What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-02-17 compared with 2025-02-18 · 249 added, 290 removed, 792 unchanged (40% of the section changed)

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Headquartered in Houston, Texas, at December 31, 2025, we employed approximately 9,900 people worldwide and had total assets of $122 billion.

Completed Acquisition of Marathon Oil Corporation

On November 22, 2024, we completed our acquisition of Marathon Oil, an independent oil and gas exploration and production company.

The acquisition adds high-quality, low cost of supply, development opportunities to our existing Lower 48 portfolio and additional LNG capacity to our global LNG portfolio through Equatorial Guinea.

At closing, the acquisition was valued at approximately $16.5 billion, in which 0.255 shares of ConocoPhillips common stock was exchanged for each outstanding share of Marathon Oil common stock, resulting in the issuance of approximately 143 million shares of ConocoPhillips common stock.

We also assumed $4.6 billion in aggregate principal amount of outstanding debt for Marathon Oil, which was recorded at fair value of $4.7 billion as of the closing date.

We expect to capture approximately $1 billion in synergies on a run rate basis within the first full year following the close of the transaction.

See Note 3 and Note 8.

At ConocoPhillips, we anticipate that commodity prices will continue to be cyclical and volatile, and our view is that a successful business strategy in the E&P industry must be resilient in lower price environments while also retaining upside during periods of higher prices.

As such, we are unhedged, remain committed to our disciplined investment framework and continually monitor market fundamentals, including the impacts associated with geopolitical tensions and conflicts, global demand for our products, oil and gas inventory levels, governmental policies, inflation and supply chain disruptions.

The macro-environment of the global energy industry continues to evolve.

Throughout 2025, the price of crude oil has been volatile due to multiple macroeconomic and geopolitical forces which slowed global oil demand growth concurrent with higher oil production from OPEC Plus and other major oil producing countries.

We continue to closely monitor the macroeconomic environment, including any impacts from tariffs, and the ongoing market volatility in the energy landscape and across global markets for implications to our business, results of operations and financial condition.

As the global energy industry continues to evolve, we remain committed to creating long-term value for our stockholders.

We believe ConocoPhillips plays an essential role in responsibly meeting the global demand for energy, while continuing to deliver competitive returns on and of capital and working to meet our previously established emissions-reduction targets.

We call this our Triple Mandate, and it represents our commitment to create long-term value for stockholders.

Our value proposition to deliver competitive returns to stockholders through price cycles is guided by our foundational principles, which consist of maintaining balance sheet strength, providing peer-leading distributions, making disciplined investments, and demonstrating responsible and reliable ESG performance.

ConocoPhillips 2024 10-K

Management’s Discussion and Analysis

Total company production in 2025 was 2,375 MBOED, yielding cash provided by operating activities of $19.8 billion.

We invested $12.1 billion into the business in the form of capital expenditures and investments, inclusive of $0.4 billion of spend related to fourth-quarter acquisitions, and provided returns of capital to shareholders of $9.1 billion through our ordinary dividend, VROC and share repurchases.

In 2024, we returned $3.6 billion through the ordinary dividend and VROC, including in December when we increased our ordinary dividend by 34 percent to 78 cents per share, effectively incorporating the amount of the prior quarter VROC into the ordinary dividend.

We invested $12.6 billion into the business in the form of capital expenditures and investments and provided returns of capital to shareholders of $9.0 billion through our ordinary dividend and share repurchases.

In 2025, we returned $4.0 billion through the ordinary dividend, inclusive of an increase in December of eight percent to 84 cents per share.

In addition, we returned $5.0 billion to shareholders through share repurchases.

As of December 31, 2024, we have repurchased $34.3 billion of our authorized share repurchase program since 2016.

In February 2025, we announced our 2025 planned return of capital to shareholders of $10 billion, at current commodity prices, through our return of capital framework.

We also declared a first-quarter ordinary dividend of 78 cents per share.

In 2024, we continued to optimize our portfolio geared towards our return focused value proposition.

In the third quarter, we added to our global LNG portfolio through agreements that provide additional access to European and Asian natural gas markets by entering into an 18-year agreement securing regasification capacity at Zeebrugge LNG terminal in Belgium which includes regasification services for approximately 0.75 MTPA of LNG beginning in 2027.

Additionally, in the third quarter, we entered into a long-term LNG sales agreement for approximately 0.5 MTPA into Asia starting in 2027.

After exercising our preferential rights, we completed our acquisition of additional working interest in the Kuparuk River Unit and Prudhoe Bay Unit in our Alaska segment in the fourth quarter of 2024.

In conjunction with the announcement of our acquisition of Marathon Oil, we communicated a disposition target of approximately $2 billion of assets across the portfolio.

We recently entered into agreements to sell noncore assets within our Lower 48 segments that are expected to close in the first half of 2025 for approximately $600 million, subject to customary closing adjustments.

In the fourth quarter of 2024, we completed strategic debt transactions, which simplified our capital structure, extended the debt portfolio's weighted average maturity, lowered its weighted average coupon and reduced near-term maturities.

See Note 3 and Note 8 .

Operationally, we remain focused on safely executing the business.

Production for 2024 was 1,987 MBOED, representing an increase of 161 MBOED or nine percent compared to 2023.

After adjusting for closed acquisitions and dispositions, production increased by 69 MBOED or three percent.

Our Lower 48 segment achieved record production of 1,152 MBOED in 2024.

Our international projects reached several key operational milestones;

including first production ahead of schedule at Eldfisk North in Norway, Nuna in Alaska and Bohai Bay in China;

and we celebrated the one thousandth cargo lift at both APLNG and Bohai Bay in China.

As of December 31, 2025, we have repurchased $39.3 billion of shares of our authorized share repurchase program since 2016.

In February 2026, we declared a first-quarter ordinary dividend of 84 cents per share.

ConocoPhillips 2025 10-K

Management’s Discussion and Analysis

In November 2024, we completed our acquisition of Marathon Oil.

In the first half of 2025, we completed the asset integration of Marathon Oil and by year-end 2025 achieved more than $1 billion of synergies on a run-rate basis and approximately $1 billion of one-time benefits.

These one-time benefits include $0.5 billion recognized previously upon close of the transaction related to the utilization of foreign tax credits, with the remainder related to cash tax benefits from net operating losses, most of which was recognized in 2025.

Separately, in the second half of 2025, we announced incremental cost reductions and margin enhancements of more than $1 billion anticipated on a run-rate basis by year-end 2026.

In late 2025, we initiated a restructuring, reducing our overall employee workforce, which in addition to lease operating cost improvements and opportunities in transportation and processing is expected to contribute approximately $0.8 billion in cost reductions.

We anticipate the remaining approximately $0.2 billion to be achieved through margin expansion.

In August 2025, we announced a total disposition target of $5 billion by year-end 2026.

We disposed of $3.2 billion of assets in 2025 and we expect to meet our $5 billion disposition target by year-end 2026.

Completed dispositions to date include the Ursa and Europa fields and Ursa Oil Pipeline Company LLC for net proceeds of $0.7 billion, the Anadarko Basin for net proceeds of $1.2 billion and other noncore Lower 48 and Corporate assets for approximately $1.3 billion.

As part of our LNG strategy to build a dynamic portfolio and expand our footprint across the value chain, we have various commercial LNG offtake agreements in North America totaling 10.2 MTPA with offtake commencing between 2026-2031.

Furthermore, we currently have a total regasification capacity in Europe of approximately 6.7 MTPA.

We continue to progress discussions across all major LNG producing and consuming regions and markets to further add high-quality positions to our portfolio.

Operationally, we remain focused on safely executing the business while also progressing key strategic initiatives.

At Willow, we made significant progress and achieved critical milestones, successfully completing our largest winter season.

In the Lower 48, we integrated Marathon Oil assets into our portfolio, focusing on operating and capital efficiencies.

Internationally, we became the sole operator of the Kebabangan Cluster (KBBC) PSC in Malaysia in January 2025, extending the PSC to 2050 and making KBBC our first operated producing asset in Malaysia.

In Canada, we achieved first oil at Surmont Pad 104W-A in December 2025.

Additionally, our equity LNG projects continued to advance at NFE and NFS in Qatar and PALNG on the U.S.

The relevant provisions of the One Big Beautiful Bill Act (OBBBA), enacted on July 4, 2025, were implemented during the third quarter of 2025.

While OBBBA did not have a material effect on our effective tax rate for the quarter, the changes introduced by the legislation impacted our current and deferred tax calculations, with approximately $0.4 billion cash tax benefit recognized in 2025.

Production for 2025 was 2,375 MBOED, representing an increase of 388 MBOED or 20 percent compared to 2024.

After adjusting for closed acquisitions and dispositions, production increased by 57 MBOED or 2.5 percent.

ConocoPhillips 2025 10-K

Management’s Discussion and Analysis

Business Environment

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We strive to maintain our ‘A’-rating, as we did throughout 2025.

