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YoY shift: Neutral
Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is 0.05pp more bullish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
-
Not scored
Net-tone change vs last year's 10-K.
MD&A
+0.05pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
No section text extracted for this filing. The 10-K may use a non-standard template that the parser doesn't recognize - the original doc is still linked in the Stats tab.
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
loss+1
terminated+1
Positive rising
benefit+3
favorable+1
MD&A (Item 7)
11,064 words
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the notes included in Part IV of this Annual Report. Additional sections in this Annual Report should be helpful to the reading of our discussion and analysis, including the following: (i) a description of our business strategy found in “Item 1. Business–Overview”; (ii) a description of recent developments, found in “Item 1. Business–Recent Developments”; and (iii) a description of risk factors affecting us and our business, found in “Item 1A. Risk Factors.” Discussions of 2023 items and year-to-year comparisons between 2024 and 2023 that are not included in this Annual Report can be found in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2024.
We expect our results of operations to continue to be affected by the following key trends: commodity prices, volume throughput and demand for our products and services, contract terms and mix, the impact of our hedging activities, the cost to operate and support assets, volatile capital markets and competition. These expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Commodity Prices
There has been, and we believe there will continue to be, volatility in commodity prices and in the relationships among natural gas, NGL and crude oil prices. The volatility and uncertainty of natural gas, NGL and crude oil prices impact drilling, completion and other investment decisions by producers and ultimately supply to our systems. See “Item 1A. Risk Factors – Our cash flow is affected by supply and demand for natural gas, NGL products, and crude oil, and by natural gas, NGL, crude oil and condensate prices, and decreases in supply, demand or these prices could adversely affect our results of operations and financial condition.”
Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices. Our processing profitability is largely dependent upon pricing and the supply of and market demand for natural gas, NGLs and condensate, both of which are beyond our control. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. While we have a significant level of margin that we derive from fee-based arrangements across our operations and particularly for our assets in the Downstream Business, our contract mix, along with our commodity hedging program, serves to mitigate the impact of commodity price movements on our cash flows. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”
The following table presents selected average annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periods presented:
Natural Gas $/MMBtu (1)
Illustrative Targa NGL $/gal (2)
Crude Oil $/Bbl (3)
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
2025 Average
4th Quarter
3rd Quarter
2nd Quarter
1st Quarter
2024 Average
Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices.
“Illustrative Targa NGL” pricing is weighted using average quarterly prices from Mont Belvieu Non-TET monthly commercial index and represents the following composition for the periods noted:
2025: 44% ethane, 32% propane, 11% normal butane, 4% isobutane and 9% natural gasoline
2024: 44% ethane, 32% propane, 11% normal butane, 4% isobutane and 9% natural gasoline
Crude oil prices are based on average quarterly prices of West Texas Intermediate crude oil as measured on the NYMEX.
Volumes and Demand for our Services
Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related activity levels from our customers. In our gathering and processing operations, plant inlet volumes, crude oil volumes and capacity utilization rates generally are driven by wellhead production and our competitive and contractual position on a regional basis and more broadly by the impact of prices for crude oil, natural gas and NGLs on exploration and production activity in the areas of our operations. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Producers generally focus their drilling activity on certain basins depending on commodity price fundamentals. Our asset systems are predominantly located in some of the most economic basins in the United States.
The factors that impact the gathering and processing volumes also impact the total volumes that flow to our Downstream Business. Accordingly, increased producer activity will drive demand for our midstream services and may result in incremental growth capital expenditures. Demand for our transportation, fractionation and other fee-based services is largely correlated with producer activity levels. Demand for our international export, storage and terminaling services has remained relatively constant, as demand for these services is based on a number of domestic and international factors.
Contract Terms, Contract Mix and the Impact of Commodity Prices
Across our operations and particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices. The significant level of margin we derive from fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure to commodity price movements. Volatility in commodity prices can have a significant impact on our profitability, especially those percent-of-proceeds contracts that create direct exposure to changes in energy prices by paying us for gathering and processing services with a portion of proceeds from the commodities handled (“equity volumes”).
Contract terms in the Gathering and Processing segment are based upon a variety of factors, including natural gas and crude quality, geographic location, competitive dynamics and the pricing environment at the time the contract is executed, and customer requirements. Our gathering and processing contract mix and, accordingly, our exposure to crude, natural gas and NGL prices may change as a result of producer preferences, competition and changes in production as wells decline at different rates or are added, our expansion into regions where different types of contracts are more common and other market factors.
The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations. Transportation and fractionation services are supported by fee-based contracts whose rates and terms are driven by NGL supply and transportation and fractionation capacity. Export services are supported by fee-based contracts whose rates and terms are driven by global LPG supply and demand fundamentals. The Logistics and Transportation segment includes predominantly fee-based contracts.
Impact of Our Commodity Price Hedging Activities
We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk by entering into financially settled derivative transactions. These transactions include swaps, futures, and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We intend to continue managing our exposure to commodity prices in the future by entering into derivative transactions. We actively manage the Downstream Business product inventory and other working capital levels to reduce exposure to changing prices. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk–Commodity Price Risk.”
Operating Expenses
Variable costs such as service and repairs can impact our results. Continued expansion of existing assets will also give rise to additional operating expenses, which will affect our results. The employees supporting our operations are employees of Targa Resources LLC, a Delaware limited liability company, and a wholly-owned subsidiary of ours.
Volatile Capital Markets and Competition
We continuously consider and enter into discussions regarding potential growth projects and acquisitions and may contemplate external funding for potential growth projects and acquisitions. Any limitations on our access to capital may impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets may be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders. These factors may impair our ability to execute our growth and acquisition strategy.
Current economic conditions and competition for asset purchases and development opportunities could limit our ability to fully execute our growth strategy. Increased volatility in commodity prices and the broader market could negatively impact the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all. We believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures in 2026 and beyond. For additional information regarding our financing activities, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Liquidity and Capital Resources.”
How We Evaluate Our Operations
The profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for natural gas, NGLs and crude oil, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, and the volumes of natural gas, NGLs and crude oil throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.
Our profitability is also impacted by fee-based contracts. Our growing capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our Downstream facilities, continued focus on adding fee-based margin to our existing and future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability.
Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (i) throughput volumes, facility efficiencies and fuel consumption, (ii) operating expenses, (iii) capital expenditures and (iv) the following non-GAAP measures: adjusted EBITDA, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment).
Throughput Volumes, Facility Efficiencies and Fuel Consumption
Our profitability is impacted by our ability to add new sources of natural gas and crude oil supplies to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing natural gas and crude oil supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, connected by third-party transportation and our NGL pipeline system, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.
In addition, we seek to increase adjusted operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets and our NGL pipelines. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.
Operating Expenses
Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and inflation, and will fluctuate depending on the scope of the activities performed during a specific period.
Capital Expenditures
Our capital expenditures are classified as growth capital expenditures and maintenance capital expenditures. Growth capital expenditures improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance revenues. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.
Capital spend associated with growth and maintenance projects is closely monitored. Return on investment is analyzed before a capital project is approved, spend is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.
Non-GAAP Measures
We utilize non-GAAP measures to analyze our performance. Adjusted EBITDA, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.
Adjusted Operating Margin
We define adjusted operating margin for our segments as revenues less product purchases and fuel. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.
Gathering and Processing adjusted operating margin consists primarily of:
service fees related to natural gas and crude oil gathering, treating and processing; and
revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and our equity volume hedge settlements.
Logistics and Transportation adjusted operating margin consists primarily of:
service fees (including the pass-through of energy costs included in certain fee rates);
system product gains and losses; and
NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change.
The adjusted operating margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.
Adjusted operating margin for our segments provides useful information to investors because it is used as a supplemental financial measure by management and by external users of our financial statements, including investors and commercial banks, to assess:
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.
Management reviews adjusted operating margin and operating margin for our segments monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. The reconciliation of our adjusted operating margin to the most directly comparable GAAP measure is presented under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – By Reportable Segment.”
Adjusted EBITDA
We define adjusted EBITDA as Net income (loss) attributable to Targa Resources Corp. before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in the adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.
Adjusted Cash Flow from Operations and Adjusted Free Cash Flow
We define adjusted cash flow from operations as adjusted EBITDA less cash interest expense on debt obligations and cash tax (expense) benefit. We define adjusted free cash flow as adjusted cash flow from operations less maintenance capital expenditures and growth capital expenditures, net of any reimbursements of project costs and contributions from noncontrolling interests and including contributions to investments in unconsolidated affiliates. Adjusted cash flow from operations and adjusted free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.
Our Non-GAAP Financial Measures
The following table reconciles the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods presented:
Year Ended December 31,
(In millions)
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Adjusted Cash Flow from Operations and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.
Interest (income) expense, net
Income tax expense (benefit)
Depreciation and amortization expense
(Gain) loss on sale or disposition of assets
Write-down of assets
(Gain) loss from financing activities
Equity (earnings) loss
Distributions from unconsolidated affiliates
Compensation on equity grants
Risk management activities
Noncontrolling interests adjustments (1)
Litigation and environmental reserves (2)
Adjusted EBITDA
Interest expense on debt obligations (3)
Cash tax (expense) benefit
Adjusted Cash Flow from Operations
Maintenance capital expenditures, net (4)
Growth capital expenditures, net (4)
Adjusted Free Cash Flow
Represents adjustments related to our subsidiaries with noncontrolling interests, including depreciation and amortization expense as well as earnings for certain plants within our WestTX joint venture not subject to noncontrolling interest accounting.
Litigation and environmental reserves includes charges related to specific litigation and environmental compliance matters that are nonrecurring in nature and outside the ordinary course of our business and/or not reflective of our ongoing core operations. We may incur such charges from time to time, and we believe it is useful to exclude these charges as we do not consider them reflective of our ongoing core operations.
Excludes amortization recognized in interest expense. The year ended December 31, 2024 includes $55.8 million of interest expense on a 2024 legal ruling associated with an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview LLC, then a subsidiary of the Company, and Noble Americas Corp (the “Splitter Agreement”).
Represents capital expenditures, net of any reimbursements of project costs and contributions from noncontrolling interests and includes contributions to investments in unconsolidated affiliates.
Consolidated Results of Operations
The following table and discussion is a summary of our consolidated results of operations for the periods presented:
Year Ended December 31,
(In millions)
Revenues:
Sales of commodities
Fees from midstream services
Total revenues
Product purchases and fuel
Operating expenses
Depreciation and amortization expense
General and administrative expense
Other operating (income) expense
Income (loss) from operations
Interest expense, net
Equity earnings (loss)
Other, net
Income tax (expense) benefit
Net income (loss)
Less: Net income (loss) attributable to noncontrolling interests
Net income (loss) attributable to Targa Resources Corp.
Premium on repurchase of noncontrolling interests, net of tax
Net income (loss) attributable to common shareholders
Financial data:
Adjusted EBITDA (1)
Adjusted cash flow from operations (1)
Adjusted free cash flow (1)
Adjusted EBITDA, adjusted cash flow from operations and adjusted free cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations–How We Evaluate Our Operations.”
NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.
2025 Compared to 2024
The increase in commodity sales reflected higher natural gas prices ($766.2 million), higher NGL and natural gas volumes ($518.7 million) and the favorable impact of hedges ($85.0 million), partially offset by lower NGL and condensate prices ($860.2 million).
The increase in fees from midstream services was primarily due to higher gas gathering and processing fees, and higher export volumes, partially offset by lower transportation and fractionation fees. Lower transportation and fractionation fees were due to a planned turnaround at a portion of our facilities in Mont Belvieu, Texas.
The decrease in product purchases and fuel reflected lower NGL prices, partially offset by higher natural gas prices, and higher NGL and natural gas volumes.
The increase in operating expenses was primarily due to higher labor, taxes and maintenance costs as a result of system expansions.
See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.
The increase in depreciation and amortization expense was primarily due to the impact of system expansions on our asset base.
The increase in general and administrative expense was primarily due to higher compensation and benefits.
The increase in other operating (income) expense was primarily due to recognition of Section 45Q tax credits earned through our carbon capture and sequestration activities.
The increase in interest expense, net, was primarily due to higher borrowings in 2025, partially offset by the recognition of cumulative interest on a legal ruling associated with the Splitter Agreement in 2024.
The increase in income tax (expense) benefit was primarily due to the increase in pre-tax book income and a decrease in income allocated to noncontrolling interest that is not taxable to the Company.
The decrease in net income attributable to noncontrolling interests was primarily due to the Badlands Transaction in the first quarter of 2025 and the acquisition of the remaining membership interest in CBF (the “CBF Acquisition”) in the fourth quarter of 2024.
The premium on repurchase of noncontrolling interests, net of tax was due to the Badlands Transaction in 2025 and the CBF Acquisition in 2024.
Results of Operations—By Reportable Segment
The following table presents our operating margins by reportable segment:
Gathering and Processing
Logistics and Transportation
Other
(In millions)
Year Ended:
December 31, 2025
December 31, 2024
Gathering and Processing Segment
Year Ended December 31,
(In millions, except operating statistics and price amounts)
Operating margin
Operating expenses
Adjusted operating margin
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2) (3)
Permian Midland (4)
Permian Delaware
Total Permian
Central (5)
Badlands (5) (6)
Coastal
Total
NGL production, MBbl/d (3)
Permian Midland (4)
Permian Delaware
Total Permian
Central (5)
Badlands (5)
Coastal
Total
Crude oil gathered, MBbl/d
Natural gas sales, BBtu/d (3)
NGL sales, MBbl/d (3)
Condensate sales, MBbl/d
Average realized prices (7):
Natural gas, $/MMBtu
NGL, $/gal
Condensate, $/Bbl
Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than Badlands.
Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.
Permian Midland includes operations in WestTX, of which we own a 72.8% undivided interest, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.
Operations include facilities that are not wholly-owned by us. For more information regarding our joint ventures and jointly owned facilities, see “Item 1. Business—Our Business Operations.”
Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the LM4 plant.
Average realized prices, net of fees, include the effect of realized commodity hedge gain/loss attributable to our equity volumes. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator, net of fees.
The following table presents the realized commodity hedge gain (loss) attributable to our equity volumes that are included in the adjusted operating margin of the Gathering and Processing segment:
Year Ended December 31, 2025
Year Ended December 31, 2024
(In millions, except volumetric data and price amounts)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Volume
Settled
Price
Spread (1)
Gain
(Loss)
Natural gas (BBtu)
NGL (MMgal)
Crude oil (MBbl)
The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
2025 Compared to 2024
The increase in adjusted operating margin was predominantly due to higher natural gas inlet volumes in the Permian, partially offset by lower volumes in other areas. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Roadrunner II plant during the second quarter of 2024, the Greenwood II plant during the fourth quarter of 2024, the Bull Moose plant during the first quarter of 2025, the Pembrook II plant during the third quarter of 2025, the Bull Moose II plant during the fourth quarter of 2025, and continued strong producer activity.
The increase in operating expenses was primarily due to higher volumes and multiple plant additions in the Permian.
Logistics and Transportation Segment
Year Ended December 31,
(In millions, except operating statistics)
Operating margin
Operating expenses
Adjusted operating margin
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)
Fractionation volumes
Export volumes (3)
NGL sales
Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
Represents the total quantity of mixed NGLs that earn a transportation margin.
Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.
2025 Compared to 2024
The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin and higher marketing margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems, the addition of Train 9 during the second quarter of 2024, the addition of the Daytona NGL Pipeline during the third quarter of 2024, and the addition of Train 10 during the fourth quarter of 2024. Marketing margin increased due to greater optimization opportunities.
The increase in operating expenses was predominantly due to system expansions and planned maintenance.
Other
Year Ended December 31,
(In millions)
Operating margin
Adjusted operating margin
Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. We have entered into derivative instruments to hedge the commodity price associated with a portion of our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Transportation segment. See further details of our risk management program in “Item 7A. – Quantitative and Qualitative Disclosures About Market Risk.”
Our Liquidity and Capital Resources
As of December 31, 2025, inclusive of our consolidated joint venture accounts, we had $166.1 million of Cash and cash equivalents on our Consolidated Balance Sheets. On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRGP Revolver, the Commercial Paper Program, the Securitization Facility, and access to debt and equity capital markets. We have the ability to supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.
We believe our sources of liquidity and capital resources are sufficient to meet our anticipated cash requirements for at least the next twelve months to satisfy our obligations, including our day-to-day operations, growth capital expenditures, dividend payments, maintenance capital expenditures, debt service and other anticipated obligations. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, see “Recent Developments.”
Short-term Liquidity
Our principal sources of short-term liquidity consist of internally generated cash flow, borrowings available under the TRGP Revolver, as well as our right to request additional commitment increases under the TRGP Revolver, the Commercial Paper Program, the Securitization Facility, proceeds from debt and equity offerings, and joint ventures and/or asset sales. Based on anticipated levels of operations and absent any disruptive events, we believe our liquidity is sufficient to finance our operations, capital expenditures, quarterly cash dividends and obligations, as discussed further below, for at least the next twelve months.
Our short-term liquidity on a consolidated basis as of January 31, 2026 was:
Consolidated Total
(In millions)
Cash on hand (1)
Total availability under the Securitization Facility
Total availability under the TRGP Revolver and Commercial Paper Program
Outstanding borrowings under the Securitization Facility
Outstanding borrowings under the TRGP Revolver and Commercial Paper Program
Outstanding letters of credit under the TRGP Revolver
Total liquidity
Includes cash held in our consolidated joint venture accounts.
Other potential capital resources associated with our existing arrangements include our right to request an additional $500.0 million in commitment increases under the TRGP Revolver, subject to the terms therein. The TRGP Revolver matures on February 18, 2030. The maturity date is extendable, subject to the lenders’ consent, by one year up to two times.
In July 2025, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to August 31, 2026.
On January 6, 2026, we used $650.0 million in borrowings from the Commercial Paper Program and $600.0 million from the Securitization Facility to fund the Stakeholder Acquisition.
A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. As of December 31, 2025, we had $20.0 million in letters of credit outstanding under the TRGP Revolver. The letters of credit also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.
Working Capital
Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels, which we closely manage, as well as liquids valuations; (iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as certain organic growth capital projects and acquisitions or divestitures.
Our working capital as of December 31, 2025 decreased $307.8 million compared to December 31, 2024. The decrease was primarily due to higher current debt obligations as a result of the reclassification of the 6.875% Notes due 2029 from Long-term debt in our Consolidated Balance Sheets in November 2025, higher payable balances due to capital spending on growth projects and lower trade receivables resulting from lower NGL prices. The decrease was partially offset by a lower outstanding balance on the Securitization Facility, lower product purchases and fuel payables resulting from lower NGL prices and a higher NGL inventory balance. See discussion below about our financing activities.
Long-term Financing
Our long-term financing consists of potentially raising funds through long-term debt obligations, the issuance of common stock, preferred stock, or joint venture arrangements. The majority of our debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRGP Revolver, Securitization Facility, and Commercial Paper Program. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of December 31, 2025, we did not have any interest rate hedges.
In February 2025, we entered into the TRGP Revolver, which provides for a revolving credit facility in an initial aggregate principal amount up to $3.5 billion (with an option to increase such maximum aggregate principal amount by up to $500.0 million in the future, subject to the terms of the TRGP Revolver) and a swing line sub-facility of up to $150.0 million. In connection with our entry into the TRGP Revolver, we terminated the Previous TRGP Revolver.
In February 2025, we completed an underwritten public offering of the 5.550% Notes due 2035 and the 6.125% Notes 2055, resulting in net proceeds of approximately $2.0 billion. We used a portion of the net proceeds from the debt issuance to fund the Badlands Transaction and for general corporate purposes, including to repay borrowings under the Commercial Paper Program.
In June 2025, we completed an underwritten public offering of the 4.900% Notes due 2030 and the 5.650% Notes due 2036, resulting in net proceeds of approximately $1.5 billion. We used a portion of the net proceeds from the debt issuance to fund the redemption of all of the Partnership’s 6.500% Notes due 2027 in July 2025, and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.
In November 2025, we completed an underwritten public offering of the 4.350% Notes due 2029 and the 5.400% Notes due 2036, resulting in net proceeds of approximately $1.7 billion. We used a portion of the net proceeds from the debt issuance to fund the redemption of all of the Partnership’s 6.875% Notes due 2029 in January 2026, and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.
In the future, we or the Partnership may redeem, purchase or exchange certain of our and/or the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness.
For information about our debt obligations, see “Note 8 – Debt Obligations” to our Consolidated Financial Statements. For information about our interest rate risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”
Compliance with Debt Covenants
As of December 31, 2025, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.
Cash Flow Analysis
Cash Flows from Operating Activities
Year Ended December 31,
(In millions)
The primary drivers of cash flows from operating activities are: (i) the collection of cash from customers from the sale of NGLs and natural gas, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation; (ii) the payment of amounts related to the purchase of NGLs and natural gas; and (iii) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.
The increase in net cash provided by operating activities was primarily due to higher collections from customers resulting from increased revenues in 2025 compared to 2024, partially offset by an increase in payments for product purchases, operating costs and interest on debt. In addition, during 2024 we made a nonrecurring one-time payment associated with the Splitter Agreement.
Cash Flows from Investing Activities
Year Ended December 31,
(In millions)
The increase in net cash used in investing activities was due to higher outlays for major growth capital projects in 2025 primarily related to construction activities, outlays for the acquisitions completed in 2025, and an increase in contributions to unconsolidated affiliates.
Cash Flows from Financing Activities
Year Ended December 31,
(In millions)
Source of Financing Activities, net
Debt, including financing costs
Repurchase of noncontrolling interests
Dividends paid to common shareholders
Contributions from (distributions to) noncontrolling interests, net
Repurchases of shares
Net cash provided by (used in) financing activities
The decrease in net cash used in financing activities was due to higher proceeds from debt financings in 2025, lower distributions to noncontrolling interests subsequent to the CBF Acquisition in the fourth quarter of 2024 and the Badlands Transaction in the first quarter of 2025 and lower repurchases of common stock, partially offset by higher repurchases of noncontrolling interests due to the Badlands Transaction and higher dividends paid in 2025.
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
Our subsidiaries that guarantee our obligations under the TRGP Revolver (the “Obligated Group”) also fully and unconditionally guarantee, jointly and severally, the payment of TRGP’s senior unsecured notes, subject to certain limited exceptions.
In lieu of providing separate financial statements for the Obligated Group, we have presented the following supplemental summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.
All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in our non-guarantor subsidiaries have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including our non-guarantor subsidiaries (referred to as “affiliates”), are presented separately in the following supplemental summarized combined financial information.
Summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group as of the end of the most recent period presented follows:
Summarized Combined Statement of Operations Information
Year Ended December 31,
(In millions)
Operating income (loss)
Net income (loss)
Common Stock Dividends
The following table details the dividends declared and/or paid by us to common shareholders for 2025:
Three Months Ended
Date Paid or
To Be Paid
Total Common
Dividends Declared
Amount of Common
Dividends Paid or
To Be Paid
Dividends on
Share-Based Awards
Dividends Declared per Share of Common Stock
(In millions, except per share amounts)
December 31, 2025
February 13, 2026
September 30, 2025
November 17, 2025
June 30, 2025
August 15, 2025
March 31, 2025
May 15, 2025
The actual amount we declare as dividends in the future depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our Board of Directors deems relevant.
Capital Expenditures
The following table details cash outlays for capital projects for the periods presented:
Year Ended December 31,
(In millions)
Capital expenditures:
Growth (1)
Maintenance (2)
Gross capital expenditures
Change in capital project payables and accruals, net
Cash outlays for capital projects
Growth capital expenditures, net of contributions from noncontrolling interests and including contributions to investments in unconsolidated affiliates, were $3,343.5 million and $3,000.4 million for the years ended December 31, 2025 and 2024.
Maintenance capital expenditures, net of contributions from noncontrolling interests, were $226.4 million and $231.9 million for the years ended December 31, 2025 and 2024.
The increase in growth capital expenditures was primarily due to expansions in our Gathering and Processing and Downstream Business.
Off-Balance Sheet Arrangements
As of December 31, 2025, there were $65.2 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.
We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see “Note 7 – Investments in Unconsolidated Affiliates” and “Note 8 – Debt Obligations” to our Consolidated Financial Statements.
Contractual Obligations
We believe we have sufficient liquidity to fund our operations and meet our short-term and long-term cash obligations. The following table is a summary of our material future contractual cash obligations as of December 31, 2025:
Contractual Obligations:
Total
Within 12 Months
(in millions)
Long-term debt obligations (1)
Interest on debt obligations (2)
Operating leases (3)
Finance leases (4)
Land site lease and rights of way (5)
Purchase obligations (6)
Other
Total
Represents scheduled future maturities of long-term debt obligation and excludes the Securitization Facility. See “Note 8 - Debt Obligations” to our Consolidated Financial Statements for more information.
Represents interest expense on long-term debt obligations based on both fixed debt interest rates and prevailing December 31, 2025 rates for floating debt. See “Note 8 - Debt Obligations” to our Consolidated Financial Statements for more information.
Includes minimum payments on operating lease obligations for compressors, office space and railcars. See “Note 10 - Leases” to our Consolidated Financial Statements for more information.
Includes minimum payments on finance lease obligations for compressors, vehicles, generators, substations and tractors. See “Note 10 - Leases” to our Consolidated Financial Statements for more information.
Land site lease and rights of way provide for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates with varying terms, some of which are perpetual. See “Note 16 - Commitments” to our Consolidated Financial Statements for more information.
Includes commitments for pipeline capacity payments for firm transportation and throughput and deficiency agreements, purchase of natural gas and NGLs, capital expenditures, operating expenses and service contracts. Contracts that will be settled at future spot prices are valued using prices as of December 31, 2025.
Critical Accounting Policies and Estimates
The accounting policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.
Business Acquisitions
For business acquisitions, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the acquisition date. Goodwill results when the cost of a business acquisition exceeds the fair value of the net identifiable assets of the acquired business. Determining fair value requires management’s judgment and involves the use of significant estimates and assumptions with respect to projections of future production volumes, pricing and cash flows, benchmark analysis of comparable public companies, discount rates, expectations regarding customer contracts and relationships, and other management estimates. The judgments made in the determination of the estimated fair value assigned to the assets acquired, liabilities assumed and any noncontrolling interest in the investee, the duration of each liability, and any resulting goodwill can materially impact the financial statements in periods after acquisition.
Depreciation of Property, Plant and Equipment and Amortization of Intangible Assets
Depreciation of our property, plant and equipment is computed using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. The determination of useful lives of property, plant and equipment requires us to make various assumptions, including our expected use of the asset and the supply of and demand for hydrocarbons in the markets served, normal wear and tear of facilities, and the extent and frequency of maintenance programs.
We amortize the costs of our intangible assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis where such pattern is not readily determinable, over the periods in which we benefit from services provided to customers. At the time assets are placed in service or acquired, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation/amortization amounts prospectively.
Impairment of Long-Lived Assets, including Intangible Assets
We evaluate long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate our carrying amount of an asset may not be recoverable, including changes to our estimates that could have an impact on our assessment of asset recoverability. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. These cash flow estimates require us to make judgments and assumptions related to operating and cash flow results, economic obsolescence, the business climate, contractual, legal and other factors.
If the carrying amount exceeds the expected future undiscounted cash flows, we recognize a non-cash pre-tax impairment charge equal to the excess of net book value over fair value. The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs and the use of an appropriate terminal value and discount rate. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our long-lived assets and the recognition of additional impairments.
Price Risk Management (Hedging)
Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. In an effort to reduce the volatility of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL, and condensate equity volumes, future commodity purchases and sales, and transportation basis risk.
One of the factors that can affect our operating results each period is the price assumptions used to value our derivative financial instruments, which are reflected at their fair values on the balance sheet. We determine the fair value of our derivative instruments using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. Changes in the methods or assumptions we use to calculate the fair value of our derivative instruments could have a material effect on our consolidated financial statements.
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see “Note 3 – Significant Accounting Policies” to our Consolidated Financial Statements.
Item 7A. Quantitative and Qualitati ve Disclosures About Market Risk
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our risk management counterparties and customers.
Risk Management
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. All of our commodity derivatives are with major financial institutions or major energy companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.
The prices for natural gas, NGLs and crude oil are volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk through 2029. Market conditions may also impact our ability to enter into future commodity derivative contracts.
Commodity Price Risk
A portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of commodities as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Both the realized settlements for a derivative instrument designated as a hedge and the related cash flows are classified in the same category as the item being hedged within the Consolidated Statement of Operations and within the Consolidated Statements of Cash Flows.
The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of December 31, 2025, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. We also enter into commodity financial instruments to help manage other short-term commodity-related business risks of our ongoing operations and in conjunction with marketing opportunities available to us in the operations of our logistics and transportation assets. With swaps, we typically receive an agreed fixed price for a specified notional quantity of commodities and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected equity volumes. We may utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.
When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The fair values of our natural gas and NGL hedges are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on NYMEX futures contracts for West Texas Intermediate light, sweet crude.
A majority of these commodity price hedges are documented pursuant to a standard International Swaps and Derivatives Association (“ISDA”) form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. While we have no current obligation to post cash, letters of credit or other additional collateral to secure these hedges so long as we maintain our current credit rating, we could be obligated to post collateral to secure the hedges in the event of an adverse change in our creditworthiness where a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.
We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas, NGL or crude oil prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.
These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls).
To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. The sensitivity analysis measures the change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does not reflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement impact on the fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a corresponding gain or loss on the hedged item under hedge accounting. The fair values of our derivative instruments are also influenced by changes in market volatility for option contracts and the discount rates used to determine the present values.
The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of December 31, 2025:
Fair Value
Result of 10% Price Decrease
Result of 10% Price Increase
(In millions)
Natural gas
NGL
Crude oil
Total
The table above contains all derivative instruments outstanding as of the stated date for the purpose of hedging commodity price risk, which we are exposed to due to our equity volumes and future commodity purchases and sales, as well as basis differentials related to our gas transportation arrangements.
Our operating revenues increased (decreased) by $(160.3) million and $(245.4) million during the years ended December 31, 2025 and 2024, respectively, as a result of transactions accounted for as derivatives. The estimated fair value of our risk management position has moved from a net liability position of $172.2 million at December 31, 2024 to a net liability position of $66.9 million at December 31, 2025. The net liability position on our derivative contracts is primarily attributable to unfavorable movement in natural gas forward basis prices.
Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRGP Revolver, the Commercial Paper Program and the Securitization Facility. As of December 31, 2025, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRGP Revolver, the Commercial Paper Program and the Securitization Facility will also increase. As of December 31, 2025, we had $161.0 million in outstanding variable rate borrowings. A hypothetical change of 100 basis points in the rate of our variable interest rate debt would impact our consolidated annual interest expense by $1.6 million based on our December 31, 2025 debt balances.
Counterparty Credit Risk
We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the ISDA agreements with our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and reduce our maximum loss due to counterparty credit risk by $6.2 million as of December 31, 2025. The range of losses attributable to our individual counterparties as of December 31, 2025 would be between $0.1 million and $14.9 million, depending on the counterparty in default.
Customer Credit Risk
We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.
We have an active credit management process, which is focused on controlling loss exposure due to bankruptcies or other liquidity issues of counterparties. Our allowance for credit losses was $0.7 million and $2.5 million as of December 31, 2025 and 2024, respectively.
During the years ended December 31, 2025 and 2024, no customer comprised 10% or greater of our consolidated revenues.
Item 8. Financial Statemen ts and Supplementary Data
Our “Consolidated Financial Statements,” together with the report of our independent registered public accounting firm, begin on page F-1 in this Annual Report.
