benefits and synergies of the Merger may not be fully achieved in a timely manner, or at all;
◦the risk that ConocoPhillips or Marathon Oil will be unable to retain and hire key personnel and maintain relationships with their suppliers and customers; the risk associated with the timing of the closing of the Merger, including the risk that the conditions to the Merger are not satisfied on a timely basis or at all or the failure of the Merger to close for any other reason or to close on the anticipated terms, including the anticipated tax treatment;
◦the risk that any regulatory approval, consent or authorization that may be required for the Merger is not obtained or is obtained subject to conditions that are not anticipated; the occurrence of any event, change or other circumstance that could give rise to the termination of the Merger;
◦unanticipated difficulties, liabilities or expenditures relating to the Merger;
◦the effect of the pendency or completion of the Merger on the parties’ business relationships and business operations generally;
◦the effect of the pendency of the Merger on the parties’ common stock prices and uncertainty as to the long-term value of ConocoPhillips’ or Marathon Oil’s common stock;
◦risks that the Merger disrupts current plans and operations of ConocoPhillips or Marathon Oil and their respective management teams and potential difficulties in hiring or retaining employees as a result of the Merger; and
•the risk factors, forward-looking statements and challenges and uncertainties described in our 2023 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. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.
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. However, under the Merger Agreement, we are subject to limitations on our ability to enter into new derivative transactions, which may prevent us from using financial derivatives to manage the risks related to commodity price and interest rate fluctuations.
See Note 8 and Note 9 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, 2024, we had open commodity derivatives related to crude oil and natural gas. Based on the September 30, 2024 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, 2024
Hypothetical Price Increase of 10%
Hypothetical Price Decrease of 10%
Derivative asset - Crude Oil
$
8
$
1
$
26
Derivative asset (liability) - Natural Gas
2
(3)
7
Total
$
10
$
(2)
$
33
Interest Rate Risk
At September 30, 2024, our portfolio of current and long-term debt is comprised of floating rate debt and fixed-rate instruments. Our Revolving Credit Facility and commercial paper borrowings are floating rate debt instruments, 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, 2024, we had no outstanding balance under our Revolving Credit Facility and $180 million outstanding borrowings under our commercial paper program. Assuming no change in the amount of floating rate debt outstanding, a hypothetical 100 basis point increase in the average interest rate under our commercial paper borrowings would have increased our annual interest expense by approximately$2 million. Actual results may vary due to changes in the amount of floating rate debt outstanding.
At September 30, 2024, we had $4.6 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, 2024, 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, 2024:
(In millions)
Fair Value at
September 30, 2024
Hypothetical Interest Rate Increase of 10%
Hypothetical Interest Rate Decrease of 10%
Interest rate asset - designated as cash flow hedges
$
11
$
13
$
9
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, 2024.
During the third quarter of 2024, 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.
We received Notices of Violation (“NOVs”) from the Environmental Protection Agency (the “EPA”) related to alleged violations of the Clean Air Act with respect to our operations on the Fort Berthold Indian Reservation between 2015 and 2019. To fully resolve this matter, on July 10, 2024, we entered into a consent decree with the EPA and Department of Justice, which was entered by the court on September 17, 2024. The consent decree requires the completion of mitigation projects, implementation of specific injunctive relief, and payment of a $65 million civil penalty, with substantially all of that civil penalty accrued in our quarterly report for the period ending March 31, 2024. In October 2024, we paid the $65 million civil penalty in full. In 2022, we began early implementation of the injunctive requirements, which are scheduled to be completed in 2025 for a total cost of approximately $177 million, over 70% of which has been incurred or included in the 2024 capital budget with the remaining amount to be spent by the end of 2025. The consent decree contains a detailed compliance schedule with deadlines for achievement of milestones through at least 2026 and requirements for ongoing permitting, inspection and monitoring, maintenance, auditing, and reporting. We do not admit liability regarding any of the allegations in the complaint associated with the consent decree and elected to resolve the allegations in a negotiated settlement rather than litigation. We do not believe that the mitigation expenditures, penalties, and injunctive relief that resulted from this settlement will have a material adverse effect on either our business or operations or the previously announced Merger Agreement with ConocoPhillips.
Other than the items set forth above, there have been no significant changes to Item 3. Legal Proceedings in our 2023 Annual Report on Form 10-K. See Note 17 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 2023 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 2023 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarter ended June 30, 2024 (“Q2 2024 Quarterly Report”). There have been no material changes or updates to the risk factors previously disclosed in our 2023 Annual Report on Form 10-K or Q2 2024 Quarterly Report.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Our Board of Directors has authorized a share repurchase program. Refer to our 2023 Annual Report on Form 10-K for historical share repurchase program authorizations and repurchase activity through December 31, 2023.
As of September 30, 2024, we have approximately $1.8 billion of authorization remaining under the share repurchase program. There were no shares of our common stock repurchased during the three months ended September 30, 2024. Upon the announcement of the Merger Agreement, we suspended our stock repurchase activity as we are subject to certain restrictions to our ability to repurchase, redeem or otherwise acquire our capital stock.
Item 5. Other Information
During the three months ended September 30, 2024, 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.
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
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XBRL Taxonomy Extension Calculation Linkbase
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XBRL Taxonomy Extension Definition Linkbase
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XBRL Taxonomy Extension Label Linkbase
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XBRL Taxonomy Extension Presentation Linkbase
104*
Cover Page Interactive Data File, formatted in iXBRL and contained in Exhibit 101
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Filed herewith.
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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.
45
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 6, 2024
MARATHON OIL CORPORATION
By:
/s/ Zach B. Dailey
Zach B. Dailey
Vice President, Controller and Chief Accounting Officer