In 2024, we initiated and completed strategic debt transactions to extend the weighted average maturity of our portfolio and reduce near-term debt maturities.

In 2025, the company retired $0.7 billion principal amount of debt at maturity.

We ended the year with cash and cash equivalents and restricted cash of $6.9 billion, short-term investments of $0.5 billion and long-term investments in debt securities of $1.1 billion, maintaining balance sheet strength.

Peer-leading distributions.

We believe in delivering value to our shareholders via our return of capital framework, which consists of a growing, sustainable ordinary dividend, share repurchases and the discretion to utilize VROC in an elevated price environment.

We believe in delivering value to our shareholders via our return of capital framework, which consists of a growing, sustainable ordinary dividend and share repurchases.

This framework is how we plan to return greater than 30 percent of our net cash provided by operating activities to shareholders.

In 2024, we returned $3.6 billion to shareholders through our ordinary dividend and VROC and $5.5 billion through share repurchases.

In 2025, we returned $4.0 billion to shareholders through our ordinary dividend and $5.0 billion through share repurchases.

Our combined dividends and share repurchases of $9.0 billion represented 46 percent of our net cash provided by operating activities.

In February 2025, we announced our 2025 planned return of capital to shareholders of $10 billion, at current commodity prices, through our return of capital framework.

ConocoPhillips 2024 10-K

Management’s Discussion and Analysis

Disciplined investments.

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As we consider our capital investment opportunities, we apply a rigorous framework that we believe allows for competitive free cash flow to be available to return to shareholders.

By allocating to our low cost of supply resource base, we are allocating to high return assets and driving resiliency to low prices.

We believe allocating capital based on low cost of supply resource base will result in higher returns and drive resiliency through low prices.

We also balance our investments between short- and longer-cycle projects.

For example, in 2024, we invested in short-cycle projects in the Lower 48 segment, as well as longer-cycle projects such as Willow in Alaska and LNG projects in Qatar and Port Arthur.

For example, in 2025, we continued to invest in short-cycle projects in the Lower 48 segment, as well as longer-cycle projects such as Willow in Alaska.

This capital allocation framework seeks to maximize free cash flow through price cycles.

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Managing costs is critical to maintaining a competitive position in our cyclical industry and positively impacts our ability to deliver strong cash from operations.

In the second half of 2025, we announced incremental cost reductions and margin enhancements of more than $1 billion anticipated on a run-rate basis by year-end 2026.

In late 2025, we initiated a restructuring, reducing our overall employee workforce, which in addition to lease operating cost improvements and opportunities in transportation and processing, is expected to contribute approximately $0.8 billion in cost reductions.

We anticipate the remaining approximately $0.2 billion to be achieved through margin expansion.

• Optimize our portfolio.

We continue to evaluate our assets to determine whether they compete for capital within our portfolio and optimize as necessary, directing capital towards the most competitive investments and disposing of assets that do not compete.

In 2024, we completed our acquisition of Marathon Oil and additional working interest in Alaska, as well as signed additional LNG regasification and sales agreements.

In 2024, we also signed an agreement to divest certain noncore assets in our Lower 48 segment.

We continually evaluate our assets to determine whether they compete for capital within our portfolio and optimize as necessary, directing capital towards the most competitive investments and disposing of assets that do not compete.

In 2025, we divested assets in Lower 48 including the Ursa and Europa fields and Ursa Oil Pipeline Company LLC, assets in the Anadarko basin and other noncore assets.

ConocoPhillips 2025 10-K

Management’s Discussion and Analysis

• Add to our proved reserve base.

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Reserve replacement represents the net change in proved reserves, net of production, divided by our current year production.

Our reserve replacement was 244 percent in 2024, reflecting a net increase from development drilling activity;

extensions and discoveries;

and purchases, including our acquisition of Marathon Oil;

partially offset by lower prices.

Our organic reserve replacement, which excludes a net increase of 886 MMBOE from sales and purchases, was 123 percent in 2024.

Our reserve replacement was 80 percent in 2025, reflecting a net decrease from dispositions in noncore assets in Lower 48 and lower prices, partially offset by development drilling activity and extensions and discoveries.

Our organic reserve replacement, which excludes a net decrease of 165 MMBOE from sales and purchases, was 99 percent in 2025.

In the three years ended December 31, 2025, our reserve replacement was 145 percent.

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Commodity Prices

Our earnings and operating cash flows generally correlate with crude oil and natural gas commodity prices.

Commodity price levels are subject to factors external to the company and over which we have no control, including but not limited to global economic health, supply or demand disruptions or fears thereof caused by civil unrest, global pandemics, military conflicts, actions taken by OPEC Plus and other major oil producing countries, environmental laws, tax regulations, governmental policies and weather-related disruptions.

The following graph depicts the average benchmark prices for WTI crude oil, Brent crude oil and U.S.

Commodity prices and the associated realizations are the most significant factor impacting our profitability and related returns on and of capital to our shareholders.

Dynamics that could influence world energy markets and commodity prices include, but are not limited to, global economic health, supply or demand disruptions or fears thereof caused by civil unrest, global pandemics, military conflicts, actions taken by OPEC Plus and other major oil producing countries, environmental laws, tariffs, governmental policies and weather-related disruptions.

Our strategy is to create value through price cycles by delivering on the financial, operational and ESG priorities that underpin our value proposition.

Our earnings and operating cash flows generally correlate with price levels for crude oil and natural gas, which are subject to factors external to the company and over which we have no control.

The following graph depicts the trend in average benchmark prices for WTI crude oil, Brent crude oil and U.S.

Henry Hub natural gas since 2023.

Brent crude oil prices decreased two percent from $82.62 per barrel in 2023 to $80.76 per barrel in 2024.

Similarly, average WTI crude oil prices decreased two percent from $77.62 per barrel in 2023 to $75.72 per barrel in 2024.

Prices were lower through 2024 due to slower global demand growth in 2024 relative to 2023 and higher supplies from non-OPEC Plus counties.

Henry Hub natural gas prices decreased 17 percent from an average of $2.74 per MMBTU in 2023 to $2.27 per MMBTU in 2024.

Natural gas prices decreased due to excess North American natural gas storage levels following a mild 2023-2024 winter.

Lower 48 segment realized gas prices decreased to $0.18 in the third quarter of 2024 driven by lower regional prices related to pipeline capacity constraints.

In the fourth quarter of 2024 prices increased as constraints were relieved and realizations ended the year at an average of $0.87.

Our realized bitumen price increased 14 percent from an average of $42.15 per barrel in 2023 to $47.92 per barrel in 2024.

The increase was driven by narrowing WCS differentials due to Trans Mountain Expansion project egress, tightening Russian sanctions impacting global heavy oil supply and improving heavy oil demand in Asia.

We continue to optimize bitumen price realizations through optimizing diluent recovery unit operation, blending and transportation strategies.

Our worldwide annual average realized price decreased six percent from $58.39 per BOE in 2023 to $54.83 per BOE in 2024 primarily due to lower crude and natural gas prices.

The following table presents average prices for 2025 compared to 2024:

Industry Prices 2025 2024 Change

Brent ($ per BBL) $ 69.06 80.76 (14) %

WTI ($ per BBL) 64.81 75.72 (14) %

Henry Hub ($ per MMBTU) 3.43 2.27 51 %

Average Realized Prices

Bitumen realized price ($ per BBL) $ 40.74 47.92 (15) %

Total realized price ($ per BBL) $ 47.01 58.39 (19) %

Crude and bitumen prices were lower through 2025 as global oil supplies increased faster than global oil demand.

Natural gas prices increased due to stronger demand and lower inventory levels relative to 2024.

Our worldwide annual average realized price decrease was driven by lower crude and bitumen prices.

ConocoPhillips 2025 10-K

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Significant items during 2025 and recent announcements included the following:

• Completed the acquisition of Marathon Oil, adding high-quality, low cost of supply inventory adjacent to the company's leading U.S.

unconventional position;

• Reported fourth-quarter 2025 earnings per share of $1.17;

• Delivered 2024 reserve replacement ratio of 244 percent and organic reserve replacement ratio of 123 percent;

• Announced planned 2025 return of capital target of $10 billion at current commodity prices and declared first-quarter 2025 ordinary dividend of $0.78 per share;

• Provided 2025 guidance including full-year capital of approximately $12.9 billion;

• Generated cash provided by operating activities of $19.8 billion;

• Distributed $9.1 billion to shareholders, including $5.5 billion through share repurchases and $3.6 billion through the ordinary dividend and VROC;

• Ended the year with cash, cash equivalents and restricted cash of $5.9 billion, short-term investments of $0.5 billion and long-term investments in debt securities of $1.1 billion;

• Advanced previously announced $2 billion disposition target by signing agreements to divest noncore Lower 48 assets of $0.6 billion, subject to customary closing adjustments and expected to close in the first half of 2025;

• Distributed $9.0 billion to shareholders, including $5.0 billion through share repurchases and $4.0 billion through the ordinary dividend;

• Ended the year with cash, cash equivalents, restricted cash and short-term investments of $7.4 billion and long-term investments of $1.1 billion.

