Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the year ended December 31, 2025 (“Annual Report”), as well as the unaudited consolidated financial statements and notes hereto included in this quarterly report on Form 10-Q for the quarter ended March 31, 2026 (“Quarterly Report”).
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:
•gathering, compressing, treating, processing, transporting, and 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.
To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as our Downstream Business).
Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast.
Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes our NGL pipeline system, which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. Our Downstream facilities are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.
Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.
Recent Developments
In response to increasing production and to meet the infrastructure needs of producers and our downstream customers, our major expansion projects include the following:
Permian Basin Processing Expansions
Our new cryogenic natural gas processing plant additions include:
•Falcon II plant, a 275 MMcf/d plant in Permian Delaware (the “Falcon II plant”), commenced operations in the first quarter of 2026.
•East Pembrook plant, a 275 MMcf/d plant in Permian Midland (the “East Pembrook plant”), commenced operations late in the first quarter of 2026.
•East Driver plant, a 275 MMcf/d plant in Permian Midland (the “East Driver plant”), expected to begin operations in the third quarter of 2026.
•Copperhead plant, a 275 MMcf/d plant in Permian Delaware (the “Copperhead plant”), expected to begin operations in the first quarter of 2027.
•Yeti plant, a 275 MMcf/d plant in Permian Delaware (the “Yeti plant”), expected to begin operations in the third quarter of 2027.
•Yeti II plant, a 275 MMcf/d plant in Permian Delaware (the “Yeti II plant”), expected to begin operations in the fourth quarter of 2027.
•Roadrunner III plant, a 265 MMcf/d plant in Permian Delaware (the “Roadrunner III plant”), expected to begin operations in the first quarter of 2028.
•Copperhead II plant, a 275 MMcf/d plant in Permian Delaware (the “Copperhead II plant”), expected to begin operations in the first quarter of 2028.
Fractionation Expansions
Our new 150 MBbl/d fractionation train additions include:
•Train 11 in Mont Belvieu, Texas (“Train 11”), commenced operations early in the second quarter of 2026.
•Train 12 in Mont Belvieu, Texas (“Train 12”), expected to begin operations in the first quarter of 2027.
•Train 13 in Mont Belvieu, Texas (“Train 13”), expected to begin operations in the first quarter of 2028.
NGL Pipeline Expansions
•In February 2025, we announced an intra-Delaware Basin expansion of our NGL pipeline system, (“Delaware Express”) in Permian Delaware. The expansion is expected to begin operations in the second quarter of 2026.
•In September 2025, we announced plans to construct the Speedway NGL Pipeline (“Speedway”) which will transport NGLs from our existing assets and future plant additions in the Permian Basin to our fractionation and storage complex in Mont Belvieu, Texas. The project consists of approximately 500 miles of 30-inch diameter pipeline and associated infrastructure with an initial capacity of approximately 500 MBbl/d, expandable to 1,000 MBbl/d. Speedway is expected to begin operations in the third quarter of 2027.
LPG Export Expansion
•In February 2025, we announced an expansion of our LPG export capabilities at our Galena Park Marine Terminal, (“the GPMT LPG Export Expansion”) to include the addition of a new pipeline from Mont Belvieu to Galena Park and additional refrigeration. Our effective export capacity will increase up to 19 MMBbl per month, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors. The GPMT LPG Export Expansion is expected to be completed in the third quarter of 2027.
Natural Gas Pipelines
•In August 2025, we announced a 43-mile extension of our Bull Run intrastate natural gas pipeline (the “Bull Run Extension”) to expand and enhance connectivity of our Permian Delaware system to the Waha hub in West Texas. The Bull Run Extension is expected to begin operations in the first quarter of 2027.
•In September 2025, we announced a new 35-mile intrastate natural gas pipeline that will enhance connectivity across several of our plants in the Permian Midland and a 55-mile conversion of an existing Targa pipeline into natural gas service (together, “Buffalo Run”) that will connect our Permian Midland and Permian Delaware intra-basin natural gas systems. Buffalo Run is expected to be completed in stages and fully complete in early 2028.
•In November 2025, we announced the Forza Pipeline (“Forza”), a new 36-mile interstate natural gas pipeline in Permian Delaware that will connect our new and existing gas plants and enhance connectivity to the Waha hub. Forza filed a certificate application on December 3, 2025, with the FERC and, pending receipt of necessary regulatory approvals, is expected to begin operations in the middle of 2028.
Acquisitions and Joint Ventures
•In July 2024, we entered into a joint venture (“Blackcomb Joint Venture”) which will construct the Blackcomb pipeline 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. The Blackcomb pipeline is expected to be in service in the fourth quarter of 2026.
•In April 2025, WhiteWater announced the Blackcomb Joint Venture reached a final investment decision to construct the Traverse pipeline, which 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. The Traverse pipeline is expected to be in service in mid-2027.
•In January 2026, we completed the acquisition of all of the membership interests in Stakeholder Midstream, LLC for $1.25 billion in cash (the “Stakeholder Acquisition”). We acquired a portfolio of complementary Permian Basin midstream infrastructure assets which have been integrated into our Permian Delaware operations. The acquisition had 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 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.
