Targa Resources TRGP · USD

Note 22 — Segment Information We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided. Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast. Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes our NGL pipeline system, which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. Our Downstream facilities are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana. Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column. The Company’s chief operating decision maker (“CODM”) is the Chief Executive Officer. The Company’s CODM assesses the segments’ performance by using each segment’s operating margin.

Note 18 — Revenue Fixed consideration allocated to remaining performance obligations The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements, with remaining contract terms ranging from 1 to 15 years. 2026 2027 2028 and after Fixed consideration to be recognized as of December 31, 2025 $ 371.6 $ 397.0 $ 1,773.8 Based on the optional exemptions that we elected to apply, the amounts presented in the table above exclude remaining performance obligations for (i) variable consideration for which the allocation exception is met and (ii) contracts with an original expected duration of one year or less. Deferred Revenue Deferred revenue as of December 31, 2025 and 2024 was $135.7 million and $119.9 million, respectively. Deferred revenue includes contributions in aid of construction received from customers related to owned property, plant, and equipment for which revenue is recognized over the expected contract term. Deferred revenue also includes consideration received in 2015 and 2017 amendments to a gas gathering and processing agreement. The deferred revenue related to these amendments is being recognized through the end of the agreement’s term in 2035. For the years ended December 31, 2025, 2024 and 2023, we recognized revenue of $20.5 million, $19.6 million and $17.4 million, respectively, from prior period deferral. The following table shows the components of deferred revenue as of the periods presented: December 31, 2025 December 31, 2024 Contributions in aid of construction $ 110.9 $ 91.1 Gas contract amendment 24.8 27.3 Other — 1.5 Total deferred revenue $ 135.7 $ 119.9 The following table shows the changes in deferred revenue for the periods presented: Year Ended December 31, 2025 2024 Balance at beginning of period $ 119.9 $ 248.8 Additions 36.3 19.7 Revenue recognized (20.5 ) (19.6 ) Reclassification to accrued liabilities (1) — (129.0 ) Balance at end of period $ 135.7 $ 119.

Note 16 — Commitments Future non-cancelable commitments comprise of operating and capital expenditures related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregate thereafter as of December 31, 2025: In Aggregate 2026 2027 2028 2029 2030 Thereafter Land sites and rights of way (1) $ 374.3 $ 11.8 $ 13.2 $ 18.6 $ 9.4 $ 8.5 $ 312.8 (1)Leases related to land sites and rights of way provide for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual. The following table shows total operating expenses incurred under the above non-cancelable commitments for the periods presented: Year Ended December 31, 2025 2024 2023 Land sites and rights of way $ 6.8 $ 7.2 $ 9.

Note 8 — Debt Obligations December 31, 2025 December 31, 2024 Current: Partnership accounts receivable securitization facility, due August 2026 (1) $ — $ 330.0 Senior unsecured notes issued by the Partnership: (2) 6.875% fixed rate, due January 2029 (3) 679.3 — Debt issuance costs, net of amortization (3) (2.3 ) — Finance lease liabilities 93.1 57.7 Current debt obligations 770.1 387.7 Long-term: TRGP senior revolving credit facility, variable rate, due February 2030 (4) 161.0 1,130.5 Senior unsecured notes issued by TRGP: 5.200% fixed rate, due July 2027 750.0 750.0 4.350% fixed rate, due January 2029 (3) 750.0 — 6.150% fixed rate, due March 2029 1,000.0 1,000.0 4.900% fixed rate, due September 2030 (5) 750.0 — 4.200% fixed rate, due February 2033 750.0 750.0 6.125% fixed rate, due March 2033 900.0 900.0 6.500% fixed rate, due March 2034 1,000.0 1,000.0 5.500% fixed rate, due February 2035 1,000.0 1,000.0 5.550% fixed rate, due August 2035 (6) 1,000.0 — 5.650% fixed rate, due February 2036 (5) 750.0 — 5.400% fixed rate, due July 2036 (3) 1,000.0 — 4.950% fixed rate, due April 2052 750.0 750.0 6.250% fixed rate, due July 2052 500.0 500.0 6.500% fixed rate, due February 2053 850.0 850.0 6.125% fixed rate, due May 2055 (6) 1,000.0 — Unamortized discount (38.3 ) (29.4 ) Senior unsecured notes issued by the Partnership: (2) 6.500% fixed rate, due July 2027 (5) — 705.2 5.000% fixed rate, due January 2028 700.3 700.3 6.875% fixed rate, due January 2029 (3) — 679.3 5.500% fixed rate, due March 2030 949.6 949.6 4.875% fixed rate, due February 2031 1,000.0 1,000.0 4.000% fixed rate, due January 2032 1,000.0 1,000.0 16,522.6 13,635.5 Debt issuance costs, net of amortization (120.6 ) (89.0 ) Finance lease liabilities 260.4 240.4 Long-term debt 16,662.4 13,786.9 Total debt obligations $ 17,432.5 $ 14,174.6 Irrevocable standby letters of credit: (4) Letters of credit outstanding under the TRGP senior revolving credit facility $ 20.0 $ 17.6 (1)As of December 31, 2025, the Partnership had no amount drawn under its $600.0 million accounts receivable securitization facility (the “Securitization Facility”), resulting in $600.0 million of remaining availability.(2)We guarantee all of the Partnership’s outstanding senior unsecured notes.(3)On November 12, 2025, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.350% Senior Unsecured Notes due 2029 and (ii) $1.0 billion aggregate principal amount of our 5.

Note 19 — Income Taxes The following table shows components of the federal and state income tax provisions for the periods presented: Year Ended December 31, 2025 2024 2023 Current expense (benefit) Federal $ 12.2 $ (0.1 ) $ 0.2 State 0.9 17.6 13.4 Total current expense (benefit) 13.1 17.5 13.6 Deferred expense (benefit) Federal 466.7 339.2 342.4 State 49.9 27.8 7.2 Total deferred expense (benefit) 516.6 367.0 349.6 Total income tax expense (benefit) $ 529.7 $ 384.5 $ 363.2 Our deferred income tax assets and liabilities as of the periods presented consist of recognition differences related to certain types of costs as follows: December 31, 2025 December 31, 2024 Deferred tax assets: Net operating loss and tax credit carryforwards $ 1,045.0 $ 1,094.9 Disallowed business interest expense carryforward 22.1 113.5 Property, plant and equipment 1.5 1.9 Other 12.6 10.1 Deferred tax assets before valuation allowance 1,081.2 1,220.4 Valuation allowance (5.9 ) (5.9 ) Deferred tax assets 1,075.3 1,214.5 Deferred tax liabilities: Investments (1) (2,468.8 ) (2,086.6 ) Deferred tax liabilities (2,468.8 ) (2,086.6 ) Net deferred tax asset (liability) $ (1,393.5 ) $ (872.1 ) Net deferred tax asset (liability) Federal $ (1,298.0 ) $ (826.7 ) State (95.5 ) (45.4 ) Long-term deferred tax liability, net $ (1,393.5 ) $ (872.1 ) (1)Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of our investment in the Partnership. We are subject to tax in the U.S. and various state jurisdictions, and we are subject to periodic audits and reviews by taxing authorities. As of December 31, 2025, examinations by the Internal Revenue Service (“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.

Note 10 — Leases We have non-cancellable operating leases primarily associated with our compressors, office facilities, rail assets, land, storage and terminal assets. We have finance leases primarily associated with our compressors, vehicles, generators, substations and tractors. Our leases have remaining lease terms of 1 to 10 years, some of which include options to extend the lease term for up to 20 years. The following table shows balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated Balance Sheets as of the periods presented: December 31, Balance Sheet Location 2025 2024 Operating leases: Lease right-of-use assets, net Other long-term assets $ 93.9 $ 103.7 Current liabilities Accrued liabilities 24.3 25.2 Non-current liabilities Other long-term liabilities 89.5 90.4 Finance leases: Lease right-of-use assets, net Property, plant and equipment, net $ 324.9 $ 285.1 Current liabilities Current debt obligations 93.1 57.7 Non-current liabilities Long-term debt 260.4 240.4 Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements of Operations, depending on the nature of the leases. Finance lease costs are included in Depreciation and amortization expense and Interest expense, net in our Consolidated Statements of Operations. The following table shows components of lease expense for the periods presented: Year Ended December 31, 2025 2024 2023 Lease cost Operating lease cost $ 28.6 $ 30.6 $ 18.3 Short-term lease cost 36.5 45.2 56.7 Variable lease cost 52.5 46.0 26.0 Finance lease cost Amortization of right-of-use assets 75.0 55.3 48.2 Interest expense 16.1 14.5 14.0 Total lease cost $ 208.7 $ 191.6 $ 163.2 The following table shows other supplemental information related to our leases for the periods presented: Year Ended December 31, 2025 2024 2023 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for operating leases $ 32.4 $ 32.4 $ 21.4 Operating cash flows for finance leases 15.9 14.2 13.9 Financing cash flows for finance leases 76.5 50.1 42.9 The weighted-average remaining lease terms for operating leases and finance leases are 5 years and 4 years, respectively. The weighted-average discount rates for operating leases and finance leases are 5.0% and 4.9%, respectively.

Note 4 — Acquisitions and Joint Ventures In January 2023, we completed the acquisition of Blackstone Energy Partners’ 25% interest in the Grand Prix Pipeline LLC (the “Grand Prix Transaction”) for aggregate consideration of $1.05 billion in cash and a final closing adjustment of $41.9 million. Following the closing of the Grand Prix Transaction, we own 100% of the interest in Grand Prix. The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax, was $490.7 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders. In December 2023, we completed the acquisition of the remaining 50% membership interest in Carnero G&P LLC (“Carnero”) from our joint venture partner for cash consideration of $27.0 million (the “Carnero Acquisition”). The change in our ownership interests was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the consideration in excess of the carrying amount, net of tax, was $20.1 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders. 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, 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, 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, pending the receipt of customary regulatory and other approvals. Both the Blackcomb and Traverse pipelines will be operated by an affiliate of WhiteWater.

Description of Processes for Assessing, Identifying, and Managing Cybersecurity Risks Cybersecurity risk is an area of focus for Targa, particularly as our operations become increasingly dependent on digital technologies. Across the world, cybersecurity incidents are occurring more frequently, use increasingly sophisticated methods and could pose serious risks to the Company’s data integrity, reputation, operations and revenue. The Company has a cybersecurity program, which uses technology and processes to help mitigate cybersecurity risks, with our Security Operations team working to monitor, assess, identify, and respond to potential cybersecurity incidents that threaten the Company. We utilize the National Institute of Standards and Technology Cybersecurity Framework as well as supplemental guidance for information and operational technologies to assess current risks against deployed current countermeasures. We seek to follow federal and state statutory and regulatory guidance and have adopted internal policies and standards that we believe are in alignment with these requirements. Our cybersecurity program covers Targa’s general corporate information and operational technology systems, which support our various lines of business. Our cybersecurity program also follows defense in depth principles, which aim to implement various layered access control, detection, prevention, and response measures. Targa has formal disaster recovery and business continuity plans, as well as a Cyber Incident Response Plan, which is periodically tested using tabletop exercises. We regularly engage with independent third parties to assess our vulnerabilities and help us mitigate cybersecurity-related risks. Targa’s security posture is also tested by internal Targa personnel and independent third parties to gauge its effectiveness. Our cybersecurity program includes a formally documented process for oversight of cybersecurity risks associated with our third-party service providers. This process begins prior to engagement. Third-party service providers are evaluated using independent assessment tools to gauge their security posture. The above cybersecurity risk management processes are integrated into our overall risk management program.