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As generally used in the energy industry and in this Annual Report, the identified terms have the following meanings:

PART I

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:

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). To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the 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. The Logistics and Transportation segment also includes the Grand Prix NGL Pipeline (“Grand Prix”), 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.

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

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:

Fractionation Expansions

Our new 150 MBbl/d fractionation train additions include:

NGL Pipeline Expansions

LPG Export Expansion

Natural Gas Pipelines

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. During the second quarter of 2023, we exhausted the 2020 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.

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”). We used a portion of the net proceeds to repay $1.0 billion in borrowings under the Term Loan Facility and the remaining net proceeds for general corporate purposes, including to repay borrowings under 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.

Organization Structure

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

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. The connectivity of our gathering and processing and Downstream operations provided by Grand Prix 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. Our logistics assets, including fractionation facilities, storage wells, our low ethane propane de-ethanizer, 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.

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. The gathering or purchase 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. The gathering or purchase 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.

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. We have a 60% ownership interest in Centrahoma.

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 Coastal system has an aggregate processing capacity of 2,025 MMcf/d and 11 MBbl/d of integrated fractionation capacity, and consists of approximately 1,000 miles of onshore gathering system pipelines, and approximately 100 miles of offshore gathering system pipelines. The processing plants are comprised of one wholly-owned and operated plant and one partially owned and operated plant. The processing plants are comprised of three wholly-owned and operated plants, one partially owned and operated plant, and one partially owned, non-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. The 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.

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

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. The Logistics and Transportation segment includes Grand Prix and associated assets, which are 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. Our fractionation, pipeline transportation, storage and terminaling businesses include approximately 2,300 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:

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.

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:

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:

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 also purchase product 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.

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:

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.”

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.

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.

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. Each of these pipelines is 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.

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. 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. 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), 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.” Specifically, during 2023, TPL SouthTex Transmission Company LP, Targa Midland Gas Pipeline LLC, Midland-Permian Pipeline LLC, Delaware-Permian Pipeline LLC, 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. We believe these pipelines are exempt from FERC’s jurisdiction under the Natural Gas Act 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.

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. We deliver mixed and purity NGL streams out of our fractionator 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. 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.

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 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 2024 equals approximately $1.5 million 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.

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:

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. For more information on environmental and occupational health and safety matters, see the following Risk Factors under Part I, Item 1A. of this Form 10-K.

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. We currently estimate an average annual cost of $4.5 million between 2024 and 2026 to implement 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. This estimate does not include 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 inspection program, which costs could be material. 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.

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.

Item 1A. Risk Factors

The nature of our business activities subjects us to certain hazards and risks. You should consider carefully the following risk factors together with all the other information contained in this report. If any of the following risks were to occur, then our business, financial condition, cash flows and results of operations could be materially adversely affected.

Summary Risk Factors

Risks Related to our Results of Operations

Risks Related to our Capital Projects and Future Growth

Risks Related to our Financial Condition

Risks Related to the Ownership of our Common Stock

Risks Related to our Indebtedness

Risks Related to Regulatory Matters

Risks Related to our Results of Operations

Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in commodity prices and/or activity levels could adversely affect our results of operations and financial condition.

Our operations can be affected by the level of natural gas, NGL and crude oil prices and the relationship between these prices. The prices of natural gas, NGLs and crude oil have been historically volatile, and we expect this volatility to continue which impacts production activity levels. Our future cash flows may be materially adversely affected if we experience significant, prolonged price deterioration that also decreases production activity levels in our areas of operation. The markets and prices for natural gas, NGLs and crude oil depend upon factors beyond our control. These factors include supply and demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:

Our commercial agreements across our Gathering and Processing and Logistics and Transportation businesses with our customers are predominantly fee-based arrangements, whereby we charge a fee for unit of throughput. Some of the commercial agreements in our natural gas gathering and processing business are percent-of-proceeds arrangements that expose us to commodity price risk. Assessment and enhancement of our security posture in predicting and responding to the changing threat landscape are core goals of our cybersecurity program. Certain of these have commodity price protection features. Under our percentage-of-proceeds arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. Under these arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index-based price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and cash flows increase or decrease, whichever is applicable, as the prices of natural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

A reduction in demand for NGL products by the petrochemical, refinery or other industries or by the fuel or export markets, or a significant increase in NGL product supply relative to this demand, could materially adversely affect our business, results of operations and financial condition.

The NGL products we produce have a variety of applications, including heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry-specific economic conditions, government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), reduced demand for propane or butane exports whether for price or other reasons, increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. A reduction in demand for NGL products, whether because of general or industry-specific economic conditions, new government regulations, including the IRA, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), reduced demand for 28 propane or butane exports whether for price or other reasons, increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Also, increased supply of NGL products could reduce the value of NGLs handled by us and reduce the margins realized. Our NGL products and their demand are affected as follows:

Ethane. Ethane is typically supplied as purity ethane and as part of an ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream, thereby reducing the volume of NGLs delivered for fractionation and marketing.

Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial

fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is increasingly driven by international exports supplying a growing global demand for the product. Domestically in the U.S., propane is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of slow global economic growth and warmer-than-normal weather.

Normal Butane. Normal butane is used in the production of isobutane, as a refined petroleum product blending component, as a fuel gas (either alone or in a mixture with propane) and in the production of ethylene and propylene. Changes in the composition of refined petroleum products resulting from governmental regulation, changes in feedstocks, products and economics, and demand for heating fuel, ethylene and propylene could adversely affect demand for normal butane. The volume of butane sold is increasingly driven by international exports supplying a growing demand for the product.

Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.

Natural Gasoline. Natural gasoline is used as a blending component for certain refined petroleum products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation, and in demand for ethylene and propylene, could affect demand for natural gasoline.

NGLs and products produced from NGLs also compete with products from global markets. Any reduced demand or increased supply for ethane, propane, normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect both demand for the services we provide and NGL prices, which could negatively impact our results of operations and financial condition.

The natural decline in production in our operating regions and in other regions from which we source NGL supplies means our long-term success depends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Any decrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and operating results.

Our gathering systems are connected to crude oil and natural gas wells from which production will naturally decline over time, which means that the cash flows associated with these sources of natural gas and crude oil will likely also decline over time. Our logistics assets are similarly impacted by declines in NGL supplies in the regions in which we operate as well as other regions from which we source NGLs. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas, NGL and crude oil supplies. A material decrease in natural gas or crude oil production from producing areas on which we rely, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural gas or crude oil that we gather and process, NGLs that we transport or NGL products delivered to our fractionation facilities. Our ability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on the level of successful drilling and production activity near our gathering systems and, in part, on the level of successful drilling and production in other areas from which we source NGL and crude oil supplies. We have no control over the level of such activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling, completion or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Even if new natural gas or crude oil reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. In response to depressed commodity prices, operators may engage in curtailment or shut-ins or substantially reduce their estimated capital expenditures, rig count and completion crews. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas in which we operate may prevent us from obtaining supplies of natural gas or crude oil to replace the natural decline in volumes from existing wells, which could result in reduced volumes through our facilities and reduced utilization of our gathering, treating, processing, transportation and fractionation assets.

Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in our respective areas of operation. Some of our competitors are large crude oil, natural gas and NGL companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than we do. Some of these competitors may expand or construct gathering, processing, storage, terminaling and transportation systems that would create additional competition for the services we provide to our customers. In addition, customers who are significant producers of natural gas may develop their own gathering, processing, storage, terminaling and transportation systems in lieu of using those operated by us. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.

Our business is highly competitive, which may affect our ability to hire, train or retain officers and employees needed to manage and operate our business.

We operate in areas in which industry activity has increased rapidly. As a result, demand for qualified personnel in these areas, particularly those related to our Permian and Badlands assets, and the cost to attract and retain such personnel, has increased over the past few years due to competition, and may increase substantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer.

In addition, there is substantial competition for experienced supervisory and managerial personnel in the midstream industry. We may not be able to retain our existing executive officers or fill new positions or vacancies created by expansion or turnover, and we have not entered into employment agreements with any of our named executive officers nor do we maintain “key man” life insurance on the lives of any of our named executive officers.

Any delay or inability to secure the officers and employees necessary for us to continue or complete our current and planned development projects, or any significant increases in costs with respect to the hiring, training or retention of qualified personnel, could have a material adverse effect on our business, financial condition and results of operations. Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development projects, or any significant increases in costs with respect to the hiring, training or retention of qualified personnel, could have a material adverse effect on our business, financial condition and results of operations.

If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and processing facilities or to our NGL pipelines, fractionators and storage facilities become partially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be adversely affected.

We depend upon third-party pipelines, storage and other facilities that provide delivery options to and from our gathering and processing facilities and our NGL pipelines, fractionators and storage facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict our ability to utilize them, our revenues could be adversely affected.

We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our operations.

We do not own most of the land on which our pipelines, terminals and compression facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or leases or if such rights of way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Additionally, the federal Tenth Circuit Court of Appeals has held that tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights of way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannot guarantee that we will always be able to renew existing rights of way or obtain new rights of way without experiencing significant costs. Any loss of rights with respect to our real property, through our inability to renew rights of way contracts or leases, or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere and reduce our revenue.

Weather events may damage our assets, limit our ability or increase the costs to operate our business and adversely impact our customers on whom we rely on for throughput as well as third party vendors from whom we receive goods, which developments could cause us to incur significant costs and adversely affect our business, results of operations and financial condition.

Weather events in the areas in which we or our customers operate can cause disruptions and in some cases suspension of our operations and development activities. For example, unseasonably wet weather, extended periods of below freezing weather, or hurricanes, among other disruptive weather patterns, may cause a loss of throughput from temporary cessation of activities or lost, damaged or ineffective equipment. Our planning for normal climatic variation, insurance programs and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated or insured against. Potential climatic changes may have significant physical effects, such as increased frequency and severity of storms, floods, droughts, extreme temperatures, wildfires and wintry conditions and could have an adverse effect on our infrastructure or continued operations as well as the operations of our oil and gas exploration and production customers that deliver natural gas to us for processing and throughput, our third party vendors that supply us with goods, utilities necessary for our, our suppliers’, or our customers’ continued operations, and third party insurance providers that make insuring products available to defray our costs or offset any damages and losses we incur. Any unusual or prolonged severe weather events or increased frequency thereof, such as freezing weather or rain, earthquakes, hurricanes, droughts, extreme temperatures, wildfires or floods in our oil and gas exploration and production customers’ or our third party vendors’ areas of operations or markets, whether due to climatic change or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

Our operations along the Gulf Coast, in offshore waters and at major river crossings in particular could be adversely impacted by changing climatic conditions, as rising sea levels, subsidence and erosion are potential causes for serious damage to our pipelines and other facilities, which could affect our ability to provide services. These damages could result in leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water, groundwater or to the Gulf of America and could result in liability, remedial obligations or otherwise have a negative impact on continued operations. These damages could result in leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water, groundwater or to the Gulf of Mexico and could result in liability, remedial obligations or otherwise have a negative impact on continued operations. Additionally, rising sea levels, subsidence and erosion processes could impact our oil and gas exploration and production customers who operate along the Gulf Coast, and they may be unable to utilize our services. Adverse climatic impacts, whether inland or along the coast or offshore, could also affect our third-party suppliers, which could limit their ability to provide us with the necessary products and services enabling us to maintain operation of our pipelines and other facilities. Moreover, we could incur significant costs to weatherize or upgrade weatherization of our facility equipment in anticipation of future weather events. Moreover, we could incur significant costs to weatherize or upgrade weatherization of our facility equipment in anticipation of future weather events. As a result, we may incur significant costs to repair, preserve or make more efficient our pipeline infrastructure and other facilities. Such costs could adversely affect our business, financial condition, results of operations and cash flows.

Our business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial results could be adversely affected.

Our operations are subject to many hazards inherent in gathering, compressing, treating, processing, transporting, purchasing and selling natural gas; transporting, storing, fractionating, treating and purchasing and selling NGLs and NGL products, including services to LPG exporters; and gathering, storing, terminaling and purchasing and selling crude oil, including:

These risks could result in substantial losses due to personal injury, loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental or natural resource damage, and may result in delay, curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent to our business. Additionally, while we are insured against pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. For example, following the occurrence of severe hurricanes along the U.S. Gulf Coast, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that could be obtained prior to such hurricanes, with some coverage unavailable at any cost. Further, due to the impacts of recent weather events, certain major insurance companies are either reducing, or no longer offering, certain coverages in Texas, among other states. If a significant accident or event occurs for which we are not fully insured or if we fail to acquire insurance for certain of our operations generally, our operations and financial results could be adversely affected.

Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodity price movements.

We sell processed natural gas at plant tailgates or at pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. We attempt to balance sales with volumes supplied from processing operations, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose us to volume imbalances, which, in conjunction with movements in commodity prices, could materially impact our income from operations and cash flow.

Portions of our pipeline systems may require increased expenditures for maintenance and repair owing to the age of some of our systems, which expenditures or resulting loss of revenue due to pipeline age or condition which could have an adverse effect on our business and results of operations.

Some portions of the pipeline systems that we operate have been in service for several decades prior to our purchase of them. Consequently, there may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of some of our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of some portions of our pipeline systems could adversely affect our business and results of operations.

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued global and domestic hostilities may adversely impact our results of operations.

The long-term impact of terrorist attacks and the threat of future terrorist attacks on our industry in general and on us in particular is not known at this time. However, resulting regulatory requirements and/or related business decisions associated with security are likely to increase our costs. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued global and domestic hostilities may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets, or indirect casualties, of an act of terror.

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage or coverage may be reduced or unavailable. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.

