Targa Resources Corp. (TRGP)

Business

Source: Form 10-K for the fiscal year ended December 31, 2025 (accession 0001193125-26-059296), with asset changes since year-end from the Form 10-Q for the quarter ended September 30, 2026 (accession 0001193125-26-449541).

Targa Resources is a U.S. midstream company: it gathers, treats and processes natural gas and crude oil for producers, mostly in the Permian Basin, and then moves the natural gas liquids (NGLs) extracted at its plants through its own pipelines to Mont Belvieu, Texas, where it fractionates them into purity products (ethane, propane, butanes, natural gasoline), stores them, sells them to petrochemical, refining and heating customers, and loads propane and butane onto ships for export at its Galena Park Marine Terminal on the Houston Ship Channel. Revenue comes from two sources: fees per unit of throughput (gathering, processing, transportation, fractionation, storage, terminaling, export), and the sale of natural gas, NGLs and condensate, including the "equity volumes" it keeps as payment under percent-of-proceeds processing contracts. The company describes its contracts as predominantly fee-based. Its exposure to commodity prices comes from the percent-of-proceeds contracts and its marketing activities, and it partly hedges that exposure.

The company reports two segments:

• Gathering and Processing (G&P). Natural gas gathering and processing, plus crude oil gathering and terminaling. At the end of 2025 it had about 31,600 miles of gathering pipelines and 54 owned and operated processing plants, across five operating areas:
  • Permian Midland: about 7,800 miles of pipe and 20 plants with 4,119 MMcf/d of capacity. Seventeen of the plants sit in the WestTX joint venture, which is about 72.8% Targa-owned and the rest owned by ExxonMobil.
  • Permian Delaware: about 7,700 miles of pipe, 19 plants with 3,835 MMcf/d of capacity, and 2.6 Bcf/d of gas-treating capacity.
  • Central: Eagle Ford, Fort Worth Basin, Oklahoma and Kansas. About 14,800 miles of pipe and 11 plants with 1,955 MMcf/d of capacity.
  • Coastal: Louisiana Gulf Coast, with 930 MMcf/d of processing capacity.
  • Badlands: Bakken/Three Forks in North Dakota, covering crude and gas gathering and the Little Missouri plants. Targa has owned all of it since buying Blackstone's 45% interest for $1.8 billion in March 2025.
• Logistics and Transportation (L&T, or "Downstream").
  • NGL pipelines: the system can carry more than 1,000 MBbl/d into Mont Belvieu.
  • Fractionation: nine wholly owned trains at Mont Belvieu with 963.0 MBbl/d of capacity, plus Train 7 (120 MBbl/d, 80% owned with Williams) and a 55.0 MBbl/d fractionator at Lake Charles, Louisiana. Targa calls itself one of the largest NGL fractionators on the Gulf Coast.
  • Storage: 35 owned storage wells with about 81 MMBbl of gross capacity.
  • LPG exports: effective export capacity of about 14.0 MMBbl per month at year-end 2025.
  • Marketing: NGL marketing, wholesale propane, refinery services and natural gas marketing. The marketing businesses are seasonal and weather-driven.

A third reporting line, "Other", holds only mark-to-market gains and losses on derivatives that are not designated as hedges.

Growth is built mainly around the Permian. The 10-Q lists 2026 start-ups for the Falcon II, East Pembrook and East Driver plants (275 MMcf/d each), the Train 11 fractionator (150 MBbl/d) and the Delaware Express NGL pipeline expansion. The following projects are under construction:

• Processing plants: Copperhead, Yeti, Yeti II, Roadrunner III, Copperhead II, Wrangler, Ranger and Ranger II. All are in Permian Delaware, all but Roadrunner III (265 MMcf/d) are 275 MMcf/d, and they are expected to start between Q4 2026 and Q2 2028.
• Fractionators: Train 13 (Q1 2028).
• NGL pipeline: Speedway, a roughly 500-mile, 30-inch pipeline from the Permian to Mont Belvieu with initial capacity of about 500 MBbl/d, expandable to 1,000 MBbl/d (Q3 2027).
• Export terminal: the Galena Park LPG export expansion, which raises effective capacity to up to 19 MMBbl per month (Q3 2027).
• Residue-gas pipelines: Buffalo Run (fully complete Q1 2028), Forza (a 36-mile FERC-regulated interstate line, Q2 2028) and Bull Run II (a 70-mile line announced in August 2026, Q2 2028).
• Joint ventures: Targa owns 17.5% of the Blackcomb joint venture, which is building the 2.5 Bcf/d Blackcomb pipeline from the Permian to Agua Dulce (expected Q4 2026) and the Traverse pipeline from Agua Dulce to Katy (mid-2027).

