UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☑
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2026
or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____ to _____
Commission File Number: 001-34991
TARGA RESOURCES CORP.
(Exact name of registrant as specified in its charter)
Delaware
20-3701075
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
811 Louisiana Street, Suite 2100, Houston, Texas
77002
(Address of principal executive offices)
(Zip Code)
(713) 584-1000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of exchange on which registered
Common Stock
TRGP
New York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
As of May 1, 2026, there were 214,643,903 shares of the registrant’s common stock, $0.001 par value, outstanding.
Total number of pages (excluding Exhibits): 48
TABLE OF CONTENTS
PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
4
Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025
Consolidated Statements of Operations for the three months ended March 31, 2026 and 2025
5
Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2026 and 2025
6
Consolidated Statements of Cash Flows for the three months ended March 31, 2026 and 2025
7
Consolidated Statements of Changes in Owners’ Equity for the three months ended March 31, 2026 and 2025
8
Notes to Consolidated Financial Statements
9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
27
Item 3. Quantitative and Qualitative Disclosures About Market Risk
41
Item 4. Controls and Procedures
44
PART II—OTHER INFORMATION
Item 1. Legal Proceedings
45
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
SIGNATURES
Signatures
47
1
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Targa Resources Corp.’s (together with its subsidiaries, including Targa Resources Partners LP (the “Partnership”), “we,” “us,” “our,” “Targa,” “TRGP,” or the “Company”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:
Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this quarterly report on Form 10-Q for the quarter ended March 31, 2026 (“Quarterly Report”) will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.
2
As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:
Bbl
Barrels (equal to 42 U.S. gallons)
BBtu
Billion British thermal units
Bcf
Billion cubic feet
Btu
British thermal units, a measure of heating value
/d
Per day
FERC
Federal Energy Regulatory Commission
GAAP
Accounting principles generally accepted in the United States of America
gal
U.S. gallons
LPG
Liquefied petroleum gas
MBbl
Thousand barrels
MMBbl
Million barrels
MMBtu
Million British thermal units
MMcf
Million cubic feet
MMgal
Million U.S. gallons
NGL(s)
Natural gas liquid(s)
NYMEX
New York Mercantile Exchange
NYSE
SCOOP
South Central Oklahoma Oil Province
STACK
Sooner Trend, Anadarko, Canadian and Kingfisher
3
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements.
CONSOLIDATED BALANCE SHEETS
March 31, 2026
December 31, 2025
(Unaudited)
(In millions)
ASSETS
Current assets:
Cash and cash equivalents
$
100.1
166.1
Trade receivables, net of allowances of $0.7 million and $0.7 million as of March 31, 2026 and December 31, 2025
1,691.7
1,474.6
Inventories
334.4
429.3
Assets from risk management activities
100.6
154.7
Other current assets
211.4
138.0
Total current assets
2,438.2
2,362.7
Property, plant and equipment, net
21,770.9
20,534.8
Intangible assets, net
2,201.2
1,651.4
Long-term assets from risk management activities
38.5
35.0
Investments in unconsolidated affiliates
315.0
307.1
Other long-term assets
343.5
327.4
Total assets
27,107.3
25,218.4
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable
1,987.9
1,873.0
Accrued liabilities
193.2
358.6
Interest payable
149.8
311.0
Liabilities from risk management activities
368.1
234.1
Current debt obligations
696.9
770.1
Total current liabilities
3,395.9
3,546.8
Long-term debt
18,434.9
16,662.4
Long-term liabilities from risk management activities
112.8
22.5
Deferred income taxes, net
1,479.2
1,393.5
Other long-term liabilities
415.5
395.0
Contingencies (see Note 12)
Owners’ equity:
Targa Resources Corp. stockholders’ equity:
Common Stock ($0.001 par value, 450,000,000 shares authorized as of March 31, 2026 and December 31, 2025)
0.2
Issued Outstanding
March 31, 2026 243,245,513 214,729,502
December 31, 2025 242,770,213 214,662,156
Additional paid-in capital
3,111.3
3,088.1
Retained earnings (deficit)
2,556.9
2,294.4
Accumulated other comprehensive income (loss)
(14.7
)
113.8
Treasury stock, at cost (28,516,011 shares and 28,108,057 shares as of March 31, 2026 and December 31, 2025)
(2,517.2
(2,428.6
Total Targa Resources Corp. stockholders’ equity
3,136.5
3,067.9
Noncontrolling interests
132.5
130.3
Total owners’ equity
3,269.0
3,198.2
Total liabilities and owners’ equity
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended March 31,
2026
2025
(In millions, except per share amounts)
Revenues:
Sales of commodities
3,344.6
3,884.4
Fees from midstream services
750.1
677.1
Total revenues
4,094.7
4,561.5
Costs and expenses:
Product purchases and fuel
2,394.5
3,257.8
Operating expenses
333.7
303.6
Depreciation and amortization expense
426.0
367.6
General and administrative expense
107.8
94.5
Other operating (income) expense
(14.2
(5.3
Income (loss) from operations
846.9
543.3
Other income (expense):
Interest expense, net
(227.6
(197.1
Equity earnings (loss)
8.6
5.5
Other, net
(16.6
0.3
Income (loss) before income taxes
611.3
352.0
Income tax (expense) benefit
(123.9
(72.2
Net income (loss)
487.4
279.8
Less: Net income (loss) attributable to noncontrolling interests
7.8
9.3
Net income (loss) attributable to Targa Resources Corp.
479.6
270.5
Premium on repurchase of noncontrolling interests, net of tax
—
70.5
Net income (loss) attributable to common shareholders
200.0
Net income (loss) per common share - basic
2.22
0.91
Net income (loss) per common share - diluted
2.21
Weighted average shares outstanding - basic
214.8
217.9
Weighted average shares outstanding - diluted
215.5
218.7
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Pre-Tax
Related Income Tax
After Tax
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value
(166.9
38.2
(128.7
(33.8
7.7
(26.1
Settlements reclassified to revenues
6.1
(1.4
4.7
Other comprehensive income (loss)
(166.7
(128.5
(27.7
6.3
(21.4
Comprehensive income (loss)
358.9
258.4
Less: Comprehensive income (loss) attributable to noncontrolling interests
Comprehensive income (loss) attributable to Targa Resources Corp.