• Delivered full-year total company and Lower 48 production of 2,375 MBOED and 1,484 MBOED, respectively;

Excluding one month of Marathon Oil production, the company and Lower 48 produced 1,955 MBOED and 1,124 MBOED, respectively;

• Reached first production at Nuna in Alaska and Bohai Phase 5 in China in the fourth quarter and at Eldfisk North in Norway in the second quarter;

• Progressed global LNG strategy with a long-term regasification agreement at Zeebrugge LNG terminal in Belgium and a long-term sales agreement in Asia;

• Exercised preferential rights and acquired additional working interests in Alaska's Kuparuk River and Prudhoe Bay Units in the fourth quarter;

• Completed debt transactions to simplify the company's capital structure post the acquisition of Marathon Oil, extending the weighted average maturity and improving the weighted average coupon of the portfolio;

• Achieved the Oil and Gas Methane Partnership 2.0 Gold Standard designation in 2024.

Production, DD&A and Capital

2025 production guidance is 2.34 to 2.38 MMBOED which includes 20 MBOED from planned turnarounds.

First-quarter 2025 production is expected to be 2.34 to 2.38 MMBOED, which includes impacts of 20 MBOED from January weather and 5 MBOED from turnarounds.

Guidance for 2025 includes DD&A of $11.3 to $11.5 billion and capital expenditures of approximately $12.9 billion.

• Completed the integration of Marathon Oil and doubled synergy capture to more than $1 billion on a run-rate basis in 2025;

achieved an additional ~$1 billion of one-time benefits;

• On track to achieve incremental cost reductions and margin enhancements of more than $1 billion on a run-rate basis by year-end 2026;

• Closed $3.2 billion in dispositions in 2025 and on track to meet $5 billion total disposition target by year-end 2026;

• Continued to advance Willow project in Alaska and equity LNG projects at NFE and NFS in Qatar and PALNG on the U.S.

all projects remain on schedule with NFE startup expected in the second half of 2026;

• Achieved Lower 48 drilling and completion efficiency improvements of more than 15% year over year;

• Advanced commercial LNG strategy by placing initial 5 MTPA of PALNG Phase 1 offtake;

secured additional offtake of 5 MTPA to bring total commercial offtake portfolio to 10 MTPA;

• Signed an agreement to extend the Waha Concession in Libya through 2050, with new fiscal terms, subject to normal regulatory approvals;

• Achieved first oil at Surmont Pad 104W-A in the fourth quarter, ahead of schedule.

Capital, Production and DD&A

Guidance for 2026 includes capital expenditures of approximately $12 billion.

Production guidance is 2.33 to 2.36 MMBOED.

First-quarter 2026 production is expected to be 2.30 to 2.34 MMBOED, inclusive of weather-related downtime.

DD&A is expected to be $11.7 to $11.9 billion.

Operating Segments

We manage our operations through six operating segments, which are primarily defined by geographic region:

We manage our operations through five operating segments, which are primarily defined by geographic region:

Europe, Middle East and North Africa;

Asia Pacific;

and Other International.

Corporate and Other represents income and costs not directly associated with an operating segment, such as most interest income and expense;

and Asia Pacific.

Effective in the fourth quarter of 2025, we determined that our former Other International operating segment, which consisted of activities associated with prior operations in other countries, was no longer an operating segment.

Residual results are aggregated into Corporate and Other.

Our historical operating segment reporting has been recast to reflect this change.

Our combined Corporate and Other represents income and costs not directly associated with an operating segment, such as most interest income and expense;

impacts from certain debt transactions;

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At December 31, 2025, our operations were producing in the U.S., Norway, Canada, Australia, China, Malaysia, Qatar, Libya and Equatorial Guinea.

Total production of 1,987 MBOED increased 161 MBOED or nine percent in 2024 compared with 2023.

Total production of 2,375 MBOED increased 388 MBOED or 20 percent in 2025 compared with 2024.

Production increases include:

• New wells online in the Lower 48, Alaska, Australia, Canada, China, Libya and Norway.

• Our acquisition of the remaining working interest in Surmont in the fourth quarter of 2023.

• New wells online in the Lower 48, Canada, Australia, Norway, Alaska, Libya, China and Malaysia.

• Our acquisition of Marathon Oil in the fourth quarter of 2024.

The increase in production during 2025 was partly offset by normal field decline.

After adjusting for closed acquisitions and dispositions, production increased by 69 MBOED or three percent.

After adjusting for closed acquisitions and dispositions, production increased by 57 MBOED or 2.5 percent.

ConocoPhillips 2025 10-K

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Sales and other operating revenues $ 58,944 54,745 56,141

Equity in earnings of affiliates 1,335 1,705 1,720

Gain (loss) on dispositions 731 51 228

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Depreciation, depletion and amortization 11,500 9,599 8,270

Foreign currency transaction (gain) loss (50) 92 (100)

Other expenses 20 181 2

Income tax provision (benefit) 4,668 4,427 5,331

Sales and other operating revenues decreased $1,396 million in 2024, primarily due to lower realized natural gas and crude prices of $1,031 million and $791 million, respectively, and the timing of sales as compared to 2023.

These decreases were partially offset by higher volumes of $2,659 million, inclusive of sales volumes from our acquisitions of Surmont and Marathon Oil, and higher realized bitumen prices of $258 million.

Gain (loss) on dispositions decreased $177 million in 2024, primarily due to the absence of gains associated with the divestitures of an equity investment and noncore assets in Lower 48 segment.

Purchased commodities decreased $1,963 million in 2024, primarily driven by lower natural gas and crude prices, partially offset by higher crude volumes.

Production and operating expenses increased $1,058 million in 2024, due to higher lease operating expenses and transportation costs in our Lower 48 and Alaska segments, higher volumes primarily in our Canada and Lower 48 segments, as well as higher expenses associated with the Surmont turnaround in our Canada segment.

Selling, general and administrative expenses increased $453 million in 2024, primarily due to transaction expenses of $545 million associated with our acquisition of Marathon Oil, partially offset by lower compensation and benefits costs, including mark-to-market impacts of certain key employee compensation programs.

See Note 15 .

DD&A increased $1,329 million in 2024 primarily due to higher volumes in our Lower 48 and Canada segments, higher rates in our Alaska and Lower 48 segments and the impact of our acquisition of Marathon Oil.

Foreign currency transaction (gain) loss for the year was improved by $142 million, primarily due to the absence of losses of $112 million associated with forward contracts in support of our Surmont acquisition.

Other expenses increased $179 million primarily related to a loss of $173 million associated with the extinguishment of debt in the fourth quarter of 2024.

Sales and other operating revenues increased $4,199 million in 2025, primarily due to higher volumes of $6,197 million, inclusive of sales volumes from our acquisition of Marathon Oil and higher realized gas prices of $824 million and the timing of sales as compared to 2024.

These increases were partially offset by lower realized crude and bitumen prices of $4,615 million and $349 million, respectively.

Equity in earnings of affiliates decreased $370 million in 2025, primarily due to lower earnings driven by lower LNG and crude prices.

Gain (loss) on dispositions increased $680 million in 2025, primarily due to gains associated with the divestitures of the Ursa and Europa fields and Ursa Oil Pipeline Company LLC and other noncore assets in our Lower 48 segment.

Purchased commodities increased $2,313 million in 2025, primarily due to higher purchased volumes associated with our acquisition of Marathon Oil, higher natural gas prices and higher purchased crude volumes, partly offset by lower crude prices.

Production and operating expenses increased $1,580 million in 2025, primarily due to impacts from our acquisition of Marathon Oil in the fourth quarter of 2024 and $216 million of severance costs related to a restructuring.

See Note 3 and See Note 14 .

Selling, general and administrative expenses decreased $265 million in 2025, primarily due to the absence of transaction expenses of $545 million associated with our acquisition of Marathon Oil in 2024, partially offset by severance costs related to a restructuring in 2025.

See Note 3 and See Note 14 .

DD&A increased $1,901 million in 2025 primarily due to impacts from our acquisition of Marathon Oil in the fourth quarter of 2024 and higher production volumes.

Other expenses decreased $161 million primarily related to the absence of a loss of $173 million associated with the extinguishment of debt in the fourth quarter of 2024.

See Note 15 —Income Taxes for information regarding our income tax provision and effective tax rate.

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Asia Pacific 1,167 1,724 1,961

Other International (1) (13) (51)

Segments Total 9,126 10,126 11,791

Corporate and Other (1,138) (881) (834)

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The Alaska segment primarily explores for, produces, transports and markets crude oil, NGLs and natural gas.

In 2024, Alaska contributed 14 percent of our consolidated liquids production and two percent of our consolidated natural gas production.