Recent acquisitions:

• Stakeholder Midstream, LLC. Bought on January 6, 2026 for $1.25 billion in cash, effective January 1, 2026. The assets are about 480 miles of gas pipelines, about 180 MMcf/d of cryogenic processing and sour-gas treating capacity, carbon-capture operations that generate Section 45Q tax credits, and a small crude gathering system. They are now part of Permian Delaware.
• Dovetail Midstream, LLC. Bought in December 2025 from Riley Exploration Permian, together with some of Riley's compressor assets, for about $122.8 million in cash. Up to $60.0 million more may be paid over five years if volume thresholds are met. The assets are compression and gas gathering in Eddy County, New Mexico.
• Nile Acquisition. Bought in December 2025 from Nile Midstream, LLC and Four Winds Midstream, LLC, both wholly owned subsidiaries of Blackbeard Holdings, LLC, for $90.3 million in cash, including capitalized transaction costs. The assets are mainly compression and pipeline infrastructure. Dovetail and Nile were Targa's two December 2025 bolt-on acquisitions.

At December 31, 2025 Targa had about 3,570 employees, none covered by collective bargaining agreements.

Risk factors

Source: Form 10-K for the fiscal year ended December 31, 2025 (accession 0001193125-26-059296), Item 1A; Q3 2026 updates from the Form 10-Q (accession 0001193125-26-449541), which makes no changes to the annual report's risk factors; producer curtailments from the earnings releases furnished with the Forms 8-K filed February 19, 2026 (accession 0001193125-26-058040) and August 6, 2026 (accession 0001193125-26-336525).

The main risks are commodity prices and the volumes they drive, the size of the construction program and the debt behind it, and regulation of an expanding pipeline network.

• Commodity prices and producer activity. Targa earns more when natural gas, NGL and condensate prices are higher. If prices fall, its cash flow under percent-of-proceeds contracts falls roughly in proportion, to the extent the volumes are unhedged. Prices also drive producers' drilling and completion decisions, and Targa has no control over them. The filings show this risk in practice: producers cut back output during periods of negative Waha natural gas prices in Q4 2025 and Q2 2026, and the average realized natural gas price in the G&P segment was negative (–$0.04/MMBtu) for the first nine months of 2026.
• Volumes must keep being replaced. Wells connected to Targa's systems decline naturally. Throughput, and the NGL supply to its fractionators, depend on new drilling near its assets. Lower NGL demand from petrochemical, refining or export markets, or a supply glut, could cut both volumes and fees. Ethane is singled out: processors can leave it in the gas stream ("ethane rejection") when gas prices are high relative to NGL prices.
• Hedging limits. Only part of the equity volumes is hedged, and the hedged share falls in later years. Hedges may not protect against basis differentials. At September 30, 2026 the net derivative liability was $272.5 million, up from $66.9 million at year-end 2025, which the company attributes mainly to unfavorable moves in natural gas forward basis prices. Exchange-traded futures require margin payments that make cash flow less predictable.
• Execution risk on capital projects. Projects may be late, over budget (tariffs on steel pipe are named as one cause) or built ahead of production growth that never arrives. Targa does not estimate reserves itself and usually does not get independent reserve evaluations for the wells connected to its systems. Acquisitions carry integration risk. Joint ventures (Blackcomb, WestTX, Train 7 and others) need partner consent for major decisions.
• Debt. Total debt obligations were $19.84 billion at September 30, 2026, up from $17.43 billion at year-end 2025. Senior unsecured debt was rated BBB (Fitch), Baa2 (Moody's) and BBB (S&P) at year-end 2025. Variable-rate borrowings were $1,311.0 million at September 30, 2026, so a 100-basis-point rate move would change annual interest expense by about $13.1 million. A downgrade would raise funding costs and could tighten covenants.
• Customer credit and concentration. Customer distress, especially when commodity prices are low, can hurt collections. In bankruptcy, gathering agreements may be rejected. In both the three and nine months to September 30, 2026, two customers each provided about 11% of consolidated revenue. No customer reached 10% in the same periods of 2025.
• Operating hazards and weather. Risks include explosions, leaks, hurricanes and freezes, especially for Gulf Coast assets and river crossings. Insurance does not cover every risk, and premiums and deductibles have risen. Some major insurers are cutting coverage in Texas. Some acquired pipelines are decades old.
• Regulation and jurisdiction.
  • FERC jurisdiction. In August 2025 FERC affirmed that Targa's Badlands assets no longer qualify for a waiver and are providing jurisdictional transportation service. Targa Badlands filed a tariff in October 2025, which FERC accepted subject to refund pending a hearing. Shippers are challenging the rates. Gathering lines could also be reclassified as FERC-regulated transmission.
  • Pipeline safety. PHMSA integrity rules apply. The company estimates integrity-program costs at about $12.5 million a year for 2026–2028.
  • Emissions and other rules. Methane rules are being reconsidered (OOOOb/OOOOc). Hydraulic-fracturing limits could reduce customers' drilling. Climate litigation is also listed as a risk.
• Tax. Targa had $4.4 billion of U.S. federal NOL carryforwards at year-end 2025 and does not expect to pay the 15% corporate alternative minimum tax in the near term. Section 382 limits, IRS challenges or changes in tax law could raise its tax bill.
• Cybersecurity. Energy assets have been named as targets in U.S. government warnings. A breach of the operational technology systems could disrupt operations.
• Open legal and environmental matters (from the Q3 2026 10-Q).
  • New Mexico. The New Mexico Environment Department's proposed Administrative Compliance Order for the Red Hills processing plant, acquired with Lucid in 2022, includes a proposed civil penalty of about $47.8 million. Targa requested a hearing in January 2025.
  • MIECO winter-storm lawsuit. In the February 2021 winter-storm contract case with MIECO, the Fifth Circuit upheld a jury verdict of about $6.9 million against Targa. On July 24, 2026 the court partially granted Targa's motion for reconsideration and certified two questions to the Texas Supreme Court.