351.1
249.1
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Amortization in interest expense
4.9
3.9
Compensation on equity grants
23.2
17.6
Deferred income tax expense (benefit)
123.9
56.9
Equity (earnings) loss of unconsolidated affiliates
(8.6
(5.5
Distributions of earnings received from unconsolidated affiliates
1.7
2.4
Risk management activities
110.3
248.8
15.8
Changes in operating assets and liabilities, net of acquisitions:
Receivables and other assets
(198.0
217.1
96.0
78.8
Accounts payable, accrued liabilities and other liabilities
(181.9
(169.3
(161.2
(147.6
Net cash provided by (used in) operating activities
739.5
954.4
Cash flows from investing activities
Outlays for property, plant and equipment
(899.5
(792.2
Outlays for business acquisition, net of cash acquired
(1,261.3
(4.0
(23.8
Return of capital from unconsolidated affiliates
3.0
2.5
0.9
Net cash provided by (used in) investing activities
(2,160.9
(813.3
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings of commercial paper notes
31,824.0
25,432.0
Repayments of commercial paper notes
(31,528.0
(25,642.5
Proceeds from borrowings under accounts receivable securitization facility
1,200.0
870.0
Repayments of accounts receivable securitization facility
(600.0
Proceeds from issuance of senior unsecured notes
1,498.4
1,993.9
Redemption of senior unsecured notes
(687.1
Principal payments of finance leases
(14.6
Costs incurred in connection with financing arrangements
(15.0
(29.3
Repurchases of common stock
(55.0
(124.9
Shares tendered for tax withholding obligations
(33.6
(46.5
Distributions to noncontrolling interests
(5.6
(17.9
Repurchase of noncontrolling interests
(1,800.0
Dividends paid to common shareholders
(218.9
(167.2
Net cash provided by (used in) financing activities
1,355.4
(147.0
Net change in cash and cash equivalents
(66.0
(5.9
Cash and cash equivalents, beginning of period
157.3
Cash and cash equivalents, end of period
151.4
See notes to consolidated financial statements
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS’ EQUITY
Retained
Accumulated
Additional
Earnings
Other
Treasury
Total
Paid in
(Accumulated
Comprehensive
Shares
Noncontrolling
Owners’
Amount
Capital
Deficit)
Income (Loss)
Interests
Equity
(In millions, except shares in thousands)
Balance, December 31, 2025
214,662
28,108
Dividend equivalent rights
(1.1
Shares issued under compensation program
476
(180
180
(228
228
Common stock dividends
Dividends - $1.00 per share
(216.0
Balance, March 31, 2026
214,730
28,516
Balance, December 31, 2024
217,764
3,089.1
1,190.0
27.5
24,000
(1,714.4
1,825.8
4,418.2
(0.7
564
(216
216
(651
651
Excise tax on repurchases of common stock
(0.5
Dividends - $0.75 per share
(164.5
(4.7
Repurchase of noncontrolling interests, net of tax
(70.5
(1,709.2
(1,779.7
Balance, March 31, 2025
217,461
3,036.2
1,295.3
24,867
(1,886.3
121.2
2,572.7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.
Note 1 — Organization and Operations
Our Organization
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.
In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” “Targa” or “TRGP” are intended to mean our consolidated business and operations. TRGP controls the general partner of and owns all of the outstanding common units representing limited partner interests in Targa Resources Partners LP, referred to herein as the “Partnership.” Targa consolidates the Partnership and its subsidiaries under GAAP, and the accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. Targa’s consolidated financial statements include differences from the consolidated financial statements of the Partnership. The most noteworthy differences are:
Our Operations
The Company is primarily engaged in the business of:
See “Note 16 – Segment Information” for certain financial information regarding our business segments.
Note 2 — Basis of Presentation
The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and do not include all information and disclosures required by GAAP. Therefore, this information should be read in conjunction with our consolidated financial statements and notes contained in our Annual Report. The information furnished herein reflects all adjustments that are, in the opinion of management, of a normal recurring nature and considered necessary for a fair statement of the results of the interim periods reported. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods have been reclassified to conform to the current year presentation. Operating results for the three months ended March 31, 2026 are not necessarily indicative of the results that may be expected for the year ending December 31, 2026.
Note 3 — Significant Accounting Policies
The accounting policies that we follow are set forth in “Note 3 – Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our Annual Report. Other than the updates noted below, there were no significant updates or revisions to our accounting policies during the three months ended March 31, 2026.
Recently issued accounting pronouncements not yet adopted
Disaggregation of Income Statement Expenses
In November 2024, the FASB issued ASU 2024-03, Comprehensive income (Topic 220): Disaggregation of Income Statement Expenses. The amendments in this update require, among other items, that public entities disclose, on an annual and interim basis, in tabular format in the footnotes to the financial statements, disaggregated information about specific categories underlying certain income statement expense line items that contain any of the following expense categories (i) purchases of inventory, (ii) employee compensation, (iii) depreciation, (iv) intangible asset amortization, and (v) depletion. Additionally, the amendments require disclosure of the total amount of selling expenses and an annual disclosure of the definition of selling expenses.
These amendments are effective for fiscal years beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027, with early adoption permitted. The disclosures may be applied either prospectively or retrospectively to any or all prior periods presented in the financial statements. We are evaluating the effect of the amendments on our notes to consolidated financial statements and expect to disclose the required information for fiscal years beginning in the annual report on Form 10-K for the year ending December 31, 2027 and for interim periods beginning in the quarterly report on Form 10-Q for the quarter ending March 31, 2028. The impact of the adoption will be limited to disclosure in the notes to consolidated financial statements.
Targeted Improvements to the Accounting for Internal-Use Software
In September 2025, the FASB issued ASU 2025-06, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software. The amendments in this update, among other items, remove all references to prescriptive and sequential software development stages and require entities to start capitalizing software costs when (i) management has authorized and committed to funding the software project, and (ii) it is probable that the project will be completed and the software will be used to perform the function intended.
These amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2027, with early adoption permitted. The amendments permit the use of prospective, modified retrospective, or full retrospective transition approaches. We are evaluating the effect of the amendments on our consolidated financial statements and related disclosures. We expect to apply the amendments for interim periods beginning in the quarterly report on Form 10-Q for the quarter ending March 31, 2028 and for fiscal years beginning in the annual report on Form 10-K for the year ending December 31, 2028.
Accounting for Government Grants Received by Business Entities
In December 2025, the FASB issued ASU 2025-10, Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities. The amendments in this update, among other items, establish guidance on the recognition, measurement and presentation of government grants received by a business entity.
These amendments are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2028, with early adoption permitted. The amendments permit the use of modified prospective, modified retrospective, or retrospective approaches. We are evaluating the effect of the amendments on our consolidated financial statements and related disclosures. We expect to apply the amendments for interim periods beginning in the quarterly report on Form 10-Q for the quarter ending March 31, 2029 and for fiscal years beginning in the annual report on Form 10-K for the year ending December 31, 2029.
10
Note 4 — Acquisitions and Joint Ventures
Badlands Acquisition
In March 2025, we completed the acquisition of Blackstone’s 45% interest in Targa Badlands LLC (“Targa Badlands”) for aggregate consideration of $1.8 billion in cash, with an additional $0.4 million of capitalized transaction costs (the “Badlands Transaction”). As a result of the acquisition, we own 100% of the interests in and earnings of Targa Badlands effective January 1, 2025. The change in our ownership interest was accounted for as an equity transaction representing the acquisition of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax, was $70.5 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders.
Dovetail Acquisition
In December 2025, we completed the purchase of all of the membership interests in Dovetail Midstream, LLC (“Dovetail”), a wholly-owned subsidiary of Riley Exploration Permian, Inc (“Riley”) and the purchase of certain compressor assets from Riley for aggregate cash consideration of approximately $122.8 million, subject to customary closing adjustments (the “Dovetail Acquisition”). The assets acquired in the Dovetail Acquisition primarily consist of compression and natural gas gathering infrastructure in Eddy County, New Mexico. Subject to certain volume-based performance thresholds, additional cash of up to $60.0 million may be payable to Riley over a five-year period from the acquisition date.
The Dovetail Acquisition was accounted for under the acquisition method in accordance with ASC 805, Business Combinations, which requires, among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. The preliminary valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions, including projections of future production volumes, commodity prices, and other cash flows, market-participant assumptions (e.g., discount rate and exit multiple), tangible asset replacement costs, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in “Note 11 – Fair Value Measurements.” These inputs require judgments and estimates at the time of valuation.
We are in the process of finalizing valuations related to property, plant and equipment, goodwill, and contingent consideration. The final valuation will be completed no later than one year from the acquisition date.
Stakeholder Acquisition
In January 2026, we completed the acquisition of all of the membership interests in Stakeholder Midstream, LLC (“Stakeholder”) for a purchase price of $1.25 billion (the “Stakeholder Acquisition”), subject to customary closing adjustments. We acquired a portfolio of complementary Permian Basin midstream infrastructure assets, including approximately 480 miles of natural gas pipelines, approximately 180 MMcf/d of cryogenic natural gas processing and sour treating capacity, carbon capture activities generating 45Q tax credits, and a small crude oil gathering system. The Stakeholder assets have been integrated into our Permian Delaware operations. The acquisition had an effective date of January 1, 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.
The Stakeholder Acquisition was accounted for under the acquisition method in accordance with ASC 805, Business Combinations, which requires, among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. The preliminary allocation of the purchase price, which is subject to certain adjustments, was based upon preliminary valuations from estimates and assumptions that management believes are reasonable; however, management’s estimates and assumptions are subject to change upon the completion of the final valuations or as information necessary to complete the fair value analysis is obtained. The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions, including projections of future production volumes, commodity prices, and other cash flows, market-participant assumptions (e.g., discount rate and exit multiple), expectations regarding customer contracts and relationships, tangible asset replacement costs, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in “Note 11 – Fair Value Measurements.” These inputs require judgments and estimates at the time of valuation. We are in the process of finalizing valuations related to the Stakeholder Acquisition, including the fair value of the property, plant and equipment and identifiable intangible assets acquired. The final valuation will be completed no later than one year from the acquisition date.
11
The following table summarizes the preliminary fair values assigned to assets acquired and liabilities assumed:
24.9
Trade receivables
82.9
2.9
595.1
653.0
Current liabilities
(59.7
(7.9
Purchase price
1,291.2
The preliminary value of property, plant and equipment is determined using the cost approach and is primarily comprised of Gathering and Processing assets that will be depreciated on a straight-line basis over an estimated weighted-average useful life of 20 years. The associated useful lives of property, plant and equipment were based on the period over which the assets are expected to contribute directly or indirectly to our future cash flows.
The preliminary value of intangible assets is comprised of customer relationships, which represent the estimated value of existing long-term contracts with customers and the expected continuation of those relationships through future renewals, that will be amortized in a manner that closely resembles the expected benefit pattern of the intangible assets over an estimated useful life of 12 years. The associated useful lives of intangible assets were based on the period over which the assets are expected to contribute directly or indirectly to our future cash flows. The preliminary fair value of customer relationships was determined at the date of acquisition based on the present value of estimated future cash flows using the multi-period excess earnings method. The significant assumptions used by management in determining the fair value of customer relationships intangible assets include future revenues, discount rate, and customer attrition rates.
The results of operations attributable to the assets and liabilities acquired in the Stakeholder Acquisition have been included in our consolidated financial statements as part of our Permian Delaware operations in our Gathering and Processing segment since the date of the acquisition. Revenues and Net Income attributable to the assets acquired for the period January 1, 2026 through March 31, 2026 were $59.7 million and $9.8 million, respectively. We expensed $8.9 million of acquisition-related costs.
Unaudited Pro Forma Financial Information
The following unaudited pro forma summary presents the consolidated results of operations for the three months ended March 31, 2026 and 2025 as if the Stakeholder Acquisition had occurred on January 1, 2025. The unaudited pro forma financial information is presented for informational purposes only and is not necessarily indicative of our results of operations that would have occurred had the transaction been consummated at the beginning of the period presented, nor is it necessarily indicative of future results.