In 2025, Alaska contributed 12 percent of our consolidated liquids production and one percent of our consolidated natural gas production.

Net Income (Loss)

Alaska reported earnings of $730 million in 2025, compared with earnings of $1,326 million in 2024.

Decreases to earnings included lower revenues resulting from lower commodity prices of $73 million and the timing of sales as compared with 2023.

Additional decreases to earnings included higher DD&A expenses of $175 million, driven by higher rates as a result of 2023 year-end downward reserve revisions as well as higher production and operating expenses of $90 million, driven by higher well work activity of $56 million and transportation related costs of $26 million.

Average production decreased one MBOED in 2024 compared with 2023, primarily due to normal field decline.

The production decrease was partly offset by new wells online at our Western North Slope and Greater Kuparuk Area assets.

Acquisition of Additional Working Interest in Kuparuk River Unit and Prudhoe Bay Unit

After exercising our preferential rights, we completed an acquisition of additional working interest in both the Kuparuk River Unit and the Prudhoe Bay Unit in the fourth quarter of 2024.

Production from the additional working interest averaged approximately five MBOED each month for November and December 2024.

Decreases to earnings included lower revenues resulting from lower commodity prices of $509 million, partly offset by higher produced volumes of $78 million.

Additional decreases to earnings included higher production and operating expenses of $151 million, driven by higher lease operating expenses and well work activity and severance costs related to a restructuring, and higher DD&A of $73 million, primarily driven by higher rates.

See Note 14 .

Average production increased five MBOED in 2025 compared with 2024, primarily due to new wells online and less downtime.

The production increase was partly offset by normal field decline.

ConocoPhillips 2025 10-K

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The Lower 48 segment consists of operations located in the contiguous U.S.

and the Gulf of Mexico and commercial operations.

and related commercial operations.

During 2025, the Lower 48 contributed 67 percent of our consolidated liquids production and 74 percent of our consolidated natural gas production.

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Lower 48 reported earnings of $5,264 million in 2025, compared with earnings of $5,175 million in 2024.

Decreases to earnings included lower revenues resulting from lower overall commodity prices of $904 million and the timing of sales as compared with 2023, partly offset by higher volumes of $1,003 million, which includes volumes added from our acquisition of Marathon Oil.

Additional decreases to earnings included higher DD&A of $562 million, driven by higher production of $250 million, higher rates of $181 million and impacts from our acquisition of Marathon Oil of $139 million;

higher production and operating expenses of $431 million, driven by higher transportation related costs of $132 million, expenses associated with our acquisition of Marathon Oil of $110 million and higher lease operating expenses of $100 million;

as well as the absence of gains associated with the divestiture of an equity investment of $100 million.

Total average production increased 85 MBOED in 2024 compared with 2023, primarily due to new wells online from our development programs in Delaware Basin, Eagle Ford, Midland Basin and Bakken and the impact from assets acquired from Marathon Oil.

The production increase was partly offset by normal field decline and higher unplanned downtime across all basins.

Acquisition of Marathon Oil

On November 22, 2024, we completed our acquisition of Marathon Oil.

The transaction added additional assets to our Lower 48 segment across several basins.

Production from Lower 48 assets acquired from Marathon Oil averaged approximately 334 MBOED in the month of December 2024.

Planned Dispositions

We recently entered into agreements to sell noncore assets within our Lower 48 segment that are expected to close in the first half of 2025 for approximately $600 million, subject to customary closing adjustments.

Increases to earnings included higher revenues resulting from higher volumes of $3,890 million, inclusive of volumes from our acquisition of Marathon Oil, partly offset by lower commodity prices of $1,999 million, driven by lower crude prices.

Additional increases included higher gains on dispositions of $494 million, primarily associated with the divestitures of the Ursa and Europa fields and Ursa Oil Pipeline Company LLC, and other noncore assets.

Decreases to earnings included higher DD&A of $1,330 million and higher production and operating expenses of $875 million, primarily driven by impacts from our acquisition of Marathon Oil.

Total average production increased 332 MBOED in 2025 compared with 2024, primarily due to new wells online from our development programs in the Delaware Basin, Eagle Ford, Bakken and Midland Basin and the impact from our acquisition of Marathon Oil.

Production increases were partly offset by normal field decline.

In 2025, we completed multiple divestitures, including the Ursa and Europa fields and Ursa Oil Pipeline Company LLC for net proceeds of $699 million, the Anadarko Basin for net proceeds of $1.2 billion and other noncore assets for $1.1 billion.

Production from these assets averaged approximately 33 MBOED in 2024.

ConocoPhillips 2025 10-K

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The Canada segment operations include the Surmont oil sands development in Alberta, the Montney unconventional play in British Columbia and commercial operations.

In 2024, Canada contributed ten percent of our consolidated liquids production and five percent of our consolidated natural gas production.

In 2025, Canada contributed nine percent of our consolidated liquids production and five percent of our consolidated natural gas production.

Net Income (Loss)

Canada reported earnings of $741 million in 2025 compared with earnings of $712 million in 2024.

Earnings included higher revenues resulting from higher volumes of $676 million;

driven by our increased working interest in Surmont of $584 million and new wells online in the Montney of $180 million, partially offset by planned turnaround activity at Surmont impacting revenues by $157 million.

Additionally, revenues increased from higher overall commodity prices of $153 million, driven primarily by higher bitumen prices.

Decreases to earnings included higher production and operating expenses of $215 million;

driven by an impact of $175 million related to higher overall production, including our increased working interest in Surmont;

as well as expenses of $55 million related to turnaround activity at Surmont.

Additional decreases to earnings included higher DD&A expenses of $166 million resulting from higher volumes and the absence of a $92 million tax benefit recognized upon the closing of a Canada Revenue Agency audit in 2023.

Increases to earnings included higher revenues resulting from higher volumes of $142 million and the timing of sales as compared with 2024 partly offset by lower commodity prices of $303 million.

Increases to earnings included lower DD&A of $63 million driven by year-end 2024 upward reserve revisions and higher other income of $62 million primarily from a change in fair value measurement associated with the Surmont contingent consideration arrangement.

Additional increases to earnings included lower production and operating expenses of $52 million driven by the absence of prior-year planned turnaround activity at Surmont.

See Note 11 .

Total average production increased 13 MBOED in 2025 compared with 2024.

Increases to production resulted from our increased working interest in Surmont as well as new wells online in the Montney and Surmont.

These production increases were partly offset by higher downtime resulting from a planned turnaround activity at a Surmont central processing facility and normal field decline.

Increases to production resulted from new wells online in the Montney and Surmont and the absence of prior-year planned turnaround activity at Surmont.

Production increases were partly offset by normal field decline.

ConocoPhillips 2025 10-K

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The Europe, Middle East and North Africa segment consists of operations principally located in the Norwegian sector of the North Sea, the Norwegian Sea, Qatar, Libya, Equatorial Guinea and commercial and terminalling operations in the U.K.

In 2024, our Europe, Middle East and North Africa operations contributed nine percent of our consolidated liquids production and 17 percent of our consolidated natural gas production.

In 2025, our Europe, Middle East and North Africa operations contributed eight percent of our consolidated liquids production and 18 percent of our consolidated natural gas production.

Net Income (Loss)

The Europe, Middle East and North Africa segment reported earnings of $1,224 million in 2025 compared with earnings of $1,189 million in 2024.

Earnings in 2024 included lower revenues resulting from lower overall commodity prices of $118 million and the timing of sales as compared with 2023, partly offset by higher volumes of $144 million, which includes $49 million from volumes added from our acquisition of Marathon Oil.

Additional decreases to earnings included higher DD&A of $51 million.

Earnings in 2025 included higher revenues resulting from higher volumes of $296 million, including volumes from our Equatorial Guinea assets from the acquisition of Marathon Oil, partly offset by lower overall realized commodity prices of $185 million, driven by lower crude prices.

Decreases to earnings included higher production and operating expenses of $88 million, primarily from our acquisition of Marathon Oil.

Consolidated Production

Average consolidated production increased 40 MBOED in 2025, compared with 2024.

The consolidated production increase was primarily due to new wells online and improved performance in Norway, as well as the impact from assets acquired from Marathon Oil.

The consolidated production increase was primarily due to the impact from assets acquired from Marathon Oil as well as new wells online in Norway and Libya.

The production increase was partly offset by normal field decline.

Acquisition of Marathon Oil

On November 22, 2024, we completed our acquisition of Marathon Oil.

The transaction added Equatorial Guinea to our global portfolio which resides in our Europe, Middle East and North Africa segment.

Production from Equatorial Guinea averaged approximately 40 MBOED in the month of December 2024.

Exploration Activity

In 2024, we charged approximately $40 million before-tax as dry hole expenses primarily for two partner operated exploration wells in the Alvheim area in the Norwegian sector of the North Sea and the Busta suspended discovery well on license PL782S.