Management's discussion, fiscal 2025

Source: Form 10-K for the fiscal year ended December 31, 2025 (accession 0001193125-26-059296), Item 7.

In 2025, revenue grew only modestly while profit rose sharply, because Targa earns its margin on volumes and fees rather than on its top line. Total revenue rose 4% to $17,028.3 million. Income from operations rose 24% to $3,331.2 million. Net income attributable to Targa Resources Corp. rose 47% to $1,923.0 million. The net-income increase was helped by much lower minority interests after the Badlands buy-in and the late-2024 purchase of the remaining stake in Cedar Bayou Fractionators. Adjusted EBITDA, the company's main non-GAAP measure, rose 20% to $4,957.4 million. Adjusted free cash flow, after $3,343.5 million of net growth capital and $226.4 million of net maintenance capital, was $539.0 million, up from $140.1 million in 2024.

Prices moved in opposite directions in 2025. Henry Hub averaged $3.43/MMBtu, up from $2.27. Targa's illustrative NGL barrel slipped to $0.61/gal from $0.63, and WTI fell to $65.58/Bbl from $75.92. In commodity sales, higher natural gas prices ($766.2 million), higher volumes ($518.7 million) and hedges ($85.0 million) outweighed lower NGL and condensate prices (–$860.2 million). Fees from midstream services rose 5% on higher gathering and processing fees and export volumes. They were held back by a planned turnaround at part of the Mont Belvieu complex. Other operating income included Section 45Q carbon-capture tax credits.

Both segments grew:

• Gathering and Processing: adjusted operating margin rose 7% to $3,346.2 million. Permian plant inlet rose 11% to 6,391.4 MMcf/d, with Permian Delaware up 14%. The growth came from plants added in 2024 and 2025 (Roadrunner II, Greenwood II, Bull Moose, Pembrook II and Bull Moose II) and from strong producer activity. Central, Badlands and Coastal volumes fell slightly.
• Logistics and Transportation: adjusted operating margin rose 17% to $3,182.0 million. NGL pipeline transportation volumes rose 21% to 968.3 MBbl/d and fractionation volumes rose 13% to 1,057.6 MBbl/d. Trains 9 and 10 and the Daytona NGL pipeline (all added in 2024) contributed, and marketing earned more from optimization opportunities. Export volumes were broadly flat at 429.1 MBbl/d.

Management expects results to keep depending on commodity prices, volumes and producer activity, contract mix, hedging, operating costs, and access to capital markets. It says it has enough liquidity for its 2026 requirements.