The summarized unaudited pro forma information reflects certain adjustments directly attributable to the Stakeholder Acquisition, including those due to conforming the acquiree’s presentation of revenue to Targa’s accounting policies, incremental depreciation and amortization related to the stepped-up fair value of assets acquired, recognition of incremental interest expense related to debt issued in connection with the acquisition, and recognition of transaction costs incurred. The pro forma information includes the income tax effects of the adjustments. The unaudited pro forma information does not reflect any anticipated cost savings, synergies or integration costs related to the Stakeholder Acquisition.
Revenues
4,612.6
493.4
264.9
12
Note 5 — Property, Plant and Equipment and Intangible Assets
Estimated Useful Lives (In Years)
Gathering systems
12,815.9
12,431.3
5 to 20
Processing and fractionation facilities
11,672.4
10,477.3
5 to 25
Terminaling and storage facilities
1,668.5
1,648.4
Transportation assets
4,774.8
4,536.0
10 to 50
Other property, plant and equipment
621.8
586.5
3 to 25
Land
215.2
209.3
Construction in progress
2,461.7
2,804.9
Finance lease right-of-use assets
520.7
507.4
5 to 14
Property, plant and equipment
34,751.0
33,201.1
Accumulated depreciation, amortization and impairment
(12,980.1
(12,666.3
Intangible assets
5,031.0
4,378.0
10 to 20
Accumulated amortization and impairment
(2,829.8
(2,726.6
During the three months ended March 31, 2026 and 2025 depreciation expense was $322.8 million and $286.1 million, respectively.
Intangible Assets
Intangible assets consist of customer contracts and customer relationships acquired in our business combinations. The fair value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers.
During the three months ended March 31, 2026 and 2025, amortization expense was $103.2 million and $81.5 million, respectively.
The estimated annual amortization expense for intangible assets is approximately $412.9 million, $377.3 million, $327.1 million, $286.2 million and $240.4 million for each of the years 2026 through 2030, respectively.
The following table shows the changes in our intangible assets for the period presented:
Three Months Ended March 31, 2026
Balance at beginning of period
Additions from Stakeholder Acquisition
Amortization
(103.2
Balance at end of period
13
Note 6 — Investments in Unconsolidated Affiliates
Our investments in unconsolidated affiliates consist of the following:
Gathering and Processing Segment
Logistics and Transportation Segment
The terms of these joint venture agreements do not afford us the degree of control required for consolidating the entities in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting.
The following table shows the activity related to our investments in unconsolidated affiliates:
Balance at December 31, 2024
Equity Earnings (Loss)
Cash Distributions
Contributions
Balance at March 31, 2025
Little Missouri 4
84.3
3.3
(4.9
87.6
GCF
66.4
1.0
67.4
Cayenne
12.3
1.5
13.8
Blackcomb
30.3
(0.3
18.9
48.9
193.3
23.8
217.7
Balance at December 31, 2025
Contributions (1)
Balance at March 31, 2026
93.7
3.5
92.8
69.2
0.1
1.9
71.2
2.2
14.5
131.9
2.8
1.8
136.5
4.0
14
Note 7 — Debt Obligations
Current:
Partnership accounts receivable securitization facility, due August 2026 (1)
600.0
Senior unsecured notes issued by the Partnership: (2)
6.875% fixed rate, due January 2029 (3)
679.3
Debt issuance costs, net of amortization (3)
(2.3
Finance lease liabilities
96.9
93.1
Long-term:
TRGP senior revolving credit facility, variable rate, due February 2030 (4)
457.0
161.0
Senior unsecured notes issued by TRGP:
5.200% fixed rate, due July 2027
750.0
4.350% fixed rate, due January 2029
6.150% fixed rate, due March 2029
1,000.0
4.900% fixed rate, due September 2030
4.350% fixed rate, due April 2031 (5)
4.200% fixed rate, due February 2033
6.125% fixed rate, due March 2033
900.0
6.500% fixed rate, due March 2034
5.500% fixed rate, due February 2035
5.550% fixed rate, due August 2035
5.650% fixed rate, due February 2036
5.400% fixed rate, due July 2036
4.950% fixed rate, due April 2052
6.250% fixed rate, due July 2052
500.0
6.500% fixed rate, due February 2053
850.0
6.125% fixed rate, due May 2055
6.050% fixed rate, due May 2056 (5)
Unamortized discount
(39.4
(38.3
5.000% fixed rate, due January 2028
700.3
5.500% fixed rate, due March 2030
949.6
4.875% fixed rate, due February 2031
4.000% fixed rate, due January 2032
18,317.5
16,522.6
Debt issuance costs, net of amortization
(132.2
(120.6
249.6
260.4
Total debt obligations
19,131.8
17,432.5
Irrevocable standby letters of credit: (4)
Letters of credit outstanding under the TRGP senior revolving credit facility
17.9
20.0
The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2026:
Range of Interest Rates Incurred
Weighted Average Interest Rate Incurred
TRGP Revolver and Commercial Paper Program
3.9% - 4.0%
3.9%
Securitization Facility
4.4% - 4.5%
4.5%
15
Compliance with Debt Covenants
As of March 31, 2026, we were in compliance with the covenants contained in our various debt agreements.
Senior Unsecured Notes Issuance
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. The March 2026 Senior Unsecured Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Thirteenth Supplemental Indenture, dated as of March 2, 2026, among us, each subsidiary guarantor and U.S. Bank Trust Company, National Association, as trustee. In connection with the offering, we recorded debt issuance costs of $15.2 million and discount of $1.6 million as reductions to the carrying value of the March 2026 Senior Unsecured Notes in Long-term debt on our Consolidated Balance Sheets. We used the net proceeds from the debt issuance for general corporate purposes, including to reduce borrowings under the Commercial Paper Program.
Debt Repurchases & Extinguishments
In January 2026, we completed the redemption of all of the $679.3 million aggregate principal amount of the Partnership’s 6.875% Senior Unsecured Notes due 2029 for a total cash payment of $687.1 million inclusive of redemption premium. We 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.