We have experienced, and may encounter from time to time, opposition to the operation and expansion of our pipelines and facilities from governmental officials, non-governmental environmental organizations and groups, landowners, tribal groups, local groups and other advocates. In some instances, we encounter opposition which disfavors hydrocarbon-based energy supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion can take many forms, including the delay, denial or termination of required governmental permits or approvals, organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets or lawsuits or other actions designed to prevent, disrupt, delay or terminate the operation or expansion of our assets and business. Similar actions pursued against our oil and gas customers could result in interruptions or limitations to their businesses, which could reduce demand for our services. Any such event that restricts, delays or prevents the expansion of our or our customers’ businesses, interrupts the revenues generated by our or our customers’ operations or causes us or our customers to make significant expenditures not covered by insurance could adversely affect our business, results of operations, and financial condition, as well as reduce the demand for our services. Regulatory attention to environmental justice matters at the federal and state level may also provide communities opposed to our operations with greater opportunities to challenge or delay the permitting approval process. Increased regulatory attention to environmental justice matters at the federal and state level may also provide communities opposed to our operations with greater opportunities to challenge or delay the permitting approval process.

We may incur significant costs and liabilities resulting from performance of pipeline integrity testing programs and related repairs, as well as from initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more rigorous enforcement of applicable legal requirements.

Pursuant to the authority under the NGPSA and HLPSA, PHMSA has established rules requiring pipeline operators to develop and implement integrity management programs for certain natural gas and hazardous liquids pipelines located where a pipeline leak or rupture could affect higher and moderate consequence risk areas, known as HCAs and MCAs, which are areas where a release could have the most significant adverse consequences. Among other things, these regulations require operators of covered pipelines to:

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2020, require PHMSA to impose more stringent pipeline safety standards on pipeline operators. As a result of those legislative enactments, PHMSA has issued several significant rulemakings. In August 2022, PHMSA finalized the last of three rules known collectively as the “Gas Mega Rule,” which collectively, among other items, imposed safety regulations on previously unregulated onshore gas gathering lines, required updated inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities and adjusted and strengthened repair, maintenance and integrity management assessment criteria for pipelines in HCAs and non-HCAs. The rule has been subject to litigation, and in August 2024, the D.C. Circuit Court agreed with the challengers that PHMSA had failed to conduct an adequate cost-benefit analysis of four of the new standards, vacating those aspects of the rules. In January 2025, PHMSA finalized a rule that enhances the safety requirements for gas distribution pipelines and requires updates to distribution integrity management programs, emergency response plans, operation and maintenance manuals and other safety practices. However, the current administration withdrew the final rule and, accordingly, it has not been codified. The integrity-related requirements and other provisions of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act, and the PIPES Act of 2020, as well as any implementation of PHMSA rules thereunder, could require us to pursue additional capital projects or conduct integrity or maintenance programs on an accelerated basis and incur increased operating costs that could have a material adverse effect on our costs of transportation services as well as our business, results of operations and financial condition.

In addition, certain states, including Texas, Louisiana, Oklahoma, New Mexico, and North Dakota, where we conduct operations, have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquids pipelines. We plan to continue our pipeline integrity inspection programs to assess and maintain the integrity of our pipelines. The results of these inspections may cause us to incur material and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

The imposition of new or enhanced safety requirements, or any issuance or reinterpretation of guidance by PHMSA or any other state or federal agencies with respect thereto, may require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which could result in increased operating costs that could have an adverse effect on our results of operations or financial position.

We are subject to cybersecurity risks. A cyber incident could occur and result in information theft, data corruption, operational disruption, disclosure of business sensitive, confidential or personally identifiable information, misdirected wire transfers, reputational harm, and financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct business. For example, we depend on digital technologies to operate our facilities, serve our customers and record financial data. At the same time, cyber incidents, including deliberate attacks, have increased. Our technologies, systems, networks, including our operational technology systems, and those of our business partners may become the target of cyberattacks or security breaches. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. Our technologies, systems and networks, and those of our vendors, suppliers, customers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could adversely disrupt our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cybersecurity risks may not be sufficient, and no security measure is infallible. As cyber incidents continue to evolve, we will be required to expend additional resources to enhance our security posture and cybersecurity defenses or to investigate and remediate any vulnerability to or consequences of cyber incidents. Advances in computer capabilities, rapid changes and innovation in the field of artificial intelligence, cryptography, inadequate facility security or other developments may result in a compromise or breach of the technology we use to safeguard confidential, personal, or otherwise protected information. As the breadth and complexity of the technologies we use continue to grow, including as a result of the use of artificial intelligence, mobile devices, cloud computing, open source software, social media and the increased reliance on devices connected to the internet, the potential risk of security breaches and cybersecurity attacks also increases. As the breadth and complexity of the technologies we use continue to grow, including as a result of the use of mobile devices, cloud services, open source software, social media and the increased reliance on devices connected to the internet, the potential risk of security breaches and cybersecurity attacks also increases. Despite ongoing efforts to improve our ability to protect data from compromise, we may not be able to protect all data across our diverse systems. Our efforts to improve security and protect data may also identify previously undiscovered instances of security breaches or other cyber incidents. Our insurance coverages may not be sufficient to cover all the losses we may experience as a result of a cyber incident.

The widespread outbreak of illnesses or any other public health crises that impacts operations and/or the global demand for energy commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.

We face risks related to major public health crises that are outside of our control and could significantly disrupt our operations and demand for our services, which could adversely affect our financial condition.

Risks Related to our Capital Projects and Future Growth

Our expansion or modification of existing assets or the construction of new assets may not result in revenue increases and are subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. For example, the construction of additional systems may be delayed or require greater capital investment if the commodity prices of certain supplies, such as steel pipe, increase due to imposed tariffs. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, fractionation facility or gas processing plant, the construction may occur over an extended period of time and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct pipelines or facilities to capture anticipated future growth in production in a region in which such growth does not materialize. For example, we do not possess reserves estimation expertise, and we typically do not obtain independent evaluations of natural gas or crude oil reserves connected to our gathering systems. As a result, the total reserves or estimated life of the reserves connected to our gathering systems could be less than we anticipate. Thus, new pipelines or facilities may receive lower volumes than we anticipate and may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. As a result, new pipelines or facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights of way prior to constructing new pipelines. We may be unable to obtain or renew such rights of way to connect new natural gas and crude oil supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights of way or to renew existing rights of way. If the cost of renewing or obtaining new rights of way increases, our cash flows could be adversely affected.

If we do not develop growth projects and/or make acquisitions for expanding existing assets or constructing new assets on economically acceptable terms, or fail to efficiently and effectively integrate developed or acquired assets with our asset base, our future growth will be limited. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to pay dividends to stockholders. In addition, any acquisitions we complete are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to pay dividends to stockholders. In addition, we may not achieve the expected results of any acquisitions and any adverse conditions or developments related to such acquisitions may have a negative impact on our operations and financial condition.