ConocoPhillips 2025 10-K

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Asia Pacific reported earnings of $1,167 million in 2025, compared with $1,724 million in 2024.

Decreases to earnings included lower revenues resulting from lower commodity prices of $49 million and lower volumes of $20 million.

Additional decreases to earnings included the absence of a tax benefit recognized in 2023 from the reversal of a tax reserve.

See Note 16 .

Earnings also decreased due to lower equity in earnings of affiliates of $57 million.

Increases to earnings included lower DD&A expenses of $27 million resulting from lower volumes.

Decreases to earnings included lower revenues resulting from lower commodity prices of $206 million.

Additional decreases to earnings included lower earnings from equity affiliates of $271 million, primarily due to lower LNG sales prices and higher exploration expenses of $64 million, primarily driven by dry hole expenses associated with certain wells in Malaysia and Australia.

Consolidated Production

Average consolidated production decreased one MBOED in 2024, compared with 2023.

The decrease was primarily due to normal field decline.

These production decreases were partly offset by development activity at Bohai Bay in China.

Average consolidated production increased three MBOED in 2025, compared with 2024.

Increases to production were primarily due to development activity in Bohai Bay in China and Gumusut in Malaysia.

Production increases were partly offset by normal field decline.

ConocoPhillips 2025 10-K

Results of Operations Table of Contents

Other International

2024 2023 2022

Net Income (Loss) ($MM)

$ (1) (13) (51)

The Other International segment consists of activities associated with prior operations in other countries.

Earnings from our Other International operations improved $12 million in 2024, compared with 2023.

Corporate and Other

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$ (1,138) (880) (821)

Net interest consists of interest and financing expense, net of interest income and capitalized interest.

Net interest expense consists of interest and debt expense, net of interest income and capitalized interest.

Net interest expense increased in 2025 due to higher interest expense driven by debt assumed from our acquisition of Marathon Oil.

See Note 3 and Note 7 .

Corporate G&A expenses include compensation programs and staff costs.

These expenses increased by $359 million in 2024 compared with 2023, primarily due to transaction expenses of $432 million associated with our acquisition of Marathon Oil, partially offset by lower compensation and benefits costs, including mark-to-market impacts of certain key employee compensation programs.

See Note 15 .

These expenses decreased by $230 million in 2025 compared with 2024, primarily due to the absence of transaction expenses of $432 million associated with our acquisition of Marathon Oil in 2024, partially offset by severance costs related to a restructuring in 2025.

See Note 3 and Note 14 .

Technology includes our investments in low-carbon technology opportunities as well as other new technologies or businesses and licensing revenues.

Other new technologies or businesses and LNG licensing activities are focused on both conventional and tight oil reservoirs, shale gas, oil sands, enhanced oil recovery as well as LNG.

Earnings in Technology decreased due to increased costs in low-carbon and other new technologies and lower licensing revenues.

Other income (expense) or "Other" includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, other costs not directly associated with an operating segment, gains or losses on early retirement of debt, holding gains or losses on equity securities and pension settlement expense.

Earnings in “Other” increased by $422 million in 2024 compared with 2023.

This was primarily due to a tax benefit of $455 million as a result of the acquisition of Marathon Oil and the subsequent utilization of foreign tax credits, and the absence of $89 million loss associated with forward foreign exchange contracts to buy CAD, in support of our acquisition of additional working interest in Surmont in 2023.

Decreases to earnings in "Other" were driven by a loss of $147 million associated with the extinguishment of debt in the fourth quarter of 2024.

Earnings in “Other” decreased by $366 million in 2025 compared with 2024.

This was primarily due to the absence of a tax benefit of $455 million as a result of the acquisition of Marathon Oil in 2024 and the subsequent utilization of foreign tax credits.

The earnings decrease was partly offset by an increase due to the absence of a loss of $147 million associated with the extinguishment of debt in the fourth quarter of 2024.

See Note 3, Note 7 and Note 15 .

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To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities, our commercial paper and credit facility programs and our ability to sell securities using our shelf registration statement.

In 2024, the primary uses of our available cash were $12.1 billion to support our ongoing capital expenditures and investments program, which included $0.4 billion of spend related to fourth-quarter acquisitions;

In 2025, the primary uses of our available cash were $12.6 billion to support our ongoing capital expenditures and investments program;

$5.0 billion to repurchase common stock;

and $3.6 billion to pay the ordinary dividend and VROC.

In addition to cash from operating activities, the other primary sources of capital were $5.6 billion in proceeds from long-term debt issuances, of which $4.1 billion was used to repurchase certain existing Marathon Oil debt assumed in the acquisition and ConocoPhillips debt;

and $0.4 billion net sales of short-term investments.

In 2024, cash and cash equivalents remained flat with 2023 at $5.6 billion.

$4.0 billion to pay the ordinary dividend;

and $0.9 billion to retire debt, partly offset by proceeds from asset sales of $3.2 billion.

In 2025, cash and cash equivalents increased by $0.9 billion to $6.5 billion.

See Note 3 and Not e 7 .

At December 31, 2025, we had cash and cash equivalents of $6.5 billion, short-term investments of $0.5 billion, and available borrowing capacity under our credit facility of $5.5 billion, totaling approximately $12.5 billion of liquidity.

In addition, we have long-term investments in debt securities of $1.1 billion.

We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Changes in Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, capital return program and required debt payments.

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Cash provided by operating activities in 2025 totaled $19.8 billion, compared with $20.1 billion for 2024, and $20.0 billion for 2023.

In 2024, cash provided by operating activities improved from 2023 due to increased production primarily from Canada and the Lower 48, including the Surmont 50 percent working interest acquired in the fourth quarter of 2023 and our acquisition of Marathon Oil in late 2024.

The decrease in 2025 compared to 2024 resulted from lower commodity prices, mostly offset by operations from the 2024 Marathon Oil acquisition.

The increase in cash provided by operating activities in 2024 compared to 2023 is due to increased production primarily from Canada and the Lower 48, including the Surmont 50 percent working interest acquired in the fourth quarter of 2023 and our acquisition of Marathon Oil in late 2024.

The increase in production was partly offset by lower commodity prices and lower distributions from equity affiliates.

The decrease in cash provided by operating activities from 2023 compared to 2022 is primarily due to lower realized commodity prices across all products, partly offset by higher sales volumes, net of associated production and operating costs.

Our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and NGLs.

Prices and margins in our industry have historically been volatile and are driven by market conditions over which we have no control.

Our short- and long-term operating cash flows are highly dependent on the prices for crude oil, bitumen, natural gas, LNG and NGLs.

Prices and margins in our industry have historically been volatile, driven by market conditions beyond our control.

Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

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Capital Resources and Liquidity

The level of absolute production volumes, as well as product and location mix, is another significant factor impacting our cash flows.

Full-year production averaged 1,987 MBOED in 2024, an increase of 161 MBOED or nine percent compared to 2023.

The level of absolute production volumes, as well as the product and location mix, is another significant factor impacting our cash flows.

Full-year production averaged 2,375 MBOED in 2025, an increase of 388 MBOED or 20 percent compared to 2024.

First-quarter 2026 production is expected to be 2.30 MMBOED to 2.34 MMBOED.

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Investing Activities

In 2024, we invested $12.1 billion in capital expenditures and investments;

$0.8 billion of which was primarily payments towards our equity investments in LNG projects, including Port Arthur Liquefaction Holdings, LLC (PALNG), QatarEnergy LNG NFE(4) (NFE4) and QatarEnergy LNG NFS(3) (NFS3);

and $0.4 billion of spend related to fourth-quarter acquisitions .

The remaining $10.9 billion funded our operating capital program.

In 2025, we invested $12.6 billion in capital expenditures and investments, $0.5 billion of which was primarily payments towards our equity investments in LNG projects, including NFE4, NFS3 and PALNG, while the remainder funded our operating capital program.

Capital expenditures invested in 2024 and 2023 were $12.1 billion and $11.2 billion, respectively.

See the “Capital Expenditures and Investments” section.

In conjunction with the announcement of our acquisition of Marathon Oil, we communicated a disposition target of approximately $2 billion of assets across the portfolio.

After exercising our preferential rights, we completed an acquisition that increased our working interest by approximately five percent in the Kuparuk River Unit and approximately 0.4 percent in the Prudhoe Bay Unit in Alaska from Chevron U.S.A.

and Union Oil Company of California in the fourth quarter of 2024 for $296 million before customary adjustments.

In August 2025, we announced a total disposition target of $5 billion by year-end 2026.

We disposed of $3.2 billion of assets in 2025 and we expect to meet our $5 billion disposition target by year-end 2026.

Proceeds from asset sales were $3.2 billion in 2025 compared with $0.3 billion in 2024 and $0.6 billion in 2023.

In 2025, we sold Lower 48 assets in the Anadarko basin for net proceeds of $1.2 billion and our interest in the Ursa and Europa fields, and Ursa Oil Pipeline Company LLC for net proceeds of $0.7 billion.

Additionally, we sold other noncore Lower 48 and Corporate assets for approximately $1.3 billion .

In the fourth quarter of 2024, after exercising our preferential rights, we completed an acquisition that increased our working interest by approximately five percent in the Kuparuk River Unit and approximately 0.4 percent in the Prudhoe Bay Unit in Alaska from Chevron U.S.A.

and Union Oil Company of California for $296 million, before customary adjustments.

In October 2023, we acquired the remaining 50 percent working interest in Surmont from TotalEnergies EP Canada Ltd.

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See Note 3 and Note 7.

Proceeds from asset sales were $0.3 billion in 2024, $0.6 billion in 2023 and $3.5 billion in 2022.

In 2022, we received proceeds of $1.4 billion for the sale of our remaining 91 million common shares of Cenovus Energy (CVE) , proceeds of approximately $1.5 billion, primarily from asset divestitures in our Asia Pacific and Lower 48 segments, and $0.5 billion in contingent payments associated with prior divestitures.

S ee Note 3 and Note 5.

We invest in short-term investments as part of our cash investment strategy, the primary objective of which is to protect principal, maintain liquidity and provide yield and total returns;

We invest in short-term and long-term investments as part of our cash investment strategy, the primary objective of which is to protect principal, maintain liquidity and provide yield and total returns;

these investments include time deposits, commercial paper, as well as debt securities classified as available for sale.

Funds for short-term investments needs to support our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid instruments with maturities within the year.

Funds we consider available to maintain resiliency in longer term price downturns and to capture opportunities outside a given operating plan may be invested in instruments with maturities greater than one year.

Funds needed for short-term investments to support our operating plan and provide resiliency to react to short-term price volatility are invested in highly liquid instruments with maturities of less than one year.

Funds we consider available to maintain resiliency in longer term price downturns and to capture opportunities outside a given operating plan are invested in highly liquid instruments with maturities of greater than one year.

See Note 10 and Note 17.

Investing activities in 2024 included net sales of $415 million of investments.

Investing activities in 2025 included net purchases of $55 million of investments.

We had net sales of $502 million of short-term investments and net purchases of $557 million of long-term investments.

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Financing Activities

Our debt balance at December 31, 2025 was $23.4 billion compared with $24.3 billion at December 31, 2024.

The current portion of debt, including payments for finance leases, is $1.0 billion.

In 2025, the company retired $0.7 billion principal amount of debt at maturity, consisting of $0.2 billion of our 3.35% Notes, $0.4 billion of our 2.4% Notes and $0.1 billion of our 8.2% Debentures.

In November 2024, we acquired Marathon Oil.

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See Note 3 and Note 7.

Our debt balance at December 31, 2024 was $24.3 billion compared with $18.9 billion at December 31, 2023.

The current portion of debt, including payments for finance leases, is $1.0 billion.

In 2024, the company retired $726 million principal amount of Notes at maturity consisting of $265 million of our 3.35% Notes and $461 million of our 2.125% Notes.

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In 2023, we issued $2.7 billion principal amount of new debt to fund our acquisition of the remaining 50 percent working interest in Surmont and completed refinancing transactions consisting of $1.1 billion in tender offers to repurchase existing debt with cash and a $1.1 billion new debt issuance to fund the repurchases, extending the weighted average maturity of our portfolio from 15 to 17 years and reducing near-term debt maturities.

In 2022, we repurchased notes, retired floating rate debt and executed a debt refinancing comprised of concurrent transactions including new debt issuances, a cash tender offer and debt exchange offers.

In aggregate, these transactions along with naturally maturing debt, reduced the company's total debt by $3.3 billion.

In 2022, we refinanced our revolving credit facility from a total aggregate principal amount of $6.0 billion to $5.5 billion with an expiration date of February 2027.

In February 2025, we refinanced our revolving credit facility maintaining a total aggregate principal amount of $5.5 billion and extended the expiration to February 2030.

Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program.

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Many of these contracts and instruments permit us to post either cash or letters of credit as collateral.

At December 31, 2024 and December 31, 2023, we had direct bank letters of credit of $278 million and $340 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business.

At December 31, 2025 and 2024, we had direct bank letters of credit of $331 million and $278 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business.

In the event of a credit rating downgrade, we may be required to post additional letters of credit.

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For information about our capital expenditures and investments, see the “Capital Expenditures and Investments” section.

Our debt balance at December 31, 2024, was $24.3 billion, an increase of $5.4 billion from the balance at December 31, 2023 of $18.9 billion.

In 2024, the company assumed $4.6 billion principal of debt with our acquisition of Marathon Oil and retired $726 million principal amount of Notes at maturity.

In addition, we completed concurrent debt transactions consisting of new long-term debt issuances of $5.2 billion;

a $4.1 billion repurchase of certain existing Marathon Oil and ConocoPhillips debt;

a non-cash obligor exchange offer to retire $0.9 billion of Marathon Oil debt in exchange for new ConocoPhillips debt;

and the remarketing of $0.4 billion in available municipal bonds.

The debt transactions simplified our capital structure, extended the debt portfolio's weighted average maturity, lowered its weighted average coupon and reduced near-term maturities.

In February 2025, we announced our 2025 planned return of capital to shareholders of $10 billion, at current commodity prices, through our return of capital framework.

We plan to deliver a compelling, growing ordinary dividend and through-cycle share repurchases.

We anticipate returning greater than 30 percent of cash from operating activities during periods where commodity prices are meaningfully higher than our planning price range.

For information about our debt balances and related debt financing transactions, see the "Significant Changes in Capital - Financing Activities" section.

We believe in delivering value to our shareholders through our return of capital framework.

The framework is structured to deliver a compelling, growing ordinary dividend and through-cycle share repurchases.

We anticipate returning greater than 30 percent of cash from operating activities through cycles.

Our 2025 total capital returned was $9.0 billion.

In 2022, we executed concurrent debt refinancing transactions, repurchased existing notes, and retired floating rate notes upon natural maturity, that in aggregate reduced our total debt by $3.3 billion, while also lowering our annual cash interest expense and extending the weighted average maturity of our debt portfolio.

See Note 8 for information regarding debt and Note 18 for information regarding non-cash consideration of the Surmont transaction.

Consistent with our commitment to deliver value to shareholders, for the full year of 2024, we paid ordinary dividends of $2.52 per common share and VROC payments of $0.60 per common share.

In the fourth quarter of 2024, we incorporated the equivalent amount of prior quarter VROC into the ordinary dividend.

In 2023 we paid ordinary dividends of $2.11 and VROC payments of $2.50 per common share and in 2022 we paid an ordinary dividend of $1.89 and VROC payments of $2.60.

Consistent with our commitment to deliver value to shareholders, for the full year of 2025, we paid ordinary dividends of $3.18 per common share.

In 2024 we paid ordinary dividends of $2.52 and VROC payments of $0.60 per common share and in 2023 we paid ordinary dividends of $2.11 and VROC payments of $2.50 per common share.

In February 2026, we declared a first-quarter ordinary dividend of $0.84 per common share payable March 2, 2026, to shareholders of record on February 18, 2026.

VROC remains a discretionary option in elevated price environments.

The ordinary dividend and VROC are subject to numerous considerations and are determined and approved each quarter by the Board of Directors.

Beginning in the first quarter of 2024, we announced and paid quarterly dividends and VROC payments concurrently.

VROC payments had been paid in the subsequent quarter of announcement in 2023 and 2022.

Our Board may determine not to pay a dividend in a quarter or may cease declaring a dividend at any time.

In late 2016, we initiated our current share repurchase program.

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Share repurchases were $5.0 billion, $5.5 billion, and $5.4 billion in 2025, 2024, and 2023, respectively.

As of December 31, 2024, share repurchases since the inception of our current program totaled 432.6 million shares and $34.3 billion since 2016.

As of December 31, 2025, share repurchases since the inception of our current program totaled 486.1 million shares for $39.3 billion since 2016.

Repurchases are made at management’s discretion, at prevailing prices, subject to market conditions and other factors.

For more information on factors considered when determining the levels of returns of capital see “Item 1A—Risk Factors – Our ability to execute our capital return program is subject to certain considerations.”

ConocoPhillips 2024 10-K

Capital Resources and Liquidity

As of December 31, 2025, in addition to the priorities described above, we have contractual obligations to purchase goods and services of approximately $45.0 billion.

We expect to fulfill $7.5 billion of these obligations in 2025.

We expect to fulfill $5.0 billion of these obligations in 2026 with the remainder over the next 25 years.

A substantial amount of LNG offtake and other product purchases are expected to be offset in the same or approximately same periods by cash received from the related sales transactions.

These figures exclude purchase commitments for jointly owned fields and facilities where we are not the operator.

Purchase obligations of $13.0 billion are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and LNG product terminals, to transport, process, treat and store commodities.

Purchase obligations of $16.8 billion are related to market-based contracts for commodity product purchases with third parties.