Note 8 — Common Stock and Related Matters
Common Share Repurchase Program
In July 2024, our Board of Directors approved a share repurchase program (the “2024 Share Repurchase Program”) for the repurchase of up to $1.0 billion of our outstanding common stock. In addition, in August 2025, our Board of Directors approved a new share repurchase program (the “2025 Share Repurchase Program” and, together with the 2024 Share Repurchase Program, the “Share Repurchase Programs”) for the repurchase of up to $1.0 billion of our outstanding common stock. 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. For the three months ended March 31, 2025, we repurchased 651,163 shares of our common stock at a weighted average per share price of $191.86 for a total net cost of $124.9 million. As of March 31, 2026, there was $1,318.6 million remaining under the Share Repurchase Programs.
Common Stock Dividends
In April 2026, we declared an increase to our common dividend to $1.25 per common share, or $5.00 per common share annualized, effective for the first quarter of 2026.
The following table details the dividends declared and/or paid by us to common shareholders for the three months ended March 31, 2026:
Three Months Ended
Date Paid orTo Be Paid
Total CommonDividends Declared
Amount of CommonDividends Paid orTo Be Paid
Dividends on Share-Based Awards
Dividends Declared per Share of Common Stock
May 15, 2026
270.4
268.3
2.1
1.25
February 13, 2026
215.0
1.00
16
Note 9 — Earnings per Common Share
Restricted Stock Unit awards (“RSUs”) that vest no later than three years following the RSUs’ grant date participate in quarterly cash dividend payments. As these RSUs and certain four-year retention awards participate in nonforfeitable dividends with the common equity owners of the Company, they are considered participating securities.
We calculate earnings per share using the two-class method. Earnings are allocated to common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings to the extent that each security participates in earnings.
The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share:
Less: Premium on repurchase of noncontrolling interests, net of tax (1)
Less: Participating share-based earnings (2)
1.2
Net income (loss) allocated to common shareholders for basic earnings per share
477.1
198.8
Dilutive effect of unvested restricted stock awards
0.7
0.8
Net income (loss) available per common share - basic
Net income (loss) available per common share - diluted
The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the inclusion of such shares would have been anti-dilutive (in millions on a weighted-average basis):
Unvested restricted stock awards
1.1
Note 10 — Derivative Instruments and Hedging Activities
The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have entered into derivative instruments to hedge the commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from 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. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices and are primarily designated as cash flow hedges for accounting purposes.
The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.
We hedge a portion of our condensate equity volumes using crude oil hedges that are based on NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.
17
We also enter into derivative instruments to help manage other short-term commodity-related business risks and take advantage of market opportunities. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues in current earnings.
At March 31, 2026, the notional volumes of our commodity derivative contracts were:
Commodity
Instrument
Unit
2027
2028
2029
Natural Gas
Swaps
MMBtu/d
93,313
77,778
77,230
Basis Swaps
483,282
356,829
279,798
24,959
NGL
Bbl/d
32,377
24,258
23,669
Futures
15,247
271
Condensate
8,263
3,316
3,244
Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. The master netting provisions reduced 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 would be up to $4.7 million, depending on the counterparty in default. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements.
The following table reflects the fair value of our derivative instruments and their location on our Consolidated Balance Sheets as of the periods presented:
Fair Value as of March 31, 2026
Fair Value as of December 31, 2025
Balance Sheet
Derivative
Location
Assets
Liabilities
Derivatives designated as hedging instruments
Commodity contracts
Current
83.4
(115.0
137.1
(14.8
Long-term
34.8
(26.2
26.1
(6.9
Total derivatives designated as hedging instruments
118.2
(141.2
163.2
(21.7
Derivatives not designated as hedging instruments
17.2
(253.1
(219.3
3.7
(86.6
8.9
(15.6
Total derivatives not designated as hedging instruments
20.9
(339.7
26.5
(234.9
Total current position
(368.1
(234.1
Total long-term position
(112.8
(22.5
Total derivatives
139.1
(480.9
189.7
(256.6
18
The following tables reflect the pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis as of the periods presented:
Gross Presentation
Pro Forma Net Presentation
Asset
Liability
Collateral
Current Position
Counterparties with offsetting positions or collateral
90.9
9.2
(186.3
Counterparties without offsetting positions - assets
0.5
Counterparties without offsetting positions - liabilities
9.7
Long-Term Position
(96.5
25.5
8.1
(40.6
(16.3
(56.9
Total Derivatives
138.6
(464.6
116.4
17.3
(226.9
17.8
(243.2
133.3
29.6
31.3
(102.5
21.4
52.7
33.4
(2.7
15.3
(7.1
1.6
16.9
166.7
26.9
46.6
(109.6
23.0
69.6
Some of our hedges are futures contracts executed through brokers that clear the hedges through an exchange. We maintain a margin deposit with the brokers in an amount sufficient to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is included within Other current assets on our Consolidated Balance Sheets and is not offset against the fair value of our derivative instruments. Our derivative instruments other than our futures contracts are executed under International Swaps and Derivatives Association agreements (“ISDAs”), which govern the key terms with our counterparties. Our ISDAs contain credit-risk related contingent features and are not secured. As of March 31, 2026, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $236.4 million. We have not been required to post any collateral related to these positions due to our credit rating. If our credit rating was to be downgraded one notch below investment grade by both Moody’s and S&P, as defined in our ISDAs, we estimate that as of March 31, 2026, we would not be required to post collateral to any counterparty and that no counterparty could request immediate, full settlement per the terms of our ISDAs.
The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of $341.8 million as of March 31, 2026. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for our counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.
19
The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue for the periods presented:
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow
Hedging Relationships
Gain (Loss) Reclassified from OCI into Income (Effective Portion)
Location of Gain (Loss)
(0.2
(6.1
As of March 31, 2026, we expect to reclassify commodity hedge related net deferred losses of $35.1 million included in Accumulated OCI into earnings before income taxes over the next twelve months. However, actual amounts reclassified into earnings could be greater or less than the net amount reported in Accumulated OCI. As of March 31, 2026, the maximum length of time over which we have hedged our exposure to the variability in future cash flows is through 2028.
Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on our Consolidated Balance Sheets and through earnings in our Consolidated Statements of Operations rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial assets and liabilities (“financial instruments”) can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the three months ended March 31, 2026, we had unrealized mark-to-market losses primarily driven by unfavorable movement in natural gas forward basis prices.
Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated
Recognized in Income on
as Hedging Instruments
Derivatives
Revenue
(243.5
(285.2
See “Note 11 – Fair Value Measurements” and “Note 16 – Segment Information” for additional disclosures related to derivative instruments and hedging activities.
Note 11 — Fair Value Measurements
Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial instruments. Derivative financial instruments are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of our financial instruments.
Fair Value of Derivative Financial Instruments
Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative instruments using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative instruments we hold.
The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The derivatives at March 31, 2026 represent a net liability position of $341.8 million which reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative instruments. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $524.1 million. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net liability of $159.5 million.
20
Fair Value of Other Financial Instruments
Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our current and long-term debt as follows:
Contingent consideration liabilities related to business acquisitions are carried at fair value.
Fair Value Hierarchy
We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:
The following table shows a breakdown by fair value hierarchy category for (i) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (ii) supplemental fair value disclosures for other financial instruments:
Carrying
Fair Value
Value
Level 1
Level 2
Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)
138.3
137.2
Liabilities from commodity derivative contracts (1)
480.1
480.0
Contingent consideration liability
7.6
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
TRGP Senior unsecured notes
14,210.6
14,226.7
Partnership’s Senior unsecured notes
3,649.9
3,606.8
189.3
189.2
256.2
255.2
12,711.7
12,928.6
4,329.2
4,316.2
21
Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets
We report certain of our swaps at fair value using Level 3 inputs due to such derivative instruments not having observable market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivative instruments valued using indicative price quotations whose contract length extends into unobservable periods. The fair value of these swaps was determined using a discounted cash flow valuation technique based on a commodity forward curve, which is based on observable or public data sources and extrapolated when observable prices are not available. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives were the forward natural gas pricing inputs, for which a significant portion of the derivative instruments’ term is beyond available forward pricing.
The fair value of the contingent consideration was determined using a Monte Carlo simulation model. Significant inputs used in the fair value measurement include forecasted volumes, term of the earn-out period, risk-adjusted discount rate, and volatility associated with the underlying assets. The inputs are not observable; therefore, the entire valuation of the contingent consideration is categorized in Level 3. The fair value of the contingent consideration is recorded within Other long-term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability are included in Other income (expense) in our Consolidated Statements of Operations.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Nonfinancial assets and liabilities, such as long-lived assets, are measured at fair value on a nonrecurring basis at acquisition or whenever impairment indicators are present. For disclosures related to valuation techniques used in the Stakeholder Acquisition, see “Note 4 – Acquisitions and Joint Ventures.”
The techniques used to fair value assets and liabilities on a nonrecurring basis may produce a fair value calculation that may not be indicative or reflective of future fair values. Furthermore, while we believe our valuation techniques are appropriate and consistent with other market participants, the use of different techniques or assumptions to determine fair value of certain financial and nonfinancial assets and liabilities could result in a different fair value measurement at the reporting date.
Note 12 — Contingencies
Legal Proceedings
We and the Partnership are parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We and the Partnership are also parties to various proceedings with governmental environmental agencies, including, but not limited to the U.S. Environmental Protection Agency (the “EPA”), Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department (the “NMED”), Louisiana Department of Environmental Quality and North Dakota Department of Environmental Quality, which assert monetary sanctions for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business.
On July 24, 2023, we received a Notice of Violation (the “New Mexico NOV”) from the NMED, Air Quality Bureau, relating to alleged air permit violations at the Red Hills gas processing facility. The alleged air permit violations occurred primarily between August 1, 2021 and June 30, 2022, while the facility was owned by Lucid Energy Delaware, LLC (“Lucid”), a subsidiary we acquired in July 2022 and renamed Targa Northern Delaware LLC. On December 5, 2024, we received a proposed Administrative Compliance Order (the “ACO”) from the NMED relating to the violations identified in the New Mexico NOV and certain other alleged violations. The ACO includes a proposed civil penalty of approximately $47.8 million and requires certain capital improvements to address the operations and excess air emissions at the Red Hills processing facility. These capital improvements, totaling approximately $140 million, were substantially completed by December 31, 2024.
On January 3, 2025, we filed a Request for Hearing with the NMED with respect to the ACO. We have cooperated with the NMED in identifying and correcting legacy environmental issues since our acquisition of Lucid, and we expect to continue to engage with the NMED to resolve this matter and certain additional matters identified during our negotiations with the NMED. Although this matter is ongoing and we cannot predict its ultimate outcome, we believe we have valid defenses to many of the NMED allegations and intend to vigorously defend this matter.
22
On October 26, 2023, we received a final judgment in a lawsuit alleging a breach of contract related to the major winter storm in February 2021. The damages awarded against us are approximately $6.9 million, not including pre-judgment interest. Both parties appealed the judgment. On December 9, 2025, the Fifth Circuit Court of Appeals (i) reversed the trial court’s summary judgment in favor of Targa and remanded the case to trial court for further proceedings and (ii) upheld the $6.9 million jury verdict in favor of MIECO. Targa has filed a motion for reconsideration, and the appeal remains pending at the Fifth Circuit Court of Appeals.
Note 13 — Revenue
Fixed consideration allocated to remaining performance obligations
The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements, with remaining contract terms ranging from 1 to 16 years.
2028 and after
Fixed consideration to be recognized as of March 31, 2026
301.3
436.3
1,975.3
Based on the optional exemptions that we elected to apply, the amounts presented in the table above exclude remaining performance obligations for (i) variable consideration for which the allocation exception is met and (ii) contracts with an original expected duration of one year or less.
Deferred Revenue
Deferred revenue as of March 31, 2026 and December 31, 2025 was $142.8 million and $135.7 million, respectively. As of March 31, 2026, $22.0 million of deferred revenue is included in Accrued liabilities and $120.8 million is included in Other long-term liabilities on our Consolidated Balance Sheets. Deferred revenue includes contributions in aid of construction received from customers related to owned property, plant, and equipment for which revenue is recognized over the expected contract term. Deferred revenue also includes consideration received in 2015 and 2017 amendments to a gas gathering and processing agreement. The deferred revenue related to these amendments is being recognized through the end of the agreement’s term in 2035.
For the three months ended March 31, 2026 and 2025, we recognized revenue of $5.3 million and $5.1 million, respectively, from prior period deferral.
For disclosures related to disaggregated revenue, see “Note 16 – Segment Information.”
Note 14 — Income Taxes
We record income taxes using an estimated annual effective tax rate and recognize specific events discretely as they occur. Our effective tax rate for the three months ended March 31, 2026 is lower than the U.S. corporate statutory rate of 21% primarily due to excess tax-deductible stock compensation. Our effective tax rate for the three months ended March 31, 2025 was lower than the U.S. corporate statutory rate of 21% primarily due to excess tax-deductible stock compensation, partially offset by state income taxes.
We regularly evaluate the realizable tax benefits of deferred tax assets and record a valuation allowance, if required, based on an estimate of the amount of deferred tax assets that we believe does not meet the more-likely-than-not criteria of being realized. As of March 31, 2026 and December 31, 2025, our valuation allowance was $5.9 million.
We are subject to tax in the U.S. and various state jurisdictions, and we are subject to periodic audits and reviews by taxing authorities. As of March 31, 2026, examinations by the Internal Revenue Service (“IRS”) are currently in process for the 2022 taxable year of certain wholly-owned and consolidated subsidiaries that are treated as partnerships for U.S. federal income tax purposes. We are responding to information requests from the IRS with respect to these audits. We do not expect there to be any audit adjustments that would materially change our taxable income.
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, it has substantially reduced our current cash taxes.
23
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 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.
Note 15 — Supplemental Cash Flow Information
Cash:
Interest paid, net of capitalized interest (1)
384.0
340.9
Income taxes paid, net of refunds
Non-cash investing activities:
Impact of net accruals on capital expenditures
48.8
(173.5
Change in ARO liability and property, plant and equipment, net due to additions and revised cash flow estimates
11.5
Non-cash financing activities:
Changes in accrued distributions to noncontrolling interests
(13.2
Changes in lease liabilities from recognition (derecognition) of right-of-use assets:
Operating lease
(9.7
Finance lease
17.0
12.7
Note 16 — Segment Information
We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.
Our Gathering and Processing segment includes assets used in the gathering and/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. The Gathering and Processing segment’s assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast.
Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exporters and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes our NGL pipeline system, which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. Our Downstream facilities are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.
Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.
24
The following tables show reportable segment information for the periods presented:
Gathering and Processing
Logistics and Transportation
Total Reportable Segments
CorporateandEliminations
285.6
3,169.3
3,454.9
(110.3
574.5
175.6
860.1
3,344.9
4,205.0
Intersegment revenues
918.3
57.1
975.4
(975.4
(0.9
8.3
(8.3
917.4
66.3
983.7
(983.7
1,777.5
3,411.2
5,188.7
233.6
100.2
333.8
Other segment items (1)
840.4
2,537.7
3,378.1
Operating margin
703.5
773.3
1,476.8
Other financial information:
Total assets (2)
16,468.3
10,381.3
26,849.6
257.6
Goodwill
118.9
Capital expenditures
581.8
358.7
940.5
948.3
Three Months Ended March 31, 2025
200.7
3,932.5
4,133.2
(248.8
475.1
202.0
675.8
4,134.5
4,810.3
1,517.0
59.4
1,576.4
(1,576.4
7.1
7.3
(7.3
1,517.2
66.5
1,583.7
(1,583.7
2,193.0
4,201.0
6,394.0
208.2
95.5
303.7
1,382.6
3,458.8
4,841.4
602.2
646.7
1,248.9
13,727.9
8,821.1
22,549.0
251.3
22,800.3
45.2
433.2
174.7
607.9
10.4
618.3
25
The following table shows our consolidated revenues disaggregated by product and service for the periods presented:
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas
473.7
681.9
2,982.8
3,376.8
Condensate and crude oil
131.8
117.0
3,588.3
4,175.7
Non-customer revenue:
Derivative activities - Hedge
Derivative activities - Non-hedge (1)
(243.7
(291.3
Total sales of commodities
Fees from midstream services:
Gathering and processing
559.7
469.0
NGL transportation, fractionation and services
68.5
73.2
Storage, terminaling and export
123.1
135.4
(1.2
Total fees from midstream services
The following table shows a reconciliation of reportable segment Operating margin to Income (loss) before income taxes for the periods presented:
Reconciliation of reportable segment operatingmargin to income (loss) before income taxes:
Total reportable segments operating margin
Other operating margin
(426.0
(367.6
(107.8
(94.5
Other operating income (expense)
14.2
5.3
26
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
We are engaged primarily in the business of:
To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as our Downstream Business).
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:
Fractionation Expansions
Our new 150 MBbl/d fractionation train additions include:
NGL Pipeline Expansions
LPG Export Expansion
Natural Gas Pipelines
28
Acquisitions and Joint Ventures
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.
29
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).
30
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.
31
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:
Logistics and Transportation adjusted operating margin consists primarily of:
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:
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.
32
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:
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Adjusted Cash Flow from Operations and Adjusted Free Cash Flow
Interest (income) expense, net
227.6
197.1
Income tax expense (benefit)
72.2
(Gain) loss on sale or disposition of assets
(1.0
Write-down of assets
4.3
2.0
(Gain) loss from financing activities
10.1
0.6
Equity (earnings) loss
Distributions from unconsolidated affiliates
Change in contingent consideration
Noncontrolling interests adjustments (1)
3.2
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
Consolidated Results of Operations
The following table and discussion is a summary of our consolidated results of operations for the periods presented:
2026 vs. 2025
(539.8
(14
%)
73.0
%
(466.8
(10
(863.3
(26
30.1
58.4
13.3
(8.9
168
56
(30.5
3.1
(16.9
NM
(51.7
72
207.6
74
(1.5
(16
209.1
77
(100
279.6
140
Financial data:
Adjusted EBITDA (1)
224.2
Adjusted cash flow from operations (1)
209.9
Adjusted free cash flow (1)
(100.3
(31
33
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:
Three Months Ended:
March 31, 2025
34
(In millions, except operating statistics and price amounts)
101.3
25.4
Adjusted operating margin
937.1
810.4
126.7
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2) (3)
Permian Midland (4)
3,153.9
2,985.6
168.3
Permian Delaware
3,576.1
3,020.3
555.8
Total Permian
6,730.0
6,005.9
724.1
Central (5)
1,027.3
984.7
42.6
Badlands (5) (6)
127.0
136.9
(9.9
(7
Coastal
547.1
398.8
148.3
37
8,431.4
7,526.3
905.1
NGL production, MBbl/d (3)
464.7
429.5
35.2
469.6
366.4
103.2
934.3
795.9
138.4
102.1
98.1
Badlands (5)
16.2
16.4
(1
37.8
32.7
5.1
1,090.4
943.1
147.3
Crude oil gathered, MBbl/d
135.1
136.1
Natural gas sales, BBtu/d (3)
3,040.3
2,592.8
447.5
NGL sales, MBbl/d (3)
625.9
570.2
55.7
Condensate sales, MBbl/d
21.8
18.1
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
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:
(In millions, except volumetric data and price amounts)
Volume Settled
Price Spread (1)
Gain (Loss)
Natural gas (BBtu)
8.4
2.02
0.96
7.4
NGL (MMgal)
67.7
0.01
97.5
(0.07
(6.6
Crude oil (MBbl)
(4.14
(2.9
15.0
35
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.
(In millions, except operating statistics)
126.6
873.5
742.2
131.3
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)
1,016.8
843.5
173.3
Fractionation volumes
1,145.2
979.9
165.3
Export volumes (3)
437.0
447.7
(10.7
(2
NGL sales
1,304.0
1,186.4
117.6
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.
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.”
36
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
Cash on hand (1)
Total availability under the Securitization Facility
Total availability under the TRGP Revolver and Commercial Paper Program
3,500.0
4,200.1
Outstanding borrowings under the Securitization Facility
Outstanding borrowings under the TRGP Revolver and Commercial Paper Program
(457.0
Outstanding letters of credit under the TRGP Revolver
Total liquidity
3,125.2
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 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.”
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
(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.
38
Cash Flows from Investing Activities
(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
Source of Financing Activities, net
Debt, including financing costs
2,009.5
Contributions from (distributions to) noncontrolling interests, net
Repurchases of shares
(88.6
(171.4
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.
39
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
Current assets
92.9
160.3
Current assets - affiliates
6.5
Long-term assets
74.5
73.3
170.6
240.1
LIABILITIES AND OWNERS’ EQUITY (DEFICIT)
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)
Summarized Combined Statement of Operations Information
Year EndedDecember 31, 2025
Operating income (loss)
(95.2
(357.1
(150.6
(603.6
The following table details the dividends on common stock declared and/or paid by us for the three months ended March 31, 2026:
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.
The following table details cash outlays for capital projects for the periods presented:
Capital expenditures:
Growth (1)
910.4
570.7
Maintenance (2)
37.9
47.6
Gross capital expenditures
Change in capital project payables and accruals, net
(48.8
173.9
Cash outlays for capital projects
899.5
792.2
The increase in growth capital expenditures was primarily due to higher construction activities during 2026.
40
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:
Result of 10% Price Decrease
Result of 10% Price Increase
(160.7
(309.1
(67.0
(141.8
Crude oil
(39.9
(73.2
(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.
42
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.
43
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.
PART II – OTHER INFORMATION
Item 1. Legal Proceedings.
The information required for this item is provided in “Note 12 – Contingencies,” under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.
Item 1A. Risk Factors.
For an in-depth discussion of our risk factors, see “Part I—Item 1A. Risk Factors” of our Annual Report. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Recent Sales of Unregistered Equity Securities.
None.
Repurchase of Equity by Targa Resources Corp., or Affiliated Purchasers.
Period
Total number of shares purchased (1)
Average price per share
Total number of shares purchased as part of publicly announced plans (2)
Maximum approximate dollar value of shares that may yet be purchased under the plans (in thousands) (2)
January 1, 2026 - January 31, 2026
176,584
185.35
1,373,581
February 1, 2026 - February 28, 2026
25,775
232.77
1,367,582
March 1, 2026 - March 31, 2026
205,595
242.42
202,026
1,318,583
Item 3. Defaults Upon Senior Securities.
Not applicable.
Item 4. Mine Safety Disclosures.
Item 5. Other Information.
Rule 10b-5 Trading Plans.
During the three months ended March 31, 2026, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.
Item 6. Exhibits.
Number
Description
Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).
Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed May 26, 2021 (File No. 001-34991)).
Certificate of Designations of Series A Preferred Stock of Targa Resources Corp., filed with the Secretary of State of the State of Delaware on March 16, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K/A filed March 17, 2016 (File No. 001-34991)).
3.4
Third Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 12, 2023 (File No. 001-34991)).
4.1
Thirteenth Supplemental Indenture, dated as of March 2, 2026, among Targa Resources Corp., as issuer, the guarantors named therein and U.S. Bank Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Targa Resources Corp.’s Current Report on Form 8-K filed March 2, 2026 (File No. 001-34991)).
4.2
Form of Notes (included in Exhibit 4.1 hereto) (incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Current Report on Form 8-K filed March 2, 2026 (File No. 001-34991)).
22.1*
List of Subsidiary Guarantors.
31.1*
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
32.1**
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS
Inline XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document
101.SCH
Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Documents
104
The cover page from this Quarterly Report on Form 10-Q for the quarter ended March 31, 2026, formatted in Inline XBRL (included with Exhibit 101 attachments).
* Filed herewith
** Furnished herewith
+ Management contract or compensatory plan or arrangement
46
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Targa Resources Corp.
(Registrant)
Date: May 7, 2026
By:
/s/ William A. Byers
William A. Byers
Chief Financial Officer
(Principal Financial Officer)