Current quarter, Q3 2026

Source: Form 10-Q for the quarter ended September 30, 2026 (accession 0001193125-26-449541), Item 2 and Notes 4, 7, 8, 9 and 13; outlook and sequential commentary from the Q3 2026 earnings release furnished as Exhibit 99.1 to the Form 8-K filed November 5, 2026 (accession 0001193125-26-448401); prior 2026 outlook figures from the earnings releases furnished with the Forms 8-K filed February 19, 2026 (accession 0001193125-26-058040), May 7, 2026 (accession 0001193125-26-210165) and August 6, 2026 (accession 0001193125-26-336525).

Results. Higher volumes from new Permian plants and from Stakeholder drove the quarter.

For the first nine months, adjusted EBITDA was $4,510.1 million (+25%) and net income attributable to the company was $1,902.4 million (+38%).

• Revenue drivers. Higher NGL, natural gas and condensate prices added $801.5 million to commodity sales, higher volumes added $383.0 million, and hedges added $68.5 million. Most of the higher sales were matched by higher product purchases.
• Higher costs. Depreciation and amortization rose 20% to $459.6 million, reflecting the Stakeholder assets, expansions and finance-lease amortization.
• Contingent payment charge. Other, net was a $22.6 million charge, mainly from an increase in the fair value of the contingent payment owed to Riley for Dovetail.
• Sequential decline. Adjusted EBITDA fell 6% from Q2 2026's $1,603 million. Lower marketing margin and lower LPG export margin (from lower volumes and fees) more than offset record Permian inlet volumes and record NGL transportation and fractionation volumes.

Segments.

• Gathering and Processing: adjusted operating margin rose 22% to $1,069.9 million.
  • Permian inlet rose 14% to a record 7,536.6 MMcf/d, and Permian Delaware rose 20% to 4,063.8 MMcf/d. The growth came from Bull Moose II, Falcon II, East Pembrook and East Driver, from producer activity, and from Stakeholder, which contributed $69.3 million of revenue and $15.6 million of net income in the quarter.
  • Crude gathered rose 39% to 152.9 MBbl/d and Coastal inlet rose 30%. Central inlet fell 7%.
  • The average realized natural gas price was $1.61/MMBtu, up from $1.20.
• Logistics and Transportation: adjusted operating margin rose 10% to $888.1 million. NGL pipeline transportation rose 15% to 1,171.7 MBbl/d, fractionation rose 11% to 1,261.5 MBbl/d (helped by Train 11) and exports rose 10% to 447.9 MBbl/d. Marketing earned more than a year earlier from optimization opportunities.

Cash flow, capital and balance sheet.

• Cash flow. Adjusted cash flow from operations was $1,276.8 million. Adjusted free cash flow fell to $33.6 million from $172.8 million because net growth capital spending rose to $1,186.0 million from $853.0 million. Nine-month operating cash flow was $3,545.9 million and investing outflows were $4,407.6 million, including the Stakeholder purchase.
• 2026 financing so far.
  • The Stakeholder purchase was funded with $650.0 million of commercial paper and $600.0 million from the receivables securitization facility.
  • The $679.3 million of subsidiary Targa Resources Partners LP's 6.875% notes due 2029 were redeemed in January, with a $10.1 million loss on extinguishment.
  • In March Targa issued $750.0 million of 4.350% notes due 2031 and $750.0 million of 6.050% notes due 2056, for about $1,483.2 million of net proceeds.
  • In July the securitization facility was extended to July 30, 2027 and enlarged to up to $800 million ($600 million committed, $200 million uncommitted).
  • A compressor lease amended in April 2026 added about $464.6 million of finance-lease liability.
• Debt and liquidity. At quarter-end, total debt obligations were $19,844.5 million and liquidity was $2,913.7 million. The company was in compliance with its debt covenants.
• Shareholder returns.
  • The quarterly dividend has been $1.25 per share since Q1 2026, up from $1.00.
  • Targa bought back 180,768 shares in Q3 for $52.0 million, at an average of $287.64 per share. For the nine months it bought back 716,671 shares for $187.1 million.
  • $1,186.5 million remained under the buyback programs.

Commercial developments. In August 2026 Targa signed 20-year, fee-based integrated agreements with ExxonMobil subsidiaries for gas gathering and processing and downstream services, with large acreage dedications in the Delaware and Midland basins. To serve them it announced the Wrangler, Ranger and Ranger II plants in Permian Delaware. It also announced the Bull Run II residue-gas pipeline.

2026 outlook. Expected 2026 adjusted EBITDA has been raised several times this year:

• February: $5.4–$5.6 billion.
• May: $5.7–$5.9 billion.
• August: toward the top of the $5.7–$5.9 billion range.
• November 5: at least $6.0 billion.

The Q3 release puts 2026 net growth capital spending at about $5.0 billion, up from the roughly $4.5 billion given in the February, May and August releases. Net maintenance capital is expected to be about $250 million. Management plans to recommend raising the dividend to $1.50 per quarter ($6.00 annualized) from Q1 2027, payable in May 2027. That would be a 20% increase on 2026, and the company expects meaningful annual increases after 2027.

Subsequent events

Source: Form 10-Q for the quarter ended September 30, 2026 (accession 0001193125-26-449541), Recent Developments and Notes 9 and 13; Q3 2026 earnings release, Exhibit 99.1 to the Form 8-K filed November 5, 2026 (accession 0001193125-26-448401).

The 10-Q has no stand-alone subsequent-events note. It reports the following items dated after September 30, 2026. It does not describe any acquisition, divestiture or new debt financing completed after quarter-end.

• Dividend. On October 13, 2026 Targa declared a Q3 dividend of $1.25 per share, 25% more than the Q3 2025 dividend. About $268 million is payable on November 17, 2026 to holders of record on October 30, 2026.
• Projects started in Q4 2026. The Train 12 fractionator (150 MBbl/d, Mont Belvieu) and the 43-mile Bull Run Extension residue-gas pipeline both began operating in Q4 2026, ahead of the schedule given in the 10-K: Q1 2027 for both. The Copperhead plant (275 MMcf/d, Permian Delaware) is in start-up.
• New projects announced in November 2026.
  • Targa will build Train 14, a 150 MBbl/d fractionator at Mont Belvieu expected to start in Q1 2029.
  • It is ordering long-lead equipment for one more Permian Midland plant and two more Permian Delaware plants, which it expects to need in 2028 or early 2029.
  • The Yeti and Yeti II plants were moved earlier, to Q2 2027 and Q3 2027.
• Environmental settlement. On November 4, 2026 the Texas Commission on Environmental Quality approved an Agreed Order resolving alleged air-emissions violations at the Mont Belvieu complex between August 2020 and December 2022. Targa had paid an administrative penalty of about $0.5 million on July 7, 2026 and agreed to fund a Supplemental Environmental Project of the same amount.

Filings that contain financial statements

Targa furnishes an earnings press release (Exhibit 99.1) with each quarterly Form 8-K. These carry a consolidated results-of-operations table (revenues through net income), segment tables with operating statistics, and a reconciliation of net income to adjusted EBITDA, adjusted cash flow from operations and adjusted free cash flow. They do not carry a full balance sheet or cash flow statement.

• Form 8-K filed November 5, 2026, accession 0001193125-26-448401: three and nine months ended September 30, 2026.
• Form 8-K filed August 6, 2026, accession 0001193125-26-336525: three and six months ended June 30, 2026.
• Form 8-K filed May 7, 2026, accession 0001193125-26-210165: three months ended March 31, 2026.
• Form 8-K filed February 19, 2026, accession 0001193125-26-058040: three months and year ended December 31, 2025.

Earnings and guidance

• November 5, 2026 (third quarter 2026), 0001193125-26-448401. Net income attributable to Targa was $658 million (third quarter 2025: $478 million). Adjusted EBITDA was $1,504 million, up 18% year over year and down 6% from the second quarter, as lower marketing and LPG export margin offset record Permian inlet, NGL transportation and fractionation volumes. Full-year 2026 adjusted EBITDA guidance was raised to "at least $6.0 billion" (from "towards the top end of $5.7 billion to $5.9 billion" in August). Net growth capital expenditures are estimated at about $5.0 billion, up from about $4.5 billion in the February, May and August releases; the November release calls the $5.0 billion a continuing estimate, so the higher figure was first given after the August 6 release. Net maintenance capital expenditures are estimated at about $250 million. Management expects to recommend a 2027 common dividend of $6.00 per share annualized ($1.50 per quarter), a 20% increase over 2026, effective for the first quarter of 2027.
• August 6, 2026 (second quarter 2026), 0001193125-26-336525. Net income attributable to Targa was $765 million (second quarter 2025: $629 million); record adjusted EBITDA was $1,603 million, up 38% year over year and 14% sequentially. Full-year 2026 adjusted EBITDA guidance was moved to the top end of the $5.7 billion to $5.9 billion range, with net growth capital expenditures of about $4.5 billion.
• May 7, 2026 (first quarter 2026), 0001193125-26-210165. Net income attributable to Targa was $480 million (first quarter 2025: $271 million); adjusted EBITDA was $1,403 million, up 19% year over year. Full-year 2026 adjusted EBITDA guidance was raised to $5.7 billion to $5.9 billion.
• February 19, 2026 (fourth quarter and full year 2025), 0001193125-26-058040. Record fourth quarter 2025 adjusted EBITDA of $1,341 million. Initial 2026 adjusted EBITDA guidance of $5.4 billion to $5.6 billion, with net growth capital expenditures of about $4.5 billion, and an intended 2026 common dividend of $5.00 per share (a 25% increase).
• November 5, 2025 (third quarter 2025), 0001193125-25-265621. Net income attributable to Targa was $478.4 million; record adjusted EBITDA of $1,274.8 million, up 19% year over year. The release announced the expected 25% increase of the 2026 dividend to $5.00 per share.

Acquisitions and commercial agreements

• Stakeholder Midstream, LLC - closed. The February 19, 2026 release (0001193125-26-058040) states that on January 6, 2026 Targa completed the previously announced acquisition of Stakeholder for $1.25 billion in cash, effective January 1, 2026, and that the assets are integrated into its Delaware Basin system. The quarterly report on Form 10-Q for the period ended September 30, 2026 (0001193125-26-449541) reports funding of $650.0 million from commercial paper and $600.0 million from the securitization facility.
• Delaware Basin bolt-on acquisitions - closed. In December 2025, Targa completed two small bolt-on acquisitions of sour gathering and compression assets in the Delaware Basin for aggregate cash consideration of about $213 million (0001193125-26-058040). Per Note 4 of the 10-K (0001193125-26-059296), the two transactions were (1) Dovetail Midstream, LLC plus certain compressor assets from Riley Exploration Permian, for about $122.8 million in cash plus up to $60.0 million of contingent consideration over five years, and (2) the Nile Acquisition, midstream assets from Nile Midstream, LLC and Four Winds Midstream, LLC (subsidiaries of Blackbeard Holdings, LLC), for $90.3 million in cash including capitalized transaction costs.
• ExxonMobil agreements (August 2026). The November 5, 2026 release (0001193125-26-448401) and the 10-Q (0001193125-26-449541) state that in August 2026 Targa entered into 20-year, fee-based agreements with subsidiaries of ExxonMobil for natural gas gathering and processing and downstream services in the Permian Basin, with acreage dedications in the Delaware and Midland basins. The agreements are described in the release and 10-Q only; no Form 8-K reports them. Three new Permian Delaware processing plants (Wrangler, Ranger, Ranger II) were announced in August 2026 to support them.

Capital projects (per the earnings releases)

• November 5, 2026 (0001193125-26-448401): Train 12 fractionator and the Bull Run Extension pipeline began operating, ahead of schedule; the Copperhead plant is in start-up. Yeti and Yeti II are now expected in the second quarter and third quarter of 2027. Long-lead items are being ordered for one more Permian Midland plant and two more Permian Delaware plants. A new 150 MBbl/d fractionator, Train 14 in Mont Belvieu, is expected to begin operating in the first quarter of 2029.
• May 7, 2026 (0001193125-26-210165): Roadrunner III and Copperhead II plants announced. February 19, 2026 (0001193125-26-058040): Yeti II plant and Train 13 fractionator announced.

Debt and financing

• Senior notes, November 2025. On November 6, 2025 Targa priced $750.0 million of 4.350% Senior Notes due 2029 and $1.0 billion of 5.400% Senior Notes due 2036 (Form 8-K, 0001193125-25-272333); the offering closed November 12, 2025 (0001193125-25-277756). Proceeds were to redeem Targa Resources Partners LP's 6.875% Senior Notes due 2029, with the remainder for general corporate purposes including commercial paper repayment. The February 19, 2026 release states the 6.875% notes were redeemed on January 15, 2026.
• Senior notes, March 2026. On February 25, 2026 Targa priced $750.0 million of 4.350% Senior Notes due 2031 and $750.0 million of 6.050% Senior Notes due 2056 (0001193125-26-076556); the offering closed March 2, 2026 (0001193125-26-085512). Proceeds were for general corporate purposes, including commercial paper repayment.
• Receivables securitization amendment, July 1, 2026 (Form 8-K filed July 6, 2026, 0001193125-26-296255). The Seventeenth Amendment extends the facility termination date to July 30, 2027 and adds a $200 million uncommitted line. About $451 million of receivable purchases were outstanding at July 1, 2026. The August 6, 2026 release states borrowing capacity of up to $800 million.
• Debt and liquidity at September 30, 2026 (0001193125-26-448401). Total consolidated debt was $19.8 billion: $17.9 billion of senior unsecured notes, $860 million of commercial paper, $451 million under the securitization facility and $796 million of finance leases. Liquidity was about $2.9 billion.

Shareholder returns

• Quarterly common dividend: $1.00 (declared for the third and fourth quarters of 2025), raised to $1.25 ($5.00 annualized) from the first quarter of 2026, a 25% increase; $1.25 was declared October 13, 2026 for the third quarter of 2026, payable November 17, 2026 (0001193125-26-448401).
• Buybacks: in the third quarter of 2026 Targa repurchased 180,768 shares at a weighted average $287.64 for a net cost of $52 million; $1,187 million remained under its repurchase programs at September 30, 2026 (0001193125-26-448401). Full-year 2025 repurchases were 3,765,272 shares for $642 million (0001193125-26-058040).

Management and board

• August 25, 2026 (Form 8-K, 0001193125-26-364099). Chief Financial Officer William A. Byers will retire effective September 1, 2026 and stay on in a non-executive role through December 31, 2026. Benjamin J. Branstetter, President - Logistics and Transportation, becomes Chief Financial Officer effective September 1, 2026 (base salary raised to $600,000). Brent B. Secrest, formerly Chief Commercial Officer of Enterprise Products Holdings LLC, becomes President - Logistics and Transportation effective September 1, 2026.
• July 17, 2026 (0001193125-26-306591). Thomas Mathiasmeier, who retired in June 2026 as President, Global Gas, Power & Emerging Markets at ConocoPhillips, was appointed a Class II director on July 16, 2026 and joined the Audit Committee.
• August 6, 2025 (0001193125-25-174533). D. Scott Pryor announced his retirement as President - Logistics and Transportation effective March 1, 2026; Branstetter was named his successor (a role he now leaves for CFO, per the August 2026 filing above).
• May 22, 2026 (0001193125-26-237018). At the May 21, 2026 annual meeting all four Class I directors were re-elected, PricewaterhouseCoopers LLP was ratified as auditor and say-on-pay was approved.

Pending transactions

No Form 8-K reports an announced merger or a pending signed acquisition; the acquisitions above are all reported as completed. The ExxonMobil agreements appear only in the earnings release and 10-Q.

About this file

TRGP annual income statement, balance sheet and cash flow

Taken from the SEC filings and normalized to actual dollars.

TRGP quarterly income statement, balance sheet and cash flow

Taken from the SEC filings and normalized to actual dollars.

TRGP year-to-date income statement and cash flow

Taken from the SEC filings and normalized to actual dollars.

TRGP trailing twelve month income statement and cash flow

Derived by AI from the figures the filings report. No filing prints these, so none of them is linked.

• Derivation. FY2025 (10-K, accession 0001193125-26-059296) plus the nine months ended September 30, 2026 less the nine months ended September 30, 2025 (10-Q, accession 0001193125-26-449541)

Adjustments

Notes

• Annual figures (FY2025, FY2024, FY2023) come from the FY2025 10-K (accession 0001193125-26-059296). The income statement and cash flow statement print three years; the balance sheet prints December 31, 2025 and 2024 only, so FY2023 carries no balance sheet. The company's non-GAAP reconciliation in that 10-K covers 2025 and 2024 only, so FY2023 carries no non-GAAP block.
• Q3 FY2026 and Q3 FY2025 (three months ended September 30), the nine-month year-to-date blocks, and the September 30, 2026 balance sheet come from the Q3 2026 10-Q (accession 0001193125-26-449541).
• The statements print dollar amounts in millions; every money figure here is stored in actual US dollars. Per-share amounts are in dollars. Weighted average share counts are printed in millions and are stored as actual share counts.
• Sign convention follows the statements: revenues and the costs-and-expenses lines are positive; 'other_operating_expense_income' is the statement's 'Other operating (income) expense' line, where a negative value is net income; interest expense, other, net and income tax are stored with the statement's sign, so a negative value reduces income. Cash outflows on the cash flow statement are negative.
• Targa computes earnings per share under the two-class method. The EPS numerator is net income attributable to Targa Resources Corp. less the premium on repurchase of noncontrolling interests (net income attributable to common shareholders), less earnings allocated to participating share-based awards ('net_income_allocated_to_common_shareholders_for_eps'). The company states that the dilutive effect of reallocating participating securities was immaterial, so the same numerator is used for basic and diluted EPS.
• The premium on repurchase of noncontrolling interests ($70.5 million in 2025, $32.9 million in 2024 and $510.1 million in 2023) reduces income available to common shareholders but not net income. The 10-Q attributes the 2025 premium, recognized in the first nine months of 2025, to the Badlands Transaction.
• 'free_cash_flow' is derived here as net cash provided by operating activities less outlays for property, plant and equipment, both as printed on the cash flow statement. It is not a figure the company reports and differs from the company's own non-GAAP 'adjusted free cash flow' (adjusted cash flow from operations less net maintenance and growth capital expenditures, which include contributions to unconsolidated affiliates), shown separately in 'non_gaap'.
• The balance sheet prints no total-liabilities line. 'total_liabilities_derived' is the sum of total current liabilities, long-term debt, long-term liabilities from risk management activities, deferred income taxes and other long-term liabilities; it equals total assets less total owners' equity in every period shown.
• 'total_debt_obligations' is the 'Total debt obligations' line of the debt note: current debt obligations plus long-term debt, including finance lease liabilities and net of unamortized discount and debt issuance costs. 'total_equity' is total owners' equity, which includes noncontrolling interests.
• The 10-Q prints its cash flow statement for the nine months only, so the quarterly entries carry no cash flow block. The segment note does print three-month capital expenditures by segment; these ('segments.total_capital_expenditures') are gross capital expenditures on an accrual basis, not cash outlays. For the nine months ended September 30, 2026 the segment total ($3,355.0 million) equals the MD&A's gross capital expenditures, against cash outlays for property, plant and equipment of $3,154.4 million.
• Segment figures come from the segment note. Segment revenues include intersegment sales, which are eliminated in consolidation, so they do not sum to consolidated revenue. Segment operating margin is the measure the company's chief operating decision maker uses; 'other_operating_margin' is the unrealized mark-to-market gain or loss on derivative contracts not designated as cash flow hedges.
• Adjusted EBITDA, adjusted cash flow from operations and adjusted free cash flow are the company's non-GAAP measures, taken from the reconciliation in MD&A. Maintenance and growth capital expenditures there are net of reimbursements and noncontrolling-interest contributions and are shown as negative deductions, as printed.
• Dividends declared per share: the quarterly figures come from the dividend tables ($1.25 for the quarter ended September 30, 2026 in the 10-Q; $1.00 for the quarter ended September 30, 2025 in the 10-K). Annual and nine-month figures are the sum of the quarterly declarations those tables print: $4.00 for 2025 (four of $1.00), $3.00 for 2024 (four of $0.75), $2.00 for 2023 (four of $0.50), $3.75 for the nine months of 2026 (three of $1.25) and $3.00 for the nine months of 2025 (three of $1.00).
• The trailing twelve months ended September 30, 2026 are derived as FY2025 plus the nine months ended September 30, 2026 less the nine months ended September 30, 2025. Earnings per share is not additive across periods and is not given for the trailing twelve months.
• Common shares outstanding are taken from the face of the balance sheet: 214,480,427 at September 30, 2026, 214,662,156 at December 31, 2025 and 217,763,821 at December 31, 2024.

Uncertainties

• No three-month cash flow figures exist for Q3 FY2026 or Q3 FY2025 in these filings: the 10-Q's cash flow statement covers nine months only, and the six-month figures needed to difference out the quarter are not printed in the 10-K or this 10-Q. Quarterly operating cash flow, cash capital outlays and free cash flow are therefore omitted.
• No balance sheet at September 30, 2025 is presented in these filings, so Q3 FY2025 carries no balance sheet block.
• The 10-K does not print a standalone fourth quarter of 2025, so no Q4 FY2025 entry is included.

Company details

Fiscal period

Source filings