The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator.

The following table summarizes our aggregate future contractual purchase obligations as of December 31, 2025:

Millions of Dollars

LNG offtake, regasification and related vessels $ 29,722

Other capacity obligations 10,890

Other product purchases 3,094

Other obligations 1,271

Total $ 44,977

ConocoPhillips 2025 10-K

Capital Resources and Liquidity

Capital Expenditures and Investments

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Asia Pacific 342 370 354

Other International — — —

Segments Total 12,438 11,646 10,113

Corporate and Other 115 472 1,135

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• Appraisal and development activities in the Montney as well as development and optimization of Surmont in Canada.

• Development activities across assets in Norway.

• Continued development activities in Malaysia and China.

• Investments in PALNG, NFE4 and NFS3.

• Development and appraisal activities across assets in Norway and development activities in Libya.

• Continued development activities in China.

• Investments in NFE4, NFS3 and PALNG.

2026 Capital Budget

In February 2025, we announced our 2025 operating plan capital is expected to be $12.9 billion.

In February 2026, we announced our 2026 operating plan capital is expected to be approximately $12 billion.

The plan includes funding for ongoing development drilling programs, major projects, exploration and appraisal activities and base maintenance.

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Amounts due to Non-Obligated Subsidiaries, noncurrent 52,813

ConocoPhillips 2024 10-K

Capital Resources and Liquidity

Contingencies

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Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us.

Our process facilitates the early evaluation and quantification of potential exposures in individual cases.

ConocoPhillips 2025 10-K

Capital Resources and Liquidity

facilitates the early evaluation and quantification of potential exposures in individual cases.

This process also enables us to track those cases that have been scheduled for trial and/or mediation.

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Federal Clean Water Act, which governs discharges to water bodies;

• EU Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH);

• EU Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals;

Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste;

Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the U.S.;

Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments;

Federal Oil Pollution Act of 1990, under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the U.S.;

Federal Emergency Planning and Community Right-to-Know Act, which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments;

Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells;

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While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

ConocoPhillips 2024 10-K

Capital Resources and Liquidity

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards and water quality standards, continue to evolve.

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Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments.

We have adopted operating principles that incorporate established industry standards designed to meet or exceed government requirements.

We have adopted operating principles that incorporate established industry standards that are designed to meet government requirements.

Our practices continually evolve as technology improves and regulations change.

ConocoPhillips 2025 10-K

Capital Resources and Liquidity

We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations.

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On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties.

These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations.

These notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations.

As of December 31, 2025, there were 20 sites around the U.S.

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There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

Expensed environmental costs were $914 million in 2024 and are expected to be approximately $1.1 billion in 2025 and 2026.

Expensed environmental costs were $834 million in 2025 and are expected to be approximately $1.0 billion in each of 2026 and 2027.

Capitalized environmental costs were $669 million in 2025 and are expected to be about $750 million and $550 million in 2026 and 2027, respectively.

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In the future, we may incur significant costs under both CERCLA and RCRA.

ConocoPhillips 2024 10-K

Capital Resources and Liquidity

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties.

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Risk Factors—We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations and Note 9 for information on environmental litigation.

ConocoPhillips 2025 10-K

Capital Resources and Liquidity

Climate Change

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These laws apply or could apply in countries where we have interests or may have interests in the future.

Additionally, some laws have been rescinded or delayed, creating policy swings that result in compliance uncertainty.

Laws in this field continue to evolve and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our operational results and financial condition.

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• The Alberta Technology Innovation and Emissions Reduction (TIER) regulation requires any existing facility with emissions equal to or greater than 100,000 metric tonnes of carbon dioxide, or equivalent, per year to meet a facility benchmark intensity.

The total cost of compliance related to this regulation in 2024 was approximately $4.5 million (net share before-tax) after savings from using our existing bank of offsets and performance credits ($7.7 million before savings).

There was no cost of compliance related to this regulation in 2025, as our Surmont asset outperformed its target benchmark intensity over the full year reporting period.

• As of April 2024, the British Columbia Output Based Pricing System (BC OBPS) regulation requires facilities or linear operations (such as oil and gas gathering systems) with emissions equal to or greater than 10,000 metric tonnes of carbon dioxide or equivalent per year to remit payments on the difference between actual emissions and allowable emissions based on product and activity benchmarks.

The benchmarks and guidance for these emissions have yet to be finalized, and compliance payments are not due until later in 2025.

Based on interim benchmarks, our BC OBPS obligation is expected to total $1.5 million (net share before-tax) for Montney in 2024.

The benchmarks and guidance for these emissions have yet to be finalized, and compliance payments for 2025 are not due until later in 2026.

Based on interim benchmarks, our BC OBPS obligation is expected to total a maximum of $12.3 million (net share before-tax) for Montney in 2025.

• In 2024, the EU passed regulation on the reduction of methane emissions in the energy sector that will apply a methane limit on oil and gas imports to the EU, as well as mandate the monitoring, reporting, verification and reduction of methane emissions.

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In the previous Australian financial year of July 1, 2024, to June 30, 2025, our operated downstream APLNG facility was in excess of its baseline emissions, while the upstream partner-operated facilities were below their baseline emissions.

As we expect there to be a surplus of eligible carbon units across the joint venture, there is no expense expected to be incurred by ConocoPhillips for the 2024 Australian financial year.

As there was a surplus of eligible carbon units across the joint venture, there was no expense incurred by ConocoPhillips for the 2025 Australian financial year.

• In 2024 the U.S.

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portfolio will result in additional compliance costs.

ConocoPhillips 2024 10-K

Capital Resources and Liquidity

• In connection with OOOOb and OOOOc rulemaking, the U.S.

EPA established the Methane Super Emitter Program whereby certified third parties can use EPA-approved technology to identify and report super-emitter events for EPA review.

An operator must initiate an investigation within five days of receiving notification from the EPA regarding a super-emitter event.

• In November 2024, the U.S.

EPA finalized the Waste Emissions Charge (WEC) as part of the Methane Emission Reduction Program (MERP) within the Inflation Reduction Act of 2022.

The implementation of the WEC will require payments to the EPA, accounting for methane emissions subject to the rule.

The filing deadline for the 2024 WEC is August 2025.

Carbon taxes in certain jurisdictions.

• We incurred carbon tax cost in our Montney operations in the first three months of 2024, before the BC OBPS came into force.

We may also incur a carbon tax for any emissions in Montney that falls outside the scope of our BC OBPS activities.

We also incur a nominal carbon tax for emissions from fossil fuel combustion at some of our Surmont operations in Alberta that occur outside of TIER facilities.

Carbon tax costs in our Canada operations totaled $1.7 million (net share before-tax).

• Effective April 1, 2025, the Canadian federal government set the consumer carbon price to zero and no longer requires a consumer carbon tax going forward.

This is separate from the obligated industrial carbon pricing schemes of Alberta TIER and BC OBPS, which remain in place.

Our operations outside of industrial carbon pricing schemes were minimal at Surmont for the first quarter of 2025, and no Federal Fuel charges were incurred at Montney in 2025.

• Our cost of compliance with Norwegian carbon legislation in 2025 was approximately $42 million (net share before-tax).

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Compliance with such legislation may expose us to significant additional liabilities.

ConocoPhillips 2025 10-K

Capital Resources and Liquidity

• Climate Private Action laws.

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Non-regulatory initiatives or agreements.

government announced on September 17, 2021 the Global Methane Pledge, a global initiative to reduce global methane emissions by at least 30 percent from 2020 levels by 2030.

• The Global Methane Pledge (GMP) was launched at COP26 by the EU and the U.S., a global initiative to reduce global methane emissions by at least 30 percent from 2020 levels by 2030.

• The agreement reached in Paris in December 2015 at the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change set out a process for achieving global emissions reductions.

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While the current administration has officially withdrawn the U.S.

from the Paris Agreement, some states have indicated that they plan to remain committed to the goals of the agreement.

from the Paris Agreement, some U.S.

states have indicated that they plan to remain committed to the goals of the agreement.

Regulated sustainability disclosures.

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The patchwork of reporting standards that is developing may require significant increases in disclosures, which may be costly to implement.

In March 2022 the U.S.

SEC proposed rule changes that would require registrants to include certain climate-related disclosures in their registration statements and periodic reports;

In January 2023 the EU finalized the Corporate Sustainability Reporting Directive that will require more detailed sustainability reporting;

In June 2023 the International Sustainability Standards Board issued inaugural sustainability reporting standards;

in October 2023 in California multiple bills were signed into law requiring climate-related disclosures for companies that conduct business in the state;

and in September 2024, the Australian Government passed legislation which mandated a new standard for climate-related disclosures.

ConocoPhillips 2024 10-K

Capital Resources and Liquidity

in September 2024, the Australian Government passed legislation which mandated a new standard for climate-related disclosures;

and in the EU, the Corporate Sustainability Reporting Directive is expected to be finalized in 2026.

Compliance with changes in laws and regulations that create a GHG tax, emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation.

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Company Response to Climate-Related Risks

The objective of our Climate Risk Strategy is to manage climate-related risk, optimize opportunities and equip the company to respond to changes in key uncertainties, including government policies around the world, technologies for emissions reduction, alternative energy technologies and changes in consumer trends.

The strategy sets out our choices around portfolio composition, emissions reductions, targets and incentives, emissions-related technology development, and our climate-related policy and finance sector engagement.

Our Climate Risk Strategy is intended to enable us to responsibly meet the global demand for energy, deliver competitive returns on and of capital and work to meet our previously established emissions-reduction targets.

First, meeting global energy demand requires a focus on delivering production that will best compete in any energy mix scenario.

This production will be delivered from resources with a competitive cost of supply and low GHG intensity, as well as portfolio diversity by market and asset type.

Next, in delivering competitive returns, ConocoPhillips has been a leader in shifting the exploration and production sector’s value proposition away from one focused on production toward one focused on returns.

Finally, to drive accountability for the emissions that are within our control, we are progressing toward our Scope 1 and Scope 2 emissions intensity targets.

The objective of our Climate-related Risk Strategy is to manage climate-related risk, optimize opportunities and equip the company to respond to changes in key uncertainties, including government policies around the world, emissions reduction technologies, alternative energy technologies and changes in consumer trends.

The strategy guides our choices around portfolio composition, emissions reductions, targets, incentives, emissions-related technology development, and our climate-related policy and finance sector engagement.

Our Climate-related Risk Strategy is intended to enable us to responsibly meet the global demand for energy, deliver competitive returns on and of capital and work to meet our operational emissions-reduction targets.

First, meeting global energy demand requires a focus on delivering production that will best compete in any energy demand scenario.

This production will be delivered from resources with a competitive cost of supply and low operational GHG intensity, as well as portfolio diversity by market and asset type.

Next, our focus is on delivering superior returns through the cycles based on our foundational principles of balance sheet strength, peer-leading distributions and disciplined investments.

ConocoPhillips 2025 10-K

Capital Resources and Liquidity

Key elements of the Climate Risk Strategy include:

to drive accountability for the emissions that are within our ownership, we are progressing toward our Scope 1 and Scope 2 emissions intensity targets.

Key elements of the Climate-related Risk Strategy include:

• Strategic flexibility and portfolio composition

◦ Building a resilient asset portfolio with a focus on low cost of supply and low GHG intensity to meet global energy demand.

◦ Building a resilient asset portfolio with a focus on low cost of supply and low operational GHG intensity to meet global energy demand.

◦ Committing to capital discipline through use of a fully burdened cost of supply, including cost of carbon, as the basis for capital allocation.

◦ Testing our portfolio against future energy demand scenarios through a comprehensive scenario planning process that helps us assess the resilience of our corporate strategy to climate risk.

• Scope 1 and 2 emissions targets and reductions

• Scope 1 and 2 GHG emissions targets and reductions

◦ Setting targets for emissions over which we have ownership and control.

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• External engagement

◦ Advocating for a well-designed, economy-wide price on carbon and engaging in development of other policy and legislation to address end-use emissions.

◦ Working with our suppliers and commercial partners to reduce emissions along the value chain.

Our Climate Risk Strategy does not include a Scope 3 emissions target.

◦ Supporting a well-designed, economy-wide price on carbon and development of other policy and legislation to address end-use emissions.

◦ Working with our suppliers and commercial partners to understand our emissions along the value chain.

Our Climate-related Risk Strategy does not include a Scope 3 emissions target.

We recognize that end-use emissions must be reduced to meet global climate objectives.

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In the absence of policy measures that address global demand, Scope 3 targets would shift production to other global operators, potentially eroding energy security and increasing emissions.

This is why we have consistently taken a prominent role in advocating for a well-designed, economy wide price on carbon and engaged in development of other policies or legislation that could address end-use emissions from high-carbon intensity energy use.

We have also expanded policy advocacy beyond carbon pricing to include energy efficiency, end-use emissions policy and regulatory action, such as support for the direct federal regulation of methane.

This is why we have consistently supported a well-designed, economy wide price on carbon as well as the development of other policies or legislation that could address end-use emissions.

We have also supported policy interests beyond carbon pricing to include energy efficiency, end-use emissions policy and regulatory action, such as support for the direct federal regulation of methane.

In support of addressing our Scope 1 and 2 emissions, we have made recent progress in several key areas.

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These projects will support our GHG emissions intensity reduction target of 50-60 percent by 2030 from a 2016 baseline for both gross operated and net equity emissions.

• Achieved the Gold Standard Reporting for emissions reporting in the Oil and Gas Methane Partnership 2.0 Initiative, one of only three U.S.

companies to earn this distinction.

• Remained on schedule to meet a target of zero routine flaring by the end of 2025 for heritage ConocoPhillips assets.

Our emissions reduction efforts are supported by our multi-disciplinary Low Carbon Technologies organization.

Risk Factors—Our ability to successfully execute on our plans to reduce our operationa l GHG emissions intensity is subject to a number of risks and uncertainties , and such reductions may be costly and challenging to achieve.

• Achieved the Gold Standard Reporting for emissions reporting in the Oil and Gas Methane Partnership 2.0 Initiative for the second consecutive year.

• Achieved our target of zero routine flaring by the end of 2025 for heritage ConocoPhillips assets by taking all economically viable steps to eliminate routine flaring in accordance with the World Bank Zero Routine Flaring Initiative.

• Introduced a new commitment to maintain flaring intensity of less than 0.75 percent of gas produced at operated assets, to be implemented in 2026.

Risk Factors—Our ability to successfully execute on our plans to reduce our operational GHG emissions intensity is subject to a number of risks and uncertainties, and such reductions may be costly and challenging to achieve.

New Accounting Standards

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This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively.

At year-end 2024, we held $14.7 billion of net capitalized unproved property costs, $10.8 billion of which was added this year through our acquisition of Marathon Oil.

At year-end 2025, we held $10.0 billion of net capitalized unproved property costs.

These capitalized costs consist primarily of individually significant and pooled leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently being drilled, suspended exploratory wells and capitalized interest.

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When estimating the fair value of unproved properties, additional risk-weighting adjustments are applied to probable and possible reserves.

The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgement and are based on industry, market and economic conditions prevalent at the time of the acquisition.

The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgment and are based on industry, market and economic conditions prevalent at the time of the acquisition.

Although we based these estimates on assumptions believed to be reasonable, these estimates are inherently unpredictable and uncertain and actual results could differ.

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Fair value is estimated using a present value approach, incorporating assumptions about estimated amounts and timing of settlements and impacts of the use of technologies.

Estimating future asset removal costs requires significant judgement.

Estimating future asset removal costs requires significant judgment.

Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs.

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This report includes 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.

All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, costs and plans, objectives of management for future operations, the anticipated benefits of our acquisition of Marathon Oil, the anticipated impact of our acquisition of Marathon Oil on the combined company’s business and future financial and operating results and the expected amount and timing of synergies from our acquisition of Marathon Oil are forward-looking statements.

Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning development or replacement of reserves and future dividends.

You can often identify our forward-looking statements by the words “ ambition ,” “ anticipate ,” “ believe ,” “ budget ,” “ continue ,” “ could ,” “ effort ,” “ estimate ,” “ expect ,” “ forecast ,” “ goal ,” “ guidance ,” “ intend ,” “ may ,” “ objective ,” “ outlook ,” “ plan ,” “ potential ,” “ predict ,” “ projection ,” “ seek ,” “ should ,” “ target ,” “ will ,” “ would ” and similar expressions.

We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general.

We based our forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general.

We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect or inaccurate, and involve risks and uncertainties we cannot predict.

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• Global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including changes as a result of any ongoing military conflict and the global response to such conflict;

geopolitical tensions;

security threats on facilities and infrastructure;

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• Broader societal attention to and efforts to address climate change may cause substantial investment in and increased adoption of competing or alternative energy sources.

• Risks, uncertainties and high costs that may prevent us from successfully executing on our Climate Risk Strategy.

• Risks, uncertainties and high costs that may prevent us from successfully executing on our Climate-related Risk Strategy.

• Lack or inadequacy of, or disruptions in, reliable transportation for our crude oil, bitumen, natural gas, LNG and NGLs.

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• Any limitations on our access to capital or increase in our cost of capital or insurance, including as a result of illiquidity, changes or uncertainty in domestic or international financial markets, foreign currency exchange rate fluctuations or investment sentiment.

• Challenges or delays to our execution of, or successful implementation of the acquisition of Marathon Oil or any future asset dispositions or acquisitions we elect to pursue;

• Challenges or delays to our execution of, or successful implementation of any future asset dispositions or acquisitions we elect to pursue;

potential disruption of our operations, including the diversion of management time and attention;

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis