Targa Resources Corp. (TRGP) Business

Item 1. Business

The following section of this Form 10-K generally refers to business developments during the year ended December 31, 2025. Discussion of prior period business developments that are not included in this Form 10-K can be found in “Part I, Item 1. Business” of our Annual Report on Form 10-K for the year ended December 31, 2024.

Overview

Targa Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream services and is one of the largest independent infrastructure companies in North America. We own, operate, acquire, and develop a diversified portfolio of complementary domestic infrastructure assets.

Our Operations

We are engaged primarily in the business of:

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gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas;

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transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and

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gathering, storing, terminaling, and purchasing and selling crude oil.

To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as our Downstream Business).

Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast.

Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes our NGL pipeline system, which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. Our Downstream facilities are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.

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The map below highlights our more significant assets as of December 31, 2025:

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Recent Developments

Permian Basin Processing Expansions

In response to increasing production and to meet the infrastructure needs of our customers, our new 275 MMcf/d cryogenic natural gas processing plant additions include:

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Bull Moose plant in Permian Delaware (the “Bull Moose plant”), commenced operations in the first quarter of 2025.

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Pembrook II plant in Permian Midland (the “Pembrook II plant”), commenced operations in the third quarter of 2025.

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Bull Moose II plant in Permian Delaware (the “Bull Moose II plant”), commenced operations in the fourth quarter of 2025.

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East Pembrook plant in Permian Midland (the “East Pembrook plant”), expected to begin operations in the second quarter of 2026.

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Falcon II plant in Permian Delaware (the “Falcon II plant”), expected to begin operations in the first quarter of 2026.

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East Driver plant in Permian Midland (the “East Driver plant”), expected to begin operations in the third quarter of 2026.

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Copperhead plant in Permian Delaware (the “Copperhead plant”), expected to begin operations in the first quarter of 2027.

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Yeti plant in Permian Delaware (the “Yeti plant”), expected to begin operations in the third quarter of 2027.

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Yeti II plant in Permian Delaware (the “Yeti II plant”), expected to begin operations in the fourth quarter of 2027.

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In February 2026, we announced we are ordering long-lead items for our next potential natural gas processing plants across the Permian Basin.

Fractionation Expansions

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In January 2023, we reached an agreement with our partners in Gulf Coast Fractionators (“GCF”) to reactivate GCF’s 135 MBbl/d fractionation facility. GCF commenced operations in the first quarter of 2025.

Our new 150 MBbl/d fractionation train additions include:

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Train 11 in Mont Belvieu, Texas (“Train 11”), expected to begin operations in the second quarter of 2026.

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Train 12 in Mont Belvieu, Texas (“Train 12”), expected to begin operations in the first quarter of 2027.

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Train 13 in Mont Belvieu, Texas (“Train 13”), expected to begin operations in the first quarter of 2028.

NGL Pipeline Expansions

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In February 2025, we announced an intra-Delaware Basin expansion of our NGL pipeline system, (“Delaware Express”) in Permian Delaware. The expansion is expected to begin operations in the second quarter of 2026.

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In September 2025, we announced plans to construct the Speedway NGL Pipeline (“Speedway”) which will transport NGLs from our existing assets and future plant additions in the Permian Basin to our fractionation and storage complex in Mont Belvieu, Texas. The project consists of approximately 500 miles of 30-inch diameter pipeline and associated infrastructure with an initial capacity of approximately 500 MBbl/d, expandable to 1,000 MBbl/d. Speedway is expected to begin operations in the third quarter of 2027.

LPG Export Expansion

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In February 2025, we announced an expansion of our LPG export capabilities at our Galena Park Marine Terminal, (“the GPMT LPG Export Expansion”) to include the addition of a new pipeline from Mont Belvieu to Galena Park and additional refrigeration. Our effective export capacity will increase up to 19 MMBbl per month, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors. The GPMT LPG Export Expansion is expected to be completed in the third quarter of 2027.

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Natural Gas Pipelines

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In August 2025, we announced a 43-mile extension of our Bull Run intrastate natural gas pipeline (the “Bull Run Extension”) to expand and enhance connectivity of our Permian Delaware system to the Waha hub in West Texas. The Bull Run Extension is expected to begin operations in the first quarter of 2027.

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In September 2025, we announced a new 35-mile intrastate natural gas pipeline that will enhance connectivity across several of our plants in the Permian Midland and a 55-mile conversion of an existing Targa pipeline into natural gas service (together, “Buffalo Run”) that will connect our Permian Midland and Permian Delaware intra-basin natural gas systems. Buffalo Run is expected to be completed in stages and fully complete in early 2028.

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In November 2025, we announced the Forza Pipeline (“Forza”), a new 36-mile interstate natural gas pipeline in Permian Delaware that will connect our new and existing gas plants and enhance connectivity to the Waha hub. Forza filed a certificate application on December 3, 2025, with the FERC and, pending receipt of necessary regulatory approvals, is expected to begin operations in the middle of 2028.

Acquisitions and Joint Ventures

In July 2024, we entered into a joint venture (“Blackcomb Joint Venture”) which will construct the Blackcomb pipeline. The Blackcomb Joint Venture is owned 70.0% by WPC, 17.5% by Targa, and 12.5% by MPLX LP. WPC is a joint venture owned 50.6% by WhiteWater Midstream LLC (“WhiteWater”), 30.4% by MPLX LP, and 19.0% by Enbridge Inc. The Blackcomb pipeline is designed to transport up to 2.5 Bcf/d of natural gas through approximately 365 miles of 42-inch pipeline from the Permian Basin in West Texas to the Agua Dulce area in South Texas and is expected to be in service in the fourth quarter of 2026, pending the receipt of customary regulatory and other approvals.

In April 2025, WhiteWater announced the Blackcomb Joint Venture reached a final investment decision to construct the Traverse pipeline. The bi-directional Traverse pipeline is designed to transport up to 2.5 Bcf/d of natural gas through approximately 160 miles of pipeline between the Agua Dulce area and the Katy area and is expected to be in service in 2027, pending the receipt of customary regulatory and other approvals. Both the Blackcomb and Traverse pipelines will be operated by an affiliate of WhiteWater.

In March 2025, we completed the acquisition of Blackstone’s 45% interest in Targa Badlands LLC (“Targa Badlands”) for aggregate consideration of $1.8 billion in cash (the “Badlands Transaction”). As a result of the acquisition, we own 100% of the interests in and earnings of Targa Badlands effective January 1, 2025.

On January 6, 2026, we completed the acquisition of Stakeholder Midstream, LLC for $1.25 billion in cash (the “Stakeholder Acquisition”). We acquired a portfolio of complementary Permian Basin midstream infrastructure assets, including approximately 480 miles of natural gas pipelines, approximately 180 MMcf/d of cryogenic natural gas processing and sour treating capacity, carbon capture activities generating 45Q tax credits, and a small crude oil gathering system. The acquisition has an effective date of January 1, 2026.

For additional information, see “Note 4 – Acquisitions and Joint Ventures” to our Consolidated Financial Statements.

Capital Allocation

In April 2025, we declared an increase to our quarterly common dividend to $1.00 per common share, or $4.00 per common share annualized, effective for the first quarter of 2025.

In May 2023, our Board of Directors approved a $1.0 billion common share repurchase program (the “2023 Share Repurchase Program”). During the first quarter of 2025, we exhausted the 2023 Share Repurchase Program.

In July 2024, our Board of Directors approved a $1.0 billion common share repurchase program (the “2024 Share Repurchase Program”). In addition, in August 2025, our Board of Directors approved a new $1.0 billion common share repurchase program (the “2025 Share Repurchase Program” and, together with the 2024 Share Repurchase Program, the “Share Repurchase Programs”). We are not obligated to repurchase any specific dollar amount or number of shares under the Share Repurchase Programs and may discontinue these programs at any time.

In the fourth quarter of 2025 and for the year ended December 31, 2025, we repurchased 226,987 and 3,765,272 shares of our common stock at a weighted average per share price of $163.01 and $170.45 for a total net cost of $37.0 million and $641.8 million, respectively. As of December 31, 2025, there was $1,373.6 million remaining under the Share Repurchase Programs.

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Financing Activities

In February 2025, we entered into a new $3.5 billion TRGP senior revolving credit facility (the “TRGP Revolver”), which provides for a revolving credit facility in an initial aggregate principal amount up to $3.5 billion and matures on February 18, 2030. The maturity date is extendable, subject to the lenders’ consent, by one year up to two times. In connection with our entry into the TRGP Revolver, we terminated our previous revolving credit facility (the “Previous TRGP Revolver”).

In February 2025, we completed an underwritten public offering of (i) $1.0 billion aggregate principal amount of our 5.550% Senior Unsecured Notes due 2035 (the “5.550% Notes due 2035”) and (ii) $1.0 billion aggregate principal amount of our 6.125% Senior Unsecured Notes due 2055 (the “6.125% Notes due 2055”), resulting in net proceeds of approximately $2.0 billion. The 5.550% Notes due 2035 and 6.125% Notes due 2055 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. We used a portion of the net proceeds from the debt issuance to fund the Badlands Transaction and the remaining net proceeds for general corporate purposes, including to repay borrowings under our unsecured commercial paper note program (the “Commercial Paper Program”).

In June 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.900% Senior Unsecured Notes due 2030 (the “4.900% Notes due 2030”) and (ii) $750.0 million aggregate principal amount of our 5.650% Senior Unsecured Notes due 2036 (the “5.650% Notes due 2036”), resulting in net proceeds of approximately $1.5 billion. The 4.900% Notes due 2030 and 5.650% Notes due 2036 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. We used a portion of the net proceeds from the debt issuance to fund the redemption of all of the Partnership’s 6.500% Senior Unsecured Notes due 2027 (the “6.500% Notes due 2027”) on July 15, 2025, and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

In July 2025, the Partnership amended the $600.0 million accounts receivable securitization facility (the “Securitization Facility”) to, among other things, extend the facility termination date to August 31, 2026.

In November 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.350% Senior Unsecured Notes due 2029 (the “4.350% Notes due 2029”) and (ii) $1.0 billion aggregate principal amount of our 5.400% Senior Unsecured Notes due 2036 (the “5.400% Notes due 2036”), resulting in net proceeds of approximately $1.7 billion. The 4.350% Notes due 2029 and 5.400% Notes due 2036 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our subsidiaries that guarantee the TRGP Revolver, so long as such subsidiary guarantors satisfy certain conditions. We used a portion of the net proceeds from the debt issuance to fund the redemption of all of the Partnership’s 6.875% Senior Unsecured Notes due 2029 (the “6.875% Notes due 2029”) on January 15, 2026, and the remaining net proceeds for general corporate purposes, including to repay borrowings under the Commercial Paper Program.

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.

For additional information about our recent debt-related transactions, see “Note 8 – Debt Obligations” to our Consolidated Financial Statements.

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Organization Structure

The diagram below shows our corporate structure as of February 19, 2026:

(1)
Common shares outstanding as of February 13, 2026.

Growth Drivers, Competitive Strengths and Strategies

While we believe that we are well positioned to execute our business strategies based on our growth drivers, competitive strengths and strategies outlined below, our business involves numerous risks and uncertainties which may prevent us from executing our strategies. These risks include the adverse impact of changes in natural gas, NGL and condensate/crude oil prices, the supply of, or demand for, these commodities, and our inability to access sufficient additional supplies to replace natural declines in production. For a more complete description of the risks associated with an investment in us, see “Item 1A. Risk Factors.”

Comprehensive package of midstream services

We provide a comprehensive package of services to natural gas and crude oil producers. These services are essential to gather, treat, process, purchase and sell and transport wellhead gas to meet pipeline standards; extract, transport and fractionate NGLs for sale into petrochemical, industrial, commercial and export markets; and gather and/or purchase and sell crude oil. We believe that our ability to offer these integrated services provides us with an advantage in competing for new supplies because we can provide substantially all of the services that producers, marketers and others require for moving natural gas, NGLs and crude oil from wellhead to market on a cost-effective basis. Additionally, we believe that the significant investment we have made to construct and acquire assets in key strategic positions and the expertise we have in operating such assets make us well-positioned to remain a leading provider of integrated services in the midstream sector.

Our transportation assets further enhance our integrated midstream service offerings across the NGL and natural gas value chain by linking supply to key markets. Our NGL pipeline system connects many of our gathering and processing positions, including the Permian Basin, with our Downstream facilities in Mont Belvieu, Texas, the major U.S. NGL market hub. Additionally, our integrated Mont Belvieu and Galena Park Marine Terminal assets allow us to provide the raw product, fractionation, storage, interconnected terminaling, refrigeration and ship loading capabilities to support exports by third-party customers.

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Strategically located and leading infrastructure positions

We believe our assets are not easily replicated, are located in many attractive and active areas of exploration and production activity and are near key markets and logistics centers. Our gathering and processing infrastructure is located in attractive oil and gas producing basins and is well positioned within each of those basins. Activity in the shale resource plays underlying our gathering assets is driven by the economics of oil, NGL, gas and condensate production from the particular reservoirs in each play impacting the volumes of natural gas and crude oil available to us for gathering, processing and/or purchase and sale on our systems. Producers continue to focus drilling activity on their most attractive acreage, especially in the Permian Basin where we have a large, well-positioned and interconnected footprint, benefiting from rig activity in and around our systems.

As drilling in these areas continues, the supply of NGLs requiring transportation to market hubs and fractionation is expected to continue to grow. Continued demand for transportation, fractionation and export capacity is expected to lead to increased demand for other related fee-based services provided by our logistics and transportation assets as well as provide other growth opportunities. The connectivity of our gathering and processing and Downstream operations provided by our NGL pipeline system further allows us to capture these growth opportunities. Additionally, we are one of the largest fractionators of NGLs along the Gulf Coast. Our fractionation assets are primarily located in key NGL market centers and are near and connected to key consumers of NGL products, including the petrochemical and industrial markets. Our logistics assets, including fractionation facilities, storage wells, our low ethane propane de-ethanizers, and our Galena Park Marine Terminal and related pipeline systems and interconnects, include connections to a number of mixed NGL (“mixed NGLs” or “Y-grade”) supply pipelines, storage, interconnection and takeaway pipelines and other transportation infrastructure. The location and interconnectivity of these assets are not easily replicated, and we have additional capability to expand their capacity.

High quality and efficient assets

Our gathering and processing systems and logistics and transportation assets consist of high-quality, well-maintained facilities, resulting in low-cost, efficient operations. Advanced technologies have been implemented for processing plants (primarily cryogenic units utilizing centralized control systems), measurement systems (essentially all electronic and electronically linked to a central database) and operations and maintenance management systems to manage work orders and implement preventative maintenance schedules (computerized maintenance management systems). These applications have allowed proactive management of our operations resulting in lower costs and minimal downtime. We have established a reputation in the midstream industry as a reliable and cost-effective supplier of services to our customers and have a track record of safe, efficient and reliable operation of our facilities. We will continue to pursue new contracts, cost efficiencies and operating improvements of our assets. In the past, such improvements have included new production and acreage commitments, reducing fuel gas and flare volumes and improving facility capacity and NGL recoveries. We will also continue to optimize existing plant assets to improve and maximize capacity and throughput.

In addition to routine annual maintenance expenses, our maintenance capital expenditures have averaged approximately $234 million per year over the last three years. We believe that our assets are well-maintained, and we are focused on continuing to operate both our existing and new assets in a prudent, safe and cost-effective manner.

Financial flexibility

We have historically maintained sufficient liquidity and have funded our growth investments with a mix of cash flow from operations, equity, debt, asset sales and joint ventures over time in order to manage our leverage ratio. Disciplined management of liquidity, leverage and commodity price volatility allow us to be flexible in our long-term growth strategy, as well as allocating our free cash flow after dividends and share repurchases in a manner that maintains a strong credit profile.

Experienced and long-term focused management team

Our current executive management team possesses breadth and depth of experience working in the midstream energy business, including certain members of our executive management team managing our businesses prior to acquisition by Targa. Other officers and key employees have significant experience in the industry, including extensive experience in operating our current assets and developing, permitting and constructing new assets.

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Attractive cash flow characteristics, with large diverse business mix with favorable contracts and increasing fee-based business

We believe that our strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows. Geographic, business and customer diversity enhances our cash flow profile. We provide our services under predominantly fee-based contract terms to a diverse mix of customers across our areas of operation. Our Gathering and Processing segment contract mix has increasing components of fee-based margin driven by: (i) fees added to percent-of-proceeds contracts for natural gas treating and compression, (ii) new/amended contracts with a combination of percent-of-proceeds and fee-based components, including fee floors, and (iii) fee-based gas gathering and processing and crude oil gathering contracts. Contracts for the Coastal portion of our Gathering and Processing segment are primarily hybrid contracts (percent-of-liquids with a fee floor) or percent-of-liquids contracts (whereby we receive an agreed upon percentage of the actual proceeds of the NGLs).

Contracts for our assets in the Downstream Business are predominantly fee-based (based on volumes and contracted rates). Our contract mix, along with our commodity hedging program, serves to mitigate the impact of commodity price movements on cash flow.

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. We have intentionally tailored our hedges to approximate specific NGL products and to approximate our actual NGL and residue natural gas delivery points. Although the degree of hedging will vary, we intend to continue to manage some of our exposure to commodity prices by entering into hedge transactions. We also monitor and manage our inventory levels with a view to mitigate losses related to downward price exposure.

Our Business Operations

Our operations are reported in two segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business).

Gathering and Processing Segment

Our Gathering and Processing segment consists of gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas and gathering, storing, terminaling and purchasing and selling crude oil. The gathering or purchasing of natural gas consists of aggregating natural gas produced from various wells through varying diameter gathering lines to processing plants. Natural gas has a widely varying composition depending on the field, the formation and the reservoir from which it is produced. The processing of natural gas consists of the extraction of embedded NGLs and the removal of water vapor and other contaminants to form (i) a stream of marketable natural gas, commonly referred to as residue gas, and (ii) a stream of mixed NGLs. Once processed, the residue gas is transported to markets through residue gas pipelines. End-users of residue gas include large commercial and industrial customers, as well as natural gas and electric utilities serving individual consumers. We sell our residue gas either directly to such end-users or to marketers into intrastate or interstate pipelines, which are typically located in close proximity or with ready access to our facilities. The gathering or purchasing of crude oil consists of aggregating crude oil production through our pipeline gathering systems, which deliver crude oil to a combination of other pipelines, rail and truck.

We continually seek new supplies of natural gas and crude oil, both to offset the natural decline in production from connected wells and to increase throughput volumes. We obtain additional natural gas and crude oil supply in our operating areas by contracting for production from new wells or by capturing existing production currently gathered by others. Competition for new natural gas and crude oil supplies is based primarily on location of assets, commercial terms including pre-existing contracts, service levels and access to markets. The commercial terms of natural gas gathering and processing arrangements and crude oil gathering are driven, in part, by capital costs, which are impacted by the proximity of systems to the supply source and by operating costs, which are impacted by operational efficiencies, facility design and economies of scale.

The Gathering and Processing segment’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast. The natural gas processed in this segment is supplied through our gathering systems which, in aggregate, consist of approximately 31,600 miles of natural gas pipelines and include 54 owned and operated processing plants.

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The Gathering and Processing segment’s operations consist of (i) Permian Midland and Permian Delaware (also referred to as “Permian”), (ii) Central, (iii) Coastal and (iv) Badlands, each as described below:

Permian Midland

The Permian Midland system consists of approximately 7,800 miles of natural gas gathering pipelines and 20 processing plants with an aggregate processing capacity of 4,119 MMcf/d, all located within the Permian Basin in West Texas. Seventeen of these plants and approximately 5,500 miles of gathering pipelines belong to a joint venture (“WestTX”). We have an approximate 72.8% ownership in WestTX with Exxon Mobil Corporation (“ExxonMobil”) owning the remaining interest.

In response to increasing production and to meet the infrastructure needs of producers, we are constructing the East Pembrook plant and the East Driver plant, each a 275 MMcf/d cryogenic natural gas processing plant, which are expected to begin operations in the second quarter of 2026 and the third quarter of 2026, respectively.

Permian Delaware

The Permian Delaware system consists of approximately 7,700 miles of natural gas gathering pipelines and 19 processing plants with an aggregate capacity of 3,835 MMcf/d, within the Delaware Basin and Central Basin in West Texas and Southeastern New Mexico, and includes aggregate gas treating capacity of 2.6 Bcf/d in addition to seven acid gas injection wells.

In response to increasing production and to meet the infrastructure needs of producers, we are constructing the Falcon II plant, the Copperhead plant, the Yeti plant and the Yeti II plant, each a 275 MMcf/d cryogenic natural gas processing plant, which are expected to begin operations in the first quarter of 2026, first quarter of 2027, third quarter of 2027 and fourth quarter of 2027, respectively.

Central

The Central system consists of approximately 14,800 miles of pipelines and 11 processing plants with an aggregate capacity of 1,955 MMcf/d, all located within the Eagle Ford Shale region, Fort Worth Basin, southern Oklahoma, north central Oklahoma and southern Kansas. Our central system includes our Centrahoma joint venture (“Centrahoma”), which is comprised of three separate processing plants with an aggregate processing capacity of 470 MMcf/d. We have a 60% ownership interest in Centrahoma with the remaining 40% interest owned by MPLX, LP.

Coastal

Our Coastal assets consist of approximately 1,000 miles of onshore gathering system pipelines located in Louisiana to gather and process natural gas produced from shallow-water central and western Gulf of America natural gas wells, and from deep shelf and deep-water Gulf of America production via connections to third-party pipelines or through pipelines owned by us. The Coastal system has an aggregate processing capacity of 930 MMcf/d and 11 MBbl/d of integrated fractionation capacity. The processing plants are comprised of one wholly-owned and operated plant and one partially owned and operated plant. Our Coastal plants have access to markets across the U.S. through the interstate natural gas pipelines to which they are interconnected. The industry continues to rationalize gas processing capacity along the western Louisiana Gulf Coast with most of the producer volumes going to more efficient plants, such as our Gillis plant.

Badlands

Our Badlands operations are located in the Bakken and Three Forks Shale plays of the Williston Basin in North Dakota. Targa Badlands includes approximately 500 miles of crude oil gathering pipelines, 120 MBbl of operational crude oil storage capacity at the Johnsons Corner Terminal, 30 MBbl of operational crude oil storage capacity at the Alexander Terminal, 30 MBbl of operational crude oil storage capacity at New Town and 25 MBbl of operational crude oil storage capacity at Stanley. Our Targa Badlands assets also include approximately 300 miles of natural gas gathering pipelines and the Little Missouri I-III natural gas processing plants, which have a processing capacity of 90 MMcf/d. Additionally, Targa operates the 200 MMcf/d Little Missouri 4 plant (“LM4 plant”), in which Targa Badlands and Hess Midstream Partners LP each own a 50% interest.

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The following table lists the Gathering and Processing segment’s processing plants and related volumes for the year ended December 31, 2025:

(1)
Cryo – Cryogenic Processing; RA – Refrigerated Absorption Processing.

(2)
Processing capacity represents all parties’ ownership.

(3)
Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of the natural gas processing plant, except for Badlands which represents the total wellhead volume.

(4)
Plant natural gas inlet and NGL production volumes represent our ownership share of volumes for partially owned plants that we proportionately consolidate based on our ownership interest, including our 72.8% undivided interest in our WestTX joint venture, as well as 100% of ownership interests for our consolidated VESCO joint venture, Stonewall, Tupelo, and Hickory Hills plants.

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(5)
Per day plant natural gas inlet and NGL production statistics for plants listed above are based on the number of calendar days during 2025.

(6)
Plant natural gas inlet throughput volumes and NGL production volumes for WestTX are presented on a pro-rata net basis representing our undivided ownership interest in WestTX, which we proportionately consolidate in our consolidated financial statements.

(7)
As a result of a non-consent election made by the joint owner in our WestTX Permian Basin assets, the Pembrook II, Heim, Legacy, Legacy II, Greenwood and Greenwood II plants are 100% owned and consolidated by Targa until each plant achieves the payout event related to the non-consent election.

(8)
The Bull Moose plant, Pembrook II plant and Bull Moose II plant commenced operations in the first quarter of 2025, third quarter of 2025 and fourth quarter of 2025, respectively.

(9)
The Monument plant has fractionation capacity of approximately 1.5 MBbl/d.

(10)
Plant is available and operates subject to market conditions, including availability of natural gas.

(11)
The Gillis plant has fractionation capacity of approximately 11 MBbl/d.

(12)
Little Missouri Trains I and II are refrigeration plants and Little Missouri Train III is a Cryo plant.

(13)
Targa owns 100% of the interest in Targa Badlands, which owns a 50% interest in the LM4 plant.

Logistics and Transportation Segment

Our Logistics and Transportation segment includes the activities and assets necessary to transport and convert mixed NGLs into NGL products and also includes other assets and value-added services described below. The Logistics and Transportation segment also includes our NGL pipeline system, which is generally connected to and supplied in part by our Gathering and Processing segment. Our Downstream facilities are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana. Our fractionation, pipeline transportation, storage and terminaling businesses include 2,600 miles of company-owned pipelines to transport mixed NGLs and specification products.

The Logistics and Transportation segment also transports, distributes, purchases, sells, and markets NGLs via terminals and transportation assets in multiple states across the U.S. The geographic diversity of our assets provides direct access to many NGL customers as well as markets via trucks, barges, ships, rail cars and open-access regulated NGL pipelines owned by third parties.

Transportation Pipelines

Our NGL pipeline system connects our gathering and processing positions throughout the Permian Basin, North Texas, and Southern Oklahoma (as well as third-party positions) to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Our NGL pipeline system has the capacity to transport more than 1,000 MBbl/d of NGLs into Mont Belvieu.

Through our 50% ownership interest in Cayenne Pipeline, LLC (“Cayenne”), we operate the Cayenne pipeline, which transports mixed NGLs from VESCO in Venice, Louisiana, to an interconnection with a third-party NGL pipeline in Toca, Louisiana.

In response to increasing production and to meet the infrastructure needs of producers and our downstream customers, we are constructing:

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Delaware Express, which is an expansion of our NGL pipeline system in the Permian Delaware. Delaware Express is expected to begin operations in the second quarter of 2026.

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Speedway, a new NGL pipeline, which will transport NGLs from our existing assets and future plant additions in the Permian Basin to our fractionation and storage complex in Mont Belvieu, Texas. The project consists of approximately 500 miles of 30-inch diameter pipeline and associated infrastructure with an initial capacity of approximately 500 MBbl/d, expandable to 1,000 MBbl/d. Speedway is expected to begin operations in the third quarter of 2027.

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the Bull Run Extension, a 43-mile extension of our Bull Run intrastate natural gas pipeline, to expand and enhance connectivity of our Permian Delaware system to the Waha hub in West Texas. The Bull Run Extension is expected to begin operations in the first quarter of 2027.

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Buffalo Run, a new 35-mile intrastate natural gas pipeline, that will enhance connectivity across several of our plants in the Permian Midland and a 55-mile conversion of an existing Targa pipeline into natural gas service. Buffalo Run will connect our Permian Midland and Permian Delaware intra-basin natural gas systems. Buffalo Run is expected to be completed in stages and fully complete in early 2028.

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Forza, a new 36-mile interstate natural gas pipeline in Permian Delaware, that will connect our new and existing gas plants and enhance connectivity to the Waha hub. Forza filed a certificate application on December 3, 2025, with the FERC and, pending receipt of necessary regulatory approvals, is expected to begin operations in the middle of 2028.

Fractionation

After being extracted in the field, mixed NGLs are typically transported to a centralized facility for fractionation where the mixed NGLs are separated into discrete NGL products: ethane, ethane-propane mix, propane, normal butane, iso-butane and natural gasoline.

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We believe that sufficient volumes of mixed NGLs will be available for fractionation in commercially viable quantities for the foreseeable future due to historical increases in NGL production from shale plays and other shale-technology-driven resource plays in areas of the U.S. that include Texas, New Mexico, Oklahoma and the Rockies and certain other basins accessed by pipelines to Mont Belvieu, as well as from conventional production of NGLs in areas such as the Permian Basin, Mid-Continent, East Texas, South Louisiana and shelf and deep-water Gulf of America.

Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and distribute NGL products is also an important competitive factor. This ability is a function of the existence of storage infrastructure and supply and market connectivity necessary to conduct such operations. We believe that the location, scope and capability of our logistics assets, including our transportation and distribution systems, give us access to both substantial sources of mixed NGLs and a large number of end-use markets.

At our Mont Belvieu operated facility, we have nine wholly-owned fractionation trains, representing an aggregate capacity of 963.0 MBbl/d and Train 7, a 120 MBbl/d fractionation train, which is a joint venture between Targa and The Williams Companies, Inc., where Targa owns an 80% equity interest. Certain fractionation-related infrastructure for Train 7, such as storage caverns and brine handling, were funded and are owned 100% by Targa. Our fractionation trains are fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park on the Houston Ship Channel.

We are constructing Trains 11, 12 and 13, each a wholly-owned 150 MBbl/d fractionation train at our Mont Belvieu operated facility. Train 11, Train 12 and Train 13 are expected to begin operations in the second quarter of 2026, the first quarter of 2027 and the first quarter of 2028, respectively.

We additionally have a wholly-owned and operated fractionation facility in Lake Charles, Louisiana, representing a capacity of 55.0 MBbl/d.

We hold an equity investment in GCF, also located at Mont Belvieu. In January 2021, the GCF facility was temporarily idled. We assumed operatorship of GCF in the first half of 2021. In January 2023, we reached an agreement with our partners to reactivate GCF’s 135 MBbl/d fractionation facility. GCF commenced operations in the first quarter of 2025.

We also own fractionation assets in Monument, New Mexico, and Gillis, Louisiana, which are included in our Gathering and Processing segment. In addition, we have a natural gasoline hydrotreater at Mont Belvieu, Texas, with a capacity of 35.0 MBbl/d that removes sulfur from natural gasoline, allowing customers to meet stringent fuel content standards.

The following table details the Logistics and Transportation segment’s fractionation and treating facilities:

(1)
Actual fractionation capacities may vary due to the composition of the NGLs being processed and does not contemplate ethane rejection.

(2)
Cedar Bayou Fractionators, L.P. (“CBF”) includes five fractionation trains.

(3)
Lake Charles Fractionator runs in a mode of ethane/propane splitting for the local petrochemical market and is configured to also handle raw product.

(4)
The GCF facility was temporarily idled in January 2021. The facility was reactivated and operational in the first quarter of 2025.

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NGL Storage and Terminaling

In general, our NGL storage assets provide warehousing of mixed NGLs, NGL products and petrochemical products in underground wells, which allows for the injection and withdrawal of such products at various times in order to meet supply and demand cycles. Similarly, our terminaling operations provide the inbound/outbound logistics and warehousing of mixed NGLs, NGL products and petrochemical products in above-ground storage tanks. Our NGL underground storage and terminaling facilities serve single markets, such as propane, as well as multiple products and markets. For example, the Mont Belvieu and Galena Park facilities have extensive pipeline connections for mixed NGL supply and delivery of component NGLs, including our NGL pipeline system. In addition, some of our facilities are connected to marine, rail and truck loading and unloading facilities that provide services and products to our customers. We provide long and short-term storage and terminaling services and throughput capability to third-party customers for a fee.

Across the Logistics and Transportation segment, we own 35 storage wells at our facilities with a gross NGL storage capacity of approximately 81 MMBbl and operate seven non-owned wells. The usage of these wells may be limited by brine handling capacity, which is utilized to displace NGLs from storage.

We operate our storage and terminaling facilities to support our key fractionation facilities at Mont Belvieu and Lake Charles for receipt of mixed NGLs and storage of fractionated NGLs to service the petrochemical, refinery, export and heating customers/markets as well as our wholesale domestic terminals that focus on logistics to service the heating market customer base. Our international export assets include our facilities at both Mont Belvieu and the Galena Park Marine Terminal near Houston, Texas, which have the capability to load propane, butanes and international grade low ethane propane. The export facilities have an effective export capacity of approximately 14.0 MMBbl per month, subject to a mix of propane and butane demand, vessel size and availability of supply, and a variety of other factors. We have the capability to load VLGC vessels, alongside small and medium sized export vessels. We continue to experience demand growth for U.S.-based NGLs (both propane and butane) for export into international markets.

The following table details the Logistics and Transportation segment’s NGL storage and terminaling facilities:

(1)
Volumes reflect total import and export across the dock/terminal and may include (i) volumes bound for domestic redeliveries to customer’s receipt points along the Houston Ship Channel, or elsewhere in the United States, and (ii) volumes that have also been handled primarily at the Mont Belvieu Terminal.

(2)
Excludes seven non-owned wells which we operate on behalf of Chevron Phillips Chemical Company LP. One additional well has been drilled and is being prepared for operations.

(3)
Five of 12 owned wells are leased to Citgo Petroleum Corporation under a long-term lease.

NGL Distribution and Marketing

We market our own NGL production and also purchase component NGL products from other NGL producers and marketers for resale. We also purchase NGL products for resale in our Logistics and Transportation segment.

We generally purchase mixed NGLs at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these component products to petrochemical manufacturers, refiners and other marketing and retail companies. This is primarily a physical settlement business in which we earn margins from purchasing and selling NGL products from customers under contract. We also earn margins by purchasing and reselling NGL products in the spot and forward physical markets.

Wholesale Domestic Marketing

Our wholesale domestic propane marketing operations primarily sell propane and related logistics services to major multi-state retailers, independent retailers and other end-users. Our propane supply originates from both our refinery/gas supply contracts and our other owned or managed Logistics and Transportation assets. We sell propane at a fixed posted price or at a market index basis at the time of delivery and in some circumstances, we earn margins on a netback basis.

The wholesale domestic propane marketing business is significantly impacted by seasonal and weather-driven demand, particularly in the winter, which can impact the price and volume of propane sold in the markets we serve.

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Refinery Services

In our refinery services business, we typically provide NGL balancing services through contractual arrangements with refiners in several locations to purchase and/or market propane and to supply butanes. We use our commercial transportation assets (discussed below) and contract for and use the storage, transportation and distribution assets included in our Logistics and Transportation segment to assist refinery customers in managing their NGL product demand and production schedules. This includes both feedstocks consumed in refinery processes and the excess NGLs produced by other refining processes. Under typical netback purchase contracts, we retain a portion of the resale price of NGL sales or receive a fixed minimum fee per gallon on products sold. Under netback sales contracts, fees are earned for locating and supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply or a minimum fee per gallon.

Key factors impacting the results of our refinery services business include production volumes, prices of propane and butanes, as well as our ability to perform receipt, delivery and transportation services in order to meet refinery demand.

Commercial Transportation

Our NGL transportation and distribution infrastructure includes a wide range of assets supporting both third-party customers and the delivery requirements of our marketing and asset management business. We provide fee-based transportation services to refineries and petrochemical companies throughout the Gulf Coast area. Our assets are also deployed to serve our wholesale domestic distribution terminals, fractionation facilities, underground storage facilities and pipeline injection terminals. These distribution assets provide a variety of ways to transport products to and from our customers. Our commercial transportation assets include both leased and owned railcars, tractors, vacuum trucks and pressurized NGL barges.

The following table details the Logistics and Transportation segment’s propane terminaling facilities:

(1)
Throughputs include volumes related to exchange agreements and third-party storage agreements.

(2)
Throughput volume reflects 100% of the facility activity.

(3)
Rail-to-truck transload equipment.

Natural Gas Marketing

We also market natural gas available to us from the Gathering and Processing segment, purchase and resell natural gas in selected U.S. markets and manage the scheduling and logistics for these activities.

Seasonality

Parts of our business are impacted by seasonality. Our Downstream marketing business can be significantly impacted by seasonal and weather-driven demand, which can impact the price and volume of product sold in the markets we serve, as well as the level of inventory we hold in order to meet anticipated demand. See further discussion of the extent to which our business is affected by seasonality in “Item 1A. Risk Factors.”

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Operational Risks and Insurance

We are subject to all risks inherent in the midstream natural gas, NGLs and crude oil businesses. These risks include, but are not limited to, explosions, fires, mechanical failure, cyberattacks, terrorist attacks, product spillage, weather, nature and inadequate maintenance of rights of way. These risks could result in damage to or destruction of operating assets and other property, or could result in personal injury, loss of life or environmental pollution, as well as curtailment or suspension of operations at the affected facility. We maintain, on behalf of ourselves and our subsidiaries, general public liability, property, boiler and machinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles or self-insured retentions that we consider reasonable and not excessive given the insurance market environment.

The occurrence of a significant loss that is not insured, fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. While we currently maintain levels and types of insurance that we believe to be prudent under current insurance industry market conditions, our inability to secure these levels and types of insurance in the future could negatively impact our business operations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates considered commercially reasonable, particularly named windstorm coverage and contingent business interruption coverage for our onshore operations, and potentially excess liability insurance given the current insurance market environment.

Competition

We face strong competition in acquiring new natural gas or crude oil supplies. Competition for natural gas and crude oil supplies is primarily based on the location and available capacity of gathering and processing facilities, pricing arrangements, reputation, efficiency, flexibility, treating capabilities (as applicable), reliability and access to end-use markets or liquid marketing hubs. Our gathering and processing operations competitors are other natural gas gatherers and processors, such as major interstate and intrastate pipeline companies, master limited partnerships and oil and gas producers.

We also compete for NGL supplies for our NGL pipeline system. Competition for NGL supplies is primarily based on the proximity of gathering and processing facilities in relation to one or more NGL pipelines, their connectivity to NGL pipeline takeaway options, access to end-use markets or liquid marketing hubs, pricing and contractual arrangements, available capacity, reputation, efficiency, flexibility, and reliability. Our NGL pipeline competitors are other midstream providers with NGL transportation capabilities, such as major interstate and intrastate pipeline companies, master limited partnerships and midstream natural gas and NGL companies.

Additionally, we face competition for mixed NGLs supplies at our fractionation facilities. The fractionators in which we own an interest in the Mont Belvieu region compete for volumes of mixed NGLs with other fractionators also located in the Mont Belvieu region. In addition, certain producers fractionate mixed NGLs for their own account in captive facilities. The fractionators in the Mont Belvieu region also compete on a more limited basis with fractionators in Conway, Kansas and a number of decentralized, smaller fractionation facilities in Texas, Louisiana and New Mexico. Our other fractionation facilities compete for mixed NGLs with the fractionators at Mont Belvieu as well as other fractionation facilities located in Louisiana. Our customers who are significant producers of mixed NGLs and NGL products or consumers of NGL products may develop their own fractionation facilities in lieu of using our services.

We also face strong competition for NGL supply, logistics and export services in our Logistics and Transportation segment. Our competitors include major oil and gas producers who market NGL products for their own account and for others. Additionally, we compete with several other NGL marketing companies, trading organizations and petrochemical operators.

Human Capital

We believe that our employees are the foundation to fostering the safe operation of our assets and delivery of services to our customers. We foster a collaborative, inclusive, and safety-minded work environment, focused on working safely every day. We seek to identify qualified internal and external talent for our organization, enabling us to execute on our strategic objectives.

As of December 31, 2025, we employed approximately 3,570 people that primarily support our operations through a wholly-owned subsidiary of ours. None of these employees are covered by collective bargaining agreements, and we consider our employee relations to be good.

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Employee Health and Safety

Safety is a core value of ours and begins with the protection and safety of our employees, contractors and communities where we operate. We value people above all else and remain committed to making safety and health our top priority. We believe that “Zero is Achievable”, and our goal is to operate and deliver our products without any injuries. We continually seek to maintain and deepen our safety culture by providing a safe working environment that encourages active employee engagement, including implementing safety programs to achieve improvements in our safety culture.

To protect our employees, contractors, and surrounding community from workplace hazards and risks, we implement and maintain an integrated system of policies, practices, and controls, including requirements to complete regular detailed safety and regulatory compliance training for all applicable individuals. For more information on the laws and regulations we are subject to with regard to employee, contractor, and community safety, please see our section below titled Environmental and Occupational Health and Safety Matters.

Employee Experience

We are committed to fostering a work environment in which all employees treat each other with dignity and respect. This commitment extends to providing equal employment and advancement opportunities based on merit and experience. We believe this to be a fundamental principle and is defined in our Equal Employment Opportunity Policy and our Code of Conduct.

Employee Talent Development and Retention

As an infrastructure operator, we understand the importance of developing and fostering talent to ensure a skilled and talented diverse workforce both now and in the future. We value and provide opportunities for cross training and increased responsibilities, including leadership learning and formal coaching. These efforts allow us to recruit from within our organization for future vocational and occupational opportunities.

Our management promotes formal and informal learning and development throughout the organization. Candid feedback is provided to employees through our annual performance review process as well as informal meetings throughout the year.

We offer developmental programs focused on building the skills of our employees and to help advance employee careers, knowledge, and skillsets through training and related programs.

To help plan and predict succession needs, we perform annual succession planning, which is discussed and reviewed with management and, for certain levels and positions, with the board of directors. We additionally monitor employee turnover rates and conduct exit interviews with employees who voluntarily leave the Company to better understand their reasons for leaving the Company.

Regulation of Operations

Regulation of pipeline gathering and transportation services, natural gas, NGL and crude oil sales, and transportation of natural gas, NGLs and crude oil may affect certain aspects of our business and the market for our products and services.

Natural Gas Gathering and Processing Regulation

Our natural gas gathering operations are typically subject to open access ratable take and/or common purchaser statutes and implementing rules and regulations in the states in which we operate, which generally require us to give pipeline access or to purchase, process, or take gas without undue discrimination. These statutes, rules, and regulations can restrict our ability as an owner of gathering and processing facilities to decide with whom (and on what terms) we contract to gather or process natural gas with similarly situated customers (subject, in each case, to the limitations and requirements of each jurisdiction). In addition, the states in which we operate have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to access and rate discrimination. Currently, Targa is contesting a discrimination complaint filed as Cause No. 28550 by Enerplus Resources (USA) Corporation with the Industrial Commission of the State of North Dakota. We cannot predict whether any additional complaints will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and, in certain cases, criminal penalties.

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Section 1(b) of the Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation as a natural gas company by FERC under the NGA. We believe that our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, to the extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are subject to Order No. 704. See “—Regulation of Operations—FERC Market Transparency Rules.”

Sales of Natural Gas, NGLs and Crude Oil

The price at which we buy and sell natural gas, NGLs and crude oil is currently not subject to federal rate regulation and, for the most part, is not subject to state rate regulation. However, with regard to our physical purchases and sales of these energy commodities and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodities Futures Trading Commission (“CFTC”). See “—Regulation of Operations—EP Act of 2005.” We are required to report to FERC information regarding natural gas sale and purchase transactions for some of our operations, depending on the volume of natural gas transacted during the prior calendar year. See “—Regulation of Operations—FERC Market Transparency Rules.” Should we violate the anti-market manipulation laws and regulations, in addition to civil penalties, we could also be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

Interstate Natural Gas

We own (in conjunction with ExxonMobil) and operate the Driver Residue Pipeline, a gas transmission pipeline extending from our Driver processing plant in West Texas approximately 10 miles to points of interconnection with intrastate and interstate natural gas transmission pipelines. We have obtained a certificate of public convenience and necessity from FERC waiving certain of the Commission’s tariff and rate regulations. If, however, we receive a bona fide request for firm service on the Driver Residue Pipeline from a third party, FERC would reexamine the waivers it has granted us and would require us to file for authorization to offer “open access” transportation under its regulations, which would impose additional costs upon us.

On December 3, 2025, we filed a certificate application to construct and operate Forza under Section 7 of the NGA as an interstate pipeline. Construction and operation of Forza is subject to approval by FERC in response to our certificate application.

Interstate Liquids

Targa NGL Pipeline Company LLC (“Targa NGL”), Targa Gulf Coast NGL Pipeline LLC (“Targa Gulf Coast”), Grand Prix Pipeline LLC (“Grand Prix Pipeline”), Targa San Andres Crude Pipeline LLC (“Targa San Andres Crude”) and Targa Badlands have interstate NGL or crude pipelines that are considered common carrier pipelines subject to regulation by FERC under the Interstate Commerce Act (the “ICA”). Targa Gulf Coast leases from Targa NGL certain pipelines that run between Mont Belvieu, Texas, and Galena Park, Texas and between Mont Belvieu, Texas, and Lake Charles, Louisiana. Each of Targa Gulf Coast’s pipelines are part of an extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides services to domestic and foreign export customers.

Unless covered by a waiver, as described below, the ICA requires that we maintain tariffs on file with FERC for interstate movements of liquids on our pipelines. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires that tariff rates for liquids pipelines, which include crude oil pipelines, refined products pipelines and NGL pipelines, be just and reasonable and non-discriminatory. Many FERC-regulated liquids pipelines, including our pipelines discussed above, use the FERC indexing methodology to change their rates. Pursuant to the FERC indexing methodology, FERC reviews the index formula every five years to determine whether a change in the methodology is required or, if not, to determine the appropriate index for the subsequent five-year period. On July 26, 2024, the D.C. Circuit Court of Appeals vacated a FERC January 2022 Rehearing Order that had reduced the oil pricing index factor for oil pipelines to use for the current five-year period. On September 17, 2024, FERC issued an order reinstating the higher oil pricing index factor and indicated FERC will address additional issues related to the D.C. Circuit Court of Appeal’s decision in a subsequent order. On October 1, 2024, Targa filed to revise its rates for Targa NGL, and on October 15, 2024, Targa filed to revise its rates for Targa Gulf Coast and Grand Prix Pipeline, in each case, in accordance with the September 17, 2024, FERC order. The revised rates became effective on November 1, 2024. On October 17, 2024, FERC issued a supplemental notice of proposed rulemaking in which FERC proposed to prospectively adopt the index that was vacated by the D.C. Circuit Court of Appeals and instituted a notice-and-comment process. On November 20, 2025, FERC withdrew the October 17, 2024, supplemental notice of proposed rulemaking and confirmed that the PPI-FG+0.78% index established in December 2020 will remain in place through June 30, 2026. On the same day, FERC approved limited relief for pipelines. Oil pipelines with index-based rates may recover applicable rate differences from March 1, 2022, to September 17, 2024.

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Targa has multiple NGL pipelines that are also considered common carrier pipelines but have qualified for a waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. All such waivers are subject to revocation, however, should a particular pipeline’s circumstances change. FERC could, either at the request of other entities or on its own initiative, assert that some or all of these pipelines no longer qualify for a waiver. In the event that FERC were to determine that one or more of these pipelines no longer qualified for a waiver, we would likely be required to file a tariff with FERC for the applicable pipeline(s) and delivery point(s), provide a cost justification for the transportation charge, and provide regulated services to all potential shippers without undue discrimination. For example, on December 16, 2022, FERC initiated an investigation and established hearing procedures in FERC Docket No. OR23-2-000 to determine whether Targa’s Badlands assets continue to qualify for the waiver of applicable FERC regulatory requirements and whether Targa is providing jurisdictional transportation service on this system. An initial decision was issued by an administrative law judge on March 26, 2024, which found that Targa’s Badlands assets no longer qualify for a waiver of FERC regulatory requirements and such assets are providing jurisdictional transportation service. FERC affirmed the administrative law judge’s initial decision on August 7, 2025, and required Targa Badlands to file a tariff setting the rates as well as the rules and regulations governing transportation service on these assets. Targa Badlands filed this initial tariff in FERC Docket No. IS26-24-000 on October 29, 2025, which FERC accepted and suspended subject to refund pending a hearing to determine, among other things, whether the rates Targa Badlands proposed are just and reasonable. Various shippers are challenging the rates contained in such tariff asserting they are not just and reasonable under the ICA, and settlement discussions in this proceeding are currently ongoing. As a result, we cannot predict the ultimate outcome of these challenges.

Tribal Lands

Our intrastate natural gas pipelines in North Dakota are subject to the various regulations of the State of North Dakota. In addition, various federal agencies within the U.S. Department of the Interior, particularly the federal Bureau of Land Management (“BLM”), Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, as well as the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. Please see “Other State and Local Regulation of Operations” below.

Intrastate Natural Gas

Though our natural gas intrastate pipelines are not subject to regulation by FERC as natural gas companies under the NGA, our intrastate pipelines may be subject to certain FERC-imposed reporting requirements depending on the volume of natural gas purchased or sold in a given year. See “—Regulation of Operations—FERC Market Transparency Rules.”

Our intrastate natural gas pipelines located in Texas are regulated by the Railroad Commission of Texas (the “RRC”) and may be required to have tariffs on file with the RRC. Some of these Texas intrastate pipelines also transport natural gas in interstate commerce pursuant to Section 311 of the Natural Gas Policy Act of 1978 (“NGPA”). Under Sections 311 and 601 of the NGPA, an intrastate pipeline may transport natural gas in interstate commerce without becoming subject to FERC regulation as a “natural-gas company” under the NGA, but must file the terms and conditions of transportation of natural gas under authority of Section 311 with FERC, and these terms and conditions must be “fair and equitable.” Specifically, during 2025, TPL SouthTex Transmission Company LP, Buffalo Run Pipeline LLC, Bull Run Pipeline LLC and Targa SouthTex Mustang Transmission Ltd. provided NGPA Section 311 service.

Our Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC, and the rates and terms of service on the pipeline may be subject to regulation by the Office of Conservation of the Louisiana Department of Natural Resources (“DNR”).

We also operate natural gas pipelines that extend from the tailgate of our processing plants to interconnections with both intrastate and interstate natural gas pipelines. We believe these pipelines are exempt from FERC’s jurisdiction under the NGA under FERC’s “stub” line exemption. Texas and Louisiana have adopted complaint-based regulation of intrastate natural gas transportation activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to pipeline access and rate discrimination. The rates we charge for intrastate transportation are deemed just and reasonable unless challenged in a complaint. A complaint also can be filed with FERC regarding the rates, terms, and conditions of service on our pipelines providing service pursuant to Section 311 of the NGPA. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state or FERC regulations can result in the imposition of administrative, civil and criminal penalties.

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Intrastate Liquids

We operate intrastate NGL common carrier pipelines in Texas. Targa Gulf Coast operates pipelines that transport mixed and purity NGL streams between Targa’s Mont Belvieu and Galena Park, Texas facilities and certain third-party facilities. Grand Prix Pipeline and Targa NGL provide transportation of mixed NGLs from points within Texas to other points within Texas, including Mont Belvieu, Texas. Targa SouthTex NGL Pipeline Ltd. operates intrastate NGL pipelines providing services between various points in Nueces, San Patricio and Refugio Counties. Targa San Andres Gas Utility LLC operates intrastate NGL pipelines providing service between various points in Yoakum and Gaines Counties. Further, we operate crude gathering pipelines in the Permian Basin. With respect to intrastate movements, these pipelines are not subject to FERC regulation, but are subject to rate regulation by the RRC.

Our intrastate NGL pipelines in Louisiana gather mixed NGLs streams that we own from processing plants in Louisiana and deliver such streams to the Gillis and Lake Charles fractionators in Lake Charles, Louisiana. We deliver mixed and purity NGL streams out of our fractionators to and from Targa-owned storage, and to other third-party facilities and pipelines in Louisiana. Additionally, through our 50% ownership interest in Cayenne, we operate the Cayenne pipeline, which transports mixed NGLs from the Venice gas plant in Venice, Louisiana, to an interconnection with a third-party NGL pipeline in Toca, Louisiana. These pipelines are not subject to FERC regulation or rate regulation by the DNR. On May 9, 2019, the Louisiana Public Service Commission (“LPSC”) approved applications to register certain pipelines of Cayenne and Targa Downstream LLC in accordance with the LPSC 2015 General Order, Docket No R-33390. LPSC regulations require that common carrier pipelines charge rates that are just and reasonable, and not unreasonably discriminatory.

EP Act of 2005

The EP Act of 2005 amended the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties up to a maximum amount that is adjusted annually for inflation, which for 2026 equals approximately $1.6 million (which amount may be updated for inflation in 2026) per violation per day for violations of the NGA or NGPA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce as well as entities that are otherwise subject to the NGA or NGPA. In 2006, FERC issued Order No. 670 to implement the anti-market manipulation provision of the EP Act of 2005. Order No. 670 does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (Order No. 704), and the quarterly reporting requirement under Order No. 735.

FERC Market Transparency Rules

Under Order No. 704, wholesale buyers and sellers of more than 2.2 Bcf of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.

Under Order No. 735, intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating under Section 1(c) of the NGA are required to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. As currently written, this rule does not apply to our Hinshaw pipelines.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other midstream natural gas companies with whom we compete.

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Other State and Local Regulation of Operations

Our business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including operations, marketing, production, pricing, community right-to-know, protection of the environment, safety, marine traffic and other matters. In addition, the Three Affiliated Tribes promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which we operate a significant portion of our Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations. For additional information regarding the potential impact of federal, state, tribal or local regulatory measures on our business, see “Risk Factors—Risks Related to Regulatory Matters.”

Environmental and Occupational Health and Safety Matters

Our business operations are subject to numerous environmental and occupational health and safety laws and regulations that may be imposed at the federal, regional, state, tribal and local levels. The activities that we conduct in connection with (i) gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas; (ii) storing, fractionating, treating, transporting, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and (iii) gathering, storing, terminaling, and purchasing and selling crude oil are subject to or may become subject to stringent environmental regulation. We have implemented programs and policies designed to monitor and pursue operation of our pipelines, plants and other facilities in a manner consistent with existing environmental and occupational health and safety laws and regulations, and have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with these laws and regulations. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operational results.

The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. legal standards, as amended from time to time:

•
the Clean Air Act (“CAA”), which restricts the emission of air pollutants from many sources and imposes various pre-construction, operational, monitoring and reporting requirements, and that the EPA has historically relied upon as authority for adopting climate change regulatory initiatives relating to greenhouse gas (“GHG”) emissions;

•
the Federal Water Pollution Control Act, also known as the Clean Water Act, which regulates discharges of pollutants to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;

•
the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

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the Resource Conservation and Recovery Act (“RCRA”), which governs the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes;

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the Oil Pollution Act of 1990, which subjects owners and operators of onshore facilities, pipelines and other facilities, as well as lessees or permittees of areas in which offshore facilities are located, that are the site of an oil spill in waters of the United States, to liability for removal costs and damages;

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the Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources;

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the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;

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the National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to impact the environment and that may require the preparation of environmental assessments and more detailed environmental impact statements that may be made available for public review and comment; and

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the Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.

These environmental and occupational health and safety laws and regulations generally restrict the level of substances generated as a result of our operations that may be emitted to ambient air, discharged to surface water, and disposed or released to surface and below-ground soils and ground water. Additionally, there exist tribal, state and local jurisdictions in the United States where we operate that also have, or are developing or considering developing, similar environmental and occupational health and safety laws and regulations governing many of these same types of activities. Any failure by us to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal fines or penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area. Certain environmental laws also provide for citizen suits, which allow environmental organizations to act in place of the government and sue operators for alleged violations of environmental law. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor determinable as existing standards are subject to change and new standards continue to evolve.

We own, lease and/or operate numerous properties that have been used for crude oil and natural gas midstream services for many years. Additionally, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. Under environmental laws such as CERCLA and RCRA, we could incur strict joint and several liability for remediating hydrocarbons, hazardous substances or wastes disposed of or released by us or prior owners or operators. We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal or to which we sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at or from such third-party sites.

Over time, the trend in environmental and occupational health and safety regulation is to typically place more restrictions and limitations on activities that may adversely affect the environment or expose workers to injury and thus, any changes in environmental or occupational health and safety laws and regulations or reinterpretation of enforcement policies that may arise in the future and result in more stringent or costly waste management or disposal, pollution control, remediation or occupational health and safety-related requirements could have a material adverse effect on our business, results of operations and financial position. We may not have insurance or be fully covered by insurance against all environmental and occupational health and safety risks, and we may be unable to pass on increased compliance costs arising out of such risks to our customers. We review regulatory and environmental issues as they pertain to us and we consider regulatory and environmental issues as part of our general risk management approach. For more information on environmental and occupational health and safety matters, see “Risks Related to Regulatory Matters” under Part I, Item 1A. of this Form 10-K.

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Pipeline Safety Matters

Many of our natural gas, NGL and crude oil pipelines are subject to regulation by the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency of the U.S. Department of Transportation (“DOT”), under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas, crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs to comprehensively evaluate certain relatively higher risk areas, known as high consequence areas (“HCAs”) and moderate consequence areas (“MCAs”), along pipelines and take additional safety measures to protect people and property in these areas. Recently, PHMSA finalized adjustments to the repair criteria for pipelines in HCAs, created new criteria for pipelines in non-HCAs, and strengthened integrity management assessment requirements. Various states have also adopted regulations, similar to existing PHMSA regulations for, and may have established agencies analogous to PHMSA to regulate, intrastate gathering and transmission lines. We currently estimate an average annual cost of approximately $12.5 million between 2026 and 2028 to continue our pipeline integrity management program inspections along certain segments of our natural gas and hazardous liquids pipelines. This estimate also includes the costs, if any, of repair, remediation, or preventative and mitigative actions that may be determined to be necessary as a result of the discovery of conditions during the ongoing inspection program. Additional unforeseen costs for repair, remediation, or preventative and mitigative actions could be material. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity inspections. Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business, financial condition or results of operations. See “Risks Related to Regulatory Matters” under Item 1A. of this Form 10-K for further discussion on pipeline safety standards, including integrity management requirements.

Title to Properties and Rights of Way

Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights of way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to ground leases or easements between us, as lessee or grantee, and the fee owner of the lands, as lessors or grantors. We and our predecessors have leased or held easements on these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold or easement estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, rights of way, permit, lease or license, and we believe that we have satisfactory title to all of our material leases, easements, rights of way, permits, leases and licenses.

Corporation Tax Matters

As of December 31, 2025, examinations by the Internal Revenue Service (the “IRS”) are currently in process for the 2022 taxable year of certain wholly-owned and consolidated subsidiaries that are treated as partnerships for U.S. federal income tax purposes. We are responding to information requests from the IRS with respect to these audits. We do not expect there to be any audit adjustments that would materially change our taxable income.

Federal statutes of limitations for returns filed in 2022 (for calendar year 2021) have expired. The statute of limitations expired on substantially all 2021 state income tax returns that were filed prior to October 15, 2022. For Texas, the statute of limitations has expired for 2021 returns (for calendar year 2020). However, tax authorities could review and adjust carryover attributes (e.g., net operating losses) generated in a closed tax year if utilized in an open tax year.

The U.S. Department of the Treasury and the IRS have issued guidance on the application of the corporate alternative minimum tax (the “CAMT”), which is a 15% minimum tax imposed on certain financial income of “applicable corporations,” including proposed regulations issued in September 2024, which may be relied upon until final regulations are released. Based on our current interpretation of the Inflation Reduction Act of 2022 (the “IRA”), the CAMT and related guidance, the impact from the One Big Beautiful Bill Act (the “OBBBA”), and several operational, economic, accounting and regulatory assumptions, we do not anticipate paying CAMT in the near term.

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Financial Information by Reportable Segment

See “Segment Information” included under Note 22 of the “Consolidated Financial Statements” for a presentation of financial results by reportable segment and see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—By Reportable Segment” for a discussion of our financial results by segment.

Available Information

We make certain filings with the SEC, including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports. We make such filings available free of charge through our website, http://www.targaresources.com, as soon as reasonably practicable after they are filed with the SEC. Our press releases and recent analyst presentations are also available on our website. The SEC also maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. The information contained on the websites referenced in this Annual Report on Form 10-K is not incorporated herein by reference.