For the three months ended March 31, 2026, we repurchased 227,801 shares of our common stock at a weighted average per share price of $241.43 for a total net cost of $55.0 million. As of March 31, 2026, there was $1,318.6 million remaining under the Share Repurchase Programs.
In April 2026, we declared an increase to our quarterly common dividend to $1.25 per common share, or $5.00 per common share annualized, effective for the first quarter of 2026.
Financing Activities
In January 2026, we used $650.0 million in borrowings from our Commercial Paper Program and $600.0 million from our Securitization Facility to fund the Stakeholder Acquisition.
In January 2026, we completed the redemption of all of the Partnership’s 6.875% Senior Unsecured Notes due 2029 (the “Partnership’s 6.875% Notes due 2029”) and recognized a debt extinguishment loss of $10.1 million, comprised of $7.8 million related to the redemption premium paid and $2.3 million from the write-off of debt issuance costs.
In March 2026, we completed an underwritten public offering of (i) $750.0 million aggregate principal amount of our 4.350% Senior Unsecured Notes due 2031 (the “4.350% Notes due 2031”) and (ii) $750.0 million aggregate principal amount of our 6.050% Senior Unsecured Notes due 2056 (the “6.050% Notes due 2056”) (collectively, the “March 2026 Senior Unsecured Notes”), resulting in net proceeds of approximately $1,483.2 million. The March 2026 Senior Unsecured Notes 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 the net proceeds from the debt issuance for general corporate purposes, including to reduce borrowings under the Commercial Paper Program.
For additional information about our recent debt-related transactions, see “Note 7 – Debt Obligations” to our Consolidated Financial Statements.
Corporation Tax Matters
As of March 31, 2026, 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.
On July 4, 2025, President Trump signed the One Big Beautiful Bill Act (the “OBBBA”) into law. Among other things, the OBBBA indefinitely extends the 100% first-year depreciation allowance on qualified property placed in service after January 19, 2025, includes favorable modifications to the business interest expense limitation, and otherwise extends and enhances certain key provisions of the Tax Cuts & Jobs Act. The OBBBA has multiple effective dates with respect to its various provisions, with certain provisions effective in 2025. While the OBBBA has not materially impacted our effective tax rate, we expect it to substantially decrease Targa’s cash taxes over the next several years.
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 OBBBA, and several operational, economic, accounting and regulatory assumptions, we do not anticipate paying CAMT in the near term.
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements that will affect us, see “Note 3 – Significant Accounting Policies” to our Consolidated Financial Statements.
How We Evaluate Our Operations
The profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for natural gas, NGLs and crude oil, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, and the volumes of natural gas, NGLs and crude oil throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.
Our profitability is also impacted by fee-based contracts. Our growing capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our Downstream facilities, continued focus on adding fee-based margin to our existing and future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability.
Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (i) throughput volumes, facility efficiencies and fuel consumption, (ii) operating expenses, (iii) capital expenditures and (iv) the following non-GAAP measures: adjusted EBITDA, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment).
Throughput Volumes, Facility Efficiencies and Fuel Consumption
Our profitability is impacted by our ability to add new sources of natural gas and crude oil supplies to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing natural gas and crude oil supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, connected by third-party transportation and our NGL pipeline system, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.
In addition, we seek to increase adjusted operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.
As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets and our NGL pipelines. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.
Operating Expenses
Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and inflation, and will fluctuate depending on the scope of the activities performed during a specific period.
Capital Expenditures
Our capital expenditures are classified as growth capital expenditures and maintenance capital expenditures. Growth capital expenditures improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance revenues. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.
Capital spend associated with growth and maintenance projects is closely monitored. Return on investment is analyzed before a capital project is approved, spend is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.
Non-GAAP Measures
We utilize non-GAAP measures to analyze our performance. Adjusted EBITDA, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.
Adjusted Operating Margin
We define adjusted operating margin for our segments as revenues less product purchases and fuel. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.
Gathering and Processing adjusted operating margin consists primarily of:
•service fees related to natural gas and crude oil gathering, treating and processing; and
•revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and our equity volume hedge settlements.
Logistics and Transportation adjusted operating margin consists primarily of:
•service fees (including the pass-through of energy costs included in certain fee rates);
•system product gains and losses; and
•NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change.
The adjusted operating margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.
Adjusted operating margin for our segments provides useful information to investors because it is used as a supplemental financial measure by management and by external users of our financial statements, including investors and commercial banks, to assess:
•the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
•the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.
Management reviews adjusted operating margin and operating margin for our segments monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. The reconciliation of our adjusted operating margin to the most directly comparable GAAP measure is presented under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – By Reportable Segment.”
Adjusted EBITDA
We define adjusted EBITDA as Net income (loss) attributable to Targa Resources Corp. before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our core operating performance. The adjusting items are detailed in the adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.
Adjusted Cash Flow from Operations and Adjusted Free Cash Flow
We define adjusted cash flow from operations as adjusted EBITDA less cash interest expense on debt obligations and cash tax (expense) benefit. We define adjusted free cash flow as adjusted cash flow from operations less maintenance capital expenditures and growth capital expenditures, net of any reimbursements of project costs and contributions from noncontrolling interests, and including contributions to investments in unconsolidated affiliates. Adjusted cash flow from operations and adjusted free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.
Our Non-GAAP Financial Measures
The following table reconciles the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated:
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
(In millions) |
|
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Adjusted Cash Flow from Operations and Adjusted Free Cash Flow |
|
|
|
|
|
Net income (loss) attributable to Targa Resources Corp. |
$ |
479.6 |
|
|
$ |
270.5 |
|
Interest (income) expense, net |
|
227.6 |
|
|
|
197.1 |
|
Income tax expense (benefit) |
|
123.9 |
|
|
|
72.2 |
|
Depreciation and amortization expense |
|
426.0 |
|
|
|
367.6 |
|
(Gain) loss on sale or disposition of assets |
|
(1.0 |
) |
|
|
(0.5 |
) |
Write-down of assets |
|
4.3 |
|
|
|
2.0 |
|
(Gain) loss from financing activities |
|
10.1 |
|
|
|
0.6 |
|
Equity (earnings) loss |
|
(8.6 |
) |
|
|
(5.5 |
) |
Distributions from unconsolidated affiliates |
|
4.7 |
|
|
|
4.9 |
|
Change in contingent consideration |
|
0.7 |
|
|
|
— |
|
Compensation on equity grants |
|
23.2 |
|
|
|
17.6 |
|
Risk management activities |
|
110.3 |
|
|
|
248.8 |
|
Noncontrolling interests adjustments (1) |
|
1.9 |
|
|
|
3.2 |
|
Adjusted EBITDA |
$ |
1,402.7 |
|
|
$ |
1,178.5 |
|
Interest expense on debt obligations (2) |
|
(222.8 |
) |
|
|
(193.2 |
) |
Cash tax (expense) benefit |
|
— |
|
|
|
(15.3 |
) |
Adjusted Cash Flow from Operations |
$ |
1,179.9 |
|
|
$ |
970.0 |
|
Maintenance capital expenditures, net (3) |
|
(37.6 |
) |
|
|
(47.3 |
) |
Growth capital expenditures, net (3) |
|
(914.4 |
) |
|
|
(594.5 |
) |
Adjusted Free Cash Flow |
$ |
227.9 |
|
|
$ |
328.2 |
|
(1)Represents adjustments related to our subsidiaries with noncontrolling interests, including depreciation and amortization expense as well as earnings for certain plants within our WestTX joint venture not subject to noncontrolling interest accounting.
(2)Excludes amortization recognized in interest expense.
(3)Represents capital expenditures, net of any reimbursements of project costs and contributions from noncontrolling interests, and includes contributions to investments in unconsolidated affiliates.
Consolidated Results of Operations
The following table and discussion is a summary of our consolidated results of operations for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
|
|
|
|
2026 |
|
|
2025 |
|
|
2026 vs. 2025 |
|
|
(In millions) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
Sales of commodities |
$ |
3,344.6 |
|
|
$ |
3,884.4 |
|
|
$ |
(539.8 |
) |
|
(14 |
%) |
Fees from midstream services |
|
750.1 |
|
|
|
677.1 |
|
|
|
73.0 |
|
|
11 |
% |
Total revenues |
|
4,094.7 |
|
|
|
4,561.5 |
|
|
|
(466.8 |
) |
|
(10 |
%) |
Product purchases and fuel |
|
2,394.5 |
|
|
|
3,257.8 |
|
|
|
(863.3 |
) |
|
(26 |
%) |
Operating expenses |
|
333.7 |
|
|
|
303.6 |
|
|
|
30.1 |
|
|
10 |
% |
Depreciation and amortization expense |
|
426.0 |
|
|
|
367.6 |
|
|
|
58.4 |
|
|
16 |
% |
General and administrative expense |
|
107.8 |
|
|
|
94.5 |
|
|
|
13.3 |
|
|
14 |
% |
Other operating (income) expense |
|
(14.2 |
) |
|
|
(5.3 |
) |
|
|
(8.9 |
) |
|
168 |
% |
Income (loss) from operations |
|
846.9 |
|
|
|
543.3 |
|
|
|
303.6 |
|
|
56 |
% |
Interest expense, net |
|
(227.6 |
) |
|
|
(197.1 |
) |
|
|
(30.5 |
) |
|
15 |
% |
Equity earnings (loss) |
|
8.6 |
|
|
|
5.5 |
|
|
|
3.1 |
|
|
56 |
% |
Other, net |
|
(16.6 |
) |
|
|
0.3 |
|
|
|
(16.9 |
) |
NM |
|
Income tax (expense) benefit |
|
(123.9 |
) |
|
|
(72.2 |
) |
|
|
(51.7 |
) |
|
72 |
% |
Net income (loss) |
|
487.4 |
|
|
|
279.8 |
|
|
|
207.6 |
|
|
74 |
% |
Less: Net income (loss) attributable to noncontrolling interests |
|
7.8 |
|
|
|
9.3 |
|
|
|
(1.5 |
) |
|
(16 |
%) |
Net income (loss) attributable to Targa Resources Corp. |
|
479.6 |
|
|
|
270.5 |
|
|
|
209.1 |
|
|
77 |
% |
Premium on repurchase of noncontrolling interests, net of tax |
|
— |
|
|
|
70.5 |
|
|
|
(70.5 |
) |
|
(100 |
%) |
Net income (loss) attributable to common shareholders |
$ |
479.6 |
|
|
$ |
200.0 |
|
|
$ |
279.6 |
|
|
140 |
% |
Financial data: |
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA (1) |
$ |
1,402.7 |
|
|
$ |
1,178.5 |
|
|
$ |
224.2 |
|
|
19 |
% |
Adjusted cash flow from operations (1) |
|
1,179.9 |
|
|
|
970.0 |
|
|
|
209.9 |
|
|
22 |
% |
Adjusted free cash flow (1) |
|
227.9 |
|
|
|
328.2 |
|
|
|
(100.3 |
) |
|
(31 |
%) |
(1)Adjusted EBITDA, adjusted cash flow from operations and adjusted free cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.”
NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025
The decrease in commodity sales reflected lower NGL, natural gas and condensate prices ($1,064.2 million), partially offset by higher NGL, natural gas and condensate volumes ($476.9 million) and the favorable impact of hedges ($47.5 million).
The increase in fees from midstream services was primarily due to higher gas gathering and processing fees, partially offset by lower export volumes.
The decrease in product purchases and fuel reflected lower NGL and natural gas prices, partially offset by higher NGL and natural gas volumes.
The increase in operating expenses was primarily due to higher labor and maintenance costs due to increased activity and system expansions, and the acquisition of certain assets in the Permian Basin.
See “—Results of Operations—By Reportable Segment” for additional information on a segment basis.
The increase in depreciation and amortization expense was primarily due to the acquisition of certain assets in the Permian Basin and the impact of system expansions on our asset base.
The increase in general and administrative expense was primarily due to higher compensation and benefits.
The increase in interest expense, net, was primarily due to higher borrowings, partially offset by an increase in capitalized interest.
The decrease in other, net, was primarily due to the premium paid on the redemption of all of the Partnership’s 6.875% Notes due 2029.
The increase in income tax (expense) benefit was primarily due to the increase in pre-tax book income.
The premium on repurchase of noncontrolling interests, net of tax was due to the Badlands Transaction in the first quarter of 2025.
Results of Operations—By Reportable Segment
The following table presents our operating margins by reportable segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and Processing |
|
|
Logistics and Transportation |
|
|
Other |
|
|
|
(In millions) |
|
Three Months Ended: |
|
|
|
|
|
|
|
|
|
March 31, 2026 |
|
$ |
703.5 |
|
|
$ |
773.3 |
|
|
$ |
(110.3 |
) |
March 31, 2025 |
|
|
602.2 |
|
|
|
646.7 |
|
|
|
(248.8 |
) |
Gathering and Processing Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
|
|
|
|
|
|
2026 |
|
|
2025 |
|
|
2026 vs. 2025 |
|
|
(In millions, except operating statistics and price amounts) |
|
Operating margin |
$ |
|
703.5 |
|
|
$ |
|
602.2 |
|
|
$ |
|
101.3 |
|
|
|
17 |
% |
Operating expenses |
|
|
233.6 |
|
|
|
|
208.2 |
|
|
|
|
25.4 |
|
|
|
12 |
% |
Adjusted operating margin |
$ |
|
937.1 |
|
|
$ |
|
810.4 |
|
|
$ |
|
126.7 |
|
|
|
16 |
% |
Operating statistics (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant natural gas inlet, MMcf/d (2) (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
3,153.9 |
|
|
|
|
2,985.6 |
|
|
|
|
168.3 |
|
|
|
6 |
% |
Permian Delaware |
|
|
3,576.1 |
|
|
|
|
3,020.3 |
|
|
|
|
555.8 |
|
|
|
18 |
% |
Total Permian |
|
|
6,730.0 |
|
|
|
|
6,005.9 |
|
|
|
|
724.1 |
|
|
|
12 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central (5) |
|
|
1,027.3 |
|
|
|
|
984.7 |
|
|
|
|
42.6 |
|
|
|
4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (5) (6) |
|
|
127.0 |
|
|
|
|
136.9 |
|
|
|
|
(9.9 |
) |
|
|
(7 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
547.1 |
|
|
|
|
398.8 |
|
|
|
|
148.3 |
|
|
|
37 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
8,431.4 |
|
|
|
|
7,526.3 |
|
|
|
|
905.1 |
|
|
|
12 |
% |
NGL production, MBbl/d (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Midland (4) |
|
|
464.7 |
|
|
|
|
429.5 |
|
|
|
|
35.2 |
|
|
|
8 |
% |
Permian Delaware |
|
|
469.6 |
|
|
|
|
366.4 |
|
|
|
|
103.2 |
|
|
|
28 |
% |
Total Permian |
|
|
934.3 |
|
|
|
|
795.9 |
|
|
|
|
138.4 |
|
|
|
17 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central (5) |
|
|
102.1 |
|
|
|
|
98.1 |
|
|
|
|
4.0 |
|
|
|
4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Badlands (5) |
|
|
16.2 |
|
|
|
|
16.4 |
|
|
|
|
(0.2 |
) |
|
|
(1 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coastal |
|
|
37.8 |
|
|
|
|
32.7 |
|
|
|
|
5.1 |
|
|
|
16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1,090.4 |
|
|
|
|
943.1 |
|
|
|
|
147.3 |
|
|
|
16 |
% |
Crude oil gathered, MBbl/d |
|
|
135.1 |
|
|
|
|
136.1 |
|
|
|
|
(1.0 |
) |
|
|
(1 |
%) |
Natural gas sales, BBtu/d (3) |
|
|
3,040.3 |
|
|
|
|
2,592.8 |
|
|
|
|
447.5 |
|
|
|
17 |
% |
NGL sales, MBbl/d (3) |
|
|
625.9 |
|
|
|
|
570.2 |
|
|
|
|
55.7 |
|
|
|
10 |
% |
Condensate sales, MBbl/d |
|
|
21.8 |
|
|
|
|
18.1 |
|
|
|
|
3.7 |
|
|
|
20 |
% |
Average realized prices (7): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, $/MMBtu |
|
|
0.57 |
|
|
|
|
2.24 |
|
|
|
|
(1.67 |
) |
|
|
(75 |
%) |
NGL, $/gal |
|
|
0.39 |
|
|
|
|
0.50 |
|
|
|
|
(0.11 |
) |
|
|
(22 |
%) |
Condensate, $/Bbl |
|
|
65.51 |
|
|
|
|
72.32 |
|
|
|
|
(6.81 |
) |
|
|
(9 |
%) |
(1)Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
(2)Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.
(3)Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.
(4)Permian Midland includes operations in WestTX, of which we own a 72.8% undivided interest, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.
(5)Operations include facilities that are not wholly owned by us.
(6)Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant.
(7)Average realized prices, net of fees, include the effect of realized commodity hedge gain/loss attributable to our equity volumes. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator, net of fees.
The following table presents the realized commodity hedge gain (loss) attributable to our equity volumes that are included in the adjusted operating margin of the Gathering and Processing segment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2026 |
|
|
Three Months Ended March 31, 2025 |
|
|
|
(In millions, except volumetric data and price amounts) |
|
|
|
Volume
Settled |
|
|
Price
Spread (1) |
|
|
Gain
(Loss) |
|
|
Volume
Settled |
|
|
Price
Spread (1) |
|
|
Gain
(Loss) |
|
Natural gas (BBtu) |
|
|
8.4 |
|
|
$ |
2.02 |
|
|
$ |
17.0 |
|
|
|
7.7 |
|
|
$ |
0.96 |
|
|
$ |
7.4 |
|
NGL (MMgal) |
|
|
67.7 |
|
|
|
0.01 |
|
|
|
0.9 |
|
|
|
97.5 |
|
|
|
(0.07 |
) |
|
|
(6.6 |
) |
Crude oil (MBbl) |
|
|
0.7 |
|
|
|
(4.14 |
) |
|
|
(2.9 |
) |
|
|
0.7 |
|
|
|
1.00 |
|
|
|
0.7 |
|
|
|
|
|
|
|
|
|
$ |
15.0 |
|
|
|
|
|
|
|
|
$ |
1.5 |
|
(1)The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025
The increase in adjusted operating margin was predominantly due to higher natural gas inlet volumes in the Permian which drove higher fee-based margin, partially offset by lower commodity prices. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Pembrook II plant during the third quarter of 2025, the Bull Moose II plant during the fourth quarter of 2025, the Falcon II plant during the first quarter of 2026, continued strong producer activity and the acquisition of certain assets in the Permian Basin during the first quarter of 2026.
The increase in operating expenses was primarily due to higher volumes, multiple plant additions and the acquisition of certain assets in the Permian Basin during the first quarter of 2026.
Logistics and Transportation Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
|
|
|
|
|
|
2026 |
|
|
2025 |
|
|
2026 vs. 2025 |
|
|
(In millions, except operating statistics) |
|
Operating margin |
$ |
|
773.3 |
|
|
$ |
|
646.7 |
|
|
$ |
|
126.6 |
|
|
|
20 |
% |
Operating expenses |
|
|
100.2 |
|
|
|
|
95.5 |
|
|
|
|
4.7 |
|
|
|
5 |
% |
Adjusted operating margin |
$ |
|
873.5 |
|
|
$ |
|
742.2 |
|
|
$ |
|
131.3 |
|
|
|
18 |
% |
Operating statistics MBbl/d (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL pipeline transportation volumes (2) |
|
|
1,016.8 |
|
|
|
|
843.5 |
|
|
|
|
173.3 |
|
|
|
21 |
% |
Fractionation volumes |
|
|
1,145.2 |
|
|
|
|
979.9 |
|
|
|
|
165.3 |
|
|
|
17 |
% |
Export volumes (3) |
|
|
437.0 |
|
|
|
|
447.7 |
|
|
|
|
(10.7 |
) |
|
|
(2 |
%) |
NGL sales |
|
|
1,304.0 |
|
|
|
|
1,186.4 |
|
|
|
|
117.6 |
|
|
|
10 |
% |
(1)Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.
(2)Represents the total quantity of mixed NGLs that earn a transportation margin.
(3)Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.
Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025
The increase in adjusted operating margin was due to higher marketing margin and higher pipeline transportation and fractionation margin. Marketing margin increased due to greater optimization opportunities. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems.
The increase in operating expenses was due to higher repairs and maintenance and higher compensation and benefits.
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
|
|
2026 |
|
|
2025 |
|
|
2026 vs. 2025 |
|
|
(In millions) |
|
Operating margin |
$ |
(110.3 |
) |
|
$ |
(248.8 |
) |
|
$ |
138.5 |
|
Adjusted operating margin |
$ |
(110.3 |
) |
|
$ |
(248.8 |
) |
|
$ |
138.5 |
|
Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. We have entered into derivative instruments to hedge the commodity price associated with a portion of our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Transportation segment. See further details of our risk management program in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”
Our Liquidity and Capital Resources
As of March 31, 2026, inclusive of our consolidated joint venture accounts, we had $100.1 million of Cash and cash equivalents on our Consolidated Balance Sheets. On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRGP Revolver, the Commercial Paper Program, the Securitization Facility, and access to debt and equity capital markets. We have the ability to supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.
We believe our sources of liquidity and capital resources are sufficient to meet our anticipated cash requirements for at least the next twelve months to satisfy our obligations, including our day-to-day operations, growth capital expenditures, dividend payments, maintenance capital expenditures, debt service and other anticipated obligations. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, see “Recent Developments.”
Short-term Liquidity
Our short-term liquidity on a consolidated basis as of March 31, 2026, was:
|
|
|
|
|
|
|
Consolidated Total |
|
|
|
(In millions) |
|
Cash on hand (1) |
|
$ |
100.1 |
|
Total availability under the Securitization Facility |
|
|
600.0 |
|
Total availability under the TRGP Revolver and Commercial Paper Program |
|
|
3,500.0 |
|
|
|
|
4,200.1 |
|
|
|
|
|
Outstanding borrowings under the Securitization Facility |
|
|
(600.0 |
) |
Outstanding borrowings under the TRGP Revolver and Commercial Paper Program |
|
|
(457.0 |
) |
Outstanding letters of credit under the TRGP Revolver |
|
|
(17.9 |
) |
Total liquidity |
|
$ |
3,125.2 |
|
(1)Includes cash held in our consolidated joint venture accounts.
Other potential capital resources associated with our existing arrangements include our right to request an additional $500.0 million in commitment increases under the TRGP Revolver, subject to the terms therein. The TRGP Revolver matures on February 18, 2030. The maturity date is extendable, subject to the lenders’ consent, by one year up to two times.
In July 2025, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to August 31, 2026.
A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. As of March 31, 2026, we had $17.9 million in letters of credit outstanding under the TRGP Revolver. The letters of credit also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.
Working Capital
Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels, which we closely manage, as well as liquids valuations; (iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility and changes in other current debt balances; and (vi) major structural changes in our asset base or business operations, such as certain organic growth capital projects and acquisitions or divestitures.
Our working capital as of March 31, 2026 increased $226.4 million compared to December 31, 2025. The increase was primarily due to the redemption of all of the Partnership’s 6.875% Notes due 2029, higher trade receivables resulting from higher natural gas and NGL prices and lower interest payable due to timing of interest payments. The increase was partially offset by a higher outstanding balance on the Securitization Facility, higher net liabilities for hedging activities, lower NGL inventory balance and higher payable balances due to capital spending on growth projects.
Long-term Financing
Our long-term financing consists of potentially raising funds through long-term debt obligations, the issuance of common stock, preferred stock, or joint venture arrangements.
In January 2026, we used $650.0 million in borrowings from our Commercial Paper Program and $600.0 million from our Securitization Facility to fund the Stakeholder Acquisition.
In January 2026, we completed the redemption of all of the Partnership’s 6.875% Notes due 2029 and recognized a debt extinguishment loss of $10.1 million, comprised of $7.8 million related to the redemption premium paid and $2.3 million from the write-off of debt issuance costs.
In March 2026, we completed an underwritten public offering of the 4.350% Notes due 2031 and the 6.050% Notes due 2056, resulting in net proceeds of approximately $1,483.2 million. We used the net proceeds from the debt issuance for general corporate purposes, including to reduce borrowings under the Commercial Paper Program.
In the future, we or the Partnership may redeem, purchase or exchange certain of our and/or the Partnership’s outstanding debt through redemption calls, cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such calls, repurchases, exchanges or redemptions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness.
For information about our debt obligations, see “Note 7 – Debt Obligations” to our Consolidated Financial Statements. For information about our interest rate risk, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”
Compliance with Debt Covenants
As of March 31, 2026, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.
Cash Flow Analysis
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
|
2026 |
|
|
2025 |
|
|
2026 vs. 2025 |
|
(In millions) |
|
$ |
739.5 |
|
|
$ |
954.4 |
|
|
$ |
(214.9 |
) |
The primary drivers of cash flows from operating activities are: (i) the collection of cash from customers from the sale of NGLs and natural gas, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation; (ii) the payment of amounts related to the purchase of NGLs and natural gas; and (iii) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.
The decrease in net cash provided by operating activities was primarily due to lower collections from customers resulting from lower revenues in 2026 compared to 2025, as well as higher operating costs, payments for hedging activities, and interest on debt, partially offset by a decrease in payments for product purchases.
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
|
2026 |
|
|
2025 |
|
|
2026 vs. 2025 |
|
(In millions) |
|
$ |
(2,160.9 |
) |
|
$ |
(813.3 |
) |
|
$ |
(1,347.6 |
) |
The increase in net cash used in investing activities was primarily due to outlays for the Stakeholder Acquisition and higher outlays for major growth capital projects in 2026.
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2026 |
|
|
2025 |
|
|
(In millions) |
|
Source of Financing Activities, net |
|
|
|
|
|
Debt, including financing costs |
$ |
1,668.5 |
|
|
$ |
2,009.5 |
|
Repurchase of noncontrolling interests |
|
— |
|
|
|
(1,800.0 |
) |
Dividends paid to common shareholders |
|
(218.9 |
) |
|
|
(167.2 |
) |
Contributions from (distributions to) noncontrolling interests, net |
|
(5.6 |
) |
|
|
(17.9 |
) |
Repurchases of shares |
|
(88.6 |
) |
|
|
(171.4 |
) |
Net cash provided by (used in) financing activities |
$ |
1,355.4 |
|
|
$ |
(147.0 |
) |
The change in net cash provided by (used in) financing activities was due to lower repurchases of noncontrolling interests primarily due to the Badlands Transaction in 2025 and lower repurchases of common stock, partially offset by lower borrowings of debt and higher dividends paid. The decrease in cash flows from our debt activity was due to the redemption of all of the Partnership’s 6.875% Notes due 2029 and lower proceeds from the issuance of our senior unsecured notes in 2026, partially offset by higher net borrowings under the Securitization Facility and the Commercial Paper Program.
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
Our subsidiaries that guarantee our obligations under the TRGP Revolver (the “Obligated Group”) also fully and unconditionally guarantee, jointly and severally, the payment of TRGP’s senior unsecured notes, subject to certain limited exceptions.
In lieu of providing separate financial statements for the Obligated Group, we have presented the following supplemental summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.
All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in our non-guarantor subsidiaries have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including our non-guarantor subsidiaries (referred to as “affiliates”), are presented separately in the following supplemental summarized combined financial information.
Summarized Combined Balance Sheet and Statement of Operations information for the Obligated Group as of the end of the most recent periods presented follows:
|
|
|
|
|
|
|
|
|
Summarized Combined Balance Sheet Information |
|
|
|
|
|
|
|
|
March 31, 2026 |
|
|
December 31, 2025 |
|
|
|
(In millions) |
|
ASSETS |
|
Current assets |
|
$ |
92.9 |
|
|
$ |
160.3 |
|
Current assets - affiliates |
|
|
3.2 |
|
|
|
6.5 |
|
Long-term assets |
|
|
74.5 |
|
|
|
73.3 |
|
Total assets |
|
$ |
170.6 |
|
|
$ |
240.1 |
|
|
|
|
|
|
|
|
LIABILITIES AND OWNERS’ EQUITY (DEFICIT) |
|
Current liabilities |
|
$ |
93.5 |
|
|
$ |
928.9 |
|
Long-term liabilities |
|
|
3,747.9 |
|
|
|
3,749.4 |
|
Targa Resources Corp. stockholders’ equity (deficit) |
|
|
(3,670.8 |
) |
|
|
(4,438.2 |
) |
Total liabilities and owners’ equity (deficit) |
|
$ |
170.6 |
|
|
$ |
240.1 |
|
|
|
|
|
|
|
|
Summarized Combined Statement of Operations Information |
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2026 |
|
|
Year Ended
December 31, 2025 |
|
|
|
(In millions) |
|
Operating income (loss) |
|
$ |
(95.2 |
) |
|
$ |
(357.1 |
) |
Net income (loss) |
|
|
(150.6 |
) |
|
|
(603.6 |
) |
Common Stock Dividends
The following table details the dividends on common stock declared and/or paid by us for the three months ended March 31, 2026:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Date Paid or
To Be Paid |
|
Total Common
Dividends Declared |
|
|
Amount of Common
Dividends Paid or
To Be Paid |
|
|
Dividends on
Share-Based Awards |
|
|
Dividends Declared per Share of Common Stock |
|
(In millions, except per share amounts) |
|
March 31, 2026 |
|
May 15, 2026 |
|
$ |
270.4 |
|
|
$ |
268.3 |
|
|
$ |
2.1 |
|
|
$ |
1.25 |
|
December 31, 2025 |
|
February 13, 2026 |
|
|
217.1 |
|
|
|
215.0 |
|
|
|
2.1 |
|
|
|
1.00 |
|
The actual amount we declare as dividends in the future depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our Board of Directors deems relevant.
Capital Expenditures
The following table details cash outlays for capital projects for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2026 |
|
|
2025 |
|
|
|
(In millions) |
|
Capital expenditures: |
|
|
|
|
|
|
Growth (1) |
|
$ |
910.4 |
|
|
$ |
570.7 |
|
Maintenance (2) |
|
|
37.9 |
|
|
|
47.6 |
|
Gross capital expenditures |
|
|
948.3 |
|
|
|
618.3 |
|
Change in capital project payables and accruals, net |
|
|
(48.8 |
) |
|
|
173.9 |
|
Cash outlays for capital projects |
|
$ |
899.5 |
|
|
$ |
792.2 |
|
(1)Growth capital expenditures, net of any reimbursements of project costs and contributions from noncontrolling interests, and including contributions to investments in unconsolidated affiliates, were $914.4 million and $594.5 million for the three months ended March 31, 2026 and 2025.
(2)Maintenance capital expenditures, net of any reimbursements of project costs and contributions from noncontrolling interests, were $37.6 million and $47.3 million for the three months ended March 31, 2026 and 2025.
The increase in growth capital expenditures was primarily due to higher construction activities during 2026.
Off-Balance Sheet Arrangements
As of March 31, 2026, there were $62.3 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our risk management counterparties and customers.
Risk Management
We evaluate counterparty risks related to our commodity derivative contracts and trade credit. All of our commodity derivatives are with major financial institutions or major energy companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.
The prices for natural gas, NGLs and crude oil are volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk through 2029. Market conditions may also impact our ability to enter into future commodity derivative contracts.
Commodity Price Risk
A portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of commodities as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Both the realized settlements for a derivative instrument designated as a hedge and the related cash flows are classified in the same category as the item being hedged within the Consolidated Statement of Operations and within the Consolidated Statements of Cash Flows.
The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of March 31, 2026, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. We also enter into commodity financial instruments to help manage other short-term commodity-related business risks of our ongoing operations and in conjunction with marketing opportunities available to us in the operations of our logistics and transportation assets. With swaps, we typically receive an agreed fixed price for a specified notional quantity of commodities and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected equity volumes. We may utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.
When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The fair values of our natural gas and NGL hedges are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on NYMEX futures contracts for West Texas Intermediate light, sweet crude.
A majority of these commodity price hedges are documented pursuant to a standard International Swaps and Derivatives Association (“ISDA”) form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. While we have no current obligation to post cash, letters of credit or other additional collateral to secure these hedges so long as we maintain our current credit rating, we could be obligated to post collateral to secure the hedges in the event of an adverse change in our creditworthiness where a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.
We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas, NGL or crude oil prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.
These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls).
To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. The sensitivity analysis measures the change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does not reflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement impact on the fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a corresponding gain or loss on the hedged item under hedge accounting. The fair values of our derivative instruments are also influenced by changes in market volatility for option contracts and the discount rates used to determine the present values.
The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of March 31, 2026:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
Result of 10% Price Decrease |
|
|
Result of 10% Price Increase |
|
|
(In millions) |
|
Natural gas |
$ |
(234.9 |
) |
|
$ |
(160.7 |
) |
|
$ |
(309.1 |
) |
NGL |
|
(67.0 |
) |
|
|
7.8 |
|
|
|
(141.8 |
) |
Crude oil |
|
(39.9 |
) |
|
|
(6.6 |
) |
|
|
(73.2 |
) |
Total |
$ |
(341.8 |
) |
|
$ |
(159.5 |
) |
|
$ |
(524.1 |
) |
The table above contains all derivative instruments outstanding as of the stated date for the purpose of hedging commodity price risk, which we are exposed to due to our equity volumes and future commodity purchases and sales, as well as basis differentials related to our gas transportation arrangements.
Our operating revenues increased (decreased) by $(243.7) million and $(291.3) million during the three months ended March 31, 2026 and 2025, respectively, as a result of transactions accounted for as derivatives. The estimated fair value of our risk management position has moved from a net liability position of $66.9 million at December 31, 2025 to a net liability position of $341.8 million at March 31, 2026. The net liability position on our derivative contracts is primarily attributable to unfavorable movement in natural gas forward basis prices.
Interest Rate Risk
We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRGP Revolver, the Commercial Paper Program and the Securitization Facility. As of March 31, 2026, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRGP Revolver, the Commercial Paper Program and the Securitization Facility will also increase. As of March 31, 2026, we had $1,057.0 million in outstanding variable rate borrowings. A hypothetical change of 100 basis points in the rate of our variable interest rate debt would impact our consolidated annual interest expense by $10.6 million based on our March 31, 2026 debt balances.
Counterparty Credit Risk
We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the ISDA agreements with our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and reduce our maximum loss due to counterparty credit risk by $22.1 million as of March 31, 2026. The maximum loss attributable to any individual counterparty as of March 31, 2026 would be up to $4.7 million, depending on the counterparty in default.
Customer Credit Risk
We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.
We have an active credit management process, which is focused on controlling loss exposure due to bankruptcies or other liquidity issues of counterparties. Our allowance for credit losses was $0.7 million and $0.7 million as of March 31, 2026 and December 31, 2025, respectively.
During the three months ended March 31, 2026, revenues from one customer within our Logistics and Transportation segment represented approximately 11% of our consolidated revenues. No customer comprised 10% or greater of our consolidated revenues during the three months ended March 31, 2025.
Item 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of the period covered in this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2026, the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting during the quarter ended March 31, 2026, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