Our ability to grow depends, in part, on our ability to develop growth projects and/or make acquisitions that result in an increase in cash generated from operations. If we are unable to develop accretive growth projects or make accretive acquisitions because we are unable to (i) develop growth projects economically or identify attractive acquisition candidates and negotiate acceptable acquisition agreements, (ii) obtain financing for these projects or acquisitions on economically acceptable terms, or (iii) compete successfully for growth projects or acquisitions, then our future growth may be limited.

Any growth project or acquisition involves potential risks, including, among other things:

If these risks materialize, any growth project or acquired assets may inhibit our growth, fail to deliver expected benefits and/or add further unexpected costs. Challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of a growth project or acquisition if we fail to successfully integrate such businesses with our operations. If we consummate any future growth project or acquisition, our capitalization and results of operations may change significantly and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future growth projects or acquisitions.

A reduction in divestitures of energy assets by industry participants or a decrease in opportunities for industry expansion could limit our opportunities for future growth projects or acquisitions and could adversely affect our operations.

Growth projects may increase our concentration in a line of business or geographic region and acquisitions may significantly increase our size and diversify the geographic areas in which we operate. In addition, we may not achieve the desired effect from any future growth projects or acquisitions.

We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.

We participate in several joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities include, among others, large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business. Without the concurrence of joint venture participants holding sufficient voting interests, we may be unable to cause our joint ventures to take or not take certain actions, even though taking or preventing those actions may be in the best interests of the particular joint venture or us. Without the concurrence of joint venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not take certain actions, even though taking or preventing those actions may be in our best interests or the particular joint venture.

In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners. Any such transaction could result in our partnering with different or additional parties.

As is common in the midstream industry, we may operate one or more of our properties with one or more joint venture partners where we own a minority interest and/or contract with a third party to control operations. These relationships could require us to share operational and other control, such that we may no longer have the flexibility to control completely the development of these properties. If we do not timely meet our financial commitments in such circumstances, our rights to participate may be adversely affected. If a joint venture partner is unable or fails to pay its portion of development costs or if a third-party operator does not operate in accordance with our expectations, our costs of operations could be increased. We could also incur liability as a result of actions taken by a joint venture partner or third-party operator. Disputes between us and the other party may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.

Risks Related to our Financial Condition

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.

Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely and reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financial reporting capabilities. These enhancements require a significant commitment of resources, personnel and the development and maintenance of formalized internal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting now or in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002.

Any failure to maintain effective controls or difficulties encountered in the effective improvement of our internal controls could prevent us from timely and reliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material effect on our results of operations, financial condition and ability to comply with our debt obligations.

We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

Many of our customers may experience financial problems that could have a significant effect on their creditworthiness, especially in a depressed commodity price environment. A decline in natural gas, NGL and crude oil prices may adversely affect the business, financial condition, results of operations, creditworthiness, cash flows and prospects of some of our customers. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from a decline in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Additionally, a decline in the share price of some of our public customers may place them in danger of becoming delisted from a public securities exchange, limiting their access to the public capital markets and further restricting their liquidity. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. To the extent one or more of our key customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Furthermore, some bankruptcy courts have found that, in certain cases, oil, gas and water gathering agreements do not create covenants running with the land under governing law and are thus subject to rejection in Chapter 11 proceedings. Whether a particular contract is subject to rejection depends on the wording of the contract, the governing law and the forum where a particular bankruptcy case is filed. Financial problems experienced by our customers could result in the impairment of our long-lived assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues. Any material nonpayment or nonperformance by our key customers or our derivative counterparties could reduce our ability to pay cash dividends to our stockholders.

Inflation and changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.

Inflationary pressures have been volatile and have resulted in and may result in additional increases to the costs of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise. To the extent elevated inflation levels exist, we may experience further cost increases for our operations, including services, labor and equipment cost increases, and any subsequent increases in benchmark interest rates could have the effect of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could negatively impact the financial and operating results of our business. Additionally, there is uncertainty about the trade policies of the new Presidential administration, particularly when pertaining to treaties, tariffs and other limitations on international trade. We may experience increases in operating costs as a result of such policies.

Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and U.S. international trade policies, or any resultant changes in monetary policy, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher prices and revenues, and/or higher interest rates would negatively impact our business, financial condition and results of operations.

Changes in future business conditions could have a negative impact on the demand for our services and could cause recorded long-lived assets to become further impaired, and our financial condition and results of operations could suffer if there is a negative impact on the demand for our services and an additional impairment of long-lived assets.

We evaluate long-lived assets, including related intangibles, for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. Global oil and natural gas commodity prices, particularly crude oil, remain volatile. Decreases in commodity prices have previously had, and could continue to have, a negative impact on the demand for our services and our market capitalization.

Should energy industry conditions deteriorate, there is a possibility that long-lived assets may be impaired in a future period. Any impairment charges that we may take in the future could be material to our financial statements. Any additional impairment charges that we may take in the future could be material to our financial statements. We cannot accurately predict the amount and timing of any impairment of long-lived assets.

Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our expected equity commodity volumes that are hedged decreases substantially over time.

We have entered into derivative transactions related to only a portion of our equity volumes, future commodity purchases and sales, and transportation basis risk. We have entered into derivative transactions related to only a portion of our equity volumes, future commodity purchases and sales, and transportation basis risk. As a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity. The percentages of our expected equity volumes that are covered by our hedges decrease over time. To the extent we hedge our commodity price risk, we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. The derivative instruments we utilize for these hedges are based on posted market prices, which may be higher or lower than the actual natural gas, NGL and condensate prices that we realize in our operations. These pricing differentials may be substantial and could materially impact the prices we ultimately realize. Market and economic conditions may adversely affect our hedge counterparties’ ability to meet their obligations. Given volatility in the financial and commodity markets, we may experience defaults by our hedge counterparties. In addition, our exchange traded futures are subject to margin requirements, which creates variability in our cash flows as commodity prices fluctuate.

As a result of these and other factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certain circumstances may actually increase the variability of our cash flows. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

If we fail to balance our purchases and sales of the commodities we handle, our exposure to commodity price risk will increase.

We may not be successful in balancing our purchases and sales of the commodities we handle. In addition, a producer could fail to deliver promised volumes to us or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance between our purchases and sales. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

The amounts we pay in dividends may vary from anticipated amounts and circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or for other uses in our business.

The determination of the amounts of cash dividends, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors, in consultation with management, deems relevant. Many of these matters are affected by factors beyond our control and therefore, the actual amount of cash that is available for dividends to our stockholders may vary from anticipated amounts.

Additionally, as events present themselves or become reasonably foreseeable, our board of directors, which determines our business strategy and our dividends, may decide to address those matters by utilizing capital that may otherwise be used for our dividend. If we issue additional shares of common or preferred stock or we incur debt, the payment of dividends on those additional shares or interest on that debt could increase the risk that we will be unable to maintain or increase our cash dividend levels.

Further, dividends to our common stockholders are not cumulative. Consequently, if dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.

Our future tax liability may be greater than expected if our NOL carryforwards are limited, we do not generate expected deductions, tax authorities successfully challenge certain of our tax positions or from changes in tax laws.

As of December 31, 2025, we have U.S. federal NOL carryforwards of $4.4 billion, which do not expire under current tax laws. Subject to the CAMT discussed below, we expect to be able to utilize these NOL carryforwards and generate deductions to offset all or a portion of our future taxable income. This expectation is based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital, and the current expectation that our NOL carryforwards will not become subject to future limitations under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”).

While we expect to be able to utilize our NOL carryforwards and generate deductions to offset all or a portion of our future taxable income (subject to the CAMT discussed below), in the event that deductions are not generated as expected, one or more of our tax positions are successfully challenged by the IRS (in a tax audit or otherwise) or our NOL carryforwards are subject to future limitations under Section 382, our future tax liability may be greater than expected.

Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes may adversely affect our financial condition, results of operations and cash flows.

U.S. federal and state legislation is periodically proposed that would, if enacted into law, make significant changes to tax laws and could materially increase our tax obligations, adversely affecting our financial condition, results of operations and cash flows. For example, on August 16, 2022, President Biden signed into law the IRA which includes, among other things, the CAMT. Under the CAMT, a 15% minimum tax will be imposed on certain financial statement income of “applicable corporations.” The IRA treats a corporation as an applicable corporation in any taxable year in which the “average annual adjusted financial statement income” of such corporation for the three taxable year period ending prior to such taxable year exceeds $1 billion.

Based on our current interpretation of the IRA, the CAMT and related guidance, the impact from the OBBBA, and several operational, economic, accounting and regulatory assumptions, we do not anticipate paying CAMT in the near term.

The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA, the CAMT and related guidance. In the future, the U.S. Department of the Treasury and the IRS are expected to release regulations and additional interpretive guidance relating to such legislation, and any significant variance from our current interpretation could result in a change in our analysis of the application of the CAMT to us.

Derivatives legislation and its implementing regulations could have a material adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), enacted in July 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act, and most of these regulations have been finalized.

In October 2020, the CFTC adopted new rules that will place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The new rules required general compliance by January 1, 2022 for covered future positions and by January 1, 2023 for covered swaps positions. We have not experienced a material impediment to, and do not expect these regulations to materially impede, our hedging activity at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. The CFTC and the federal banking regulators have adopted regulations requiring certain counterparties to swaps to post initial and variation margin. However, our current hedging activities would qualify for the non-financial end user exemption from the margin requirements.

The Dodd-Frank Act and any new regulations could increase the cost of derivative contracts or potentially reduce the availability of derivatives to protect against risks we encounter. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

The European Union (the “EU”) and other non-U.S. jurisdictions are also implementing regulations with respect to the derivatives market. To the extent we enter into swaps with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may be impacted by such regulations. The implementing regulations adopted by the EU and by other non-U.S. jurisdictions could have a material adverse effect on us, our financial condition and our results of operations.

Risks Related to the Ownership of our Common Stock

Future sales of our common stock could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We or our stockholders may sell shares of common stock in subsequent public offerings and/or private transactions. We may also issue additional shares of common stock or convertible securities. As of December 31, 2025, we had 214,662,156 outstanding shares of common stock. We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including provisions which require:

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations and powers, preferences, including preferences over our common stock respecting dividends and distributions, rights, qualifications, limitations and restrictions as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our common stock.

Risks Related to Our Indebtedness

Increases in interest rates, due to associated Federal Reserve policies or otherwise, could adversely affect our cost of capital, which could increase our funding costs and reduce the overall profitability of our business.

We have significant exposure to increases in interest rates. As of December 31, 2025, certain of our and the Partnership’s debt were at variable interest rates. As a result of the variable interest rates on our debt, our results of operations could be adversely affected by increases in interest rates, due to associated Federal Reserve policies or otherwise. As a result of our variable interest debt, our results of operations could be adversely affected by increases in interest rates, due to associated Federal Reserve policies or otherwise. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Additionally, like all equity investments, an investment in our equity securities is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments. Reduced demand for our common stock resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common stock to decline. 41 Reduced demand for our common stock resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common stock to decline.

We have a substantial amount of indebtedness which may adversely affect our financial position and we may still be able to incur substantially more debt, which could collectively increase the risks associated with compliance with our financial covenants.

Our substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractual commitments, could have other important consequences to us, including the following:

Our long-term unsecured debt is currently rated by Fitch, Moody’s and S&P. As of December 31, 2025, Targa’s senior unsecured debt was rated “BBB” by Fitch, “Baa2” by Moody’s and “BBB” by S&P. Any future downgrades in our credit ratings could negatively impact our cost and terms of raising capital, and a downgrade could also adversely affect our ability to effectively execute aspects of our strategy and to access capital in the public markets. Any future downgrades in our credit ratings could negatively impact our cost of raising capital, and a downgrade could also adversely affect our ability to effectively execute aspects of our strategy and to access capital in the public markets.

Our International Swaps and Derivatives Association agreements (“ISDAs”) contain credit-risk related contingent features. As of December 31, 2025, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $104.1 million. Our derivative positions are unsecured. If our credit rating was to be downgraded one notch below investment grade by both Moody’s and S&P, as defined in our ISDAs, we estimate that as of December 31, 2025, we would not be required to post collateral to any counterparties per the terms of our ISDAs.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, investments or capital expenditures, acquisitions, selling assets, restructuring or refinancing debt, or seeking additional equity capital, and such results may adversely affect our ability to make cash dividends. We may not be able to affect any of these actions on satisfactory terms, or at all.

We may be able to incur substantial additional indebtedness in the future. The TRGP Revolver provides an available commitment of $3.5 billion, with a requirement to maintain a minimum available borrowing capacity equal to the aggregate amount outstanding under the Commercial Paper Program, and allows us to request increases in commitments up to an additional $500.0 million. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial. If we incur additional debt, this could increase the risks associated with compliance with our financial covenants.

The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in business or to take certain actions, including to pay dividends to our stockholders.

The agreements governing our outstanding indebtedness contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interests, such as:

A downgrade in our credit rating could also result in our indebtedness agreements imposing additional restrictive covenants that may place further operating and financial limitations on our business. In addition, certain of our debt agreements require us to satisfy and maintain specified financial ratios and other financial condition tests. In addition, certain of our debt agreements require us to satisfy and maintain specified financial ratios and other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

A breach of any of these covenants could result in an event of default under our debt agreements. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If we are unable to repay the accelerated debt under the Securitization Facility, the lenders under the Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. We have pledged the accounts receivables of Targa Receivables LLC under the Securitization Facility. If the indebtedness under our debt agreements is accelerated, we cannot assure you that we will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Risks Related to Regulatory Matters

Our and our customers’ operations are subject to a number of risks related to the potential threat of climate change, including evolving regulations for methane and other GHG emissions from the oil and gas sector, that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, reduce demand for the products and services we provide, and reduce our or our customers’ ability to access capital.

Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. As a result, our operations as well as the operations of our oil and natural gas exploration and production customers, are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. Notwithstanding the EPA’s recent proposal to revoke the “Endangerment Finding,” which supports the majority of EPA’s GHG-related regulations, the EPA under previous presidential administrations adopted a number of rules that included, among other things, efforts concerning the reduction, monitoring and reporting of GHG emissions. In August 2022, the IRA was signed into law, which amended the CAA to impose a first-time fee on the emission of excess methane above statutory methane emissions thresholds from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. In November 2024, the EPA issued a final rule implementing the methane emissions fee, although in February 2025, Congress repealed the rule under the Congressional Review Act. Additionally, in the OBBBA, Congress delayed the implementation of the methane emission fee until 2034. We cannot predict if the current Presidential administration and/or Congress may take further actions with respect to the IRA or methane emissions fee, the future implementation of which is uncertain at this time. However, compliance with this and other air pollution control and permitting requirements has the potential to increase our and our customers’ operating costs and delay development of our projects, which could adversely affect our business and results of operations. A material decrease in such divestitures or in opportunities for economic commercial expansion would limit our opportunities for future growth projects or acquisitions and could adversely affect our operations and cash flows available to pay cash dividends to our stockholders.

In recent years, there has been considerable focus on the regulation of methane emissions from the oil and gas sector. In response to President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources known as OOOOc, in December 2023. However, in March 2025, the EPA announced plans to reconsider OOOOb and OOOOc, in line with the current Presidential administration’s deregulatory agenda. In response to President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources known as OOOOc, in December 2023. Under the final rules, states have two years to prepare and submit their plans to impose methane emission controls on existing sources. Additionally, in November 2025, the EPA finalized an interim rule extending the compliance deadlines for certain provisions provided in OOOOb and OOOOc. Litigation challenging the EPA’s final interim rule extending such compliance deadlines for new and existing oil and gas sources remains pending.

Various states and groups of states have also adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on areas of coverage similar to what the federal government has or may consider, including GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.

Governmental, scientific, and public concern from sources across the world over the potential threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States. For instance, the prior Presidential administration issued several executive orders focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas. President Biden has issued several executive orders and strategies focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas. The use of executive orders in the United States to advance political objectives of Presidential administrations increases regulatory uncertainty for us. Other administrations may issue executive orders that are more favorable to the development and consumption of hydrocarbons. Regulations may be focused on addressing climate change and may impact the costs to produce, or demand for, oil and gas. In April 2024, the BLM finalized a rule that would limit flaring from well sites on federal lands, as well as require an operator to submit a waste minimization plan or a self-certification statement committing the operator to capturing 100% of the gas produced from a well and pay royalties on lost gas as part of the permit application process. This rule is currently subject to litigation and its implementation has been halted in North Dakota, Texas, Utah, Montana and Wyoming. Additionally, the BLM has halted enforcement of various regulatory compliance deadlines associated with the rule until the end of 2026. Any regulatory changes that restrict or require modifications to our or our suppliers’ existing operations or future expansions plans could reduce the demand for the products and services we provide, increase our operating costs and may have a negative impact on our financial condition. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas in which we operate may prevent us from obtaining supplies of natural gas or crude oil to replace the natural decline in volumes from existing wells, which could result in reduced volumes through our facilities and reduced utilization of our gathering, treating, processing, transportation and fractionation assets.

Litigation risks exist from certain cities, local governments, and other plaintiffs who may bring suit against large oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or consumers by failing to adequately disclose those impacts. Should we be targeted by such litigation, involvement in such a case could have adverse financial and reputational impacts and an unfavorable ruling could significantly impact our operations and adversely impact our financial condition. Should we be targeted by any similar litigation, involvement in such a case could have adverse financial and reputational impacts and an unfavorable ruling could significantly impact our operations and adversely impact our financial condition.

Additionally, from time to time, certain stockholders and bondholders currently invested in fossil fuel energy companies but concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energy companies have been attentive to sustainability lending, requesting additional action relating to the management of GHG emissions, and some of them may elect not to provide funding for fossil fuel energy companies, although this trend has waned in recent times. Institutional investors who provide financing to fossil fuel energy companies have also become more attentive to sustainability lending practices that favor “clean” power sources such as wind and solar photovoltaic, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Any material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our and our suppliers’ and customers’ businesses and operations. Adverse climatic impacts, whether inland or along the coast or offshore, could also affect our third-party suppliers, which could limit their ability to provide us with the necessary products and services enabling us to maintain operation of our pipelines and other facilities. In October 2023, the State of California adopted several laws that require disclosure of various climate risks, targets, and metrics. However, these laws are currently subject to litigation. To the extent implemented, laws such as these or similar laws may result in increased legal, accounting and financial compliance costs for us and our suppliers and customers to comply, including the implementation of significant additional internal controls processes and procedures regarding matters that have not been subject to such controls in the past, and impose increased oversight obligations on our management and board of directors. While implementing rules on certain of these laws are outstanding, both the California laws and the SEC rule, to the extent finalized, may result in increased legal, accounting and financial compliance costs for us and our suppliers and customers to comply, including the implementation of significant additional internal controls processes and procedures regarding matters that have not been subject to such controls in the past, and impose increased oversight obligations on our management and board of directors. We may also face increased litigation risks related to disclosures made pursuant to these requirements.

Increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other extreme weather events, as well as chronic shifts in temperature and precipitation patterns. For further discussion, please see Weather events may damage our assets, limit our ability or increase the costs to operate our business and adversely impact our customers on whom we rely on for throughput as well as third party vendors from whom we receive goods, which developments could cause us to incur significant costs and adversely affect our business, results of operations and financial condition.

Stakeholder and market attention to sustainability matters may impact the disclosure obligations of our business.

Companies across industries face scrutiny from a variety of stakeholders related to their sustainability practices. Societal expectations regarding sustainability initiatives and disclosures and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our customers’ products and our services, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing societal expectations regarding sustainability initiatives and disclosures and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our customers’ products and our services, reduced profits, increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Attention to climate change, for example, may result in demand shifts for our or our customers’ hydrocarbon products and additional governmental investigations and private litigation against us or those customers. Increasing attention to climate change, for example, may result in demand shifts for our or our customers’ hydrocarbon products and additional governmental investigations and private litigation against us or those customers.

As part of our ongoing effort to enhance our sustainability practices, our Board of Directors has established a Sustainability Committee. Committee members oversee management’s implementation of sustainability policies and procedures in coordination with other committees of the Board as appropriate. Committee members oversee management’s implementation of sustainability policies and provide insight to the Board on the effectiveness of integrating sustainability into our various business activities. We also have a vice president of sustainability, who reports directly to our CEO and also regularly provides reports on relevant sustainability matters to our Board of Directors. We have also appointed a senior vice president of sustainability, who reports directly to our CEO and also regularly provides reports on relevant sustainability matters to our Board of Directors. We published our 2024 Sustainability Report, which provides updates on our performance related to certain sustainability topics and certain sustainability goals, such as reductions in methane intensity in line with the ONE Future goals. We also published our 2022 Sustainability Report, which provides updates on our performance related to certain sustainability topics and sets certain sustainability goals, such as reductions in methane intensity in line with the ONE Future goals. While we may elect to seek out various additional voluntary sustainability targets now or in the future, such targets are often aspirational. Moreover, despite our governance oversight in place, many of our sustainability targets and goals are ambitious, and we may not be able to adequately identify sustainability-related risks and opportunities and, further, may not be able to meet our sustainability targets and goals in the manner or on such a timeline as initially contemplated, or at all, including as a result of unforeseen costs or technical difficulties associated with achieving such results. Moreover, even if we are to achieve our targets and goals or complete other sustainability initiatives, there is no guarantee that doing so will have the desired effect. Sustainability-related actions or statements that we may make or take are sometimes based on expectations, assumptions, or third-party information that we currently believe to be reasonable, but which may subsequently be determined to be erroneous or be subject to misinterpretation. For example, methodologies regarding the monitoring and calculation of climate risks and GHG emissions are evolving, and it is possible that stakeholders, either currently or at some point in future, may not agree with our approach. Moreover, to the extent we elected to pursue such targets and were able to achieve the desired target levels, such achievement may have been accomplished as a result of entering into various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our sustainability impact instead of actual changes in our sustainability performance. However, we cannot guarantee that there will be sufficient offsets for purchase or that, notwithstanding our reliance on any reputable third party registries, that the offsets we do purchase will successfully achieve the emissions reductions they represent. Notwithstanding our election to pursue aspirational targets now or in the future, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other sustainability-related goals, but we cannot guarantee that we will be able to pursue or implement such goals because of potential costs or technical or operational obstacles. If we fail to, or are perceived to fail to, comply with or advance certain sustainability initiatives (including the timeline and manner in which we complete such initiatives), we may be subject to various adverse impacts, including reputational damage and potential stakeholder engagement and/or litigation, even if such initiatives are currently voluntary.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings and proxy voting recommendation processes for evaluating companies on their approach to sustainability matters. Additionally, we and other companies in our industry publish sustainability reports that are made available to investors. Such ratings, proxy advisory services, and reports are used by some investors to inform their investment and voting decisions. Such ratings and reports are used by some investors to inform their investment and voting decisions. Certain lenders may decide not to provide funding to us or our customers’ companies based on sustainability concerns, which could adversely affect our financial condition and access to capital for potential growth projects. Also, certain institutional lenders may decide not to provide funding to us or our customers’ companies based on sustainability concerns, which could adversely affect our financial condition and access to capital for potential growth projects. Investors, lenders, and other stakeholders that focus on issues related to environmental justice and natural capital may result in increased scrutiny of our processes on such issues. Increasingly, investors, lenders, and other stakeholders are focusing on issues related to environmental justice and natural capital, which may result in increased scrutiny of our processes on such issues.

Certain public statements with respect to sustainability matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues are becoming increasingly subject to heightened scrutiny from public and governmental authorities, as well as other parties, related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential sustainability benefits. For example, the SEC has taken enforcement action against companies for sustainability-related misconduct, including alleged greenwashing. Regulators, such as the SEC and various state agencies, as well as non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain sustainability statements, goals, or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and governmental authorities related to our sustainability efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Many of our customers and suppliers may be subject to similar expectations and challenges, which may augment or create additional risks, including risks that may not be known to us. Additionally, many of our customers and suppliers may be subject to similar expectations and challenges, which may augment or create additional risks, including risks that may not be known to us.

We could incur significant costs in complying with more stringent occupational safety and health requirements.

We are subject to stringent federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the federal Occupational Safety and Health Administration’s (“OSHA”) hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. Failure to comply with these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctions including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, any of which could have a material adverse effect on our business, financial condition and results of operations.

State laws and regulations limiting hydraulic fracturing activities could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets.

While we do not conduct hydraulic fracturing, many of our oil and gas exploration and production customers do perform such activities. Hydraulic fracturing is typically regulated by state oil and gas commissions and many states have adopted legal requirements that have imposed new or more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities, including in states where we or our customers conduct operations. Hydraulic fracturing is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over, proposed or promulgated regulations governing, and conducted investigations relating to certain aspects of the process, including the EPA. States could further elect to suspend or prohibit hydraulic fracturing activities in the future. While governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular, non-governmental organizations may also seek to restrict hydraulic fracturing through ballot initiatives, such as those that have been pursued in Colorado. New or more stringent laws, regulations or regulatory or ballot initiatives relating to the hydraulic fracturing process could lead to our customers reducing crude oil and natural gas drilling activities using hydraulic fracturing techniques, while increased public opposition to activities using such techniques may result in operational delays, restrictions, cessations, or increased litigation. New or more stringent laws, regulations, executive orders or regulatory or ballot initiatives relating to the hydraulic fracturing process could lead to our customers reducing crude oil and natural gas drilling activities using hydraulic fracturing techniques, while increased public opposition to activities using such techniques may result in operational delays, restrictions, cessations, or increased litigation. Any one or more of such developments could reduce demand for our gathering, processing and fractionation services and have a material adverse effect on our business, financial condition and results of operations.

Our operations are subject to environmental laws and regulations and a failure to comply or an accidental release into the environment may cause us to incur significant costs and liabilities.

Our operations are subject to numerous federal, tribal, state and local environmental laws and regulations governing occupational health and safety, the discharge of pollutants into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations enforced by various governmental authorities, such as the EPA and BLM, and analogous state agencies. For more information regarding the regulation of our operations, see “Item 1. Business—Regulation of Operations, Environmental and Occupational Health and Safety Matters. For more information regarding the regulation of our operations, see “Item 1. Business—Regulation of Operations. ”

The risk of incurring environmental costs and liabilities in connection with our operations is significant due to our handling of natural gas, NGLs, crude oil and other petroleum products, because of air emissions and product-related discharges arising out of our operations, and as a result of historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages and fines or penalties for related violations of environmental laws or regulations.

Moreover, stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. For example, in March 2023, the EPA issued its Good Neighbor Plan rule, which imposes emissions-related requirements on fossil fuel-fired power plants and other industrial users in 22 states, including Texas and Louisiana, which could reduce demand for our products and accelerate the transition away from oil and gas to other sources of energy. The Good Neighbor Plan was to have become effective in 2026, but in June 2024, was stayed by the U.S. Supreme Court. However, following the change in Presidential administrations, the EPA has announced its intention to revisit the Good Neighbor Plan. We cannot predict what actions the current Presidential administration will take with respect to the Good Neighbor Plan and any such actions and their timing remain uncertain.

There continues to be uncertainty on the federal government’s applicable jurisdictional reach under the Clean Water Act over waters of the United States, including wetlands, as the EPA and the U.S. Army Corps of Engineers (“Corps”) have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach. Following legal challenges, the implementation of the most recent September 2023 rule currently varies by state. However, in November 2025, the EPA and the Corps proposed a rule to further update and narrow the September 2023 definition of WOTUS, guided by the Sackett v. EPA decision. To the extent any judicial ruling or administrative rulemaking or other action further changes the scope of the Clean Water Act’s jurisdiction in areas where we or our customers conduct operations, we could face increased delays, restrictions or cessation of the development of projects, longer permitting timelines, or increased compliance expenditures or mitigation costs for our and our oil and natural gas customers’ operations, which may reduce the rate of production of natural gas or crude oil from operators with whom we have a business relationship and, in turn, have a material adverse effect on our business, results of operations and cash flows. The implementation of the final rule, results of the litigation and any further expansion of the scope of the Clean Water Act’s jurisdiction in areas where we or our customers conduct operations, could lead to delays, restrictions or cessation of the development of projects, result in longer permitting timelines, or increased compliance expenditures or mitigation costs for our and our oil and natural gas customers’ operations, which may reduce the rate of production of natural gas or crude oil from operators with whom we have a business relationship and, in turn, have a material adverse effect on our business, results of operations and cash flows.

Separately, Nationwide Permit (“NWP”) 12, which is available under the Clean Water Act for certain oil and gas activities, has been subject to legal challenges and regulatory revision in recent years. The Corps has been engaged in a formal review of NWP 12 as a result of these actions. However, while this review is ongoing, the Corps has resumed permitting decisions. Although we cannot predict what actions the new Presidential administration may take to revise NWP 12, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps. While the full extent and impact of these actions is unclear at this time, any disruption in our ability to obtain coverage under NWP 12 or other general permits may result in increased costs and project delays if we are forced to seek individual permits from the Corps. This in turn could have an adverse effect on our business, financial condition and results of operation.

A change in the jurisdictional characterization of some of our assets by federal, state, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may (i) cause our revenues to decline and operating expenses to increase or (ii) delay or increase the cost of expansion projects.

With the exception of the Driver Residue Pipeline, TPL SouthTex Transmission Company LP, Buffalo Run Pipeline LLC, Bull Run Pipeline LLC, and Targa SouthTex Mustang Transmission Ltd., which are each subject to FERC regulation under the NGPA or limited FERC regulation under the NGA, and Forza Pipeline LLC which will be subject to FERC jurisdiction under the NGA, our natural gas pipeline operations are generally exempt from FERC regulation, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses, including certain FERC reporting and posting requirements in a given year., which are each subject to FERC regulation under the NGPA or limited FERC regulation under the NGA, our natural gas pipeline operations are generally exempt from FERC regulation, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses, including certain FERC reporting and posting requirements in a given year. We believe that the natural gas pipelines in 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, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

Targa NGL, Targa Gulf Coast, Grand Prix Pipeline, Targa San Andres Crude, and Targa Badlands have pipelines that are considered common carrier pipelines subject to regulation by FERC under the ICA. The ICA requires that we maintain tariffs on file with FERC for each of these common carrier pipelines that have not been granted a waiver. The ICA requires that we maintain tariffs on file with FERC for each of the Targa NGL, Targa Gulf Coast and Grand Prix Pipeline common carrier pipelines that have not been granted a waiver. With respect to pipelines that have been granted a waiver of the ICA and related regulations by FERC, should a particular pipeline’s circumstances change, FERC could, either at the request of other entities or on its own initiative, assert that such pipeline no longer qualifies 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), provide a cost justification for the transportation charge, and provide regulated services to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on these pipelines could adversely affect our results of operations.

The classification of some of our gathering facilities, transportation pipelines, and purchase and sale transactions as FERC-jurisdictional or non-jurisdictional may be subject to change based on future determinations by FERC, the courts or Congress, in which case, our operating costs could increase and we could be subject to enforcement actions under the EP Act of 2005.

Various federal agencies within the U.S. Department of the Interior, particularly the BLM, Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, along with 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. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands can generally be subject to the Native American tribal court system. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.

Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas and liquids regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the natural gas and liquids markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas and liquids pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity. For more information regarding the regulation of our operations, see “Item 1. Business—Regulation of Operations.”

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the EP Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for violations of the NGA or NGPA 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, as well as authority to order disgorgement of profits associated with any violation. While our systems other than the Driver Residue Pipeline, TPL SouthTex Transmission Company LP, TPL SouthTex Pipeline Company LLC, Buffalo Run Pipeline LLC, Bull Run Pipeline LLC, Targa SouthTex Mustang Transmission Ltd. While our systems other than the Driver Residue Pipeline, TPL SouthTex Transmission Company LP, TPL SouthTex Pipeline Company LLC, Targa Midland Gas Pipeline LLC, 49 Midland-Permian Pipeline LLC, Delaware-Permian Pipeline LLC, and Targa SouthTex Mustang Transmission Ltd. , and Forza Pipeline LLC have not been regulated by FERC under the NGA or NGPA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements., have not been regulated by FERC under the NGA or NGPA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. In addition, FERC has civil penalty authority under the ICA to impose penalties for violations under the ICA up to a maximum amount that is adjusted annually for inflation, which for 2026 was up to approximately $16,590 (which amount may be updated for inflation in 2026) per violation per day, and failure to comply with the ICA and regulations implementing the ICA could subject us to civil penalty liability. In addition, FERC has civil penalty authority under the ICA to impose penalties for violations under the ICA up to a maximum amount that is adjusted annually for inflation, which for 2024 was up to approximately $16,170 per violation per day, and failure to comply with the ICA and regulations implementing the ICA could subject us to civil penalty liability. For more information regarding regulation of our operations, see “Item 1. Business—Regulation of Operations.” Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time.

We are subject to cybersecurity and data privacy laws and regulations, and we may become subject to litigation and directives relating to our processing of personal information.

The jurisdictions in which we operate (including the United States) have laws governing how we must respond to a cyber incident that results in the unauthorized access, disclosure, or loss of personal information. Additionally, laws and regulations governing data privacy and unauthorized disclosure of personal information and imposing certain cybersecurity-related requirements pose increasingly complex compliance challenges. For example, Texas has enacted data privacy legislation. Some or all of such legislation will elevate our compliance costs over time. Our business involves collection, use, and other processing of personal information and personally identifiable information of our employees, investors, contractors, suppliers, and customer contacts. As legislation continues to develop and cyber incidents continue to evolve, we will likely be required to expend significant resources to continue to modify or enhance our protective measures to comply with such legislation and to detect, investigate and remediate vulnerabilities to cyber incidents. Any failure by us, or a company we acquire, to comply with such laws and regulations could result in reputational harm, loss of goodwill, penalties, liabilities, remediation costs, or mandated changes in our business practices. Each has the potential to materially impact our financial condition.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity