Targa Resources (TRGP) 10-K 22 Feb 23 2021 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Feb. 17, 2023	Jun. 30, 2022
Cover [Abstract]
Entity Registrant Name	TARGA RESOURCES CORP.
Trading Symbol	TRGP
Entity Central Index Key	0001389170
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		226,639,398
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2022
Entity Small Business	false
Entity Shell Company	false
Entity Emerging Growth Company	false
Entity Current Reporting Status	Yes
Entity Tax Identification Number	20-3701075
Entity File Number	001-34991
Entity Address, Address Line One	811 Louisiana Street
Entity Address, Address Line Two	Suite 2100
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	584-1000
Entity Interactive Data Current	Yes
Title of 12(b) Security	Common Stock
Security Exchange Name	NYSE
Entity Incorporation, State or Country Code	DE
Document Annual Report	true
Document Transition Report	false
Entity Well-known Seasoned Issuer	Yes
Entity Public Float			$ 13,379.6
Entity Voluntary Filers	No
ICFR Auditor Attestation Flag	true
Auditor Firm ID	238
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Houston, Texas
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant’s definitive proxy statement for the 2023 Annual Meeting of Stockholders, to be filed no later than 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates, are incorporated by reference into Part III of this Annual Report on Form 10-K.

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 219	$ 158.5
Trade receivables, net of allowances of $2.2 million and $0.1 million at December 31, 2022 and December 31, 2021	1,408.4	1,331.9
Inventories	393.8	153.4
Assets from risk management activities	179.9	43.1
Other current assets	155.5	82.9
Total current assets	2,356.6	1,769.8
Property, plant and equipment, net	14,214.6	11,667.7
Intangible assets, net	2,734.6	1,094.8
Long-term assets from risk management activities	24.5	7.7
Investments in unconsolidated affiliates	131.3	586.5
Other long-term assets	98.4	81.7
Total assets	19,560	15,208.2
Current liabilities:
Accounts payable	1,448.8	1,402.3
Accrued liabilities	273.3	272.2
Distributions payable	16.2	64.5
Interest payable	174	138.5
Liabilities from risk management activities	320.1	258.2
Current debt obligations	834.3	162.8
Total current liabilities	3,066.7	2,298.5
Long-term debt	10,702.1	6,434.4
Long-term liabilities from risk management activities	140.1	109.3
Deferred income taxes, net	327.7	136
Other long-term liabilities	341.2	301.6
Commitments and Contingencies (see Notes 17 and 18)
Targa Resources Corp. stockholders' equity:
Common stock ($0.001 par value, 450,000,000 shares authorized as of December 31, 2022 and December 31, 2021)	0.2	0.2
Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, zero shares issued and outstanding)	0	0
Additional paid-in capital	3,702.3	4,268.9
Retained earnings (deficit)	(626.8)	(1,822.3)
Accumulated other comprehensive income (loss)	54.7	(230.9)
Treasury stock, at cost (11,896,829 shares as of December 31, 2022 and 7,884,171 shares as of December 31, 2021)	(464.7)	(204.1)
Total Targa Resources Corp. stockholders' equity	2,665.7	2,011.8
Noncontrolling interests	2,316.5	3,166.9
Total owners' equity	4,982.2	5,178.7
Total liabilities, Series A Preferred Stock and owners' equity	19,560	15,208.2
Series A Preferred Stock
Current liabilities:
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference (1,200,000 shares authorized, zero and 919,300 shares issued and outstanding as of December 31, 2022 and December 31, 2021), net of discount (see Note 11)	$ 0	$ 749.7

CONSOLIDATED BALANCE SHEETS (_2

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Trade receivables, allowances	$ 2.2	$ 0.1
Targa Resources Corp. stockholders' equity:
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	237,939,058	236,105,293
Common stock, shares outstanding (in shares)	226,042,229	228,221,122
Preferred stock, par value (in dollar per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized (in shares)	98,800,000	98,800,000
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Treasury stock, shares (in shares)	11,896,829	7,884,171
Series A Preferred Stock
LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Preferred Series A Liquidation Stock Percentage	9.50%	9.50%
Preferred Stock, Liquidation Preference Per Share	$ 1,000	$ 1,000
Preferred Stock, Shares Authorized	1,200,000	1,200,000
Preferred Stock, Shares Issued	0	919,300
Preferred Stock, Shares Outstanding	0	919,300

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Total revenues		$ 20,929.8	$ 16,949.8	$ 8,260.3
Costs and expenses:
Product purchases and fuel		16,882.1	13,729.5	5,186.5
Operating expenses		912.8	747	698.4
Depreciation and amortization expense		1,096	870.6	865.1
General and administrative expense		309.7	273.2	254.6
Impairment of long-lived assets			452.3	2,442.8
Other operating (income) expense		0.2	12.4	116.6
Income (loss) from operations		1,729	864.8	(1,303.7)
Other income (expense):
Interest expense, net		(446.1)	(387.9)	(391.3)
Equity earnings (loss)		9.1	(23.9)	72.6
Gain (loss) from financing activities		(49.6)	(16.6)	45.6
Gain (loss) from sale of equity-method investment		435.9
Other, net		(15.1)	0.5	3.7
Income (loss) before income taxes		1,663.2	436.9	(1,573.1)
Income tax (expense) benefit		(131.8)	(14.8)	248.1
Net income (loss)		1,531.4	422.1	(1,325)
Less: Net income (loss) attributable to noncontrolling interests		335.9	350.9	228.9
Net income (loss) attributable to Targa Resources Corp.		1,195.5	71.2	(1,553.9)
Premium on repurchase of noncontrolling interests, net of tax	[1]	53.2
Dividends on Series A Preferred Stock		30	87.3	91.7
Deemed dividends on Series A Preferred Stock		215.5		39.2
Net income (loss) attributable to common shareholders		$ 896.8	$ (16.1)	$ (1,684.8)
Net income (loss) per common share - basic		$ 3.95	$ (0.07)	$ (7.26)
Net income (loss) per common share - diluted		$ 3.88	$ (0.07)	$ (7.26)
Weighted average shares outstanding - basic		227.3	228.6	232.2
Weighted average shares outstanding - diluted		231.1	228.6	232.2
Sales of Commodities [Member]
Revenues:
Total revenues		$ 19,066	$ 15,602.5	$ 7,171
Fees from Midstream Services [Member]
Revenues:
Total revenues		$ 1,863.8	$ 1,347.3	$ 1,089.3
[1] Represents premium paid on the DevCo JV Repurchase. See Note 4 – Acquisitions and Divestitures.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Net income (loss)	$ 1,531.4	$ 422.1	$ (1,325)
Commodity hedging contracts:
Other comprehensive income (loss), pre-tax	367.4	(117.3)	(309.1)
Other comprehensive income (loss), related income tax	(81.8)	28.2	74.8
Other comprehensive income (loss), after tax	285.6	(89.1)	(234.3)
Comprehensive income (loss)	1,817	333	(1,559.3)
Less: Comprehensive income (loss) attributable to noncontrolling interests	335.9	350.9	228.9
Comprehensive income (loss) attributable to Targa Resources Corp.	1,481.1	(17.9)	(1,788.2)
Commodity Contracts [Member]
Commodity hedging contracts:
Change in fair value, pre-tax	(5.6)	(534.6)	(218.3)
Change in fair value, related income tax	1.3	128.4	51.5
Change in fair value, after tax	(4.3)	(406.2)	(166.8)
Settlements reclassified to revenues, pre-tax	373	417.3	(90.8)
Settlements reclassified to revenues, related income tax	(83.1)	(100.2)	23.3
Settlements reclassified to revenues, after tax	$ 289.9	$ 317.1	$ (67.5)

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK - USD ($) $ in Millions	Total	Cumulative Effect, Period of Adoption, Adjustment [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member] Cumulative Effect, Period of Adoption, Adjustment [Member]	Retained Earnings (Accumulated Deficit) [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Shares [Member]	Noncontrolling Interests [Member]	Series A Preferred Stock	Series A Preferred Stock Cumulative Effect, Period of Adoption, Adjustment [Member]
Balance at Dec. 31, 2019	$ 8,442.9		$ 0.2	$ 5,221.2		$ (339.6)	$ 92.5	$ (53.5)	$ 3,522.1
Balance (in shares) at Dec. 31, 2019			232,844,000					1,010,000
Series A Preferred Stock at Dec. 31, 2019										$ 278.8
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	66.2			66.2
Distribution equivalent rights	(5.4)			(5.4)
Shares issued under compensation program (in shares)			939,000
Shares tendered for tax withholding obligations	(5.9)							$ (5.9)
Shares tendered for tax withholding obligations (in shares)			(235,000)					235,000
Repurchases of common stock	(91.5)							$ (91.5)
Repurchases of common stock (in shares)			(5,486,000)					5,486,000
Series A Preferred Stock dividends
Preferred stock dividends	(91.7)					(91.7)
Dividends in excess of retained earnings				(91.7)		91.7
Deemed dividends - accretion of beneficial conversion feature	(37.6)
Deemed dividends - accretion of beneficial conversion feature / partial repurchase of Series A Preferred Stock	(39.2)			(39.2)						37.6
Common stock dividends
Common stock dividends	(282)					(282)
Dividends in excess of retained earnings				(282)		282
Partial repurchase of Series A Preferred Stock	(29.2)			(29.2)						(15)
Distributions to noncontrolling interests	(570.7)								(570.7)
Contributions from noncontrolling interests	41.5								41.5
Non-cash allocation to noncontrolling interests	27.5								27.5
Other comprehensive income (loss)	(234.3)						(234.3)
Net income (loss)	(1,325)					(1,553.9)			228.9
Balance at Dec. 31, 2020	5,903.2	$ (448.3)	$ 0.2	4,839.9	$ (448.3)	(1,893.5)	(141.8)	$ (150.9)	3,249.3
Balance (in shares) at Dec. 31, 2020			228,062,000					6,731,000
Series A Preferred Stock at Dec. 31, 2020										301.4	$ 448.3
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	59.2			59.2
Distribution equivalent rights	(3.1)			(3.1)
Shares issued under compensation program (in shares)			1,312,000
Shares tendered for tax withholding obligations	(13.2)							$ (13.2)
Shares tendered for tax withholding obligations (in shares)			(397,000)					397,000
Repurchases of common stock	$ (40)							$ (40)
Repurchases of common stock (in shares)	(756,478)		(756,000)					756,000
Series A Preferred Stock dividends
Preferred stock dividends	$ (87.3)					(87.3)
Dividends in excess of retained earnings				(87.3)		87.3
Common stock dividends
Common stock dividends	(91.5)					(91.5)
Dividends in excess of retained earnings				(91.5)		91.5
Distributions to noncontrolling interests	(449.1)								(449.1)
Contributions from noncontrolling interests	15.8								15.8
Other comprehensive income (loss)	(89.1)						(89.1)
Net income (loss)	422.1					71.2			350.9
Balance at Dec. 31, 2021	5,178.7		$ 0.2	4,268.9		(1,822.3)	(230.9)	$ (204.1)	3,166.9
Balance (in shares) at Dec. 31, 2021			228,221,000					7,884,000
Series A Preferred Stock at Dec. 31, 2021										749.7
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Compensation on equity grants	57.5			57.5
Distribution equivalent rights	(7.1)			(7.1)
Shares issued under compensation program (in shares)			1,834,000
Shares tendered for tax withholding obligations	(35.8)							$ (35.8)
Shares tendered for tax withholding obligations (in shares)			(601,000)					601,000
Repurchases of common stock	$ (224.8)							$ (224.8)
Repurchases of common stock (in shares)	(3,412,354)		(3,412,000)					3,412,000
Series A Preferred Stock dividends
Preferred stock dividends	$ (30)					(30)
Dividends in excess of retained earnings				(30)		30
Deemed dividends - accretion of beneficial conversion feature	(215.5)			(215.5)
Common stock dividends
Common stock dividends	(318.3)					(318.3)
Dividends in excess of retained earnings				(318.3)		318.3
Redemption of Series A preferred Stock	(749.7)
Distributions to noncontrolling interests	(354.5)								(354.5)
Contributions from noncontrolling interests	26.1								26.1
Repurchase of noncontrolling interests, net of tax	(911.1)			(53.2)					(857.9)
Other comprehensive income (loss)	285.6						285.6
Net income (loss)	1,531.4					1,195.5			335.9
Balance at Dec. 31, 2022	$ 4,982.2		$ 0.2	$ 3,702.3		$ (626.8)	$ 54.7	$ (464.7)	$ 2,316.5
Balance (in shares) at Dec. 31, 2022			226,042,000					11,897,000
Series A Preferred Stock at Dec. 31, 2022										$ 0

CONSOLIDATED STATEMENTS OF CH_2

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Stockholders' Equity [Abstract]
Preferred stock dividends, per share	$ 47.50	$ 95	$ 95
Common stock dividends, per share	$ 1.40	$ 0.40	$ 1.21

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities
Net income (loss)		$ 1,531.4	$ 422.1	$ (1,325)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		10.5	10.3	11.1
Compensation on equity grants		57.5	59.2	66.2
Depreciation and amortization expense		1,096	870.6	865.1
Impairment of long-lived assets			452.3	2,442.8
(Gain) loss on sale or disposition of assets	[1]	(9.6)	2	58.4
Write-downs of assets	[2]	9.8	10.3	55.6
Accretion of asset retirement obligations		4.8	4	3.6
Deferred income tax expense (benefit)		125.1	12.1	(232.7)
Equity (earnings) loss of unconsolidated affiliates		(9.1)	23.9	(72.6)
Distributions of earnings received from unconsolidated affiliates		12.2	84	86.8
Risk management activities		302.5	116	(228.2)
(Gain) loss from financing activities		49.6	16.6	(45.6)
(Gain) loss from sale of equity-method investment		(435.9)
Change in contingent considerations			0.1	(0.3)
Changes in operating assets and liabilities, net of acquisitions:
Receivables and other assets		219.7	(392.4)	(25.6)
Inventories		(236.2)	40.6	(27.7)
Accounts payable, accrued liabilities and other liabilities		(383)	565.3	105.7
Interest payable		35.5	5.9	6.9
Net cash provided by operating activities		2,380.8	2,302.9	1,744.5
Cash flows from investing activities
Outlays for property, plant and equipment		(1,334.3)	(505.1)	(951.6)
Outlays for business acquisition, net of cash acquired		(3,503.9)
Outlays for asset acquisition, net of cash acquired		(205.2)
Proceeds from sale of assets		23	12.2	198.7
Investments in unconsolidated affiliates		(1.5)	(0.6)	(2.7)
Proceeds from sale of equity-method investment		857
Return of capital from unconsolidated affiliates		16.8	20.2	13.2
Other, net		(1.6)	0.1	4.3
Net cash provided by (used in) investing activities		(4,149.7)	(473.2)	(738.1)
Debt obligations:
Proceeds from borrowings under credit facilities		5,845	620	2,195
Repayments of credit facilities		(5,555)	(1,455)	(1,795)
Proceeds from borrowings of commercial paper notes		30,504.3
Repayments of commercial paper notes		(29,495.6)
Proceeds from borrowings under term loan facility		1,500
Proceeds from borrowings under accounts receivable securitization facility		1,230	630	576.4
Repayments of accounts receivable securitization facility		(580)	(830)	(596.4)
Proceeds from issuance of senior notes		2,741.4	1,000	1,000
Redemption of senior notes		(1,473.2)	(1,132)	(1,390.6)
Principal payments of finance leases		(19.7)	(12.5)	(12.4)
Costs incurred in connection with financing arrangements		(45.7)	(9.6)	(9.9)
Repurchase of shares		(260.6)	(53.2)	(97.4)
Contributions from noncontrolling interests		26.1	15.8	41.5
Redemption of Preferred Units				(125)
Distributions to noncontrolling interests		(316.4)	(500)	(439.2)
Repurchase of noncontrolling interests		(926.3)
Redemption of Series A Preferred Stock		(965.2)
Partial repurchase of Series A Preferred Stock				(45.8)
Distributions to Partnership unitholders				(11.7)
Dividends paid to common and Series A Preferred shareholders		(379.7)	(187.5)	(384.2)
Net cash provided by (used in) financing activities		1,829.4	(1,914)	(1,094.7)
Net change in cash and cash equivalents		60.5	(84.3)	(88.3)
Cash and cash equivalents, beginning of period		158.5	242.8	331.1
Cash and cash equivalents, end of period		$ 219	$ 158.5	$ 242.8
[1] Primarily related to the sale of assets in Channelview, Texas in 2020. See Note 4 – Acquisitions and Divestitures for further discussion regarding these sales. Related to the write-down of certain assets to their recoverable amounts.

Organization and Operations

Organization and Operations	12 Months Ended
	Dec. 31, 2022
Organization [Abstract]
Organization and Operations	Note 1 — Organizati on and Operations Our Organization Targa Resources Corp. (NYSE: TRGP) owns, operates, acquires, and develops a diversified portfolio of complementary domestic midstream infrastructure assets. In this Annual 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 consolidated the Partnership and its subsidiaries under GAAP, and prepared accompanying consolidated financial statements 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: • the inclusion of the TRGP senior revolving credit facility and term loan facility; • the inclusion of the TRGP senior notes; • the inclusion of the TRGP commercial paper notes; • the inclusion of Series A Preferred Stock (“Series A Preferred”) prior to full redemption in May 2022; and • the impacts of TRGP’s treatment as a corporation for U.S. federal income tax purposes. Our Operations The Company is primarily engaged in the business of: • gathering, compressing, treating, processing, transporting, and purchasing and selling natural gas; • transporting, storing, fractionating, treating, and purchasing and selling NGLs and NGL products, including services to LPG exporters; and • gathering, storing, terminaling, and purchasing and selling crude oil. See Note 24 – Segment Information for certain financial information regarding our business segments.

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Note 2 — Basis of Presentation These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2022 and 2021, and the results of operations, comprehensive income (loss), cash flows, and changes in owners’ equity for the years ended December 31, 2022, 2021 and 2020 . We have prepared these consolidated financial statements in accordance with GAAP. 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.

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Significant Accounting Policies	Note 3 — Significant Accounting Policies Consolidation Policy Our consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain gas gathering and processing facilities in which we own an undivided interest and are responsible for our proportionate share of the costs and expenses of the facilities. Third party ownership interests in our controlled subsidiaries are presented as noncontrolling interests within the equity section of our Consolidated Balance Sheets, except in the case of undivided interest ownership. In our Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income (Loss), noncontrolling interests reflect the attribution of results to third-party investors. All intercompany balances and transactions have been eliminated in consolidation. As of December 31, 2022, our consolidated joint ventures include the following: Gathering and Processing Segment • 50 % ownership interest in the Carnero G&P LLC; • 60 % ownership interest in Centrahoma Processing LLC; • 55 % ownership interest in Targa Badlands LLC; • 72.8 % undivided interest in the assets of Targa Pipeline Mid-Continent WestTex LLC; and • 76.8 % ownership interest in Venice Energy Services Company, LLC. Logistics and Transportation Segment • 88 % ownership interest in Cedar Bayou Fractionators, L.P.; • 75 % ownership interest in Grand Prix Pipeline LLC through the Grand Prix Joint Venture (prior to the Grand Prix Transaction, as defined in Note 4 – Acquisitions and Divestitures); and • 80 % ownership interest in Targa Train 7 LLC. We apply the equity method of accounting to investments over which we exercise significant influence over the operating and financial policies of our investee, but do not exercise control. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as a non-cash pre-tax impairment loss within Equity earnings (loss) in our Consolidated Statements of Operations. As of December 31, 2022, our investments in unconsolidated affiliates include the following: Gathering and Processing Segment • 50 % ownership interest in Little Missouri 4 LLC (“Little Missouri 4”). Logistics and Transportation Segment • 50 % ownership interest in Cayenne Pipeline, LLC (“Cayenne”); and • 38.8 % ownership interest in Gulf Coast Fractionators (“GCF”). Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Estimates and judgments are based on information available at the time such estimates and judgments are made. Changes in facts and circumstances may result in revised estimates and actual results could differ materially from those estimates. Estimates and judgments are used in, among other things, (i) estimating unbilled revenues, product purchases and operating and general and administrative cost accruals, (ii) developing fair value assumptions, including estimates of future cash flows and discount rates, (iii) analyzing long-lived assets for possible impairment, (iv) estimating the useful lives of assets, (v) estimating contingencies, guarantees and indemnifications and (vi) estimating redemption value of mandatorily redeemable preferred interests. Cash and Cash Equivalents Cash and cash equivalents include all cash on hand, demand deposits, and short-term, highly liquid investments that are readily convertible into cash, and have original maturities of three months or less. Allowance for Doubtful Accounts Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. We estimate the allowance for doubtful accounts through various procedures, including extensive review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts. We continuously evaluate our ability to collect amounts owed to us. Receivables are considered past due if full payment is not received by the contractual due date. Our evaluation procedures also include performing account reconciliations, dispute resolution and payment confirmation. As the financial condition of any counterparty changes, circumstances develop or additional information becomes available, adjustments to our allowance may be required. Inventories Our inventories consist primarily of NGL product inventories, which are valued at the lower of cost or net realizable value, using the average cost method. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are included in Property, plant and equipment. Product Exchanges Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities. Gas Processing Imbalances Quantities of natural gas and/or NGLs over-delivered or under-delivered, related to certain gas plant operational balancing agreements, are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or net realizable value using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs. Derivative Instruments We utilize derivative instruments to manage the volatility of our cash flows due to fluctuating energy commodity prices. For balance sheet classification purposes, we analyze the fair values of the derivative instruments on a contract by contract basis and report the related fair values and any related collateral by counterparty on a gross basis. Cash flows from derivative instruments designated as hedges are recognized in the same financial statement line item as the cash flows from the respective item being hedged. We formally document all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in achieving the offset of changes in cash flows attributable to the hedged risk. We record all derivative instruments at fair value with the exception of those that we apply the normal purchases and normal sales election. The table below summarizes the accounting treatment for our derivative instruments, and the impact on our consolidated financial statements: Recognition and Measurement Derivative Treatment Balance Sheet Income Statement Normal Purchases and Normal Sales Fair value not recorded Earnings recognized when volumes are physically delivered or received Mark-to-Market Recorded at fair value Change in fair value recognized currently in earnings Cash Flow Hedge Recorded at fair value with changes in fair value deferred in Accumulated Other Comprehensive Income ("AOCI") The gain/loss on the derivative instrument is reclassified out of AOCI into earnings when the forecasted transaction occurs We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated, ceases to be highly effective or the forecasted transaction is no longer probable to occur. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately. Property, Plant and Equipment Property, plant and equipment is recorded at acquisition cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including our expected use of the asset and the supply of, and demand for, hydrocarbons in the markets served, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations. Expenditures for routine maintenance and repairs are expensed as incurred. Expenditures to refurbish an asset that increases its existing service potential or prevents environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. Certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs, are capitalized. Impairment of Long-Lived Assets We evaluate long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate our carrying amount of an asset may not be recoverable, including changes to our estimates that could have an impact on our assessment of asset recoverability. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. These cash flow estimates require us to make judgments and assumptions related to operating and cash flow results, economic obsolescence, the business climate, contractual, legal and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize a non-cash pre-tax impairment loss equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs, and the use of an appropriate terminal value and discount rate. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our long-lived assets and the recognition of additional impairments. We believe our estimates and models used to determine fair value are similar to what a market participant would use. Goodwill Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not subject to amortization but is tested for impairment at least annually. This test requires us to attribute goodwill to an appropriate reporting unit, which is an operating segment or one level below an operating segment (also known as a component). We evaluate goodwill for impairment on November 30 of each year, or whenever impairment indicators are present. Prior to us conducting the goodwill impairment test, we complete a review of the carrying values of our long-lived assets, including property, plant and equipment and other intangible assets. If it is determined that the carrying values are not recoverable, we reduce the carrying values of the long-lived assets pursuant to our policy on property, plant and equipment. As part of our goodwill impairment test, we may first assess qualitative factors to determine if the quantitative goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or determine that a goodwill impairment test is required, our annual goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount (including attributed goodwill). We recognize an impairment loss in our Consolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment loss will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, when measuring goodwill, we consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit, if applicable. Intangible Assets Our intangible assets include producer dedications under long-term contracts and customer relationships associated with business and asset acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. We amortize the costs of our assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis, where such pattern is not readily determinable, over the periods in which we benefit from services provided to customers. Asset Retirement Obligations Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. We record a liability and increase the basis in the underlying asset for the present value of each expected ARO when there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction. Our obligations are estimated based on discounted cash flow (“DCF”) estimates. Over time, the ARO liability is accreted to its present value as a period cost and the capitalized amount is depreciated over the asset’s respective useful life. At least annually, we review the projected timing and amount of AROs and reflect revisions as an increase or decrease in the carrying amount of the liability and the basis in the underlying asset. Upon settlement, we will recognize any difference between the recorded amount and the actual settlement cost as a gain or loss. Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt and any original issue discount or premium are deferred and charged to interest expense over the term of the related debt. Debt issuance costs related to revolving credit facilities and commercial paper notes are presented as other long-term assets, and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction to the carrying amount of long-term debt on the Consolidated Balance Sheets. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issuance costs. Accounts Receivable Securitization Facility Proceeds from the sale or contribution of certain receivables under the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities in our Consolidated Statements of Cash Flows. Environmental Liabilities and Other Loss Contingencies We accrue a liability for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources, when the loss is probable and reasonably estimable. Income Taxes We file many income tax returns with the United States Department of the Treasury, as well as numerous states. We are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense, together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are reported on a net basis by jurisdiction within our Consolidated Balance Sheets. We report these timing differences based on statutory tax rates applicable to the scheduled timing difference reversal periods. We assess the likelihood that we will recover our deferred tax assets from future taxable income. We establish a valuation allowance if we believe that it is more likely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax assets will not be realized. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence to determine whether, based on the weight of the evidence, we need a valuation allowance. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies. Dividends Preferred and common dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital. Mandatorily Redeemable Preferred Interests Mandatorily redeemable preferred interests, which represent our joint venture partners’ interests in two joint ventures, have been included in other long-term liabilities on our Consolidated Balance Sheets, and such interests with multiple or indeterminate redemption dates were reported at their estimated redemption value as of the reporting dates. These point-in-time values did not represent the amount that ultimately would be redeemed in the future. Changes in the redemption value have been included in interest expense, net in our Consolidated Statements of Operations. Effective September 1, 2022, we redeemed our joint venture partner's mandatorily redeemable preferred interests in the two joint ventures that, separately, owned a 100 % interest in the WestOK natural gas gathering and processing system and a 72.8 % undivided interest in the WestTX natural gas gathering and processing system. Prior to the redemption, the joint ventures collectively held $ 1.9 billion face value in notes receivable from our partner, which were due July 2042 . The interest rate payable under the notes receivable was a variable LIBOR-based rate. For the years ended December 31, 2022, 2021 and 2020, interest income (expense) on the notes receivable was $( 1.8 ) million, $ 12.3 million and $ 8.6 million, net of the return paid to our partner, which was reflected within Interest expense, net in our Consolidated Statements of Operations. Comprehensive Income Comprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as cash flow hedges . Revenue Recognition Our operating revenues are primarily derived from the following activities: • sales of natural gas, NGLs, condensate and crude oil; • services related to compressing, gathering, treating, and processing of natural gas; and • services related to NGL fractionation, terminaling and storage, transportation and treating. We have multiple types of contracts with commercial counterparties and many of these contracts contain embedded fees with settlement provisions that deduct these fees from the sales price paid by Targa in exchange for commodities. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606, Revenue from Contracts with Customers . Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases and fuel. Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues. We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis. Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price. Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract. The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation. Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days . As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue. We have certain long-term contractual arrangements under which we have received consideration, but for which all conditions for revenue recognition have not been met. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided. Contract Assets We classify our contract assets as receivables because we generally have an unconditional right to payment for the commodities sold or services performed at the end of the reporting period. Share-Based Compensation We award share-based compensation to employees and non-employee directors in the form of restricted stock, restricted stock units and performance share units. Compensation expense on our equity-classified awards is recorded at grant-date fair value. Compensation expense is recognized in general and administrative expense over the requisite service period of each award, and forfeitures are recognized as they occur. We may purchase a portion of the shares issued to satisfy employees’ tax withholding obligations on vested awards. These shares are recorded in treasury stock, at cost, and cash paid is classified as a financing activity in our Consolidated Statements of Cash Flows. All excess tax benefits and tax deficiencies related to share-based compensation are recognized as income tax benefit or expense in our Consolidated Statements of Operations, with the tax effects of exercised or vested awards treated as discrete items in the reporting period which they occur. Excess tax benefits are classified as an operating activity. Earnings per Share Basic earnings (loss) per common share (“EPS”) is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock, restricted stock units and performance share units. Diluted EPS includes any dilutive effect of preferred stock, unvested restricted stock, restricted stock units and performance share units. The dilutive effect is calculated through the application of (i) the if-converted method for convertible preferred stock, and (ii) the treasury stock method for unvested stock awards. Leases We recognize the following for all leases (with the exception of short-term leases) at the commencement date: • A lease liability, which is a lessee’s obligation to make lease payments arising from a lease. • A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered short-term leases, which are excluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of future lease payments over the lease term. The right-of-use asset also includes any lease prepayments and excludes lease incentives. As most of the Company’s leases do not provide an implicit interest rate, we use our incremental borrowing rate as the discount rate to compute the present value of our lease liability. The discount rate applied is determined based on information available on the date of adoption for all leases existing as of that date, and on the date of lease commencement for all subsequent leases. Our lease arrangements may include variable lease payments based on an index or market rate, or may be based on performance. For variable lease payments based on an index or market rate, we estimate and apply a rate based on information available at the commencement date. Variable lease payments based on performance are excluded from the calculation of the right-of-use asset and lease liability, and are recognized in our Consolidated Statements of Operations when the contingency underlying such variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options are included in the measurement of our right-of-use asset and liability, provided we determine that we are reasonably certain to exercise the option. Recent Accounting Pronouncements Recently Adopted Accounting Pronouncements Revenue Contract Assets and Liabilities Acquired in a Business Combination In October 2021, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. Amendments in this update require application of Accounting Standards Codification 606, Revenue from Contracts with Customers ("ASC 606") to recognize and measure contract assets and contract liabilities from contracts with customers acquired in a business combination. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2022, with early adoption permitted. However, an entity that elects to early adopt must apply the amendments to all business combinations that occurred during the fiscal year that includes the interim period. We early adopted the amendments on April 1, 2022 and have applied them to business combinations in 2022. We applied the amendments to the Delaware Basin Acquisition, as defined in Note 4 – Acquisitions and Divestitures, by recognizing co

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2021
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 4 – Acquisitions and Divestitures Acquisitions DevCo Joint Ventures In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix NGL Pipeline (“Grand Prix”), Gulf Coast Express Pipeline (“GCX”) and a 110 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). For a four-year period beginning on the date that all three projects commenced commercial operations, we had the option to acquire all or part of Stonepeak’s interests in the DevCo JVs (the “DevCo JV Call Right”). The purchase price payable for such partial or full interests was based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs. In January 2022, we exercised the DevCo JV Call Right and closed on the purchase of all of Stonepeak’s interests in the DevCo JVs for $ 926.3 million (the “DevCo JV Repurchase”). Following the DevCo JV Repurchase, we owned a 75 % interest in the Permian to Mont Belvieu segment of Grand Prix through Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”) (prior to the Grand Prix Transaction, as defined below), a 100 % interest in Train 6 and a 25 % equity interest in GCX (prior to the GCX Sale as defined below in February 2022). The changes in our ownership interests were accounted for as equity transactions representing the acquisitions of noncontrolling interests. The amount of the redemption price in excess of the carrying amount, net of tax was $ 53.2 million, which was accounted for as a premium on repurchase of noncontrolling interests, and resulted in a reduction to Net income (loss) attributable to common shareholders. In addition, the DevCo JV Repurchase resulted in an $ 857.9 million reduction of Noncontrolling interests on our Consolidated Balance Sheets. Subsequent Event On January 9, 2023, we completed the acquisition of Blackstone Energy Partners’ 25 % interest in Grand Prix Joint Venture (the “Grand Prix Transaction”) for aggregate consideration of $ 1.05 billion, subject to certain closing adjustments. Following the closing of the Grand Prix Transaction, we own 100 % of the interest in Grand Prix. South Texas Acquisition In April 2022, we completed the acquisition of Southcross Energy Operating LLC and its subsidiaries (“Southcross”) for a purchase price of $ 201.9 million (the “South Texas Acquisition”), subject to customary closing adjustments. We made a final net working capital adjustment payment of approximately $ 1.5 million in the fourth quarter of 2022. We acquired a portfolio of complementary midstream infrastructure assets and associated contracts that have been integrated into our SouthTX Gathering and Processing operations, including the remaining interests in the two joint ventures in South Texas that we previously held as investments in unconsolidated affiliates and that have been consolidated beginning in the second quarter of 2022. We accounted for the purchase as an asset acquisition and have capitalized $ 1.8 million of acquisition-related costs and assumed liabilities of $ 1.8 million as components of the cost of assets acquired. We allocated $ 28.1 million to our purchase of Southcross’ interest in the two joint ventures for purposes of consolidation and $ 169.7 million, $ 3.9 million and $ 5.3 million of the residual cost to property, plant and equipment, current assets and liabilities, net and other non-current assets, respectively. Delaware Basin Acquisition In July 2022, we completed the acquisition of all of the interests in Lucid Energy Delaware, LLC (“Lucid”) from Riverstone Holdings LLC and Goldman Sachs Asset Management for approximately $ 3.5 billion in cash (the “Delaware Basin Acquisition”), subject to customary closing adjustments. We received a final net working capital adjustment payment of approximately $ 11.4 million in the fourth quarter of 2022. We funded the acquisition with (i) $ 1.5 billion in proceeds drawn under our Term Loan Agreement with Mizuho Bank, Ltd. (“Mizuho”) as the Administrative Agent and a lender, and other lenders party thereto (the “Term Loan Facility”), (ii) $ 750.0 million in aggregate principal amount of our 5.200 % Senior Notes due 2027 (the “ 5.200 % Notes”) and $ 500.0 million in aggregate principal amount of our 6.250 % Senior Notes due 2052 (the “ 6.250 % Notes”) pursuant to an underwritten public offering that closed in July 2022 and (iii) $ 800.0 million drawn on our $ 2.75 billion TRGP revolving credit facility (the “TRGP Revolver”). We recorded $ 16.9 million of debt issuance costs related to the Term Loan Facility, the 5.200 % Notes and the 6.250 % Notes in our Consolidated Balance Sheets. See Note 8 – Debt Obligations for further details on our financing activities. The assets acquired in the Delaware Basin Acquisition provide natural gas gathering, treating, and processing services in the Delaware Basin, through owning and operating approximately 1,050 miles of natural gas pipelines and approximately 1.4 billion cubic feet per day (“Bcf/d”) of cryogenic natural gas processing capacity primarily in Eddy and Lea counties of New Mexico. The Delaware Basin Acquisition assets increase our footprint in the Delaware Basin and are integrated into our Permian Delaware operations. The Delaware Basin 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 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 15 – Fair Value Measurements. These inputs require judgments and estimates at the time of valuation. The following table summarizes the purchase price allocation based on the final fair values assigned to assets acquired and liabilities assumed (in millions): Cash and cash equivalents $ 9.9 Trade receivables, net of allowances (1) 211.0 Other current assets 3.5 Property, plant and equipment, net 1,669.0 Intangible assets, net 1,882.0 Other long-term assets 57.3 Current liabilities ( 236.7 ) Other long-term liabilities ( 100.7 ) Purchase price $ 3,495.3 (1) The fair value of the assets acquired includes trade receivables of $ 211.0 million. The gross amount due under contract was $ 213.4 million, of which $ 2.4 million was expected to be uncollectible. Trade receivables, net of allowances, excludes $ 18.5 million that was due from Targa. We reflected this settlement of a preexisting relationship as a reduction of the purchase price in accordance with ASC 805. The 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 value of intangible assets is comprised of customer relationships, which represent estimated value of long-term contracts with customers, that will be amortized in a manner that closely resembles the expected benefit pattern of the intangible assets over an estimated useful life of 14 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 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 fair values of the tangible and intangible assets are Level 3 measurements in the fair value hierarchy. The fair value of the intangible assets was determined by applying a discounted cash flow approach, which utilized a discount rate of approximately 19 % based on our estimate of the risk that a theoretical market participant would assign to the respective intangible assets, and customer attrition rates of approximately 5 %. The results of operations attributable to the assets and liabilities acquired in the Delaware Basin Acquisition have been included in our consolidated financial statements as part of our Permian Delaware operations in the Gathering and Processing segment since the date of the acquisition. Revenue and Net Income attributable to the assets acquired for the period August 1, 2022 through December 31, 2022 were $ 374.1 million and $ 7.9 million, respectively. As of December 31, 2022 , we had incurred $ 14.4 million of acquisition-related costs. Unaudited Pro Forma Financial Information The following unaudited pro forma summary presents the consolidated results of operations for the years ended December 31, 2022 and 2021 as if the Delaware Basin Acquisition had occurred on January 1, 2021. 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. Year Ended December 31, 2022 2021 Revenues $ 21,268.9 $ 17,464.7 Net income (loss) 1,477.4 215.7 The summarized unaudited pro forma information has been calculated after applying our accounting policies and reflects adjustments for the following: • Reflects depreciation and amortization based on the fair values of property, plant and equipment and intangible assets, respectively. Property, plant and equipment are depreciated utilizing a straight-line approach. Intangible assets are amortized in a manner that closely resembles their expected benefit pattern; • Excludes $ 14.4 million of acquisition-related costs incurred as of December 31, 2022 from pro forma net income for the year ended December 31, 2022. Pro forma net income for the year ended December 31, 2021 was adjusted to include those costs; • Excludes the impact of operations previously sold by Lucid, prior to Targa’s acquisition of Lucid; • Excludes the impact of historical activity between Targa and Lucid, prior to Targa’s acquisition of Lucid; • Excludes general and administrative expense related to Lucid’s former parent company, which Targa did not acquire; • Excludes amortization of interest expense and debt issuance costs associated with Lucid’s debt, which was not assumed by Targa; • Includes interest expense and debt issuance cost amortization associated with Targa’s borrowings to finance the Delaware Basin Acquisition; and • Reflects the income tax effects of the above pro forma adjustments. Divestitures Sale of Assets in Channelview, Texas In October 2020, we closed on the sale of our assets in Channelview, Texas for approximately $ 58 million. As a result of the sale, we recognized a loss of $ 58.3 million included within Other operating (income) expense in our Consolidated Statements of Operations to reduce the carrying value of our assets to their recoverable amounts. The sale of the assets is included in our Logistics and Transportation segment and does not qualify for reporting as a discontinued operation, as its divestiture did not represent a strategic shift that would have a major effect on our operations or financial results. Sale of Targa GCX Pipeline LLC In May 2022, we completed the sale of Targa GCX Pipeline LLC, which held a 25 % equity interest in GCX, to a third party for $ 857.0 million (the “GCX Sale”). As a result of the GCX Sale, we recognized a gain of $ 435.9 million in Gain (loss) from sale of equity method investment in our Consolidated Statements of Operations in 2022. See Note 7 – Investments in Unconsolidated Affiliates for further discussion on South Texas Acquisition and GCX Sale.

Property, Plant and Equipment a

Property, Plant and Equipment and Intangible Assets	12 Months Ended
	Dec. 31, 2022
Property Plant And Equipment And Intangible Assets [Abstract]
Property, Plant and Equipment and Intangible Assets	Note 5 — Property, Plant and E quipment and Intangible Assets Property, Plant and Equipment and Intangible Assets December 31, 2022 December 31, 2021 Estimated Useful Lives (In Years) Gathering systems $ 10,403.1 $ 9,318.2 5 to 20 Processing and fractionation facilities 7,421.2 6,388.8 5 to 25 Terminaling and storage facilities 1,341.6 1,313.8 5 to 25 Transportation assets 2,919.3 2,671.0 10 to 50 Other property, plant and equipment 387.6 340.9 3 to 50 Land 163.3 160.8 — Construction in progress 1,011.0 347.0 — Finance lease right-of-use assets 266.1 55.6 5 to 14 Property, plant and equipment 23,913.2 20,596.1 Accumulated depreciation, amortization and impairment ( 9,698.6 ) ( 8,928.4 ) Property, plant and equipment, net $ 14,214.6 $ 11,667.7 Intangible assets 4,379.7 2,642.9 10 to 20 Accumulated amortization and impairment ( 1,645.1 ) ( 1,548.1 ) Intangible assets, net $ 2,734.6 $ 1,094.8 During the preparation of the Company's 2020 consolidated financial statements, the Company identified certain gathering pipelines that should not have had value ascribed to them as part of a prior acquisition as these assets were inactive. The Company does not believe this error is material to its previously issued historical consolidated financial statements for any of the periods impacted and accordingly, has not adjusted the historical financial statements. The Company wrote these assets down in 2020 and recognized a non-cash loss of $ 32.4 million in Other operating (income) expense in our Consolidated Statements of Operations. For each of the years ended December 31, 2022, 2021 and 2020 depreciation expense was $ 853.8 million, $ 739.6 million and $ 721.1 million, respectively. Intangible Assets Intangible assets consist of customer relationships acquired in the Delaware Basin Acquisition, and customer contracts and customer relationships acquired in prior 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. For each of the years ended December 31, 2022, 2021 and 2020 , amortization expense for our intangible assets was $ 242.2 million, $ 131.0 million and $ 144.0 million, respectively. The estimated annual amortization expense for intangible assets is approximately $ 384.0 million, $ 373.2 million, $ 326.0 million, $ 279.8 million and $ 252.2 million for each of the years 2023 through 2027. As of December 31, 2022 , the weighted average amortization period for our intangible assets was approximately 12.4 years. The changes in our intangible assets are as follows: December 31, 2022 December 31, 2021 Balance at beginning of period $ 1,094.8 $ 1,382.4 Additions from Delaware Basin Acquisition 1,882.0 — Impairment — ( 156.6 ) Amortization ( 242.2 ) ( 131.0 ) Balance at end of period $ 2,734.6 $ 1,094.8 Impairments of Long-Lived Assets We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of such assets may not be recoverable, including changes to our estimates that could have an impact on our assessment of asset recoverability. 2021 In the fourth quarter of 2021, we recorded a non-cash pre-tax impairment charge of $ 452.3 million, comprised of $ 295.7 million for the impairment of certain gas processing facilities and gathering systems, and $ 156.6 million related to the impairment of intangible customer relationships associated with our Central operations in the Gathering and Processing segment. The impairment was a result of our assessment that forecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. Underlying our assessment were lower expectations regarding volumes and rates associated with the renewal of future expiring contracts and negotiation of new contracts in the South Texas region. 2020 In the first quarter of 2020, we recorded a non-cash pre-tax impairment charge of $ 2,442.8 million, comprised of $ 2,234.2 million related to the impairment of certain gas processing facilities and gathering systems associated with our Central operations and our Coastal operations in the Gathering and Processing segment, and $ 208.6 million related to the impairment of intangible customer relationships associated with our Central operations in the Gathering and Processing segment. The impairment was a result of our assessment that forecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. Underlying our assessment was an observed global commodity price decline due to factors that significantly impacted both demand and supply. As the COVID-19 pandemic spread, causing travel and other restrictions to be implemented globally, the demand for commodities declined. Additionally, the supply shock late in the first quarter of 2020 from certain major oil producing nations increasing production also significantly contributed to the sharp drop in commodity prices. The drop in commodity prices resulted in prompt reactions from some domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production. Our impairment assessment forecasted continued decline in natural gas production across the Mid-Continent and Gulf of Mexico regions. For the 2021 and 2020 impairment assessments discussed above, we determined fair value through the use of discounted estimated cash flows to measure the impairment loss for each asset group for which undiscounted future net cash flows were not sufficient to recover the net book value. The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs, and the use of an appropriate terminal value and discount rate. We believe our estimates and models used to determine fair value are similar to what a market participant would use. The fair value measurement of our long-lived assets was based, in part, on significant inputs not observable in the market (as discussed above) and thus represents a Level 3 measurement. The significant unobservable inputs used include discount rates and determination of terminal values. We utilized a weighted average discount rate of 9.5 % and 14.0 % when deriving the fair value of the asset groups impaired during 2021 and 2020, respectively. The weighted average discount rate and terminal values reflect management’s best estimate of inputs a market participant would utilize. The carrying value adjustments are included in Impairment of long-lived assets in our Consolidated Statements of Operations. We may identify additional triggering events in the future, which will require additional evaluations of the recoverability of the carrying value of our long-lived assets and may result in future impairments.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Note 6 – Goodwill As of December 31, 2022, we had $ 45.2 million of goodwill included in Other long-term assets on the Consolidated Balance Sheets related to the March 2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin. December 31, 2022 December 31, 2021 Permian Midland $ 23.2 $ 23.2 Permian Delaware 22.0 22.0 Goodwill $ 45.2 $ 45.2 The future cash flows and resulting fair values of these reporting units are sensitive to changes in crude oil, natural gas and NGL prices. The direct and indirect effects of significant declines in commodity prices from the date of acquisition would likely cause the fair values of these reporting units to fall below their carrying values, and could result in an impairment of goodwill. As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. For our 2022, 2021 and 2020 annual evaluations, we performed a qualitative assessment, which indicated that it is not more likely than not that the fair values of the Permian Midland and Permian Delaware reporting units were less than their carrying amounts, and therefore, a quantitative goodwill impairment test was not necessary. Our qualitative assessment considered, among other things, the overall financial performance and future outlook of the Permian Midland and Permian Delaware reporting units, industry and market considerations, and other relevant entity-specific events. The fair value measurements utilized for the evaluation of goodwill for impairment are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 15 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
Investments in Unconsolidated Affiliates	Note 7 – Investments in Unconsolidated Affiliates Our investments in unconsolidated affiliates consist of the following: Gathering and Processing Segment • 50 % operated ownership interest in Little Missouri 4. Logistics and Transportation Segment • 38.8 % operated ownership interest in GCF; and • 50 % operated ownership interest in Cayenne. The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting. In April 2022, we completed the South Texas Acquisition. Prior to closing the South Texas Acquisition, we had two operated joint ventures in South Texas: a 75 % interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”) and a 50 % interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford” and, together with T2 LaSalle, the “T2 Joint Ventures”). Following the closing of the South Texas Acquisition, we own 100 % of the interest in the T2 Joint Ventures. In May 2022, we completed the GCX Sale. Prior to the GCX Sale, we owned a 25 % non-operated ownership interest in GCX. Following the announcement of the GCX Sale in February 2022, we ceased recognizing equity earnings (loss) due to the terms of the sales agreement. As a result of the GCX Sale, we recognized a gain of $ 435.9 million in Gain (loss) from sale of equity method investment in our Consolidated Statements of Operations in 2022. The following table shows the activity related to our investments in unconsolidated affiliates: Balance at December 31, 2019 Equity Earnings (Loss) Cash Distributions Disposition/ Contributions Balance at December 31, 2020 GCX $ 447.5 $ 66.3 $ ( 81.3 ) $ — $ 2.7 $ 435.2 Little Missouri 4 103.7 10.8 ( 9.8 ) — — 104.7 T2 Eagle Ford 89.6 ( 8.9 ) ( 0.9 ) — — 79.8 T2 LaSalle 44.8 ( 4.8 ) ( 0.4 ) — — 39.6 GCF 37.2 2.9 ( 1.6 ) — — 38.5 Cayenne 15.9 6.3 ( 6.0 ) — — 16.2 Total $ 738.7 $ 72.6 $ ( 100.0 ) $ — $ 2.7 $ 714.0 Balance at December 31, 2020 Equity Earnings (Loss) Cash Distributions Disposition/ Contributions Balance at December 31, 2021 GCX $ 435.2 $ 63.4 $ ( 78.1 ) $ — $ 0.5 $ 421.0 Little Missouri 4 104.7 10.9 ( 17.5 ) — — 98.1 T2 Eagle Ford 79.8 ( 57.0 ) ( 1.0 ) — 0.1 21.9 T2 LaSalle 39.6 ( 35.0 ) ( 0.4 ) — — 4.2 GCF (1) 38.5 ( 8.6 ) ( 1.1 ) — — 28.8 Cayenne 16.2 2.4 ( 6.1 ) — — 12.5 Total $ 714.0 $ ( 23.9 ) $ ( 104.2 ) $ — $ 0.6 $ 586.5 Balance at December 31, 2021 Equity Earnings (Loss) Cash Distributions Disposition/ Contributions Balance at December 31, 2022 GCX $ 421.0 $ 5.7 $ ( 14.3 ) $ ( 412.4 ) $ — $ — Little Missouri 4 98.1 5.5 ( 12.9 ) — — 90.7 GCF (1) 28.8 ( 3.2 ) — — 1.5 27.1 T2 Eagle Ford (2) 21.9 ( 0.6 ) ( 0.8 ) ( 20.5 ) — — T2 LaSalle (2) 4.2 ( 0.3 ) — ( 3.9 ) — — Cayenne 12.5 2.0 ( 1.0 ) — — 13.5 Total $ 586.5 $ 9.1 $ ( 29.0 ) $ ( 436.8 ) $ 1.5 $ 131.3 (1) In January 2021, GCF was temporarily idled and Targa assumed operatorship in the first half of 2021. In January 2023, we reached an agreement with our partners to reactivate GCF. The facility is expected to be operational during the first quarter of 2024. (2) Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100 % owned and consolidated by Targa. Our equity loss for the year ended December 31, 2021 included the effect of impairments in the carrying values of our investments in the T2 Joint Ventures. As a result of the decrease in current and expected future utilization of the underlying assets, we determined that factors indicated that a decrease in the value of our investments occurred that was other than temporary. As a result of the evaluation, we recorded non-cash pre-tax impairment losses of $ 47.3 million and $ 29.9 million on our investments in T2 Eagle Ford and T2 LaSalle, respectively, in the fourth quarter of 2021. The impairment losses represented our proportionate share of impairment charges recorded by the joint ventures, as well as impairments of the unamortized excess fair values resulting from the purchase accounting related to the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015.

Debt Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Debt Obligations	Note 8 — De bt Obligations December 31, 2022 December 31, 2021 Current: Partnership accounts receivable securitization facility, due September 2023 (1) $ 800.0 $ 150.0 Finance lease liabilities 34.3 12.8 Current debt obligations 834.3 162.8 Long-term: Term loan facility, variable rate, due July 2025 1,500.0 — TRGP senior revolving credit facility, variable rate, due February 2027 (2) 1,298.7 — Senior unsecured notes issued by TRGP: 5.200 % fixed rate, due July 2027 750.0 — 4.200 % fixed rate, due February 2033 750.0 — 4.950 % fixed rate, due April 2052 750.0 — 6.250 % fixed rate, due July 2052 500.0 — Unamortized discount ( 8.4 ) — Senior unsecured notes issued by the Partnership: (3) 5.875 % fixed rate, due April 2026 — 963.2 5.375 % fixed rate, due February 2027 — 468.1 6.500 % fixed rate, due July 2027 705.2 705.2 5.000 % fixed rate, due January 2028 700.3 700.3 6.875 % fixed rate, due January 2029 679.3 679.3 5.500 % fixed rate, due March 2030 949.6 949.6 4.875 % fixed rate, due February 2031 1,000.0 1,000.0 4.000 % fixed rate, due January 2032 1,000.0 1,000.0 10,574.7 6,465.7 Debt issuance costs, net of amortization ( 65.6 ) ( 45.0 ) Finance lease liabilities 193.0 13.7 Long-term debt 10,702.1 6,434.4 Total debt obligations $ 11,536.4 $ 6,597.2 Irrevocable standby letters of credit: (2) Letters of credit outstanding under the TRGP senior revolving credit facility $ 33.2 $ — Letters of credit outstanding under the Partnership senior — 71.3 $ 33.2 $ 71.3 (1) As of December 31, 2022, the Partnership had $ 800.0 million of qualifying receivables under its $ 800.0 million Securitization Facility, resulting in zero availability. (2) In February 2022, we entered into the TRGP Revolver which matures in February 2027, and terminated our previous TRGP senior secured revolving credit facility (the “Previous TRGP Revolver”) and the Partnership’s senior secured revolving credit facility (the “Partnership Revolver”). In July 2022, we established an unsecured commercial paper note program (the “Commercial Paper Program”), the borrowings of which are supported through maintaining a minimum available borrowing capacity under our TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program. As of December 31, 2022, the TRGP Revolver had $ 290.0 million borrowings outstanding and the Commercial Paper Program had $ 1.0 billion borrowings outstanding, resulting in approximately $ 1.4 billion of available liquidity, after accounting for outstanding letters of credit. As of December 31, 2021, we had no balance outstanding under the Previous TRGP Revolver or the Partnership Revolver. (3) As of February 2022, we guarantee all of the Partnership’s outstanding senior unsecured notes. The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2022: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRGP Revolver and Commercial Paper Program 1.5 % - 5.9 % 3.6 % Securitization Facility 1.1 % - 5.2 % 3.0 % Term Loan Facility 4.1 % - 5.8 % 4.6 % Compliance with Debt Covenants As of December 31, 2022, we were in compliance with the covenants contained in our various debt agreements. In February 2022, we and certain of our subsidiaries entered into a parent guarantee whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of all of the obligations of the Partnership and Targa Resources Partners Finance Corporation (together with the Partnership, the “Partnership Issuers”) under the respective indentures governing the Partnership Issuers’ senior unsecured notes. As of December 31, 2022, $ 5.0 billion of the Partnership Issuers' senior unsecured notes was outstanding. Debt Obligations Partnership’s Accounts Receivable Securitization Facility In April 2022, the Partnership amended the Securitization Facility to, among other things, extend the facility termination date to April 19, 2023 and replace the LIBOR-based interest rate option with SOFR-based interest rate options, including term SOFR and daily simple SOFR. In September 2022, the Partnership amended the Securitization Facility to, among other things, increase the facility size from $ 400.0 million to $ 800.0 million and extend the facility termination date to September 1, 2023 . The Securitization Facility provides up to $ 800.0 million of borrowing capacity at SOFR rates plus a margin through September 1, 2023 . Under the Securitization Facility, certain Partnership subsidiaries sell or contribute certain qualifying receivables, without recourse, to another of its consolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of the Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to third-party financial institutions. Sold or contributed receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of the selling or contributing subsidiaries or the Partnership. Any excess receivables are eligible to satisfy the claims. TRGP Credit Agreement In February 2022, the Company entered into the TRGP Revolver with Bank of America, N.A., as the Administrative Agent, Collateral Agent and Swing Line Lender, and the other lenders party thereto. The TRGP Revolver provides for a revolving credit facility in an initial aggregate principal amount up to $ 2.75 billion (with an option to increase such maximum aggregate principal amount by up to $ 500.0 million in the future, subject to the terms of the TRGP Revolver) and a swing line sub-facility of up to $ 100.0 million. The TRGP Revolver matures on February 17, 2027 . In February 2022, TRGP and the Partnership received a corporate investment grade credit rating from Standard & Poor’s Financial Services LLC (“S&P”) and Fitch Ratings Inc., and in March 2022, the Partnership received a corporate investment grade credit rating from Moody’s Investors Service, Inc. (“Moody’s”). As a result, in accordance with the TRGP Revolver, the collateral under the TRGP Revolver was released from the liens securing our obligations thereunder. The revolving credit facility bears interest at the Company’s option at: (a) the Base Rate, which is the highest of Bank of America’s prime rate, the federal funds rate plus 0.5 % and the Term SOFR (as such term is defined in the TRGP Revolver rate plus 1.0 % (subject in each case to a floor of 0.0 %), plus an applicable margin ranging from 0.125 % to 0.75 %, dependent on the Company’s non-credit-enhanced senior unsecured long-term debt ratings (or, if no such debt is outstanding at such time, then the corporate, issuer or similar rating with respect to the Company that has been most recently announced) (the “Debt Rating”), or (b) Term SOFR (which includes, for Term SOFR loans, a SOFR adjustment of plus 0.10 %) plus an applicable margin ranging from 1.125 % to 1.75 %, dependent on the Company’s Debt Rating. The Company is required to pay a commitment fee equal to an applicable rate ranging from 0.125 % to 0.35 % (dependent on the Company’s Debt Rating), in each case times the actual daily unused portion of the revolving credit facility. The obligations under the TRGP Revolver are guaranteed by substantially all material wholly-owned domestic subsidiaries of the Company, including by the Partnership. The TRGP Revolver requires the Company to maintain a ratio of consolidated funded indebtedness to consolidated adjusted EBITDA (the “Consolidated Leverage Ratio”), determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, of no more than 5.50 to 1.00 . The TRGP Revolver restricts the Company’s ability to make dividends to stockholders if a default or an event of default (as defined in the TRGP Revolver) exists or would result from such distribution. In addition, the TRGP Revolver contains various covenants that may limit, among other things, the Company’s ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates. Term Loan Facility In July 2022, we entered into the Term Loan Facility. The Term Loan Facility provides for a three-year , $ 1.5 billion unsecured term loan facility and matures in July 2025 . We used the proceeds from the Term Loan Facility to fund a portion of the Delaware Basin Acquisition. The Term Loan Facility bears interest at the Company’s option at: (a) the Base Rate (as defined in the Term Loan Facility), which is the highest of the (i) federal funds rate plus 0.5 %, (ii) Mizuho’s prime rate, and (iii) the Term SOFR (as defined in the Term Loan Facility) rate plus 1.0 % (subject in each case to a floor of 0.0 %), plus an applicable margin ranging from 0.125 % to 0.75 % dependent on the Company’s non-credit-enhanced senior unsecured long-term debt ratings (or, if no such debt is outstanding at such time, then the corporate, issuer or similar rating with respect to the Company that has been most recently announced) (the “Debt Rating”), or (b) Term SOFR plus 0.10 % plus an applicable margin ranging from 1.125 % to 1.75 % dependent on the Debt Rating . Our obligations under the Term Loan Facility are guaranteed by substantially all material wholly-owned domestic restricted subsidiaries of the Company, including the Partnership. The Term Loan Facility requires the Company to maintain a Consolidated Leverage Ratio (as defined in the Term Loan Facility), determined as of the last day of each quarter for the four-fiscal-quarter-period ending on the date of determination, of no more than 5.50 to 1.00 . For any four-fiscal-quarter-period during which a material acquisition or disposition occurs, the total leverage ratio will be determined on a pro forma basis as though such event had occurred as of the first day of such four-fiscal-quarter-period. The Term Loan Facility limits the Company’s ability to make dividends to stockholders if an event of default (as defined in the Term Loan Facility) exists or would result from such distribution. In addition, the Term Loan Facility contains various covenants that may limit, among other things, the Company’s ability to incur subsidiary indebtedness, grant liens, make investments, merge or consolidate, and engage in transactions with affiliates. Commercial Paper Program In July 2022, we established the Commercial Paper Program. Under the terms of the Commercial Paper Program, we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year. Amounts available under the Commercial Paper Program may be issued, repaid and re-issued from time to time, with the maximum aggregate face or principal amount outstanding at any one time not to exceed $ 2.75 billion. We maintain a minimum available borrowing capacity under the TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program as support. The Commercial Paper Program is guaranteed by each subsidiary that guarantees the TRGP Revolver. The commercial paper notes are presented in Long-term debt on our Consolidated Balance Sheets. TRGP’s Senior Unsecured Notes All issues of our senior unsecured notes (the “TRGP Notes”) rank pari passu with our existing and future senior indebtedness, including debt issued under the TRGP Revolver, the Commercial Paper Program and the Term Loan Facility, and rank senior in right of payment to any of our future subordinated indebtedness. The TRGP Notes are unconditionally guaranteed by certain of our subsidiaries that guarantee the TRGP Revolver. Each guarantee ranks equally in right of payment with all of such guarantor’s existing and future unsecured senior debt and other unsecured guarantees of senior debt. The notes and the guarantees are effectively junior to any secured indebtedness of ours or any guarantor to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other obligations of our subsidiaries that do not guarantee the notes. Interest on all issues of TRGP’s Notes are payable semi-annually. The indenture governing the TRGP Notes restricts (i) our ability and the ability of our subsidiaries to incur liens and (ii) TRGP’s ability to merge or consolidate with or sell, lease, convey transfer or otherwise dispose of all or substantially all of its assets to another company. These covenants are subject to a number of important exceptions and qualifications. We may redeem the TRGP Notes, in whole or in part, at any time prior to the applicable par call date at a redemption price equal to the principal amount plus an applicable make-whole premium, plus accrued and unpaid interest, to the redemption date, as specified in the indenture of each series. After the applicable par call date, the TRGP Notes may be redeemed at a price equal to par, plus accrued and unpaid interest to the redemption date, as specified in the indenture of each series. In the future, we may redeem, purchase or exchange certain of our 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 or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Partnership’s Senior Unsecured Notes All issues of the Partnership's senior unsecured notes are pari passu with existing and future senior indebtedness. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by the Partnership and the Partnership’s restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the TRGP Revolver and the Securitization Facility, which is secured by accounts receivable pledged under the facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears. The Partnership’s senior unsecured notes and associated indenture agreements restrict (i) the Partnership’s ability and the ability of certain of its subsidiaries to incur liens and (ii) the Partnership's ability to merge or consolidate with or sell, lease, convey transfer or otherwise dispose of all or substantially all of its assets to another company. These covenants are subject to a number of important exceptions and qualifications. The Partnership may redeem the senior unsecured notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount plus an applicable make-whole premium, plus accrued and unpaid interest and liquidation damages, if any, to the redemption date, as specified in the indenture of each series. The Partnership may also redeem up to 35 % of the aggregate principal amount of each series of notes at the redemption dates and prices set forth in the indentures plus accrued and unpaid interest and liquidation damages, if any, to the redemption date with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65 % of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 180 days of the date of the closing of such equity offering. In the future, we or the Partnership may redeem, purchase or exchange certain of our and 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 or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Senior Unsecured Notes Issuances In August 2020, the Partnership issued $ 1.0 billion aggregate principal amount of 4.875 % Senior Notes due 2031 (the “August 2020 Offering”), resulting in net proceeds of approximately $ 991 million. A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer (the “August Tender Offer”) of the Partnership’s 6.750 % Senior Notes due 2024 (the “6.750% Notes”) and redeem any 6.750 % Notes that remained outstanding after consummation of the August Tender Offer, with the remainder used for repayment of borrowings under the Previous TRGP Revolver. See “Debt Repurchases and Extinguishments” for further details of the August Tender Offer. In February 2021, the Partnership issued $ 1.0 billion aggregate principal amount of 4.000 % Senior Notes due 2032 (the “February 2021 Offering”), resulting in net proceeds of approximately $ 991 million. The 4.000 % Senior Notes due 2032 have substantially similar terms and covenants as our other series of Senior Notes. A portion of the net proceeds from the issuance was used to fund the concurrent cash tender offer (the “February Tender Offer”) and subsequent redemption for the Partnership’s 5.125 % Senior Notes due 2025 (the “5.125% Notes”), with the remainder used for repayment of borrowings under the Partnership Revolver and Previous TRGP Revolver. See “Debt Repurchases and Extinguishments” for further details of the February Tender Offer. In April 2022, we completed an underwritten public offering of (i) $ 750.0 million aggregate principal amount of our 4.200 % Senior Notes due 2033 (the “ 4.200 % Notes”) and (ii) $ 750.0 million aggregate principal amount of our 4.950 % Senior Notes due 2052 (the “ 4.950 % Notes”), resulting in net proceeds of approximately $ 1.5 billion. The 4.200 % Notes and the 4.950 % 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 4.200 % Notes and the 4.950 % Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain First Supplemental Indenture, dated as of April 6, 2022, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee. A portion of the net proceeds from the issuance was used to fund the concurrent cash tender offer (the “March Tender Offer”) and the subsequent redemption of the Partnership’s 5.875 % Senior Notes due April 2026 (the “ 5.875 % Notes”), with the remainder of the net proceeds used for repayment of the outstanding borrowings under the TRGP Revolver. See “Debt Repurchases and Extinguishments” for further details of the March Tender Offer. In July 2022, we completed an underwritten public offering of the 5.200 % Notes and the 6.250 % Notes, resulting in net proceeds of approximately $ 1.2 billion. The 5.200 % Notes and the 6.250 % 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 5.200 % Notes and the 6.250 % Notes were issued pursuant to the Indenture, dated as of April 6, 2022, as supplemented by that certain Third Supplemental Indenture, dated as of July 7, 2022, among us, such subsidiary guarantors and U.S. Bank Trust Company, National Association, as trustee. We used the net proceeds from the issuance to fund a portion of the Delaware Basin Acquisition. Debt Repurchases & Extinguishments During the first half of 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, paying $ 239.8 million plus accrued interest to repurchase $ 303.3 million of the notes. As a result, we recorded a gain due to debt extinguishment of $ 61.1 million. Concurrent with the August 2020 Offering, the Partnership commenced the August Tender Offer to purchase for cash, subject to certain terms and conditions, any and all of our outstanding 6.750 % Notes. We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $ 262.1 million. Subsequent to the closing of the August Tender Offer in August 2020, the Partnership redeemed the 6.750 % Notes for the remaining note balance of $ 318.0 million (the “2024 Note Redemption”). As a result of the August Tender Offer and the 2024 Note Redemption, we recorded a loss due to debt extinguishment of $ 13.7 million. In November 2020, the Partnership redeemed the $ 559.6 million remaining balance of its 5.250 % Senior Notes due 2023. As a result, we recorded a loss due to debt extinguishment of $ 1.8 million. Concurrent with the February 2021 Offering, the Partnership commenced the February Tender Offer to redeem subject to certain terms and conditions, any and all of our outstanding 5.125 % Notes. As a result of the February Tender Offer and the subsequent redemption of the 5.125% Notes, we recorded a loss due to debt extinguishment of $ 14.9 million. Additionally, Targa Pipeline Partners LP (the “TPL”) redeemed all of the outstanding TPL 4.750% Senior Notes due 2021 and TPL 5.875 % Senior Notes due 2023 (collectively, the “TPL Notes”) in February 2021 with available liquidity under the Partnership Revolver. As a result of the redemptions of the TPL Notes, we recorded a gain due to debt extinguishment of $ 0.2 million. The Partnership redeemed all of the outstanding 4.250 % Senior Notes due 2023 (the “4.250% Senior Notes”) in May 2021 with available liquidity under the Partnership Revolver. As a result of the redemption of the 4.250% Senior Notes, we recorded a loss due to debt extinguishment of $ 1.9 million. In February 2022, in connection with entering into the TRGP Revolver, we terminated the Previous TRGP Revolver and Partnership Revolver. As a result of the termination of the Previous TRGP Revolver and the Partnership Revolver, we recorded a loss of $ 0.8 million due to a write-off of debt issuance costs. The Partnership redeemed all of the outstanding 5.375 % Senior Notes due 2027 (the “5.375% Notes”) in March 2022 with available liquidity under the TRGP Revolver. As a result of the redemption of the 5.375% Notes, we recorded a loss due to debt extinguishment of $ 15.0 million. Concurrent with the 4.200 % Notes and the 4.950 % Notes offering, we commenced the March Tender Offer to redeem subject to certain terms and conditions, any and all of the Partnership's outstanding 5.875 % Notes. As a result of the March Tender Offer and the subsequent redemption of the 5.875% Notes, we recorded a loss due to debt extinguishment of $ 33.8 million. The following table summarizes the impact of debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2022 2021 2020 Discount (premium) over face value paid upon redemption: TPL Notes $ — $ 0.2 $ — 5.125% Senior Notes due 2025 — ( 12.5 ) 4.4 6.750% Senior Notes due 2024 — — ( 11.1 ) 5.875% Senior Notes due 2026 ( 29.3 ) — 7.1 5.375% Senior Notes due 2027 ( 12.6 ) — 5.3 5.000% Senior Notes due 2028 — — 11.7 6.500% Senior Notes due 2027 — — 9.3 6.875% Senior Notes due 2029 — — 15.5 5.500% Senior Notes due 2030 — — 10.2 Write-off of debt issuance costs: Previous TRGP Revolver and Partnership Revolver ( 0.8 ) — — 5.125% Senior Notes due 2025 — ( 2.4 ) ( 0.1 ) 4.250% Senior Notes due 2023 — ( 1.9 ) — 5.250% Senior Notes due 2023 — — ( 1.8 ) 6.750% Senior Notes due 2024 — — ( 2.6 ) 5.875% Senior Notes due 2026 ( 4.5 ) — ( 0.2 ) 5.375% Senior Notes due 2027 ( 2.4 ) — ( 0.2 ) 5.000% Senior Notes due 2028 — — ( 0.4 ) 6.500% Senior Notes due 2027 — — ( 0.4 ) 6.875% Senior Notes due 2029 — — ( 0.6 ) 5.500% Senior Notes due 2030 — — ( 0.5 ) Gain (loss) from financing activities $ ( 49.6 ) $ ( 16.6 ) $ 45.6 The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2022, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2023 2024 2025 2026 2027 Thereafter TRGP Revolver and Commercial Paper Program $ 1,298.7 $ — $ — $ — $ — $ 1,298.7 $ — TRGP Senior unsecured notes 2,741.6 — — — — 749.0 1,992.6 Term Loan Facility 1,500.0 — — 1,500.0 — — — Partnership's Senior unsecured notes 5,034.4 — — — — 705.2 4,329.2 Securitization Facility 800.0 800.0 — — — — — Total $ 11,374.7 $ 800.0 $ — $ 1,500.0 $ — $ 2,752.9 $ 6,321.8 Subsequent Event In January 2023, we completed an underwritten public offering of (i) $ 900.0 million in aggregate principal amount of our 6.125 % Senior Notes due 2033 and (ii) $ 850.0 million in aggregate principal amount of our 6.500 % Senior Notes due 2053, resulting in net proceeds of approximately $ 1.7 billion. We used a portion of the net proceeds from the issuance to fund the Grand Prix Transaction and the remaining net proceeds for general corporate purposes, including to reduce borrowings under the TRGP Revolver and the Commercial Paper Program.

Other Long-term Liabilities

Other Long-term Liabilities	12 Months Ended
	Dec. 31, 2022
Other Liabilities, Noncurrent [Abstract]
Other Long-term Liabilities	Note 9 — Other Long-term Liabilities Other long-term liabilities are comprised of the following obligations: December 31, 2022 December 31, 2021 Deferred revenue $ 198.8 $ 171.8 Asset retirement obligations 97.9 72.1 Operating lease liabilities 28.6 34.5 Other liabilities 15.9 23.2 Total other long-term liabilities $ 341.2 $ 301.6 Deferred Revenue Deferred revenue as of December 31, 2022 and 2021 was $ 198.8 million and $ 171.8 million, respectively, which includes $ 129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter. In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is dependent on the outcome of current litigation with Vitol. See Note 18 - Contingencies for more information. Deferred revenue includes nonmonetary consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processing agreement. We measured the estimated fair value of the gathering assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. In December 2017, we received monetary consideration to further amend the terms of the 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. Deferred revenue also includes contributions in aid of construction received from customers for which revenue is recognized over the expected contract term. For the years ended December 31, 2022, 2021 and 2020, we recognized $ 7.5 million, $ 3.9 million and $ 3.8 million of revenue for these transactions, respectively. The following table shows the components of deferred revenue: December 31, 2022 December 31, 2021 Splitter agreement $ 129.0 $ 129.0 Gas contract amendment 32.3 34.8 Contributions in aid of construction (1) 31.7 — Other 5.8 8.0 Total deferred revenue $ 198.8 $ 171.8 (1) Amount reflects additions of deferred revenue related to the Delaware Basin Acquisition. The following table shows the changes in deferred revenue: 2022 2021 Balance at beginning of period $ 171.8 $ 168.5 Additions 34.5 7.2 Revenue recognized ( 7.5 ) ( 3.9 ) Balance at end of period $ 198.8 $ 171.8 Asset Retirement Obligations Our ARO primarily relate to certain gas gathering pipelines and processing facilities and NGL pipelines. The changes in our ARO are as follows: 2022 2021 Beginning of period $ 72.1 $ 68.3 Additions (1) 20.2 — Accretion expense 4.8 4.0 Change in cash flow estimate 0.8 ( 0.2 ) End of period $ 97.9 $ 72.1 (1) Amount reflects additions of ARO related to the Delaware Basin Acquisition.

Leases

Leases	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Leases	Note 10 – L eases We have non-cancellable operating leases primarily associated with our office facilities, rail assets, land, storage and terminal assets. We have finance leases primarily associated with our substations, compressors, tractors and vehicles. Our leases have remaining lease terms of 1 to 10 years, some of which include options to extend the lease term for up to 20 years. The balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated Balance Sheets are as follows: December 31, Balance Sheet Location 2022 2021 Right-of-use assets Operating leases, gross Other long-term assets $ 57.3 $ 50.8 Finance leases, gross (1) Property, plant and equipment 266.1 55.6 Lease liabilities Current: Operating leases Accrued liabilities $ 14.4 $ 11.7 Finance leases (1) Current debt obligations 34.3 12.8 Non-current: Operating leases Other long-term liabilities $ 28.6 $ 34.5 Finance leases (1) Long-term debt 193.0 13.7 (1) The December 31, 2022 balance includes $ 171.2 million of assets and $ 167.0 million of liabilities related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended. Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements of Operations, depending on the nature of the leases. Finance lease costs are included in Depreciation and amortization expense and Interest expense, net in our Consolidated Statements of Operations. The components of lease expense were as follows: Year Ended December 31, 2022 2021 2020 Lease cost Operating lease cost $ 17.7 $ 12.2 $ 11.6 Short-term lease cost 35.0 20.4 20.7 Variable lease cost 17.9 5.7 5.5 Finance lease cost Amortization of right-of-use assets 20.3 13.3 13.6 Interest expense 3.5 1.1 1.4 Total lease cost $ 94.4 $ 52.7 $ 52.8 Other supplemental information related to our leases are as follows: Year Ended December 31, 2022 2021 2020 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for operating leases $ 18.8 $ 14.1 $ 12.3 Operating cash flows for finance leases 2.7 1.0 1.4 Financing cash flows for finance leases 19.7 12.5 12.4 The weighted-average remaining lease terms for operating leases and finance leases are 5 years and 7 years , respectively. The weighted-average discount rates for operating leases and finance leases are 4.0 % and 4.8 % , respectively. The following table presents the maturities of our lease liabilities under non-cancellable leases as of December 31, 2022: Operating Leases Finance Leases 2023 $ 15.7 $ 42.5 2024 9.9 38.5 2025 5.2 37.1 2026 4.5 35.4 2027 4.0 30.9 Thereafter 7.8 80.9 Total undiscounted cash flows 47.1 265.3 Less imputed interest ( 4.1 ) ( 38.0 ) Total lease liabilities $ 43.0 $ 227.3

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
Preferred Stock	Note 11 – P referred Stock Preferred Stock Prior to the redemption in May 2022, our Series A Preferred had a liquidation value of $ 1,000 per share and bore a cumulative 9.5 % fixed dividend payable quarterly 45 days after the end of each fiscal quarter . The Series A Preferred had no mandatory redemption date, but was redeemable at our election on or prior to March 16, 2022 for a 10 % premium to the liquidation preference and for a 5 % premium to the liquidation preference thereafter. The Series A Preferred ranked senior to the common outstanding stock with respect to the payment of dividends and distributions in liquidation. The holders of Series A Preferred generally only had voting rights in certain circumstances, subject to certain exceptions, which included: • the issuance or the increase by the Company of any specific class or series of stock that was senior to the Series A Preferred, • the issuance or the increase by any of the Company’s consolidated subsidiaries of any specific class or series of securities, • changes to the Certificates of Incorporation or Designations of the Series A Preferred that would have materially and adversely affected the Preferred Stock holder, • the issuance of stock on parity with the Series A Preferred, subject to certain exceptions, if the Company had exceeded a stipulated fixed charge coverage ratio or an aggregate amount of net proceeds from all future issuances of Parity Stock, or would have used the proceeds of such issuance to pay dividends, • the incurrence of indebtedness, other than indebtedness that complies with a stipulated fixed charge coverage ratio or under the TRGP Revolver (or replacement commercial bank facilities) in an aggregate amount up to $ 2.75 billion. The Series A Preferred did not qualify as a liability instrument because it was not mandatorily redeemable. However, as SEC Regulation S-X, Rule 5-02-27 does not permit a probability assessment for a change of control provision, our Series A Preferred must be presented as mezzanine equity between liabilities and shareholders’ equity on our Consolidated Balance Sheets because a change of control event, although not considered probable, could have forced the Company to redeem the Series A Preferred. A maximum of 44,260,953 common shares would have been issued upon conversion of the Series A Preferred. Preferred Stock Partial Redemption In December 2020, we repurchased 45,800 shares of the Series A Preferred at $ 1,000 per share (the “Liquidation Preference”), plus an amount equal to all unpaid dividends through the repurchase date. The repurchase was executed at a discount relative to the redemption price of $ 1,100 per share (the Liquidation Preference multiplied by 110 %), which became effective March 16, 2021. The difference between the consideration paid (including unpaid dividends of $ 1.1 million) and the net carrying value of the shares repurchased was $ 2.7 million, which was recorded as an addition to preferred stock dividends for the year ended December 31, 2020. Preferred Stock Redemption In May 2022, we redeemed all of our issued and outstanding shares of Series A Preferred at a redemption price of $ 1,050.00 per share, plus $ 8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022 . The difference between the consideration paid of $ 973.4 million (including unpaid dividends of $ 8.2 million) and the net carrying value of the shares redeemed was $ 223.7 million, of which $ 215.5 million was recorded as deemed dividends in our Consolidated Statements of Operations in the second quarter of 2022. Following the redemption, we have no Series A Preferred outstanding and all rights of the holders of shares of Series A Preferred were terminated. Preferred Stock Dividends During the year ended December 31, 2022, we paid $ 51.8 million of dividends to preferred shareholders. During the years ended December 31, 2021 and 2020 we paid $ 87.3 million and $ 91.7 million of dividends at a rate of $ 23.75 per share each quarter to Series A Preferred shareholders, and recorded deemed dividends of $ 39.2 million for the year ended December 31, 2020, attributable to accretion of the preferred discount resulting from the beneficial conversion feature accounting model. Such accretion was included in the book value of the Series A Preferred. After adoption of ASU 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity in 2021, we no longer recognize such accretion.

Common Stock and Related Matter

Common Stock and Related Matters	12 Months Ended
	Dec. 31, 2022
Class of Stock Disclosures [Abstract]
Common Stock and Related Matters	Note 12 — C ommon Stock and Related Matters Public Offerings of Common Stock On May 9, 2017, we entered into an equity distribution agreement under the May 2016 Shelf (the “May 2017 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregated amount of $ 750.0 million of our common stock (“2017 ATM Program”). On September 20, 2018, we entered into an equity distribution agreement under the May 2016 Shelf (the “September 2018 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregated amount of $ 750.0 million of our common stock (“2018 ATM Program”). In May 2019, we filed (i) the May 2019 Shelf, (ii) a new prospectus supplement to continue the 2017 ATM Program and (iii) a new prospectus supplement to continue the 2018 ATM Program. In March 2022, we filed with the SEC a universal shelf registration statement on Form S-3 that registers the issuance and sale of certain debt and equity securities from time to time in one or more offerings (the “March 2022 Shelf”). The March 2022 Shelf will expire in March 2025. During 2020, 2021 and 2022 , no shares of common stock were issued under either the May 2017 EDA or the September 2018 EDA. As a result, we have $ 382.1 million and $ 750.0 million remaining under the May 2017 EDA and September 2018 EDA, respectively, as of December 31, 2022. Common Share Repurchase Program In October 2020, our board of directors approved a share repurchase program (the "Share Repurchase Program") for the repurchase of up to $ 500.0 million of our outstanding common stock. For the year ended December 31, 2022, we repurchased 3,412,354 shares of our common stock at a weighted average price of $ 65.87 for a total net cost of $ 224.8 million. For the year ended December 31, 2021, we repurchased 756,478 shares of our common stock at a weighted average price of $ 52.81 for a total net cost of $ 40.0 million. There was $ 143.8 million remaining under the Share Repurchase Program as of December 31, 2022. Common Stock Dividends In January 2022, we declared an increase to our common dividend to $ 0.35 per common share or $ 1.40 per common share annualized effective for the fourth quarter of 2021. The following table details the dividends declared and/or paid by us to common shareholders for the years ended December 31, 2022, 2021 and 2020: Three Months Ended Date Paid or Total Common Amount of Common Accrued Dividends Declared per Share of Common Stock (In millions, except per share amounts) 2022 December 31, 2022 February 15, 2023 $ 80.5 $ 79.3 $ 1.2 $ 0.35000 September 30, 2022 November 15, 2022 80.5 79.2 1.3 0.35000 June 30, 2022 August 15, 2022 80.7 79.3 1.4 0.35000 March 31, 2022 May 16, 2022 81.2 79.8 1.4 0.35000 2021 December 31, 2021 February 15, 2022 $ 81.4 $ 80.1 $ 1.3 $ 0.35000 September 30, 2021 November 15, 2021 23.3 22.9 0.4 0.10000 June 30, 2021 August 16, 2021 23.3 22.9 0.4 0.10000 March 31, 2021 May 14, 2021 23.3 22.9 0.4 0.10000 2020 December 31, 2020 February 16, 2021 $ 23.3 $ 22.9 $ 0.4 $ 0.10000 September 30, 2020 November 16, 2020 23.8 23.3 0.5 0.10000 June 30, 2020 August 17, 2020 23.7 23.3 0.4 0.10000 March 31, 2020 May 15, 2020 23.7 23.3 0.4 0.10000 (1) Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Earnings per Common Share

Earnings per Common Share	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
Earnings per Common Share	Note 13 — Ea rnings per Common Share 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: Year Ended December 31, 2022 2021 2020 (In millions, except per share amounts) Net income (loss) attributable to Targa Resources Corp. $ 1,195.5 $ 71.2 $ ( 1,553.9 ) Less: Premium on repurchase of noncontrolling interests, net of tax (1) 53.2 — — Less: Dividends on Series A Preferred (2) 30.0 87.3 91.7 Less: Deemed dividends on Series A Preferred (3) 215.5 — 39.2 Net income (loss) attributable to common shareholders for basic earnings per share $ 896.8 $ ( 16.1 ) $ ( 1,684.8 ) Weighted average shares outstanding - basic 227.3 228.6 232.2 Dilutive effect of unvested stock awards (4) 3.8 — — Weighted average shares outstanding - diluted 231.1 228.6 232.2 Net income (loss) available per common share - basic $ 3.95 $ ( 0.07 ) $ ( 7.26 ) Net income (loss) available per common share - diluted $ 3.88 $ ( 0.07 ) $ ( 7.26 ) (1) Represents premium paid on the DevCo JV Repurchase. See Note 4 – Acquisitions and Divestitures. (2) Includes $ 8.2 million and $ 1.1 million attributable to the dividends paid upon the full redemption and partial repurchase of Series A Preferred in 2022 and 2020, respectively. (3) Includes $ 215.5 million and $ 1.6 million attributable to the full redemption and partial repurchase of Series A Preferred in 2022 and 2020, respectively. See Note 11 – Preferred Stock for further discussion. (4) For the years ended December 31, 2021 and 2020, all unvested restricted stock awards and Series A Preferred were antidilutive because a net loss existed for each of those periods. 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): Year Ended December 31, 2022 2021 2020 Unvested restricted stock awards — 3.3 2.3 Series A Preferred (1) 14.9 44.3 46.4 (1) The Series A Preferred had no mandatory redemption date, but was redeemable at our election for a 5 % premium to the liquidation preference subsequent to March 16, 2022 . In May 2022, we redeemed all of our issued and outstanding Series A Preferred at a redemption price of $ 1,050.00 per share, plus $ 8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022 . See Note 11 – Preferred Stock for further discussion.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Not e 14 — 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 the 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 the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes. 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 as current income. At December 31, 2022, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2023 2024 2025 2026 2027 Natural Gas Swaps MMBtu/d 175,687 105,377 28,334 — — Natural Gas Basis Swaps MMBtu/d 591,610 298,407 244,267 82,500 25,000 NGL Swaps Bbl/d 43,115 21,134 4,813 — — NGL Futures Bbl/d 21,512 383 — — — Condensate Swaps Bbl/d 6,427 3,232 853 — — 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 $ 19.1 million as of December 31, 2022. The range of losses attributable to our individual counterparties would be between $ 1.9 million and $ 16.4 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 schedules reflect the fair value of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of December 31, 2022 Fair Value as of December 31, 2021 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 158.7 $ ( 93.8 ) $ 25.5 $ ( 252.6 ) Long-term 24.2 ( 30.9 ) 6.2 ( 84.3 ) Total derivatives designated as hedging instruments $ 182.9 $ ( 124.7 ) $ 31.7 $ ( 336.9 ) Derivatives not designated as hedging instruments Commodity contracts Current $ 21.2 $ ( 226.3 ) $ 17.6 $ ( 5.6 ) Long-term 0.3 ( 109.2 ) 1.5 ( 25.0 ) Total derivatives not designated as hedging instruments $ 21.5 $ ( 335.5 ) $ 19.1 $ ( 30.6 ) Total current position $ 179.9 $ ( 320.1 ) $ 43.1 $ ( 258.2 ) Total long-term position 24.5 ( 140.1 ) 7.7 ( 109.3 ) Total derivatives $ 204.4 $ ( 460.2 ) $ 50.8 $ ( 367.5 ) The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro Forma Net Presentation December 31, 2022 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 162.2 $ ( 316.7 ) $ 12.2 $ 27.2 $ ( 169.5 ) Counterparties without offsetting positions - assets 17.7 — — 17.7 — Counterparties without offsetting positions - liabilities — ( 3.4 ) — — ( 3.4 ) 179.9 ( 320.1 ) 12.2 44.9 ( 172.9 ) Long-Term Position Counterparties with offsetting positions or collateral 24.5 ( 137.4 ) 22.4 7.3 ( 97.8 ) Counterparties without offsetting positions - assets — — — — — Counterparties without offsetting positions - liabilities — ( 2.7 ) — — ( 2.7 ) 24.5 ( 140.1 ) 22.4 7.3 ( 100.5 ) Total Derivatives Counterparties with offsetting positions or collateral 186.7 ( 454.1 ) 34.6 34.5 ( 267.3 ) Counterparties without offsetting positions - assets 17.7 — — 17.7 — Counterparties without offsetting positions - liabilities — ( 6.1 ) — — ( 6.1 ) $ 204.4 $ ( 460.2 ) $ 34.6 $ 52.2 $ ( 273.4 ) Gross Presentation Pro Forma Net Presentation December 31, 2021 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 39.2 $ ( 241.9 ) $ 5.0 $ 0.3 $ ( 198.0 ) Counterparties without offsetting positions - assets 3.9 — — 3.9 — Counterparties without offsetting positions - liabilities — ( 16.3 ) — — ( 16.3 ) 43.1 ( 258.2 ) 5.0 4.2 ( 214.3 ) Long-Term Position Counterparties with offsetting positions or collateral 7.4 ( 95.1 ) 3.1 — ( 84.6 ) Counterparties without offsetting positions - assets 0.3 — — 0.3 — Counterparties without offsetting positions - liabilities — ( 14.2 ) — — ( 14.2 ) 7.7 ( 109.3 ) 3.1 0.3 ( 98.8 ) Total Derivatives Counterparties with offsetting positions or collateral 46.6 ( 337.0 ) 8.1 0.3 ( 282.6 ) Counterparties without offsetting positions - assets 4.2 — — 4.2 — Counterparties without offsetting positions - liabilities — ( 30.5 ) — — ( 30.5 ) $ 50.8 $ ( 367.5 ) $ 8.1 $ 4.5 $ ( 313.1 ) 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 located 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 (“ISDA”) agreements, which govern the key terms with our counterparties. Our ISDA agreements contain credit-risk related contingent features. Following the release of the collateral securing our TRGP Revolver, our derivative positions are no longer secured. As of December 31, 2022, we have outstanding net derivative positions that contain credit-risk related contingent features that are in a net liability position of $ 266.7 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 December 31, 2022, we would be required to post $ 31.4 million of collateral to certain counterparties 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 $ 255.8 million as of December 31, 2022. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the 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. The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue for the periods indicated: Derivatives in Cash Flow Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Hedging Relationships 2022 2021 2020 Commodity contracts $ ( 5.6 ) $ ( 534.6 ) $ ( 218.3 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2022 2021 2020 Revenues $ ( 373.0 ) $ ( 417.3 ) $ 90.8 Based on valuations as of December 31, 2022, we expect to reclassify commodity hedge related deferred gains of $ 63.4 million included in accumulated other comprehensive income (loss) into earnings before income taxes through the end of 2025, with $ 70.1 million of gains to be reclassified over the next twelve months. 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 the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the year ended December 31, 2022 , the unrealized mark-to-market losses are primarily attributable to unfavorable movements in natural gas forward basis prices, as compared to our positions. Derivatives Not Designated Location of Gain (Loss) Recognized in Gain (Loss) Recognized in Income on Derivatives as Hedging Instruments Income on Derivatives 2022 2021 2020 Commodity contracts Revenue $ ( 381.7 ) $ ( 73.3 ) $ 206.1 See Item 7A. Quantitative and Qualitative Disclosures About Market Risk, Note 15 – Fair Value Measurements and Note 24 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 15 — Fair Value Measurements Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“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 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 contracts 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 contracts 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 December 31, 2022, represent a net liability of $ 255.8 million, and reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. 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 $ 455.3 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 $ 56.3 million. 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. Long-term 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 long-term debt as follows: • the TRGP Revolver, commercial paper notes, Securitization Facility and Term Loan Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and • the TRGP senior unsecured notes and the Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the debt. 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: • Level 1 – observable inputs such as quoted prices in active markets; • Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and • Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions. The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: December 31, 2022 Carrying Fair Value Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Assets from commodity derivative contracts (1) $ 201.6 $ 201.6 $ — $ 201.6 $ — Liabilities from commodity derivative contracts (1) 457.4 457.4 — 457.4 — Financial Instruments Recorded on Our Cash and cash equivalents 219.0 219.0 — — — TRGP Revolver and Commercial Paper Program 1,298.7 1,298.7 — 1,298.7 — TRGP Senior unsecured notes 2,741.6 2,452.6 — 2,452.6 — Term Loan Facility 1,500.0 1,500.0 — 1,500.0 — Partnership's Senior unsecured notes 5,034.4 4,711.3 — 4,711.3 — Securitization Facility 800.0 800.0 — 800.0 — December 31, 2021 Carrying Fair Value Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Assets from commodity derivative contracts (1) $ 46.6 $ 46.6 $ — $ 46.6 $ — Liabilities from commodity derivative contracts (1) 363.3 363.3 — 363.3 — Financial Instruments Recorded on Our Cash and cash equivalents 158.5 158.5 — — — Partnership's Senior unsecured notes 6,465.7 6,924.5 — 6,924.5 — Securitization Facility 150.0 150.0 — 150.0 — (1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 14 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes . Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets We report certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable market prices or implied volatilities 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 derivatives valued using indicative price quotations whose contract length extends into unobservable periods. The fair value of these swaps is determined using a discounted cash flow valuation technique, for which the primary input to the valuation model is the forward commodity basis curve, and 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 (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. As of December 31, 2022 and December 31, 2021 , we had no derivative contracts categorized as Level 3. 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. During the year ended December 31, 2021, we recorded a non-cash pre-tax impairment of $ 452.3 million. The impairment charge is primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central operations in the Gathering and Processing segment. During the year ended December 31, 2020, we recorded non-cash pre-tax impairments of $ 2,442.8 million. The impairment charge is primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central operations and full impairment of our Coastal operations. For disclosures related to valuation techniques, see Note 4 – Acquisitions and Divestitures and Note 5 – Property, Plant and Equipment and Intangible Assets. The techniques described above 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.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions	Not e 16 — Related Party Transactions Transactions with Unconsolidated Affiliates The following table summarizes transactions with unconsolidated affiliates: GCF T2 Joint Ventures (1) Cayenne GCX (2) Little Missouri 4 Total 2022: Revenues $ — $ 1.2 $ — $ — $ 8.5 $ 9.7 Product purchases and fuel — — ( 4.7 ) ( 25.0 ) — ( 29.7 ) Operating expenses ( 1.7 ) ( 0.7 ) ( 0.3 ) — ( 2.6 ) ( 5.3 ) General and administrative expenses — — — — ( 0.9 ) ( 0.9 ) 2021: Revenues $ — $ 4.4 $ — $ — $ 10.6 $ 15.0 Product purchases and fuel — — ( 4.8 ) ( 66.5 ) — ( 71.3 ) Operating expenses ( 1.1 ) ( 2.3 ) ( 0.2 ) — ( 2.5 ) ( 6.1 ) General and administrative expenses — — — — ( 0.8 ) ( 0.8 ) 2020: Revenues $ 0.4 $ 4.5 $ — $ 0.2 $ 12.6 $ 17.7 Product purchases and fuel — — ( 5.9 ) ( 67.2 ) — ( 73.1 ) Operating expenses ( 16.0 ) ( 1.2 ) ( 0.2 ) — ( 2.2 ) ( 19.6 ) General and administrative expenses — — — — ( 0.8 ) ( 0.8 ) (1) Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100 % owned and consolidated by Targa. (2) Following the closing of the GCX Sale in May 2022, Targa no longer has an ownership interest in GCX. Relationship with Targa Resources Partners LP We provide general and administrative and other services to the Partnership, associated with the Partnership’s existing assets and assets acquired from third parties. The Partnership Agreement between the Partnership and us, as general partner of the Partnership, governs the reimbursement of costs incurred on behalf of the Partnership. The employees supporting the Partnership’s operations are our employees. The Partnership reimburses us for the payment of certain operating expenses, including compensation and benefits of operating personnel assigned to the Partnership’s assets, and for the provision of various general and administrative services for the benefit of the Partnership. We perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Commitments	Note 17 — Commitments Future non-cancelable commitments related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregate thereafter: In Aggregate 2023 2024 2025 2026 2027 Thereafter Land sites and rights of way (1) $ 247.6 $ 6.9 $ 6.7 $ 7.4 $ 9.4 $ 8.6 $ 208.6 (1) Land site lease and rights of way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual. Total expenses incurred under the above non-cancelable commitments were: 2022 2021 2020 Land sites and rights of way $ 5.8 $ 5.9 $ 6.5

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2022
Loss Contingency [Abstract]
Contingencies	Note 18 – 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, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, 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 December 26, 2018 , Vitol filed a lawsuit in the 80th District Court of Harris County (the “District Court”), Texas against Targa Channelview LLC, then a subsidiary of the Company (“Targa Channelview”), seeking recovery of $ 129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached the Splitter Agreement, which provided for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $ 129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit. On October 15, 2020 , the District Court awarded Vitol $ 129.0 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $ 10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company appealed the award in the Fourteenth Court of Appeals in Houston, Texas. In October 2020, we sold Targa Channelview but, under the agreements governing the sale, we retained the liabilities associated with the Vitol proceedings. On September 13, 2022, the Fourteenth Court of Appeals upheld the trial court’s judgment in part with regard to the return of Vitol’s prior payments, but modified the judgment to delete Vitol’s ability to recover any damages related to losses or demurrage on crude oil. We have filed a petition for review with the Supreme Court of Texas, and the appeal remains pending. The cumulative amount of interest on the award through December 31, 2022, if accrued, would have been approximately $ 42.6 million.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Revenue	Note 19 – 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 17 years . 2023 2024 2025 and after Fixed consideration to be recognized as of December 31, 2022 $ 449.9 $ 451.4 $ 2,163.0 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. For additional information on our revenue recognition policy, see Note 3 – Significant Accounting Policies, and for disclosures related to disaggregated revenue, see Note 24 – Segment Information.

Other Operating (Income) Expens

Other Operating (Income) Expense	12 Months Ended
	Dec. 31, 2022
Other Income and Expenses [Abstract]
Other Operating (Income) Expense	Not e 20 – Other Operating (Income) Expense Other operating (income) expense is comprised of the following: Year Ended December 31, 2022 2021 2020 (Gain) loss on sale or disposition of business and assets (1) $ ( 9.6 ) $ 2.0 $ 58.4 Write-down of assets (2) 9.8 10.3 55.6 Other — 0.1 2.6 Total other operating (income) expense $ 0.2 $ 12.4 $ 116.6 (1) Primarily related to the sale of assets in Channelview, Texas in 2020. See Note 4 – Acquisitions and Divestitures for further discussion regarding these sales. (2) Related to the write-down of certain assets to their recoverable amounts.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income Taxes	Note 21 – Inco me Taxes Components of the federal and state income tax provisions for the periods indicated are as follows: 2022 2021 2020 Current expense (benefit) $ 6.7 $ 2.7 $ ( 15.4 ) Deferred expense (benefit) 125.1 12.1 ( 232.7 ) Total income tax expense (benefit) $ 131.8 $ 14.8 $ ( 248.1 ) Our deferred income tax assets and liabilities as of December 31, 2022 and 2021 consist of recognition differences related to certain types of costs as follows: 2022 2021 Deferred tax assets: Net operating loss $ 1,568.5 $ 1,411.3 Disallowed business interest expense carryforward 10.3 3.8 Deferred tax assets before valuation allowance 1,578.8 1,415.1 Valuation allowance ( 36.9 ) ( 214.4 ) Deferred tax assets 1,541.9 1,200.7 Deferred tax liabilities: Investments (1) ( 1,842.0 ) ( 1,323.0 ) Property, plant, and equipment ( 4.2 ) ( 4.1 ) Other ( 23.4 ) ( 9.6 ) Deferred tax liabilities ( 1,869.6 ) ( 1,336.7 ) Net deferred tax asset (liability) $ ( 327.7 ) $ ( 136.0 ) Net deferred tax asset (liability) Federal $ ( 290.5 ) $ ( 106.7 ) State ( 37.2 ) ( 29.3 ) Long-term deferred tax liability, net $ ( 327.7 ) $ ( 136.0 ) (1) Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of our investment in the Partnership. On March 27, 2020, the Coronavirus Aid, Relief and Economic Security (“CARES”) Act was enacted. The CARES Act provided corporate taxpayers an expanded five-year net operating loss (“NOL”) carryback period for losses generated in tax years 2018 through 2020. Additionally, the CARES Act allowed corporate taxpayers to request an immediate refund of alternative minimum tax credits. We requested a cash refund from the Internal Revenue Service (“IRS”) of approximately $ 44 million related to the CARES Act provisions and received the refund in the second quarter of 2020. On October 6, 2021 and April 7, 2022, we received notice from the IRS that it intends to audit three direct and indirectly wholly-owned subsidiaries of the Company (Targa Resources Partners LP, Targa Downstream LLC and Targa Midstream Services LLC) treated as partnerships for federal tax purposes for the 2019 and 2020 tax years. We are responding to the information requests from the IRS on these audits. The Company is not aware of any potential audit findings that would give rise to adjustments to taxable income and does not anticipate material changes related to these audits. All federal statutes of limitations for returns filed in 2019 (for calendar year 2018) have expired. For Texas, the statute of limitations has expired for 2018 returns (for calendar year 2017). Similarly, the statute of limitations expired on substantially all 2018 state income tax returns that were filed prior to October 15, 2019. However, tax authorities have the ability to review and adjust carryover attributes (e.g., NOLs) generated in a closed tax year if utilized in an open tax year. During the preparation of the Company's 2021 consolidated financial statements, the Company identified errors related to its 2020 state tax provision. The Company does not believe these errors are material to its previously issued historical consolidated financial statements for any of the periods impacted and accordingly, has not adjusted the historical financial statements. In 2021, the Company recorded an additional $ 23.3 million of income tax expense in the Consolidated Statements of Operations and corresponding increase to its deferred tax liabilities in the Consolidated Balance Sheets. As of December 31, 2022, we have total NOL carryforwards of $ 6.8 billion, $ 1.4 billion of which will expire between 2036 and 2037 . The remaining $ 5.4 billion NOL will not expire, but is limited to offsetting 80 % of taxable income per year. During 2020, we recorded a federal tax-effected valuation allowance of $ 194.2 million against our deferred tax assets, primarily due to the tax consequences of the impairment of long-lived assets. See Note 5 – Property Plant and Equipment and Intangible Assets. As of December 31, 2022 , our tax effected valuation allowance was $ 36.9 million, a decrease of $ 177.5 million from December 31, 2021 . Of this valuation allowance, $ 6.4 million of the valuation allowance is federal, and the remaining $ 30.5 million is state. Set forth below is the reconciliation between our Income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision in our Consolidated Statements of Operations for the periods indicated: Income tax reconciliation: 2022 2021 2020 Income (loss) before income taxes $ 1,663.2 $ 436.9 $ ( 1,573.1 ) Less: Net income attributable to noncontrolling interest ( 335.9 ) ( 350.9 ) ( 228.9 ) Income attributable to Targa Resources Corp. before income taxes 1,327.3 86.0 ( 1,802.0 ) Federal statutory income tax rate 21 % 21 % 21 % Provision for federal income taxes 278.7 18.1 ( 378.4 ) Valuation allowance ( 177.5 ) ( 46.2 ) 194.2 State income taxes, net of federal tax benefit 33.6 ( 5.4 ) ( 51.2 ) CARES Act NOL carryback — — ( 16.9 ) State tax provision error correction — 23.3 — Return-to-provision ( 0.6 ) ( 1.3 ) — Change in statutory income tax rate ( 1.7 ) 21.0 — Permanent adjustments 5.6 4.1 4.5 Stock compensation shortfall/(windfall) ( 6.3 ) 1.4 — Other, net — ( 0.2 ) ( 0.3 ) Income tax provision (benefit) $ 131.8 $ 14.8 $ ( 248.1 ) We have not identified any uncertain tax positions. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves for uncertain income tax positions have been recorded. On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “IRA”) which, among other things, introduced a corporate alternative minimum tax (the “CAMT”), imposed a 1 % excise tax on stock buybacks and tax incentives to promote clean energy. Under the CAMT, a 15 % minimum tax will be imposed on certain financial statement income of “applicable corporations.” The IRA treats a corporation as an applicable corporation in for any taxable year in which the “average annual adjusted financial statement income” of such corporation for the three taxable year period ending prior to such taxable year exceeds $ 1 billion. On December 27, 2022, the Department of the Treasury and the IRS issued guidance on the application of the CAMT which may be relied upon until final regulations are released. Based on our interpretation of the IRA, the CAMT and related guidance and a number of operational, economic, accounting and regulatory assumptions, we do not anticipate qualifying as an “applicable corporation” in the near term, but we are likely to become an applicable corporation in a subsequent tax year. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash available for distribution in that year, but provide an offsetting credit against our regular U.S. federal income tax liability for a future year. As a result, our current expectation is that the impact of the CAMT is limited to timing differences in future tax years. Given the complexities of the IRA and the CAMT, we will continue to monitor and evaluate the potential future impact to our financial statements. Subsequent Events In January 2023, the IRS notified us that it completed the examination of Targa’s NOL carryback and associated refund previously claimed under the CARES Act with no exceptions. Additionally, in January 2023, we received notice from the IRS that it intends to audit an indirectly wholly-owned subsidiary of the Company (Targa Badlands Holdings LLC) which is treated as a partnership for federal tax purposes for the 2020 tax year.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 22 - S upplemental Cash Flow Information Year Ended December 31, 2022 2021 2020 Cash: Interest paid, net of capitalized interest (1) $ 401.3 $ 356.0 $ 374.1 Income taxes (received) paid, net 1.6 1.3 43.7 Non-cash investing activities: Change in deadstock commodity inventory $ ( 3.8 ) $ ( 15.0 ) $ 5.3 Impact of capital expenditure accruals on property, plant and equipment, net 60.1 53.0 ( 226.9 ) Transfers from materials and supplies inventory to property, plant and equipment — 2.4 2.1 Change in ARO liability and property, plant and equipment due to revised cash flow estimate and additions 0.8 ( 0.2 ) ( 1.8 ) Non-cash financing activities: Non-cash distributions to noncontrolling interests (2) $ 64.2 $ — $ — Changes in accrued distributions to noncontrolling interests ( 26.1 ) ( 50.9 ) ( 5.2 ) Reduction of owner's equity related to accrued dividends on unvested equity awards under share compensation arrangements 7.1 3.1 5.4 Accretion of deemed dividends on Series A Preferred — — 37.6 Lease liabilities arising from recognition of right-of-use assets: Operating lease $ 9.7 $ 20.1 $ 13.2 Finance lease (3) 220.7 24.7 6.0 (1) Interest capitalized on major projects was $ 16.3 million, $ 4.1 million and $ 33.0 million for the years ended December 31, 2022, 2021 and 2020 . (2) Represents the transfer of an undivided interest in certain gas gathering and processing facilities to a joint owner upon Targa's recovery of a specified payout amount for our initial full funding of the facilities. (3) The December 31, 2022 balance includes $ 171.2 million related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended.

Compensation Plans

Compensation Plans	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Compensation Plans	Note 23 – Co mpensation Plans 2010 Targa Resources Corp. Stock Incentive Plan In December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan (the “2010 TRGP Plan”) for employees, consultants and non-employee directors of the Company. In May 2017, the 2010 TRGP Plan was amended and restated. Total authorized shares of common stock under the plan is 15,000,000 , comprised of 5,000,000 shares originally available and an additional 10,000,000 shares that became available in May 2017. The 2010 TRGP Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as Incentive Options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards, (v) phantom stock awards, (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards. Unless otherwise specified, the compensation costs for the awards listed below were recognized as expenses over related vesting periods based on the grant-date fair values, reduced by forfeitures incurred. Restricted Stock Awards - Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends, and paid in cash when the award vests. Upon issuance, the restricted stock awards will be included in the outstanding shares of our common stock. The Compensation Committee of the Targa board of directors (the “Compensation Committee”) awarded our common stock to our outside directors. In 2022, 2021 and 2020, we issued 31,117 , 67,591 and 31,621 shares of director grants with weighted average grant-date fair values of $ 56.32 , $ 30.33 and $ 39.85 , respectively. Restricted Stock Units Awards – Restricted Stock Units (“RSUs”) are similar to restricted stock, except that shares of common stock are not issued until the RSUs vest. The vesting periods generally vary from one to six years . In 2022, 2021 and 2020, we issued 943,352 , 848,630 and 1,299,592 shares of RSUs with weighted average grant-date fair values of $ 63.87 , $ 37.94 and $ 24.64 . Restricted Stock Units in Lieu of Bonus – In 2020 and 2019, we granted 81,336 and 95,687 shares of RSUs in lieu of cash bonuses for certain of our executives at the weighted average grant-date fair value of $ 41.39 and $ 42.83 . The 2020 and 2019 grants vested in 2021 and 2022, respectively. The following table summarizes the restricted stock and RSUs under the 2010 TRGP Plan in shares and in dollars for the year indicated. Number Weighted Average Outstanding at December 31, 2021 3,690,828 $ 37.42 Granted 974,469 63.63 Forfeited ( 83,372 ) 38.80 Vested ( 1,353,507 ) 44.12 Outstanding at December 31, 2022 3,228,418 42.60 Performance Share Units During 2022, 2021 and 2020 , we granted 173,011 , 319,320 and 291,365 performance share units (“PSUs”) to executive management for the 2022, 2021 and 2020 compensation cycle that will vest/have vested in January 2025 , January 2024 and January 2023 . The PSUs granted under the 2010 TRGP Plan are three-year equity-settled awards linked to the performance of shares of our common stock. The awards also include dividend equivalent rights (“DERs”) that are based on the notional dividends accumulated during the vesting period. The vesting of the PSUs is dependent on the satisfaction of a combination of certain service-related conditions and the Company’s total shareholder return (“TSR”) relative to the TSR of the members of a specified comparator group of publicly-traded midstream companies (the “LTIP Peer Group”) measured over designated periods. For the PSUs granted in 2020, 2021 and 2022, the TSR performance factor is determined by the Compensation Committee based on relative TSR over a cumulative three-year performance period. The Compensation Committee determines a guideline performance percentage for the performance period and the percentage may then be decreased or increased by the Compensation Committee at its discretion. The grantee will become vested in a number of PSUs equal to the target number awarded multiplied by the TSR performance factor, and vested PSUs will be settled by the issuance of Company common stock. The value of dividend equivalent rights will be paid in cash when the awards vest. Compensation cost for equity-settled PSUs was recognized as an expense over the performance period based on fair value at the grant date. The compensation cost will be reduced if forfeitures occur. Fair value was calculated using a simulated share price that incorporates peer ranking. DERs associated with equity-settled PSUs were accrued over the performance period as a reduction of owners’ equity. We evaluated the grant date fair value using a Monte Carlo simulation model and historical volatility assumption with an expected term of three years . The expected volatilities were 80 %, 80 % and 32 % for PSUs granted in 2022, 2021 and 2020. The following table summarizes the PSUs under the 2010 TRGP Plan in shares and in dollars for the years indicated. Number Weighted Average Outstanding at December 31, 2021 867,209 $ 63.24 Granted 173,011 108.55 Forfeited ( 13,779 ) 74.75 Vested ( 256,524 ) 64.46 Outstanding at December 31, 2022 769,917 72.81 Stock Compensation Expenses Stock compensation expense under our plans totaled $ 57.5 million, $ 59.2 million, and $ 66.3 million for the years ended December 31, 2022, 2021 and 2020. As of December 31, 2022, we have $ 88.8 million of unrecognized compensation expense associated with share-based awards and an approximate remaining weighted average vesting periods of 2.3 years related to our various compensation plans. The fair values of share-based awards vested in 2022, 2021 and 2020 were $ 93.0 million, $ 73.8 million and $ 62.7 million. Cash dividends paid for the vested awards were $ 9.6 million, $ 8.7 million and $ 9.4 million for 2022, 2021 and 2020. In relation to our equity compensation plans, we recognized $ 6.7 million in windfall tax benefits for the year ended December 31, 2022 , $ 1.6 million and $ 2.0 million of tax deficiencies for the years ended December 31, 2021 and 2020, respectively. Subsequent Events In January 2023, the Compensation Committee made the following awards under the 2010 TRGP Plan. • 23,518 shares of restricted stock to our outside directors that will vest in January 2024 . • 140,020 shares of RSUs to executive management for the 2023 compensation cycle that will vest in January 2026 . • 140,020 shares of PSUs to executive management for the 2023 compensation cycle that will vest in January 2026 . In January 2023, 31,117 shares of director grants vested with no shares withheld to satisfy tax withholding obligations. In January 2023, 472,265 shares of RSUs vested with 165,203 shares withheld to satisfy tax withholding obligations. In January 2023, 728,417 shares of 2021 PSUs vested with 272,681 shares withheld to satisfy tax withholding obligations. Targa 401(k) Plan We have a 401(k) plan whereby we match 100 % of up to 5 % of an employee’s contribution (subject to certain limitations in the plan). We also contribute an amount equal to 3 % of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100 % in cash. As part of our cost reduction measures in response to the COVID-19 pandemic, we temporarily suspended our matching contributions in the second quarter of 2020, and reinstated such contributions on January 1, 2021. We made contributions to the 401(k) plan totaling $ 26.6 million, $ 21.8 million and $ 16.2 million during 2022, 2021 and 2020 .

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
Segment Information	Note 24 — 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 and the Gulf of Mexico. 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 Grand Prix, which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our Downstream facilities in Mont Belvieu, Texas. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment, and 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. Reportable segment information is shown in the following tables: Year Ended December 31, 2022 Gathering and Processing Logistics and Transportation Other Corporate Total Revenues Sales of commodities $ 919.7 $ 18,448.7 $ ( 302.4 ) $ — $ 19,066.0 Fees from midstream services 1,157.3 706.5 — — 1,863.8 2,077.0 19,155.2 ( 302.4 ) — 20,929.8 Intersegment revenues Sales of commodities 9,169.4 541.7 — ( 9,711.1 ) — Fees from midstream services 0.6 45.2 — ( 45.8 ) — 9,170.0 586.9 — ( 9,756.9 ) — Revenues $ 11,247.0 $ 19,742.1 $ ( 302.4 ) $ ( 9,756.9 ) $ 20,929.8 Operating margin (1) $ 1,981.0 $ 1,456.3 $ ( 302.4 ) Other financial information: Total assets (2) $ 12,133.6 $ 7,175.7 $ — $ 250.7 $ 19,560.0 Goodwill $ 45.2 $ — $ — $ — $ 45.2 Capital expenditures $ 918.1 $ 453.0 $ — $ 23.3 $ 1,394.4 Year Ended December 31, 2021 Gathering and Processing Logistics and Transportation Other Corporate Total Revenues Sales of commodities $ 606.8 $ 15,111.6 $ ( 115.9 ) $ — $ 15,602.5 Fees from midstream services 747.3 600.0 — — 1,347.3 1,354.1 15,711.6 ( 115.9 ) — 16,949.8 Intersegment revenues Sales of commodities 6,067.9 409.5 — ( 6,477.4 ) — Fees from midstream services 3.5 38.6 — ( 42.1 ) — 6,071.4 448.1 — ( 6,519.5 ) — Revenues $ 7,425.5 $ 16,159.7 $ ( 115.9 ) $ ( 6,519.5 ) $ 16,949.8 Operating margin (1) $ 1,325.3 $ 1,264.3 $ ( 115.9 ) Other financial information: Total assets (2) $ 7,998.1 $ 7,041.9 $ 14.0 $ 154.2 $ 15,208.2 Goodwill $ 45.2 $ — $ — $ — $ 45.2 Capital expenditures $ 471.7 $ 78.1 $ — $ 10.7 $ 560.5 Year Ended December 31, 2020 Gathering and Processing Logistics and Transportation Other Corporate Total Revenues Sales of commodities $ 659.9 $ 6,281.4 $ 229.7 $ — $ 7,171.0 Fees from midstream services 487.2 602.1 — — 1,089.3 1,147.1 6,883.5 229.7 — 8,260.3 Intersegment revenues Sales of commodities 2,173.2 205.9 — ( 2,379.1 ) — Fees from midstream services 6.5 31.5 — ( 38.0 ) — 2,179.7 237.4 — ( 2,417.1 ) — Revenues $ 3,326.8 $ 7,120.9 $ 229.7 $ ( 2,417.1 ) $ 8,260.3 Operating margin (1) $ 1,017.7 $ 1,128.0 $ 229.7 Other financial information: Total assets (2) $ 8,743.5 $ 6,860.0 $ 86.3 $ 185.9 $ 15,875.7 Goodwill $ 45.2 $ — $ — $ — $ 45.2 Capital expenditures $ 293.9 $ 414.0 $ — $ 18.9 $ 726.8 (1) Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues. (2) Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities. The following table shows our consolidated revenues disaggregated by product and service for the periods presented: Year Ended December 31, 2022 2021 2020 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $ 5,470.2 $ 3,523.9 $ 1,359.0 NGL 13,785.2 12,210.8 5,181.3 Condensate and crude oil 565.3 358.4 264.0 Petroleum products — — 69.8 19,820.7 16,093.1 6,874.1 Non-customer revenue: Derivative activities - Hedge ( 373.0 ) ( 417.3 ) 90.8 Derivative activities - Non-hedge (1) ( 381.7 ) ( 73.3 ) 206.1 ( 754.7 ) ( 490.6 ) 296.9 Total sales of commodities 19,066.0 15,602.5 7,171.0 Fees from midstream services: Revenue recognized from contracts with customers: Gathering and processing 1,137.2 730.3 476.0 NGL transportation, fractionation and services 285.1 190.6 163.1 Storage, terminaling and export 372.2 379.7 401.9 Other 69.3 46.7 48.3 Total fees from midstream services 1,863.8 1,347.3 1,089.3 Total revenues $ 20,929.8 $ 16,949.8 $ 8,260.3 (1) Represents derivative activities that are not designated as hedging instruments under ASC 815. The following table shows a reconciliation of reportable segment Operating margin to Income (loss) before income taxes for the periods presented: Year Ended December 31, 2022 2021 2020 Reconciliation of reportable segment operating Gathering and Processing operating margin $ 1,981.0 $ 1,325.3 $ 1,017.7 Logistics and Transportation operating margin 1,456.3 1,264.3 1,128.0 Other operating margin ( 302.4 ) ( 115.9 ) 229.7 Depreciation and amortization expense ( 1,096.0 ) ( 870.6 ) ( 865.1 ) General and administrative expense ( 309.7 ) ( 273.2 ) ( 254.6 ) Impairment of long-lived assets — ( 452.3 ) ( 2,442.8 ) Interest expense, net ( 446.1 ) ( 387.9 ) ( 391.3 ) Equity earnings (loss) 9.1 ( 23.9 ) 72.6 Gain (loss) on sale or disposition of assets 9.6 ( 2.0 ) ( 58.4 ) Write-down of assets ( 9.8 ) ( 10.3 ) ( 55.6 ) Gain (loss) from financing activities ( 49.6 ) ( 16.6 ) 45.6 Gain (loss) from sale of equity method investment 435.9 — — Other, net ( 15.1 ) — 1.1 Income (loss) before income taxes $ 1,663.2 $ 436.9 $ ( 1,573.1 )

Significant Accounting Polici_2

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Consolidation Policy	Consolidation Policy Our consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain gas gathering and processing facilities in which we own an undivided interest and are responsible for our proportionate share of the costs and expenses of the facilities. Third party ownership interests in our controlled subsidiaries are presented as noncontrolling interests within the equity section of our Consolidated Balance Sheets, except in the case of undivided interest ownership. In our Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income (Loss), noncontrolling interests reflect the attribution of results to third-party investors. All intercompany balances and transactions have been eliminated in consolidation. As of December 31, 2022, our consolidated joint ventures include the following: Gathering and Processing Segment • 50 % ownership interest in the Carnero G&P LLC; • 60 % ownership interest in Centrahoma Processing LLC; • 55 % ownership interest in Targa Badlands LLC; • 72.8 % undivided interest in the assets of Targa Pipeline Mid-Continent WestTex LLC; and • 76.8 % ownership interest in Venice Energy Services Company, LLC. Logistics and Transportation Segment • 88 % ownership interest in Cedar Bayou Fractionators, L.P.; • 75 % ownership interest in Grand Prix Pipeline LLC through the Grand Prix Joint Venture (prior to the Grand Prix Transaction, as defined in Note 4 – Acquisitions and Divestitures); and • 80 % ownership interest in Targa Train 7 LLC. We apply the equity method of accounting to investments over which we exercise significant influence over the operating and financial policies of our investee, but do not exercise control. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as a non-cash pre-tax impairment loss within Equity earnings (loss) in our Consolidated Statements of Operations. As of December 31, 2022, our investments in unconsolidated affiliates include the following: Gathering and Processing Segment • 50 % ownership interest in Little Missouri 4 LLC (“Little Missouri 4”). Logistics and Transportation Segment • 50 % ownership interest in Cayenne Pipeline, LLC (“Cayenne”); and • 38.8 % ownership interest in Gulf Coast Fractionators (“GCF”).
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Estimates and judgments are based on information available at the time such estimates and judgments are made. Changes in facts and circumstances may result in revised estimates and actual results could differ materially from those estimates. Estimates and judgments are used in, among other things, (i) estimating unbilled revenues, product purchases and operating and general and administrative cost accruals, (ii) developing fair value assumptions, including estimates of future cash flows and discount rates, (iii) analyzing long-lived assets for possible impairment, (iv) estimating the useful lives of assets, (v) estimating contingencies, guarantees and indemnifications and (vi) estimating redemption value of mandatorily redeemable preferred interests.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents include all cash on hand, demand deposits, and short-term, highly liquid investments that are readily convertible into cash, and have original maturities of three months or less.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. We estimate the allowance for doubtful accounts through various procedures, including extensive review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts. We continuously evaluate our ability to collect amounts owed to us. Receivables are considered past due if full payment is not received by the contractual due date. Our evaluation procedures also include performing account reconciliations, dispute resolution and payment confirmation. As the financial condition of any counterparty changes, circumstances develop or additional information becomes available, adjustments to our allowance may be required.
Inventories	Inventories Our inventories consist primarily of NGL product inventories, which are valued at the lower of cost or net realizable value, using the average cost method. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are included in Property, plant and equipment.
Product Exchanges	Product Exchanges Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities.
Gas Processing Imbalances	Gas Processing Imbalances Quantities of natural gas and/or NGLs over-delivered or under-delivered, related to certain gas plant operational balancing agreements, are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or net realizable value using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.
Derivative Instruments	Derivative Instruments We utilize derivative instruments to manage the volatility of our cash flows due to fluctuating energy commodity prices. For balance sheet classification purposes, we analyze the fair values of the derivative instruments on a contract by contract basis and report the related fair values and any related collateral by counterparty on a gross basis. Cash flows from derivative instruments designated as hedges are recognized in the same financial statement line item as the cash flows from the respective item being hedged. We formally document all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in achieving the offset of changes in cash flows attributable to the hedged risk. We record all derivative instruments at fair value with the exception of those that we apply the normal purchases and normal sales election. The table below summarizes the accounting treatment for our derivative instruments, and the impact on our consolidated financial statements: Recognition and Measurement Derivative Treatment Balance Sheet Income Statement Normal Purchases and Normal Sales Fair value not recorded Earnings recognized when volumes are physically delivered or received Mark-to-Market Recorded at fair value Change in fair value recognized currently in earnings Cash Flow Hedge Recorded at fair value with changes in fair value deferred in Accumulated Other Comprehensive Income ("AOCI") The gain/loss on the derivative instrument is reclassified out of AOCI into earnings when the forecasted transaction occurs We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated, ceases to be highly effective or the forecasted transaction is no longer probable to occur. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment is recorded at acquisition cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including our expected use of the asset and the supply of, and demand for, hydrocarbons in the markets served, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations. Expenditures for routine maintenance and repairs are expensed as incurred. Expenditures to refurbish an asset that increases its existing service potential or prevents environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. Certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs, are capitalized.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets We evaluate long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate our carrying amount of an asset may not be recoverable, including changes to our estimates that could have an impact on our assessment of asset recoverability. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. These cash flow estimates require us to make judgments and assumptions related to operating and cash flow results, economic obsolescence, the business climate, contractual, legal and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize a non-cash pre-tax impairment loss equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs, and the use of an appropriate terminal value and discount rate. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our long-lived assets and the recognition of additional impairments. We believe our estimates and models used to determine fair value are similar to what a market participant would use.
Goodwill	Goodwill Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not subject to amortization but is tested for impairment at least annually. This test requires us to attribute goodwill to an appropriate reporting unit, which is an operating segment or one level below an operating segment (also known as a component). We evaluate goodwill for impairment on November 30 of each year, or whenever impairment indicators are present. Prior to us conducting the goodwill impairment test, we complete a review of the carrying values of our long-lived assets, including property, plant and equipment and other intangible assets. If it is determined that the carrying values are not recoverable, we reduce the carrying values of the long-lived assets pursuant to our policy on property, plant and equipment. As part of our goodwill impairment test, we may first assess qualitative factors to determine if the quantitative goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or determine that a goodwill impairment test is required, our annual goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount (including attributed goodwill). We recognize an impairment loss in our Consolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment loss will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, when measuring goodwill, we consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit, if applicable.
Intangible Assets	Intangible Assets Our intangible assets include producer dedications under long-term contracts and customer relationships associated with business and asset acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. We amortize the costs of our assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis, where such pattern is not readily determinable, over the periods in which we benefit from services provided to customers.
Asset Retirement Obligations	Asset Retirement Obligations Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. We record a liability and increase the basis in the underlying asset for the present value of each expected ARO when there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction. Our obligations are estimated based on discounted cash flow (“DCF”) estimates. Over time, the ARO liability is accreted to its present value as a period cost and the capitalized amount is depreciated over the asset’s respective useful life. At least annually, we review the projected timing and amount of AROs and reflect revisions as an increase or decrease in the carrying amount of the liability and the basis in the underlying asset. Upon settlement, we will recognize any difference between the recorded amount and the actual settlement cost as a gain or loss.
Debt Issuance Costs	Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt and any original issue discount or premium are deferred and charged to interest expense over the term of the related debt. Debt issuance costs related to revolving credit facilities and commercial paper notes are presented as other long-term assets, and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction to the carrying amount of long-term debt on the Consolidated Balance Sheets. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issuance costs.
Accounts Receivable Securitization Facility	Accounts Receivable Securitization Facility Proceeds from the sale or contribution of certain receivables under the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities in our Consolidated Statements of Cash Flows.
Environmental Liabilities and Other Loss Contingencies	Environmental Liabilities and Other Loss Contingencies We accrue a liability for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources, when the loss is probable and reasonably estimable.
Income Taxes	Income Taxes We file many income tax returns with the United States Department of the Treasury, as well as numerous states. We are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense, together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are reported on a net basis by jurisdiction within our Consolidated Balance Sheets. We report these timing differences based on statutory tax rates applicable to the scheduled timing difference reversal periods. We assess the likelihood that we will recover our deferred tax assets from future taxable income. We establish a valuation allowance if we believe that it is more likely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax assets will not be realized. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence to determine whether, based on the weight of the evidence, we need a valuation allowance. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.
Dividends	Dividends Preferred and common dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital.
Mandatorily Redeemable Preferred Interests	Mandatorily Redeemable Preferred Interests Mandatorily redeemable preferred interests, which represent our joint venture partners’ interests in two joint ventures, have been included in other long-term liabilities on our Consolidated Balance Sheets, and such interests with multiple or indeterminate redemption dates were reported at their estimated redemption value as of the reporting dates. These point-in-time values did not represent the amount that ultimately would be redeemed in the future. Changes in the redemption value have been included in interest expense, net in our Consolidated Statements of Operations. Effective September 1, 2022, we redeemed our joint venture partner's mandatorily redeemable preferred interests in the two joint ventures that, separately, owned a 100 % interest in the WestOK natural gas gathering and processing system and a 72.8 % undivided interest in the WestTX natural gas gathering and processing system. Prior to the redemption, the joint ventures collectively held $ 1.9 billion face value in notes receivable from our partner, which were due July 2042 . The interest rate payable under the notes receivable was a variable LIBOR-based rate. For the years ended December 31, 2022, 2021 and 2020, interest income (expense) on the notes receivable was $( 1.8 ) million, $ 12.3 million and $ 8.6 million, net of the return paid to our partner, which was reflected within Interest expense, net in our Consolidated Statements of Operations.
Comprehensive Income	Comprehensive Income Comprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as cash flow hedges
Revenue Recognition	Revenue Recognition Our operating revenues are primarily derived from the following activities: • sales of natural gas, NGLs, condensate and crude oil; • services related to compressing, gathering, treating, and processing of natural gas; and • services related to NGL fractionation, terminaling and storage, transportation and treating. We have multiple types of contracts with commercial counterparties and many of these contracts contain embedded fees with settlement provisions that deduct these fees from the sales price paid by Targa in exchange for commodities. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606, Revenue from Contracts with Customers . Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases and fuel. Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues. We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis. Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price. Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract. The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation. Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days . As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue. We have certain long-term contractual arrangements under which we have received consideration, but for which all conditions for revenue recognition have not been met. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided. Contract Assets We classify our contract assets as receivables because we generally have an unconditional right to payment for the commodities sold or services performed at the end of the reporting period.
Share-Based Compensation	Share-Based Compensation We award share-based compensation to employees and non-employee directors in the form of restricted stock, restricted stock units and performance share units. Compensation expense on our equity-classified awards is recorded at grant-date fair value. Compensation expense is recognized in general and administrative expense over the requisite service period of each award, and forfeitures are recognized as they occur. We may purchase a portion of the shares issued to satisfy employees’ tax withholding obligations on vested awards. These shares are recorded in treasury stock, at cost, and cash paid is classified as a financing activity in our Consolidated Statements of Cash Flows. All excess tax benefits and tax deficiencies related to share-based compensation are recognized as income tax benefit or expense in our Consolidated Statements of Operations, with the tax effects of exercised or vested awards treated as discrete items in the reporting period which they occur. Excess tax benefits are classified as an operating activity.
Earnings per Share	Earnings per Share Basic earnings (loss) per common share (“EPS”) is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock, restricted stock units and performance share units. Diluted EPS includes any dilutive effect of preferred stock, unvested restricted stock, restricted stock units and performance share units. The dilutive effect is calculated through the application of (i) the if-converted method for convertible preferred stock, and (ii) the treasury stock method for unvested stock awards.
Leases	Leases We recognize the following for all leases (with the exception of short-term leases) at the commencement date: • A lease liability, which is a lessee’s obligation to make lease payments arising from a lease. • A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered short-term leases, which are excluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of future lease payments over the lease term. The right-of-use asset also includes any lease prepayments and excludes lease incentives. As most of the Company’s leases do not provide an implicit interest rate, we use our incremental borrowing rate as the discount rate to compute the present value of our lease liability. The discount rate applied is determined based on information available on the date of adoption for all leases existing as of that date, and on the date of lease commencement for all subsequent leases. Our lease arrangements may include variable lease payments based on an index or market rate, or may be based on performance. For variable lease payments based on an index or market rate, we estimate and apply a rate based on information available at the commencement date. Variable lease payments based on performance are excluded from the calculation of the right-of-use asset and lease liability, and are recognized in our Consolidated Statements of Operations when the contingency underlying such variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options are included in the measurement of our right-of-use asset and liability, provided we determine that we are reasonably certain to exercise the option.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Recently Adopted Accounting Pronouncements Revenue Contract Assets and Liabilities Acquired in a Business Combination In October 2021, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2021-08, Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. Amendments in this update require application of Accounting Standards Codification 606, Revenue from Contracts with Customers ("ASC 606") to recognize and measure contract assets and contract liabilities from contracts with customers acquired in a business combination. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2022, with early adoption permitted. However, an entity that elects to early adopt must apply the amendments to all business combinations that occurred during the fiscal year that includes the interim period. We early adopted the amendments on April 1, 2022 and have applied them to business combinations in 2022. We applied the amendments to the Delaware Basin Acquisition, as defined in Note 4 – Acquisitions and Divestitures, by recognizing contract liabilities from contracts with customers in accordance with ASC 606. Recently issued accounting pronouncements not yet adopted Supplier Finance Programs In September 2022, the FASB issued ASU 2022-04, Liabilities—Supplier Finance Programs (Subtopic 405-50). Amendments in this update require annual and interim disclosure of the key terms of outstanding supplier finance programs and a rollforward of the related obligations. These amendments do not affect the recognition, measurement or financial statement presentation of the supplier finance program obligations. These amendments are effective for fiscal years beginning after December 15, 2022, except for the rollforward requirements, which is effective for fiscal years beginning after December 15, 2023. We have evaluated the effect of the amendments on our consolidated financial statements and will disclose the required information beginning in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2023.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2022
Business Combinations [Abstract]
Summary of Preliminary Fair Values Assigned to Assets Acquired and Liabilities Assumed	The following table summarizes the purchase price allocation based on the final fair values assigned to assets acquired and liabilities assumed (in millions): Cash and cash equivalents $ 9.9 Trade receivables, net of allowances (1) 211.0 Other current assets 3.5 Property, plant and equipment, net 1,669.0 Intangible assets, net 1,882.0 Other long-term assets 57.3 Current liabilities ( 236.7 ) Other long-term liabilities ( 100.7 ) Purchase price $ 3,495.3 (1) The fair value of the assets acquired includes trade receivables of $ 211.0 million. The gross amount due under contract was $ 213.4 million, of which $ 2.4 million was expected to be uncollectible. Trade receivables, net of allowances, excludes $ 18.5 million that was due from Targa. We reflected this settlement of a preexisting relationship as a reduction of the purchase price in accordance with ASC 805.
Schedule of Unaudited Pro Forma Financial Information	The following unaudited pro forma summary presents the consolidated results of operations for the years ended December 31, 2022 and 2021 as if the Delaware Basin Acquisition had occurred on January 1, 2021. 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. Year Ended December 31, 2022 2021 Revenues $ 21,268.9 $ 17,464.7 Net income (loss) 1,477.4 215.7

Property, Plant and Equipment_2

Property, Plant and Equipment and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2022
Property Plant And Equipment And Intangible Assets [Abstract]
Property Plant and Equipment and Intangible Assets	Property, Plant and Equipment and Intangible Assets December 31, 2022 December 31, 2021 Estimated Useful Lives (In Years) Gathering systems $ 10,403.1 $ 9,318.2 5 to 20 Processing and fractionation facilities 7,421.2 6,388.8 5 to 25 Terminaling and storage facilities 1,341.6 1,313.8 5 to 25 Transportation assets 2,919.3 2,671.0 10 to 50 Other property, plant and equipment 387.6 340.9 3 to 50 Land 163.3 160.8 — Construction in progress 1,011.0 347.0 — Finance lease right-of-use assets 266.1 55.6 5 to 14 Property, plant and equipment 23,913.2 20,596.1 Accumulated depreciation, amortization and impairment ( 9,698.6 ) ( 8,928.4 ) Property, plant and equipment, net $ 14,214.6 $ 11,667.7 Intangible assets 4,379.7 2,642.9 10 to 20 Accumulated amortization and impairment ( 1,645.1 ) ( 1,548.1 ) Intangible assets, net $ 2,734.6 $ 1,094.8
Schedule of Changes in Intangible Assets	The changes in our intangible assets are as follows: December 31, 2022 December 31, 2021 Balance at beginning of period $ 1,094.8 $ 1,382.4 Additions from Delaware Basin Acquisition 1,882.0 — Impairment — ( 156.6 ) Amortization ( 242.2 ) ( 131.0 ) Balance at end of period $ 2,734.6 $ 1,094.8

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	December 31, 2022 December 31, 2021 Permian Midland $ 23.2 $ 23.2 Permian Delaware 22.0 22.0 Goodwill $ 45.2 $ 45.2

Investments in Unconsolidated_2

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
Activity Related to Partnership's Investments and Combined Financial Information in Unconsolidated Affiliates	The following table shows the activity related to our investments in unconsolidated affiliates: Balance at December 31, 2019 Equity Earnings (Loss) Cash Distributions Disposition/ Contributions Balance at December 31, 2020 GCX $ 447.5 $ 66.3 $ ( 81.3 ) $ — $ 2.7 $ 435.2 Little Missouri 4 103.7 10.8 ( 9.8 ) — — 104.7 T2 Eagle Ford 89.6 ( 8.9 ) ( 0.9 ) — — 79.8 T2 LaSalle 44.8 ( 4.8 ) ( 0.4 ) — — 39.6 GCF 37.2 2.9 ( 1.6 ) — — 38.5 Cayenne 15.9 6.3 ( 6.0 ) — — 16.2 Total $ 738.7 $ 72.6 $ ( 100.0 ) $ — $ 2.7 $ 714.0 Balance at December 31, 2020 Equity Earnings (Loss) Cash Distributions Disposition/ Contributions Balance at December 31, 2021 GCX $ 435.2 $ 63.4 $ ( 78.1 ) $ — $ 0.5 $ 421.0 Little Missouri 4 104.7 10.9 ( 17.5 ) — — 98.1 T2 Eagle Ford 79.8 ( 57.0 ) ( 1.0 ) — 0.1 21.9 T2 LaSalle 39.6 ( 35.0 ) ( 0.4 ) — — 4.2 GCF (1) 38.5 ( 8.6 ) ( 1.1 ) — — 28.8 Cayenne 16.2 2.4 ( 6.1 ) — — 12.5 Total $ 714.0 $ ( 23.9 ) $ ( 104.2 ) $ — $ 0.6 $ 586.5 Balance at December 31, 2021 Equity Earnings (Loss) Cash Distributions Disposition/ Contributions Balance at December 31, 2022 GCX $ 421.0 $ 5.7 $ ( 14.3 ) $ ( 412.4 ) $ — $ — Little Missouri 4 98.1 5.5 ( 12.9 ) — — 90.7 GCF (1) 28.8 ( 3.2 ) — — 1.5 27.1 T2 Eagle Ford (2) 21.9 ( 0.6 ) ( 0.8 ) ( 20.5 ) — — T2 LaSalle (2) 4.2 ( 0.3 ) — ( 3.9 ) — — Cayenne 12.5 2.0 ( 1.0 ) — — 13.5 Total $ 586.5 $ 9.1 $ ( 29.0 ) $ ( 436.8 ) $ 1.5 $ 131.3 (1) In January 2021, GCF was temporarily idled and Targa assumed operatorship in the first half of 2021. In January 2023, we reached an agreement with our partners to reactivate GCF. The facility is expected to be operational during the first quarter of 2024. (2) Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100 % owned and consolidated by Targa.

Debt Obligations (Tables)

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Outstanding Debt	December 31, 2022 December 31, 2021 Current: Partnership accounts receivable securitization facility, due September 2023 (1) $ 800.0 $ 150.0 Finance lease liabilities 34.3 12.8 Current debt obligations 834.3 162.8 Long-term: Term loan facility, variable rate, due July 2025 1,500.0 — TRGP senior revolving credit facility, variable rate, due February 2027 (2) 1,298.7 — Senior unsecured notes issued by TRGP: 5.200 % fixed rate, due July 2027 750.0 — 4.200 % fixed rate, due February 2033 750.0 — 4.950 % fixed rate, due April 2052 750.0 — 6.250 % fixed rate, due July 2052 500.0 — Unamortized discount ( 8.4 ) — Senior unsecured notes issued by the Partnership: (3) 5.875 % fixed rate, due April 2026 — 963.2 5.375 % fixed rate, due February 2027 — 468.1 6.500 % fixed rate, due July 2027 705.2 705.2 5.000 % fixed rate, due January 2028 700.3 700.3 6.875 % fixed rate, due January 2029 679.3 679.3 5.500 % fixed rate, due March 2030 949.6 949.6 4.875 % fixed rate, due February 2031 1,000.0 1,000.0 4.000 % fixed rate, due January 2032 1,000.0 1,000.0 10,574.7 6,465.7 Debt issuance costs, net of amortization ( 65.6 ) ( 45.0 ) Finance lease liabilities 193.0 13.7 Long-term debt 10,702.1 6,434.4 Total debt obligations $ 11,536.4 $ 6,597.2 Irrevocable standby letters of credit: (2) Letters of credit outstanding under the TRGP senior revolving credit facility $ 33.2 $ — Letters of credit outstanding under the Partnership senior — 71.3 $ 33.2 $ 71.3 (1) As of December 31, 2022, the Partnership had $ 800.0 million of qualifying receivables under its $ 800.0 million Securitization Facility, resulting in zero availability. (2) In February 2022, we entered into the TRGP Revolver which matures in February 2027, and terminated our previous TRGP senior secured revolving credit facility (the “Previous TRGP Revolver”) and the Partnership’s senior secured revolving credit facility (the “Partnership Revolver”). In July 2022, we established an unsecured commercial paper note program (the “Commercial Paper Program”), the borrowings of which are supported through maintaining a minimum available borrowing capacity under our TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program. As of December 31, 2022, the TRGP Revolver had $ 290.0 million borrowings outstanding and the Commercial Paper Program had $ 1.0 billion borrowings outstanding, resulting in approximately $ 1.4 billion of available liquidity, after accounting for outstanding letters of credit. As of December 31, 2021, we had no balance outstanding under the Previous TRGP Revolver or the Partnership Revolver. (3) As of February 2022, we guarantee all of the Partnership’s outstanding senior unsecured notes.
Range of Interest Rates and Weighted Average Interest Rate Incurred on Variable Rate Debt Obligations	The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2022: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRGP Revolver and Commercial Paper Program 1.5 % - 5.9 % 3.6 % Securitization Facility 1.1 % - 5.2 % 3.0 % Term Loan Facility 4.1 % - 5.8 % 4.6 %
Results of Tender Offers	The following table summarizes the impact of debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2022 2021 2020 Discount (premium) over face value paid upon redemption: TPL Notes $ — $ 0.2 $ — 5.125% Senior Notes due 2025 — ( 12.5 ) 4.4 6.750% Senior Notes due 2024 — — ( 11.1 ) 5.875% Senior Notes due 2026 ( 29.3 ) — 7.1 5.375% Senior Notes due 2027 ( 12.6 ) — 5.3 5.000% Senior Notes due 2028 — — 11.7 6.500% Senior Notes due 2027 — — 9.3 6.875% Senior Notes due 2029 — — 15.5 5.500% Senior Notes due 2030 — — 10.2 Write-off of debt issuance costs: Previous TRGP Revolver and Partnership Revolver ( 0.8 ) — — 5.125% Senior Notes due 2025 — ( 2.4 ) ( 0.1 ) 4.250% Senior Notes due 2023 — ( 1.9 ) — 5.250% Senior Notes due 2023 — — ( 1.8 ) 6.750% Senior Notes due 2024 — — ( 2.6 ) 5.875% Senior Notes due 2026 ( 4.5 ) — ( 0.2 ) 5.375% Senior Notes due 2027 ( 2.4 ) — ( 0.2 ) 5.000% Senior Notes due 2028 — — ( 0.4 ) 6.500% Senior Notes due 2027 — — ( 0.4 ) 6.875% Senior Notes due 2029 — — ( 0.6 ) 5.500% Senior Notes due 2030 — — ( 0.5 ) Gain (loss) from financing activities $ ( 49.6 ) $ ( 16.6 ) $ 45.6
Schedule of Contractual Maturities of Outstanding Debt Obligations	The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2022, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2023 2024 2025 2026 2027 Thereafter TRGP Revolver and Commercial Paper Program $ 1,298.7 $ — $ — $ — $ — $ 1,298.7 $ — TRGP Senior unsecured notes 2,741.6 — — — — 749.0 1,992.6 Term Loan Facility 1,500.0 — — 1,500.0 — — — Partnership's Senior unsecured notes 5,034.4 — — — — 705.2 4,329.2 Securitization Facility 800.0 800.0 — — — — — Total $ 11,374.7 $ 800.0 $ — $ 1,500.0 $ — $ 2,752.9 $ 6,321.8 Future non-cancelable commitments related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregate thereafter: In Aggregate 2023 2024 2025 2026 2027 Thereafter Land sites and rights of way (1) $ 247.6 $ 6.9 $ 6.7 $ 7.4 $ 9.4 $ 8.6 $ 208.6 (1) Land site lease and rights of way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual.

Other Long-term Liabilities (Ta

Other Long-term Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Other Liabilities, Noncurrent [Abstract]
Schedule of Other Long-term Liabilities	Other long-term liabilities are comprised of the following obligations: December 31, 2022 December 31, 2021 Deferred revenue $ 198.8 $ 171.8 Asset retirement obligations 97.9 72.1 Operating lease liabilities 28.6 34.5 Other liabilities 15.9 23.2 Total other long-term liabilities $ 341.2 $ 301.6
Components of deferred revenue	The following table shows the components of deferred revenue: December 31, 2022 December 31, 2021 Splitter agreement $ 129.0 $ 129.0 Gas contract amendment 32.3 34.8 Contributions in aid of construction (1) 31.7 — Other 5.8 8.0 Total deferred revenue $ 198.8 $ 171.8 (1) Amount reflects additions of deferred revenue related to the Delaware Basin Acquisition.
Changes in Deferred revenue	The following table shows the changes in deferred revenue: 2022 2021 Balance at beginning of period $ 171.8 $ 168.5 Additions 34.5 7.2 Revenue recognized ( 7.5 ) ( 3.9 ) Balance at end of period $ 198.8 $ 171.8
Changes in Aggregate Asset Retirement Obligations	The changes in our ARO are as follows: 2022 2021 Beginning of period $ 72.1 $ 68.3 Additions (1) 20.2 — Accretion expense 4.8 4.0 Change in cash flow estimate 0.8 ( 0.2 ) End of period $ 97.9 $ 72.1 (1) Amount reflects additions of ARO related to the Delaware Basin Acquisition.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Summary of Balances of Right of Use Assets and Liabilities of Finance Leases and Operating Leases	The balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated Balance Sheets are as follows: December 31, Balance Sheet Location 2022 2021 Right-of-use assets Operating leases, gross Other long-term assets $ 57.3 $ 50.8 Finance leases, gross (1) Property, plant and equipment 266.1 55.6 Lease liabilities Current: Operating leases Accrued liabilities $ 14.4 $ 11.7 Finance leases (1) Current debt obligations 34.3 12.8 Non-current: Operating leases Other long-term liabilities $ 28.6 $ 34.5 Finance leases (1) Long-term debt 193.0 13.7 (1) The December 31, 2022 balance includes $ 171.2 million of assets and $ 167.0 million of liabilities related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended.
Summary of Components of Lease Expense	Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements of Operations, depending on the nature of the leases. Finance lease costs are included in Depreciation and amortization expense and Interest expense, net in our Consolidated Statements of Operations. The components of lease expense were as follows: Year Ended December 31, 2022 2021 2020 Lease cost Operating lease cost $ 17.7 $ 12.2 $ 11.6 Short-term lease cost 35.0 20.4 20.7 Variable lease cost 17.9 5.7 5.5 Finance lease cost Amortization of right-of-use assets 20.3 13.3 13.6 Interest expense 3.5 1.1 1.4 Total lease cost $ 94.4 $ 52.7 $ 52.8
Summary of Other Supplemental Information Related to Leases	Other supplemental information related to our leases are as follows: Year Ended December 31, 2022 2021 2020 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for operating leases $ 18.8 $ 14.1 $ 12.3 Operating cash flows for finance leases 2.7 1.0 1.4 Financing cash flows for finance leases 19.7 12.5 12.4
Summary of Maturities of Lease Liabilities Under Non-cancellable Leases	The following table presents the maturities of our lease liabilities under non-cancellable leases as of December 31, 2022: Operating Leases Finance Leases 2023 $ 15.7 $ 42.5 2024 9.9 38.5 2025 5.2 37.1 2026 4.5 35.4 2027 4.0 30.9 Thereafter 7.8 80.9 Total undiscounted cash flows 47.1 265.3 Less imputed interest ( 4.1 ) ( 38.0 ) Total lease liabilities $ 43.0 $ 227.3

Common Stock and Related Matt_2

Common Stock and Related Matters (Tables)	12 Months Ended
	Dec. 31, 2022
Class of Stock Disclosures [Abstract]
Dividends Declared and/or Paid	The following table details the dividends declared and/or paid by us to common shareholders for the years ended December 31, 2022, 2021 and 2020: Three Months Ended Date Paid or Total Common Amount of Common Accrued Dividends Declared per Share of Common Stock (In millions, except per share amounts) 2022 December 31, 2022 February 15, 2023 $ 80.5 $ 79.3 $ 1.2 $ 0.35000 September 30, 2022 November 15, 2022 80.5 79.2 1.3 0.35000 June 30, 2022 August 15, 2022 80.7 79.3 1.4 0.35000 March 31, 2022 May 16, 2022 81.2 79.8 1.4 0.35000 2021 December 31, 2021 February 15, 2022 $ 81.4 $ 80.1 $ 1.3 $ 0.35000 September 30, 2021 November 15, 2021 23.3 22.9 0.4 0.10000 June 30, 2021 August 16, 2021 23.3 22.9 0.4 0.10000 March 31, 2021 May 14, 2021 23.3 22.9 0.4 0.10000 2020 December 31, 2020 February 16, 2021 $ 23.3 $ 22.9 $ 0.4 $ 0.10000 September 30, 2020 November 16, 2020 23.8 23.3 0.5 0.10000 June 30, 2020 August 17, 2020 23.7 23.3 0.4 0.10000 March 31, 2020 May 15, 2020 23.7 23.3 0.4 0.10000 (1) Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Earnings per Common Share (Tabl

Earnings per Common Share (Tables)	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
Reconciliation of Net Income and Weighted Average Shares Outstanding Used in Computing Basic and Diluted Net Income Per Common Share	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: Year Ended December 31, 2022 2021 2020 (In millions, except per share amounts) Net income (loss) attributable to Targa Resources Corp. $ 1,195.5 $ 71.2 $ ( 1,553.9 ) Less: Premium on repurchase of noncontrolling interests, net of tax (1) 53.2 — — Less: Dividends on Series A Preferred (2) 30.0 87.3 91.7 Less: Deemed dividends on Series A Preferred (3) 215.5 — 39.2 Net income (loss) attributable to common shareholders for basic earnings per share $ 896.8 $ ( 16.1 ) $ ( 1,684.8 ) Weighted average shares outstanding - basic 227.3 228.6 232.2 Dilutive effect of unvested stock awards (4) 3.8 — — Weighted average shares outstanding - diluted 231.1 228.6 232.2 Net income (loss) available per common share - basic $ 3.95 $ ( 0.07 ) $ ( 7.26 ) Net income (loss) available per common share - diluted $ 3.88 $ ( 0.07 ) $ ( 7.26 ) (1) Represents premium paid on the DevCo JV Repurchase. See Note 4 – Acquisitions and Divestitures. (2) Includes $ 8.2 million and $ 1.1 million attributable to the dividends paid upon the full redemption and partial repurchase of Series A Preferred in 2022 and 2020, respectively. (3) Includes $ 215.5 million and $ 1.6 million attributable to the full redemption and partial repurchase of Series A Preferred in 2022 and 2020, respectively. See Note 11 – Preferred Stock for further discussion. (4) For the years ended December 31, 2021 and 2020, all unvested restricted stock awards and Series A Preferred were antidilutive because a net loss existed for each of those periods.
Summary of Potential Common Stock Equivalents Excluded from Determination of Diluted Earnings Per Share	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): Year Ended December 31, 2022 2021 2020 Unvested restricted stock awards — 3.3 2.3 Series A Preferred (1) 14.9 44.3 46.4

Derivative Instruments and He_2

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Notional Volume of Commodity Hedges	At December 31, 2022, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2023 2024 2025 2026 2027 Natural Gas Swaps MMBtu/d 175,687 105,377 28,334 — — Natural Gas Basis Swaps MMBtu/d 591,610 298,407 244,267 82,500 25,000 NGL Swaps Bbl/d 43,115 21,134 4,813 — — NGL Futures Bbl/d 21,512 383 — — — Condensate Swaps Bbl/d 6,427 3,232 853 — —
Fair Values of Derivative Instruments	The following schedules reflect the fair value of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of December 31, 2022 Fair Value as of December 31, 2021 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 158.7 $ ( 93.8 ) $ 25.5 $ ( 252.6 ) Long-term 24.2 ( 30.9 ) 6.2 ( 84.3 ) Total derivatives designated as hedging instruments $ 182.9 $ ( 124.7 ) $ 31.7 $ ( 336.9 ) Derivatives not designated as hedging instruments Commodity contracts Current $ 21.2 $ ( 226.3 ) $ 17.6 $ ( 5.6 ) Long-term 0.3 ( 109.2 ) 1.5 ( 25.0 ) Total derivatives not designated as hedging instruments $ 21.5 $ ( 335.5 ) $ 19.1 $ ( 30.6 ) Total current position $ 179.9 $ ( 320.1 ) $ 43.1 $ ( 258.2 ) Total long-term position 24.5 ( 140.1 ) 7.7 ( 109.3 ) Total derivatives $ 204.4 $ ( 460.2 ) $ 50.8 $ ( 367.5 )
Pro Forma Impact of Derivatives Net in Consolidated Balance Sheet	The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro Forma Net Presentation December 31, 2022 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 162.2 $ ( 316.7 ) $ 12.2 $ 27.2 $ ( 169.5 ) Counterparties without offsetting positions - assets 17.7 — — 17.7 — Counterparties without offsetting positions - liabilities — ( 3.4 ) — — ( 3.4 ) 179.9 ( 320.1 ) 12.2 44.9 ( 172.9 ) Long-Term Position Counterparties with offsetting positions or collateral 24.5 ( 137.4 ) 22.4 7.3 ( 97.8 ) Counterparties without offsetting positions - assets — — — — — Counterparties without offsetting positions - liabilities — ( 2.7 ) — — ( 2.7 ) 24.5 ( 140.1 ) 22.4 7.3 ( 100.5 ) Total Derivatives Counterparties with offsetting positions or collateral 186.7 ( 454.1 ) 34.6 34.5 ( 267.3 ) Counterparties without offsetting positions - assets 17.7 — — 17.7 — Counterparties without offsetting positions - liabilities — ( 6.1 ) — — ( 6.1 ) $ 204.4 $ ( 460.2 ) $ 34.6 $ 52.2 $ ( 273.4 ) Gross Presentation Pro Forma Net Presentation December 31, 2021 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 39.2 $ ( 241.9 ) $ 5.0 $ 0.3 $ ( 198.0 ) Counterparties without offsetting positions - assets 3.9 — — 3.9 — Counterparties without offsetting positions - liabilities — ( 16.3 ) — — ( 16.3 ) 43.1 ( 258.2 ) 5.0 4.2 ( 214.3 ) Long-Term Position Counterparties with offsetting positions or collateral 7.4 ( 95.1 ) 3.1 — ( 84.6 ) Counterparties without offsetting positions - assets 0.3 — — 0.3 — Counterparties without offsetting positions - liabilities — ( 14.2 ) — — ( 14.2 ) 7.7 ( 109.3 ) 3.1 0.3 ( 98.8 ) Total Derivatives Counterparties with offsetting positions or collateral 46.6 ( 337.0 ) 8.1 0.3 ( 282.6 ) Counterparties without offsetting positions - assets 4.2 — — 4.2 — Counterparties without offsetting positions - liabilities — ( 30.5 ) — — ( 30.5 ) $ 50.8 $ ( 367.5 ) $ 8.1 $ 4.5 $ ( 313.1 )
Amounts Recorded in Other Comprehensive Income and Amounts Reclassified from OCI to Revenue	The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue for the periods indicated: Derivatives in Cash Flow Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Hedging Relationships 2022 2021 2020 Commodity contracts $ ( 5.6 ) $ ( 534.6 ) $ ( 218.3 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2022 2021 2020 Revenues $ ( 373.0 ) $ ( 417.3 ) $ 90.8
Gain (Loss) Recognized in Income on Derivatives	The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the year ended December 31, 2022 , the unrealized mark-to-market losses are primarily attributable to unfavorable movements in natural gas forward basis prices, as compared to our positions.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Breakdown by Fair Value Hierarchy Category for Financial Instruments Included in Consolidated Balance Sheets	The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: December 31, 2022 Carrying Fair Value Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Assets from commodity derivative contracts (1) $ 201.6 $ 201.6 $ — $ 201.6 $ — Liabilities from commodity derivative contracts (1) 457.4 457.4 — 457.4 — Financial Instruments Recorded on Our Cash and cash equivalents 219.0 219.0 — — — TRGP Revolver and Commercial Paper Program 1,298.7 1,298.7 — 1,298.7 — TRGP Senior unsecured notes 2,741.6 2,452.6 — 2,452.6 — Term Loan Facility 1,500.0 1,500.0 — 1,500.0 — Partnership's Senior unsecured notes 5,034.4 4,711.3 — 4,711.3 — Securitization Facility 800.0 800.0 — 800.0 — December 31, 2021 Carrying Fair Value Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Assets from commodity derivative contracts (1) $ 46.6 $ 46.6 $ — $ 46.6 $ — Liabilities from commodity derivative contracts (1) 363.3 363.3 — 363.3 — Financial Instruments Recorded on Our Cash and cash equivalents 158.5 158.5 — — — Partnership's Senior unsecured notes 6,465.7 6,924.5 — 6,924.5 — Securitization Facility 150.0 150.0 — 150.0 — (1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 14 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes .

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Summary of Transactions with Unconsolidated Affiliates	The following table summarizes transactions with unconsolidated affiliates: GCF T2 Joint Ventures (1) Cayenne GCX (2) Little Missouri 4 Total 2022: Revenues $ — $ 1.2 $ — $ — $ 8.5 $ 9.7 Product purchases and fuel — — ( 4.7 ) ( 25.0 ) — ( 29.7 ) Operating expenses ( 1.7 ) ( 0.7 ) ( 0.3 ) — ( 2.6 ) ( 5.3 ) General and administrative expenses — — — — ( 0.9 ) ( 0.9 ) 2021: Revenues $ — $ 4.4 $ — $ — $ 10.6 $ 15.0 Product purchases and fuel — — ( 4.8 ) ( 66.5 ) — ( 71.3 ) Operating expenses ( 1.1 ) ( 2.3 ) ( 0.2 ) — ( 2.5 ) ( 6.1 ) General and administrative expenses — — — — ( 0.8 ) ( 0.8 ) 2020: Revenues $ 0.4 $ 4.5 $ — $ 0.2 $ 12.6 $ 17.7 Product purchases and fuel — — ( 5.9 ) ( 67.2 ) — ( 73.1 ) Operating expenses ( 16.0 ) ( 1.2 ) ( 0.2 ) — ( 2.2 ) ( 19.6 ) General and administrative expenses — — — — ( 0.8 ) ( 0.8 ) (1) Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100 % owned and consolidated by Targa. (2) Following the closing of the GCX Sale in May 2022, Targa no longer has an ownership interest in GCX.

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Total Expenses on Non-Cancelable Commitments	Total expenses incurred under the above non-cancelable commitments were: 2022 2021 2020 Land sites and rights of way $ 5.8 $ 5.9 $ 6.5

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Summary of Estimated Minimum Revenue Expected to be Recognized in Future Related to Unsatisfied 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 17 years . 2023 2024 2025 and after Fixed consideration to be recognized as of December 31, 2022 $ 449.9 $ 451.4 $ 2,163.0

Other Operating (Income) Expe_2

Other Operating (Income) Expense (Tables)	12 Months Ended
	Dec. 31, 2022
Other Income and Expenses [Abstract]
Other Operating (Income) Expense	Other operating (income) expense is comprised of the following: Year Ended December 31, 2022 2021 2020 (Gain) loss on sale or disposition of business and assets (1) $ ( 9.6 ) $ 2.0 $ 58.4 Write-down of assets (2) 9.8 10.3 55.6 Other — 0.1 2.6 Total other operating (income) expense $ 0.2 $ 12.4 $ 116.6 (1) Primarily related to the sale of assets in Channelview, Texas in 2020. See Note 4 – Acquisitions and Divestitures for further discussion regarding these sales. (2) Related to the write-down of certain assets to their recoverable amounts.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Components of Federal and State Income Tax Provisions	Components of the federal and state income tax provisions for the periods indicated are as follows: 2022 2021 2020 Current expense (benefit) $ 6.7 $ 2.7 $ ( 15.4 ) Deferred expense (benefit) 125.1 12.1 ( 232.7 ) Total income tax expense (benefit) $ 131.8 $ 14.8 $ ( 248.1 )
Deferred Tax Assets and Liabilities	Our deferred income tax assets and liabilities as of December 31, 2022 and 2021 consist of recognition differences related to certain types of costs as follows: 2022 2021 Deferred tax assets: Net operating loss $ 1,568.5 $ 1,411.3 Disallowed business interest expense carryforward 10.3 3.8 Deferred tax assets before valuation allowance 1,578.8 1,415.1 Valuation allowance ( 36.9 ) ( 214.4 ) Deferred tax assets 1,541.9 1,200.7 Deferred tax liabilities: Investments (1) ( 1,842.0 ) ( 1,323.0 ) Property, plant, and equipment ( 4.2 ) ( 4.1 ) Other ( 23.4 ) ( 9.6 ) Deferred tax liabilities ( 1,869.6 ) ( 1,336.7 ) Net deferred tax asset (liability) $ ( 327.7 ) $ ( 136.0 ) Net deferred tax asset (liability) Federal $ ( 290.5 ) $ ( 106.7 ) State ( 37.2 ) ( 29.3 ) Long-term deferred tax liability, net $ ( 327.7 ) $ ( 136.0 ) (1) Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of our investment in the Partnership.
Reconciliation of Income Tax Provision (Benefit)	Set forth below is the reconciliation between our Income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision in our Consolidated Statements of Operations for the periods indicated: Income tax reconciliation: 2022 2021 2020 Income (loss) before income taxes $ 1,663.2 $ 436.9 $ ( 1,573.1 ) Less: Net income attributable to noncontrolling interest ( 335.9 ) ( 350.9 ) ( 228.9 ) Income attributable to Targa Resources Corp. before income taxes 1,327.3 86.0 ( 1,802.0 ) Federal statutory income tax rate 21 % 21 % 21 % Provision for federal income taxes 278.7 18.1 ( 378.4 ) Valuation allowance ( 177.5 ) ( 46.2 ) 194.2 State income taxes, net of federal tax benefit 33.6 ( 5.4 ) ( 51.2 ) CARES Act NOL carryback — — ( 16.9 ) State tax provision error correction — 23.3 — Return-to-provision ( 0.6 ) ( 1.3 ) — Change in statutory income tax rate ( 1.7 ) 21.0 — Permanent adjustments 5.6 4.1 4.5 Stock compensation shortfall/(windfall) ( 6.3 ) 1.4 — Other, net — ( 0.2 ) ( 0.3 ) Income tax provision (benefit) $ 131.8 $ 14.8 $ ( 248.1 )

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Year Ended December 31, 2022 2021 2020 Cash: Interest paid, net of capitalized interest (1) $ 401.3 $ 356.0 $ 374.1 Income taxes (received) paid, net 1.6 1.3 43.7 Non-cash investing activities: Change in deadstock commodity inventory $ ( 3.8 ) $ ( 15.0 ) $ 5.3 Impact of capital expenditure accruals on property, plant and equipment, net 60.1 53.0 ( 226.9 ) Transfers from materials and supplies inventory to property, plant and equipment — 2.4 2.1 Change in ARO liability and property, plant and equipment due to revised cash flow estimate and additions 0.8 ( 0.2 ) ( 1.8 ) Non-cash financing activities: Non-cash distributions to noncontrolling interests (2) $ 64.2 $ — $ — Changes in accrued distributions to noncontrolling interests ( 26.1 ) ( 50.9 ) ( 5.2 ) Reduction of owner's equity related to accrued dividends on unvested equity awards under share compensation arrangements 7.1 3.1 5.4 Accretion of deemed dividends on Series A Preferred — — 37.6 Lease liabilities arising from recognition of right-of-use assets: Operating lease $ 9.7 $ 20.1 $ 13.2 Finance lease (3) 220.7 24.7 6.0 (1) Interest capitalized on major projects was $ 16.3 million, $ 4.1 million and $ 33.0 million for the years ended December 31, 2022, 2021 and 2020 . (2) Represents the transfer of an undivided interest in certain gas gathering and processing facilities to a joint owner upon Targa's recovery of a specified payout amount for our initial full funding of the facilities. (3) The December 31, 2022 balance includes $ 171.2 million related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended.

Compensation Plans (Tables)

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2022
Restricted Stock Units (RSUs) [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Summary of Restricted Stock Awards	The following table summarizes the restricted stock and RSUs under the 2010 TRGP Plan in shares and in dollars for the year indicated. Number Weighted Average Outstanding at December 31, 2021 3,690,828 $ 37.42 Granted 974,469 63.63 Forfeited ( 83,372 ) 38.80 Vested ( 1,353,507 ) 44.12 Outstanding at December 31, 2022 3,228,418 42.60
PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Summary of Performance Share Units	The following table summarizes the PSUs under the 2010 TRGP Plan in shares and in dollars for the years indicated. Number Weighted Average Outstanding at December 31, 2021 867,209 $ 63.24 Granted 173,011 108.55 Forfeited ( 13,779 ) 74.75 Vested ( 256,524 ) 64.46 Outstanding at December 31, 2022 769,917 72.81

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
Reportable Segment Information	Reportable segment information is shown in the following tables: Year Ended December 31, 2022 Gathering and Processing Logistics and Transportation Other Corporate Total Revenues Sales of commodities $ 919.7 $ 18,448.7 $ ( 302.4 ) $ — $ 19,066.0 Fees from midstream services 1,157.3 706.5 — — 1,863.8 2,077.0 19,155.2 ( 302.4 ) — 20,929.8 Intersegment revenues Sales of commodities 9,169.4 541.7 — ( 9,711.1 ) — Fees from midstream services 0.6 45.2 — ( 45.8 ) — 9,170.0 586.9 — ( 9,756.9 ) — Revenues $ 11,247.0 $ 19,742.1 $ ( 302.4 ) $ ( 9,756.9 ) $ 20,929.8 Operating margin (1) $ 1,981.0 $ 1,456.3 $ ( 302.4 ) Other financial information: Total assets (2) $ 12,133.6 $ 7,175.7 $ — $ 250.7 $ 19,560.0 Goodwill $ 45.2 $ — $ — $ — $ 45.2 Capital expenditures $ 918.1 $ 453.0 $ — $ 23.3 $ 1,394.4 Year Ended December 31, 2021 Gathering and Processing Logistics and Transportation Other Corporate Total Revenues Sales of commodities $ 606.8 $ 15,111.6 $ ( 115.9 ) $ — $ 15,602.5 Fees from midstream services 747.3 600.0 — — 1,347.3 1,354.1 15,711.6 ( 115.9 ) — 16,949.8 Intersegment revenues Sales of commodities 6,067.9 409.5 — ( 6,477.4 ) — Fees from midstream services 3.5 38.6 — ( 42.1 ) — 6,071.4 448.1 — ( 6,519.5 ) — Revenues $ 7,425.5 $ 16,159.7 $ ( 115.9 ) $ ( 6,519.5 ) $ 16,949.8 Operating margin (1) $ 1,325.3 $ 1,264.3 $ ( 115.9 ) Other financial information: Total assets (2) $ 7,998.1 $ 7,041.9 $ 14.0 $ 154.2 $ 15,208.2 Goodwill $ 45.2 $ — $ — $ — $ 45.2 Capital expenditures $ 471.7 $ 78.1 $ — $ 10.7 $ 560.5 Year Ended December 31, 2020 Gathering and Processing Logistics and Transportation Other Corporate Total Revenues Sales of commodities $ 659.9 $ 6,281.4 $ 229.7 $ — $ 7,171.0 Fees from midstream services 487.2 602.1 — — 1,089.3 1,147.1 6,883.5 229.7 — 8,260.3 Intersegment revenues Sales of commodities 2,173.2 205.9 — ( 2,379.1 ) — Fees from midstream services 6.5 31.5 — ( 38.0 ) — 2,179.7 237.4 — ( 2,417.1 ) — Revenues $ 3,326.8 $ 7,120.9 $ 229.7 $ ( 2,417.1 ) $ 8,260.3 Operating margin (1) $ 1,017.7 $ 1,128.0 $ 229.7 Other financial information: Total assets (2) $ 8,743.5 $ 6,860.0 $ 86.3 $ 185.9 $ 15,875.7 Goodwill $ 45.2 $ — $ — $ — $ 45.2 Capital expenditures $ 293.9 $ 414.0 $ — $ 18.9 $ 726.8 (1) Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues. (2) Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.
Revenues Disaggregated by Product and Service	The following table shows our consolidated revenues disaggregated by product and service for the periods presented: Year Ended December 31, 2022 2021 2020 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $ 5,470.2 $ 3,523.9 $ 1,359.0 NGL 13,785.2 12,210.8 5,181.3 Condensate and crude oil 565.3 358.4 264.0 Petroleum products — — 69.8 19,820.7 16,093.1 6,874.1 Non-customer revenue: Derivative activities - Hedge ( 373.0 ) ( 417.3 ) 90.8 Derivative activities - Non-hedge (1) ( 381.7 ) ( 73.3 ) 206.1 ( 754.7 ) ( 490.6 ) 296.9 Total sales of commodities 19,066.0 15,602.5 7,171.0 Fees from midstream services: Revenue recognized from contracts with customers: Gathering and processing 1,137.2 730.3 476.0 NGL transportation, fractionation and services 285.1 190.6 163.1 Storage, terminaling and export 372.2 379.7 401.9 Other 69.3 46.7 48.3 Total fees from midstream services 1,863.8 1,347.3 1,089.3 Total revenues $ 20,929.8 $ 16,949.8 $ 8,260.3 (1) Represents derivative activities that are not designated as hedging instruments under ASC 815.
Reconciliation of Reportable Segment Operating Margin to Income (Loss) Before Income Taxes	The following table shows a reconciliation of reportable segment Operating margin to Income (loss) before income taxes for the periods presented: Year Ended December 31, 2022 2021 2020 Reconciliation of reportable segment operating Gathering and Processing operating margin $ 1,981.0 $ 1,325.3 $ 1,017.7 Logistics and Transportation operating margin 1,456.3 1,264.3 1,128.0 Other operating margin ( 302.4 ) ( 115.9 ) 229.7 Depreciation and amortization expense ( 1,096.0 ) ( 870.6 ) ( 865.1 ) General and administrative expense ( 309.7 ) ( 273.2 ) ( 254.6 ) Impairment of long-lived assets — ( 452.3 ) ( 2,442.8 ) Interest expense, net ( 446.1 ) ( 387.9 ) ( 391.3 ) Equity earnings (loss) 9.1 ( 23.9 ) 72.6 Gain (loss) on sale or disposition of assets 9.6 ( 2.0 ) ( 58.4 ) Write-down of assets ( 9.8 ) ( 10.3 ) ( 55.6 ) Gain (loss) from financing activities ( 49.6 ) ( 16.6 ) 45.6 Gain (loss) from sale of equity method investment 435.9 — — Other, net ( 15.1 ) — 1.1 Income (loss) before income taxes $ 1,663.2 $ 436.9 $ ( 1,573.1 )

Significant Accounting Polici_3

Significant Accounting Policies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Sep. 01, 2022 JointVenture	Dec. 31, 2019 USD ($)
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
interest income (expense)	$ (446.1)	$ (387.9)	$ (391.3)
WestTex LLC [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	72.80%
Logistics and Transportation [Member] | Cedar Bayou Fractionators LP [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	88%
Logistics and Transportation [Member] | Grand Prix Joint Venture [Member] | Targa Resources Partners Lp [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	75%
Logistics and Transportation [Member] | Train Seven [Member] | Targa Resources Partners Lp [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	80%
Logistics and Transportation [Member] | Cayenne Pipeline Limited Liability Company [Member] | Targa Resources Partners Lp [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	50%
Logistics and Transportation [Member] | Gulf Coast Fractionators [Member] | Targa Resources Partners Lp [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	38.80%
Gathering and Processing [Member] | Carnero Joint Venture [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	50%
Gathering and Processing [Member] | Centrahoma Processing LLC [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	60%
Gathering and Processing [Member] | Targa Badland [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	55%
Gathering and Processing [Member] | Venice Energy Services [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	76.80%
Gathering and Processing [Member] | Cayenne Pipeline Limited Liability Company [Member] | Targa Resources Partners Lp [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest	50%
Series A Preferred Stock [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Carrying value	$ 0	749.7	301.4		$ 278.8
Cumulative Effect, Period of Adoption, Adjustment [Member] | Series A Preferred Stock [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Carrying value			448.3
Minimum [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Payment of commodities due period	10 days
Maximum [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Payment of commodities due period	30 days
Mandatorily Redeemable Preferred Interests [Member] | West OK [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest				100%
Mandatorily Redeemable Preferred Interests [Member] | West TX [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Ownership interest				72.80%
Mandatorily Redeemable Preferred Interests [Member] | Joint Ventures [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Number of joint ventures | JointVenture				2
Notes receivable, face amount	$ 1,900
Notes receivable, due date	Jul. 31, 2042
interest income (expense)	$ (1.8)	$ 12.3	$ 8.6

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information Acquisitions (Details) $ in Millions, Bcf in Billions

1 Months Ended

3 Months Ended

5 Months Ended

12 Months Ended

Jan. 09, 2023 USD ($)

Feb. 06, 2018 JointVenture

Jul. 31, 2022 USD ($) Miles Bcf

May 31, 2022 USD ($)

Apr. 30, 2022 USD ($) JointVenture

Jan. 31, 2022 USD ($)

Apr. 30, 2021 USD ($)

Dec. 31, 2022 USD ($)

Dec. 31, 2022 USD ($)

Dec. 31, 2022 USD ($)

Feb. 28, 2022

Dec. 31, 2021 USD ($)

Business Acquisition [Line Items]

Repurchase of interest

$ 926.3

Premium on repurchase of noncontrolling interests, net of tax

[1]

53.2

Debt issuance cost

$ 65.6

$ 65.6

$ 65.6

$ 45

Weighted average amortization period, intangible assets

12 years 4 months 24 days

South Texas Acquisition

Business Acquisition [Line Items]

Business acquisition, purchase price

$ 201.9

Business acquisition, purchase price closing adjustment

1.5

Number of operated joint ventures | JointVenture

2

Acquisition-related costs

$ 1.8

Amount of liabilities assumed

1.8

Purchase of interest in joint venture

28.1

Cost to property, plant and equipment

169.7

Cost to current assets and liabilities, net

3.9

Cost to other non-current assets

$ 5.3

Delaware Basin Acquisition

Business Acquisition [Line Items]

Business acquisition, purchase price

$ 3,500

Net working capital adjustment amount

$ 11.4

Acquisition-related costs

$ 14.4

Cost to property, plant and equipment

1,669

Cost to other non-current assets

57.3

Debt issuance cost

$ 1,500

Distance of natural gas pipelines | Miles

1,050

Natural gas processing capacity in service or under construction | Bcf

1.4

Estimated average useful life of property, plant and equipment

20 years

Weighted average amortization period, intangible assets

14 years

Finite-lived intangible assets acquired, discount rate

19%

Customer attrition rate

5%

Revenue attributable to the assets acquired from the date of acquisition

374.1

Revenue attributable to the assets acquired from the date of acquisition

$ 7.9

Debt instrument drawn amount

$ 800

Debt issuance costs

16.9

Blackstone Energy Partners | Subsequent Event [Member]

Business Acquisition [Line Items]

Ownership interest

25%

Ownership interest in assets

100%

Business acquisition, purchase price

$ 1,050

GCX DevCo JV [Member]

Business Acquisition [Line Items]

Ownership interest

25%

Repurchase of interest

$ 857

Revolving Credit Facility [Member] | Delaware Basin Acquisition

Business Acquisition [Line Items]

Debt instrument drawn amount

2,750

5.200% Senior Notes Due 2027 [Member] | Delaware Basin Acquisition

Business Acquisition [Line Items]

Aggregate principal amount issued

$ 750

Interest rate on fixed rate debt

5.20%

6.250% Senior Notes Due 2052 [Member] | Delaware Basin Acquisition

Business Acquisition [Line Items]

Aggregate principal amount issued

$ 500

Interest rate on fixed rate debt

6.25%

6.25%

6.25%

6.25%

Stonepeak Infrastructure Partners [Member] | GCX DevCo JV [Member]

Business Acquisition [Line Items]

Number of development joint ventures | JointVenture

3

Train 6 [Member] | Train 6 DevCo JV [Member] | Mont Belvieu, Texas [Member]

Business Acquisition [Line Items]

Ownership interest in assets

110%

DevCo JV Repurchase [Member]

Business Acquisition [Line Items]

Repurchase of interest

$ 926.3

Premium on repurchase of noncontrolling interests, net of tax

$ 53.2

Cash paid for purchase of noncontrolling interests

$ 857.9

DevCo JV Repurchase [Member] | Grand Prix Joint Venture [Member]

Business Acquisition [Line Items]

Ownership interest

75%

DevCo JV Repurchase [Member] | GCX DevCo JV [Member]

Business Acquisition [Line Items]

Ownership interest

25%

DevCo JV Repurchase [Member] | Train 6 [Member]

Business Acquisition [Line Items]

Ownership interest in assets

100%

[1] Represents premium paid on the DevCo JV Repurchase. See Note 4 – Acquisitions and Divestitures.

Acquisitions and Divestitures_2

Acquisitions and Divestitures - Summary of Preliminary Fair Values Assigned to Assets Acquired and Liabilities Assumed (Details) - Delaware Basin Acquisition [Member] $ in Millions	Jul. 31, 2022 USD ($)
Business Acquisition [Line Items]
Cash and cash equivalents	$ 9.9
Trade receivables, net of allowances	211	[1]
Other current assets	3.5
Property, plant and equipment, net	1,669
Intangible assets, net	1,882
Other long-term assets	57.3
Current liabilities	(236.7)
Other long-term liabilities	(100.7)
Purchase price	$ 3,495.3
[1] The fair value of the assets acquired includes trade receivables of $ 211.0 million. The gross amount due under contract was $ 213.4 million, of which $ 2.4 million was expected to be uncollectible. Trade receivables, net of allowances, excludes $ 18.5 million that was due from Targa. We reflected this settlement of a preexisting relationship as a reduction of the purchase price in accordance with ASC 805.

Acquisitions and Divestitures_3

Acquisitions and Divestitures - Summary of Preliminary Fair Values Assigned to Assets Acquired and Liabilities Assumed (Parenthetical) (Details) - USD ($) $ in Millions	Dec. 31, 2022	Jul. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Trade receivables, net of allowances	$ 1,408.4		$ 1,331.9
Delaware Basin Acquisition [Member]
Business Acquisition [Line Items]
Fair value of the assets acquired includes trade receivables		$ 211
Gross amount due under contract		213.4
Expected to be uncollectible		2.4
Trade receivables, net of allowances		$ 18.5

Acquisitions and Divestitures_4

Acquisitions and Divestitures - Schedule of Unaudited Pro Forma Financial Information (Details) - Delaware Basin Acquisition - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Revenues	$ 21,268.9	$ 17,464.7
Net income (loss)	$ 1,477.4	$ 215.7

Acquisitions and Divestitures_5

Acquisitions and Divestitures - Additional Information Divestitures (Details) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
		May 31, 2022	Oct. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Assets And Liabilities Held For Sale [Line Items]
Gain (loss) on sale or disposal of assets	[1]			$ 9.6	$ (2)	$ (58.4)
Proceeds from sale of assets				23	$ 12.2	$ 198.7
Gain (loss) from sale of equity-method investment				435.9
GCX DevCo JV [Member]
Assets And Liabilities Held For Sale [Line Items]
Subsidiary ownership interest sale percentage		25%
Repurchase of interest		$ 857
Gain (loss) from sale of equity-method investment				$ 435.9
Channelview, Texas [Member]
Assets And Liabilities Held For Sale [Line Items]
Proceeds from sale of assets			$ 58
Other Operating Income (Expense) [Member] | Channelview, Texas [Member]
Assets And Liabilities Held For Sale [Line Items]
Gain (loss) on sale or disposal of assets			$ (58.3)
[1] Primarily related to the sale of assets in Channelview, Texas in 2020. See Note 4 – Acquisitions and Divestitures for further discussion regarding these sales.

Property, Plant and Equipment_3

Property, Plant and Equipment and Intangible Assets - Property, Plant and Equipment and Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 23,913.2	$ 20,596.1
Accumulated depreciation, amortization and impairment	(9,698.6)	(8,928.4)
Property, plant and equipment, net	14,214.6	11,667.7
Intangible assets	4,379.7	2,642.9
Accumulated amortization and impairment	(1,645.1)	(1,548.1)
Intangible assets, net	$ 2,734.6	1,094.8	$ 1,382.4
Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	10 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	20 years
Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 10,403.1	9,318.2
Gathering Systems [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Gathering Systems [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	20 years
Processing and Fractionation Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 7,421.2	6,388.8
Processing and Fractionation Facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Processing and Fractionation Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	25 years
Terminaling and Storage Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 1,341.6	1,313.8
Terminaling and Storage Facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Terminaling and Storage Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	25 years
Transportation Assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 2,919.3	2,671
Transportation Assets [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	10 years
Transportation Assets [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	50 years
Other Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 387.6	340.9
Other Property, Plant and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	3 years
Other Property, Plant and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	50 years
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 163.3	160.8
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,011	347
Finance Lease Right-of-Use Assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 266.1	$ 55.6
Finance Lease Right-of-Use Assets [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Finance Lease Right-of-Use Assets [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	14 years

Property, Plant and Equipment_4

Property, Plant and Equipment and Intangible Assets - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2021	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Depreciation expense			$ 853.8	$ 739.6	$ 721.1
Non-cash pre-tax impairments	$ 452.3	$ 2,442.8		452.3	$ 2,442.8
Impairment of Intangible				$ 156.6
Impairment of Oil and Gas Properties	$ 295.7	2,234.2
Weighted average discount rate percentage	9.50%			9.50%	14%
Estimated amortization expense for intangible assets [Abstract]
Amortization			242.2	$ 131	$ 144
2023			384
2024			373.2
2025			326
2026			279.8
2027			$ 252.2
Weighted average amortization period, intangible assets			12 years 4 months 24 days
Customer Relationships [Member]
Property, Plant and Equipment [Line Items]
Impairment of Intangible	$ 156.6	$ 208.6
Impairment, Intangible Asset, Finite-Lived, Statement of Income or Comprehensive Income [Extensible Enumeration]	Non-cash pre-tax impairments	Non-cash pre-tax impairments
Other Operating Income (Expense) [Member]
Property, Plant and Equipment [Line Items]
Non-cash loss recognized from assets written off			$ 32.4

Property, Plant and Equipment_5

Property, Plant and Equipment and Intangible Assets - Schedule of Changes in Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Finite-Lived Intangible Assets [Roll Forward]
Balance at beginning of period	$ 1,094.8	$ 1,382.4
Additions from Delaware Basin Acquisition	1,882
Impairment		(156.6)
Amortization	(242.2)	(131)	$ (144)
Balance at end of period	$ 2,734.6	$ 1,094.8	$ 1,382.4

Goodwill - Additional Informati

Goodwill - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Goodwill [Line Items]
Goodwill	$ 45.2	$ 45.2
Other Long-term Assets [Member]
Goodwill [Line Items]
Goodwill	$ 45.2

Goodwill - Schedule of Goodwill

Goodwill - Schedule of Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Goodwill [Line Items]
Goodwill	$ 45.2	$ 45.2
Permian Midland [Member]
Goodwill [Line Items]
Goodwill	23.2	23.2
Permian Delaware [Member]
Goodwill [Line Items]
Goodwill	$ 22	$ 22

Investments in Unconsolidated_3

Investments in Unconsolidated Affiliates - Additional Information (Details) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2021 USD ($)	Dec. 31, 2022 USD ($)	Apr. 30, 2022 JointVenture	Feb. 28, 2022
Schedule Of Equity Method Investments [Line Items]
Gain (loss) from sale of equity-method investment		$ 435.9
GCX DevCo JV [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest				25%
Gain (loss) from sale of equity-method investment		$ 435.9
T2 La Salle
Schedule Of Equity Method Investments [Line Items]
Non-cash pre-tax impairment losses	$ 29.9
T2 Eagle Ford [Member]
Schedule Of Equity Method Investments [Line Items]
Non-cash pre-tax impairment losses	$ 47.3
South Texas Acquisition
Schedule Of Equity Method Investments [Line Items]
Number of operated joint ventures | JointVenture			2
Targa Resources Partners LP [Member] | Gulf Coast Fractionators LP [Member] | Logistics and Transportation [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest		38.80%
Targa Resources Partners LP [Member] | Cayenne Joint Venture [Member] | Logistics and Transportation [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest		50%
Targa Resources Partners LP [Member] | Cayenne Joint Venture [Member] | Gathering and Processing [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest		50%
Targa Resources Partners LP [Member] | Little Missouri 4 [Member] | Gathering and Processing [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest		50%
Targa Resources Partners LP [Member] | South Texas Acquisition
Schedule Of Equity Method Investments [Line Items]
Number of operated joint ventures | JointVenture			2
Targa Resources Partners LP [Member] | South Texas Acquisition | T2 Joint Ventures [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest			100%
Targa Resources Partners LP [Member] | South Texas Acquisition | T2 La Salle
Schedule Of Equity Method Investments [Line Items]
Ownership interest			75%
Targa Resources Partners LP [Member] | South Texas Acquisition | T2 Eagle Ford [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest			50%

Investments in Unconsolidated_4

Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		$ 586.5
Equity earnings (loss)		9.1		$ (23.9)		$ 72.6
Balance at end of period		131.3		586.5
Targa Resources Partners LP [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		586.5		714		738.7
Equity earnings (loss)		9.1		(23.9)		72.6
Cash Distributions		(29)		(104.2)		(100)
Disposition/ Consolidation		(436.8)
Contributions		1.5		0.6		2.7
Balance at end of period		131.3		586.5		714
Targa Resources Partners LP [Member] | GCX [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		421		435.2		447.5
Equity earnings (loss)		5.7		63.4		66.3
Cash Distributions		(14.3)		(78.1)		(81.3)
Disposition/ Consolidation		(412.4)
Contributions				0.5		2.7
Balance at end of period				421		435.2
Targa Resources Partners LP [Member] | Little Missouri 4 [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		98.1		104.7		103.7
Equity earnings (loss)		5.5		10.9		10.8
Cash Distributions		(12.9)		(17.5)		(9.8)
Balance at end of period		90.7		98.1		104.7
Targa Resources Partners LP [Member] | T2 Eagle Ford
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		21.9	[1]	79.8		89.6
Equity earnings (loss)		(0.6)	[1]	(57)		(8.9)
Cash Distributions		(0.8)	[1]	(1)		(0.9)
Disposition/ Consolidation	[1]	(20.5)
Contributions				0.1
Balance at end of period				21.9	[1]	79.8
Targa Resources Partners LP [Member] | T2 La Salle
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		4.2	[1]	39.6		44.8
Equity earnings (loss)		(0.3)	[1]	(35)		(4.8)
Cash Distributions				(0.4)		(0.4)
Disposition/ Consolidation	[1]	(3.9)
Balance at end of period				4.2	[1]	39.6
Targa Resources Partners LP [Member] | Gulf Coast Fractionators LP [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		28.8	[2]	38.5	[2]	37.2
Equity earnings (loss)		(3.2)	[2]	(8.6)	[2]	2.9
Cash Distributions				(1.1)	[2]	(1.6)
Contributions	[2]	1.5
Balance at end of period	[2]	27.1		28.8		38.5
Targa Resources Partners LP [Member] | Cayenne Joint Venture [Member]
Schedule Of Equity Method Investments [Line Items]
Balance at beginning of period		12.5		16.2		15.9
Equity earnings (loss)		2		2.4		6.3
Cash Distributions		(1)		(6.1)		(6)
Balance at end of period		$ 13.5		$ 12.5		$ 16.2
[1] Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100 % owned and consolidated by Targa. In January 2021, GCF was temporarily idled and Targa assumed operatorship in the first half of 2021. In January 2023, we reached an agreement with our partners to reactivate GCF. The facility is expected to be operational during the first quarter of 2024.

Investments in Unconsolidated_5

Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Parenthetical) (Details)	Apr. 30, 2022
Targa Resources Partners LP [Member] | South Texas Acquisition | T2 Joint Ventures [Member]
Schedule Of Equity Method Investments [Line Items]
Ownership interest	100%

Debt Obligations - Summary Of D

Debt Obligations - Summary Of Debt Obligations (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Current Obligations of the Partnership [Abstract]
Partnership accounts receivable securitization facility, due September 2023	[1]	$ 800	$ 150
Finance lease liabilities	[2]	34.3	12.8
Current debt obligations		834.3	162.8
Long-term [Abstract]
Long-term debt including Unamortized premium(discount) and Debt issuance costs		10,574.7	6,465.7
Debt issuance costs, net of amortization		(65.6)	(45)
Finance lease liabilities	[2]	193	13.7
Long-term debt		10,702.1	6,434.4
Total debt obligations		11,536.4	6,597.2
Letters of credit outstanding		33.2	71.3
Senior Unsecured Notes [Member]
Long-term [Abstract]
Unamortized discount		(8.4)	0
Senior Unsecured Notes [Member] | Senior Unsecured 5.875% Notes due April 2026 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Long-term debt	[3]	0	963.2
Senior Unsecured Notes [Member] | Senior Unsecured 5.375% Notes due February 2027 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Long-term debt	[3]	0	468.1
Senior Unsecured Notes [Member] | Senior Unsecured 6.500% fixed rate, due July 2027 [Member]
Long-term [Abstract]
Long-term debt		750	0
Senior Unsecured Notes [Member] | Senior Unsecured 6.500% fixed rate, due July 2027 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Long-term debt	[3]	705.2	705.2
Senior Unsecured Notes [Member] | Senior Unsecured 5.000% Notes due January 2028 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Long-term debt	[3]	700.3	700.3
Senior Unsecured Notes [Member] | Senior Unsecured of 6.875% Senior Notes due January 2029 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Long-term debt	[3]	679.3	679.3
Senior Unsecured Notes [Member] | Senior Unsecured of 5.500% Senior Notes due March 2030 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Long-term debt	[3]	949.6	949.6
Senior Unsecured Notes [Member] | Senior Unsecured 4.875% Notes due February 2031 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Long-term debt	[3]	1,000	1,000
Senior Unsecured Notes [Member] | Senior Unsecured of 4.000% Senior Notes due January 2032 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Long-term debt	[3]	1,000	1,000
Senior Unsecured Notes [Member] | Senior Unsecured 4.200% Notes due February 2033 [Member]
Long-term [Abstract]
Long-term debt		750	0
Senior Unsecured Notes [Member] | Senior Unsecured 4.950% Notes due April 2052 [Member]
Long-term [Abstract]
Long-term debt		750	0
Senior Unsecured Notes [Member] | Senior Unsecured 6.250% fixed rate, due July 2052 [Member]
Long-term [Abstract]
Long-term debt		500	0
Revolving Credit Facility [Member] | TRP Senior Secured Revolving Credit Facility due June 2023 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Letters of credit outstanding	[4]	0	71.3
Revolving Credit Facility [Member] | TRGP Senior Revolving Credit Facility due February 2027 [Member]
Long-term [Abstract]
Long-term debt	[4]	1,298.7	0
Revolving Credit Facility [Member] | TRGP Senior Revolving Credit Facility due February 2027 [Member] | Targa Resources Partners LP [Member]
Long-term [Abstract]
Letters of credit outstanding	[4]	33.2	0
Term Loan Facility, Variable Rate, due July 2025
Long-term [Abstract]
Long-term debt		$ 1,500	$ 0
[1] As of December 31, 2022, the Partnership had $ 800.0 million of qualifying receivables under its $ 800.0 million Securitization Facility, resulting in zero availability. The December 31, 2022 balance includes $ 171.2 million of assets and $ 167.0 million of liabilities related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended. As of February 2022, we guarantee all of the Partnership’s outstanding senior unsecured notes. In February 2022, we entered into the TRGP Revolver which matures in February 2027, and terminated our previous TRGP senior secured revolving credit facility (the “Previous TRGP Revolver”) and the Partnership’s senior secured revolving credit facility (the “Partnership Revolver”). In July 2022, we established an unsecured commercial paper note program (the “Commercial Paper Program”), the borrowings of which are supported through maintaining a minimum available borrowing capacity under our TRGP Revolver equal to the aggregate amount outstanding under the Commercial Paper Program. As of December 31, 2022, the TRGP Revolver had $ 290.0 million borrowings outstanding and the Commercial Paper Program had $ 1.0 billion borrowings outstanding, resulting in approximately $ 1.4 billion of available liquidity, after accounting for outstanding letters of credit. As of December 31, 2021, we had no balance outstanding under the Previous TRGP Revolver or the Partnership Revolver.

Debt Obligations - Summary Of_2

Debt Obligations - Summary Of Debt Obligations (Parenthetical) (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
		Apr. 30, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Sep. 30, 2022	Sep. 29, 2022	Apr. 30, 2022	Feb. 28, 2021	Aug. 31, 2020
Debt Instrument [Line Items]
Proceeds from borrowings under accounts receivable securitization facility			$ 1,230	$ 630	$ 576.4
Partnership accounts receivable securitization facility, due September 2023	[1]		$ 800	$ 150
Senior Unsecured 4¼% Notes due November 2023 [Member]
Debt Instrument [Line Items]
Maturity date		May 31, 2021
Interest rate on fixed rate debt		4.25%
Senior Unsecured 4.875% Notes due February 2031 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt										4.875%
Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Maturity date			Sep. 01, 2023
Proceeds from borrowings under accounts receivable securitization facility			$ 800
Partnership accounts receivable securitization facility, due September 2023			800
Remaining borrowing capacity			0
Maximum borrowing capacity			$ 800
Revolving Credit Facility [Member] | TRGP Senior Revolving Credit Facility due February 2027 [Member]
Debt Instrument [Line Items]
Maturity date			Feb. 28, 2027	Feb. 28, 2027
Remaining borrowing capacity			$ 290
Revolving Credit Facility [Member] | Commercial Paper Program [Member]
Debt Instrument [Line Items]
Remaining borrowing capacity			1,000
Revolving Credit Facility [Member] | Letters of Credit [Member]
Debt Instrument [Line Items]
Remaining borrowing capacity			$ 1,400
Term Loan Facility, Variable Rate, due July 2025
Debt Instrument [Line Items]
Maturity date			Jul. 31, 2025	Jul. 31, 2025
Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt								4.20%	5.125%
Senior Unsecured Notes [Member] | Senior Unsecured 5.875% Notes due April 2026 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt								5.875%
Senior Unsecured Notes [Member] | Senior Unsecured 6.500% fixed rate, due July 2027 [Member]
Debt Instrument [Line Items]
Maturity date			Jul. 31, 2027	Jul. 31, 2027
Interest rate on fixed rate debt			5.20%	5.20%
Senior Unsecured Notes [Member] | Senior Unsecured 4.200% Notes due February 2033 [Member]
Debt Instrument [Line Items]
Maturity date			Feb. 28, 2033	Feb. 28, 2033
Interest rate on fixed rate debt			4.20%	4.20%				4.20%
Senior Unsecured Notes [Member] | Senior Unsecured 4.950% Notes due April 2052 [Member]
Debt Instrument [Line Items]
Maturity date			Apr. 30, 2052	Apr. 30, 2052
Interest rate on fixed rate debt			4.95%	4.95%				4.95%
Senior Unsecured Notes [Member] | Senior Unsecured 6.250% fixed rate, due July 2052 [Member]
Debt Instrument [Line Items]
Maturity date			Jul. 31, 2052	Jul. 31, 2052
Interest rate on fixed rate debt			6.25%	6.25%
Senior Unsecured Notes [Member] | Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Maturity date			Sep. 01, 2023
Maximum borrowing capacity						$ 800	$ 400
Targa Resources Partners LP [Member] | Targa Pipeline Partners L P | Senior Unsecured 5 7/8% Notes due August 2023 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt									5.875%
Targa Resources Partners LP [Member] | Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility, due September 2023 [Member]
Debt Instrument [Line Items]
Maturity date			Sep. 01, 2023	Sep. 01, 2023
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5.875% Notes due April 2026 [Member]
Debt Instrument [Line Items]
Maturity date			Apr. 30, 2026	Apr. 30, 2026
Interest rate on fixed rate debt			5.875%	5.875%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5.375% Notes due February 2027 [Member]
Debt Instrument [Line Items]
Maturity date			Feb. 28, 2027	Feb. 28, 2027
Interest rate on fixed rate debt			5.375%	5.375%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6.500% fixed rate, due July 2027 [Member]
Debt Instrument [Line Items]
Maturity date			Jul. 31, 2027	Jul. 31, 2027
Interest rate on fixed rate debt			6.50%	6.50%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5.000% Notes due January 2028 [Member]
Debt Instrument [Line Items]
Maturity date			Jan. 31, 2028	Jan. 31, 2028
Interest rate on fixed rate debt			5%	5%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured of 6.875% Senior Notes due January 2029 [Member]
Debt Instrument [Line Items]
Maturity date			Jan. 31, 2029	Jan. 31, 2029
Interest rate on fixed rate debt			6.875%	6.875%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 4.875% Notes due February 2031 [Member]
Debt Instrument [Line Items]
Maturity date			Feb. 28, 2031	Feb. 28, 2031
Interest rate on fixed rate debt			4.875%	4.875%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured of 5.500% Senior Notes due March 2030 [Member]
Debt Instrument [Line Items]
Maturity date			Mar. 31, 2030	Mar. 31, 2030
Interest rate on fixed rate debt			5.50%	5.50%
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured of 4.000% Senior Notes due January 2032 [Member]
Debt Instrument [Line Items]
Maturity date			Jan. 31, 2032	Jan. 31, 2032
Interest rate on fixed rate debt			4%	4%
[1] As of December 31, 2022, the Partnership had $ 800.0 million of qualifying receivables under its $ 800.0 million Securitization Facility, resulting in zero availability.

Debt Obligations - Range of Int

Debt Obligations - Range of Interest Rates and Weighted Average Interest Rate Incurred on Variable Rate Debt Obligations (Details)	Dec. 31, 2022
TRGP Revolver and Commercial Paper Program [Member]
Debt Instrument [Line Items]
Weighted average interest rate incurred	3.60%
Targa Resources Partners LP [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Weighted average interest rate incurred	4.60%
Targa Resources Partners LP [Member] | Securitization Facility [Member]
Debt Instrument [Line Items]
Weighted average interest rate incurred	3%
Minimum [Member] | TRGP Revolver and Commercial Paper Program [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	1.50%
Minimum [Member] | Targa Resources Partners LP [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	4.10%
Minimum [Member] | Targa Resources Partners LP [Member] | Securitization Facility [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	1.10%
Maximum [Member] | TRGP Revolver and Commercial Paper Program [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	5.90%
Maximum [Member] | Targa Resources Partners LP [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	5.80%
Maximum [Member] | Targa Resources Partners LP [Member] | Securitization Facility [Member]
Debt Instrument [Line Items]
Range of interest rates incurred	5.20%

Debt Obligations - Compliance w

Debt Obligations - Compliance with Debt Covenants - Additional Information (Details) $ in Millions	Dec. 31, 2022 USD ($)
Debt Instrument [Line Items]
Senior unsecured notes	$ 11,374.7
Senior Unsecured Notes [Member] | Targa Resources Partners LP and Targa Resources Partners Finance Corporation "TRP Issuers" [Member]
Debt Instrument [Line Items]
Senior unsecured notes	$ 5,000

Debt Obligations - Partnership'

Debt Obligations - Partnership's Accounts Receivable Securitization Facility - Additional Information (Details) - Accounts Receivable Securitization Facility [Member] - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Apr. 30, 2022	Dec. 31, 2022	Sep. 30, 2022	Sep. 29, 2022
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 800
Termination date		Sep. 01, 2023
Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 800	$ 400
Termination date		Sep. 01, 2023
Senior Unsecured of 4% Senior Notes due 2032 [Member] | Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Termination date	Apr. 19, 2023

Debt Obligations - TRGP Credit

Debt Obligations - TRGP Credit Agreement - Additional Information (Details) - New TRP Revolver [Member] - USD ($)	1 Months Ended	12 Months Ended
	Feb. 28, 2022	Dec. 31, 2022
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity	$ 2,750,000,000
Maximum borrowing capacity	500,000,000
Remaining borrowing capacity	$ 100,000,000
Maturity date	Feb. 17, 2027
Basis spread on variable rate		0%
Federal Funds Rate [Member]
Debt Instrument [Line Items]
Basis spread on variable rate		0.50%
Term SOFR [Member]
Debt Instrument [Line Items]
Basis spread on variable rate		1%
Term SOFR [Member] | SOFR Adjustment For Term SOFR Loans [Member]
Debt Instrument [Line Items]
Basis spread on variable rate		0.10%
Minimum [Member]
Debt Instrument [Line Items]
Leverage ratio before collateral release date		1
Minimum [Member] | Debt Rating [Member]
Debt Instrument [Line Items]
Commitment fee percentage		0.125%
Minimum [Member] | Term SOFR [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member]
Debt Instrument [Line Items]
Basis spread on variable rate		1.125%
Minimum [Member] | Base Rate [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member]
Debt Instrument [Line Items]
Basis spread on variable rate		0.125%
Maximum [Member]
Debt Instrument [Line Items]
Leverage ratio before collateral release date		5.50
Maximum [Member] | Debt Rating [Member]
Debt Instrument [Line Items]
Commitment fee percentage		0.35%
Maximum [Member] | Term SOFR [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member]
Debt Instrument [Line Items]
Basis spread on variable rate		1.75%
Maximum [Member] | Base Rate [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member]
Debt Instrument [Line Items]
Basis spread on variable rate		0.75%

Debt Obligations - Term Loan Fa

Debt Obligations - Term Loan Facility - Additional Information (Details) - Term Loan Facility [Member] - USD ($) $ in Billions	1 Months Ended	12 Months Ended
	Jul. 31, 2022	Dec. 31, 2022
Debt Instrument [Line Items]
Term loan facility, term	3 years
Maturity date	Jul. 31, 2025
Interest rate, description		The Term Loan Facility bears interest at the Company’s option at: (a) the Base Rate (as defined in the Term Loan Facility), which is the highest of the (i) federal funds rate plus 0.5%, (ii) Mizuho’s prime rate, and (iii) the Term SOFR (as defined in the Term Loan Facility) rate plus 1.0% (subject in each case to a floor of 0.0%), plus an applicable margin ranging from 0.125% to 0.75% dependent on the Company’s non-credit-enhanced senior unsecured long-term debt ratings (or, if no such debt is outstanding at such time, then the corporate, issuer or similar rating with respect to the Company that has been most recently announced) (the “Debt Rating”), or (b) Term SOFR plus 0.10% plus an applicable margin ranging from 1.125% to 1.75% dependent on the Debt Rating
Basis spread on variable rate	0%
Minimum [Member]
Debt Instrument [Line Items]
Leverage ratio before collateral release date	1
Maximum [Member]
Debt Instrument [Line Items]
Leverage ratio before collateral release date	5.50
Non Credit Enhanced Senior Unsecured Long Term Debt Ratings [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	1.125%
Non Credit Enhanced Senior Unsecured Long Term Debt Ratings [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	1.75%
Federal Funds Rate [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	0.50%
Term SOFR Rate [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	1%
Term SOFR Rate [Member] | Non Credit Enhanced Senior Unsecured Long Term Debt Ratings [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	0.10%
Base Rate [Member] | Non Credit Enhanced Senior Unsecured Long Term Debt Ratings [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	0.125%
Base Rate [Member] | Non Credit Enhanced Senior Unsecured Long Term Debt Ratings [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate	0.75%
Unsecured Debt [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued	$ 1.5

Debt Obligations - Commercial P

Debt Obligations - Commercial Paper Program - Additional Information (Details)) - Commercial Paper Program [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Jul. 31, 2022
Debt Instrument [Line Items]
Amount outstanding		$ 2,750
Debt Instrument, Description	Under the terms of the Commercial Paper Program, we may issue, from time to time, unsecured commercial paper notes with varying maturities of less than one year.

Debt Obligations - Partnershi_2

Debt Obligations - Partnership's Senior Unsecured Notes - Additional Information (Details) - Senior Unsecured Notes [Member]	12 Months Ended
	Dec. 31, 2022
Debt Instrument [Line Items]
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings	35%
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption	65%
Redemption condition, maximum number of days from date of closing of equity offerings	180 days

Debt Obligations - Senior Unsec

Debt Obligations - Senior Unsecured Notes Issuances - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended					12 Months Ended
	Jul. 31, 2022	Apr. 30, 2022	Feb. 28, 2022	Feb. 28, 2021	Aug. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Sep. 01, 2020
Senior Unsecured 4.875% Notes due February 2031 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt					4.875%
Senior Unsecured Notes Due2027 [Member]
Debt Instrument [Line Items]
Maturity date			Mar. 31, 2022
Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt		4.20%		5.125%
Senior Unsecured Notes [Member] | Senior Unsecured 4.875% Notes due February 2031 [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued					$ 1,000
Net proceeds from private placement of notes					$ 991
Senior Unsecured Notes [Member] | Senior Unsecured 6.750% Notes due March 2024 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt					6.75%			6.75%
Senior Unsecured Notes [Member] | Senior Unsecured Notes Due February2033 [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued		$ 750
Interest rate on fixed rate debt		4.20%				4.20%	4.20%
Maturity date						Feb. 28, 2033	Feb. 28, 2033
Senior Unsecured Notes [Member] | Senior Unsecured Notes Due April2052 [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued		$ 750
Interest rate on fixed rate debt		4.95%				4.95%	4.95%
Maturity date						Apr. 30, 2052	Apr. 30, 2052
Net proceeds from private placement of notes		$ 1,500
Senior Unsecured Notes [Member] | Senior Unsecured Notes Due April2026 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt		5.875%
Senior Unsecured Notes [Member] | Senior Unsecured Notes Due2027 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt	5.20%
Senior Unsecured Notes [Member] | Senior Unsecured Notes Due2052 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt	6.25%
Net proceeds from private placement of notes	$ 1,200
Senior Unsecured Notes [Member] | Senior Unsecured of 4% Senior Notes due 2032 [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued				$ 1,000
Interest rate on fixed rate debt				4%
Net proceeds from private placement of notes				$ 991
Senior Unsecured Notes [Member] | Senior Unsecured 5.125% Notes due 2025 [Member]
Debt Instrument [Line Items]
Interest rate on fixed rate debt				5.125%

Debt Obligations - Debt Repurch

Debt Obligations - Debt Repurchases & Extinguishments - Additional Information (Details) - USD ($) $ in Millions

1 Months Ended

6 Months Ended

12 Months Ended

Sep. 01, 2020

Jan. 31, 2023

Feb. 28, 2022

Apr. 30, 2021

Feb. 28, 2021

Nov. 30, 2020

Jun. 30, 2020

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Jul. 31, 2022

Apr. 30, 2022

Aug. 31, 2020

Debt Instrument [Line Items]

Debt repurchased, payment

$ 239.8

Debt repurchased, book value

303.3

Gain (loss) from financing activities

$ 61.1

$ (49.6)

$ (16.6)

$ 45.6

Debt repurchased, gain

(49.6)

$ (16.6)

45.6

Gain (loss) due to debt extinguishments

$ (14.9)

Senior Unsecured 6.750% Notes due March 2024 [Member]

Debt Instrument [Line Items]

Face amount of notes redeemed

$ 318

$ 262.1

Gain (loss) due to debt extinguishments

$ (13.7)

Senior Unsecured 5.250% Notes due May 2023 [Member]

Debt Instrument [Line Items]

Face amount of notes redeemed

$ 559.6

Gain (loss) due to debt extinguishments

$ 0.8

$ (1.8)

Senior Notes due 2027 [Member]

Debt Instrument [Line Items]

Gain (loss) due to debt extinguishments

$ 33.8

Maturity date

Mar. 31, 2022

TRGP Revolver [Member]

Debt Instrument [Line Items]

Gain (loss) due to debt extinguishments

$ 15

Senior Unsecured 4.250% Notes due November 2023 [Member]

Debt Instrument [Line Items]

Interest rate on fixed rate debt

4.25%

Gain (loss) due to debt extinguishments

$ (1.9)

Maturity date

May 31, 2021

Senior Unsecured Notes [Member]

Debt Instrument [Line Items]

Interest rate on fixed rate debt

5.125%

4.20%

Senior Unsecured Notes [Member] | Subsequent Event [Member]

Debt Instrument [Line Items]

Net proceeds from private placement of notes

$ 1,700

Senior Unsecured Notes [Member] | Senior Unsecured 6.750% Notes due March 2024 [Member]

Debt Instrument [Line Items]

Interest rate on fixed rate debt

6.75%

6.75%

Senior Unsecured Notes [Member] | Senior Unsecured 5.250% Notes due May 2023 [Member]

Debt Instrument [Line Items]

Interest rate on fixed rate debt

5.25%

Senior Unsecured Notes [Member] | Senior Notes due 2027 [Member]

Debt Instrument [Line Items]

Interest rate on fixed rate debt

5.20%

Senior Unsecured Notes [Member] | Senior Unsecured Notes Due February2033 [Member]

Debt Instrument [Line Items]

Interest rate on fixed rate debt

4.20%

4.20%

4.20%

Maturity date

Feb. 28, 2033

Feb. 28, 2033

Aggregate principal amount issued

$ 750

Senior Unsecured Notes [Member] | Senior Unsecured 6.500% Notes due 2053 [Member] | Subsequent Event [Member]

Debt Instrument [Line Items]

Interest rate on fixed rate debt

6.50%

Aggregate principal amount issued

$ 850

Targa Resources Partners LP [Member] | Targa Pipeline Partners L P

Debt Instrument [Line Items]

Gain (loss) due to debt extinguishments

$ 0.2

Targa Resources Partners LP [Member] | Senior Notes due 2027 [Member] | Targa Pipeline Partners L P

Debt Instrument [Line Items]

Interest rate on fixed rate debt

5.375%

Targa Resources Partners LP [Member] | Senior Unsecured 4.200% Notes due 2027 [Member]

Debt Instrument [Line Items]

Interest rate on fixed rate debt

4.20%

Targa Resources Partners LP [Member] | Senior Unsecured 4.950% Notes due 2027 [Member]

Debt Instrument [Line Items]

Interest rate on fixed rate debt

4.95%

Targa Resources Partners LP [Member] | Senior Unsecured 5.875% Notes due 2027 [Member]

Debt Instrument [Line Items]

Interest rate on fixed rate debt

5.875%

Targa Resources Partners LP [Member] | Senior Unsecured 5.875% Notes due August 2023 [Member] | Targa Pipeline Partners L P

Debt Instrument [Line Items]

Interest rate on fixed rate debt

5.875%

Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member]

Debt Instrument [Line Items]

Write-off debt issuance cost

$ 0

$ 0

$ 1.8

Debt Obligations - Debt Repur_2

Debt Obligations - Debt Repurchases Summary (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Gain (loss) from financing activities	$ (49.6)	$ (16.6)	$ 45.6
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member]
Debt Instrument [Line Items]
Write-off of debt issuance costs	0	0	(1.8)
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | 5.125% Senior Notes due 2025 [Member]
Debt Instrument [Line Items]
Discount over face value paid upon redemption	0	(12.5)	4.4
Write-off of debt issuance costs	0	(2.4)	(0.1)
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | 6.750% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Discount over face value paid upon redemption	0	0	(11.1)
Write-off of debt issuance costs	0	0	(2.6)
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | 5.875% Senior Notes due 2026 [Member]
Debt Instrument [Line Items]
Discount over face value paid upon redemption	(29.3)	0	7.1
Write-off of debt issuance costs	(4.5)	0	(0.2)
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | 5.375% Senior Notes due 2027 [Member]
Debt Instrument [Line Items]
Discount over face value paid upon redemption	(12.6)	0	5.3
Write-off of debt issuance costs	(2.4)	0	(0.2)
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | 5.000% Senior Notes due 2028 [Member]
Debt Instrument [Line Items]
Discount over face value paid upon redemption	0	0	11.7
Write-off of debt issuance costs	0	0	(0.4)
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | 6.500% Senior Notes due 2027 [Member]
Debt Instrument [Line Items]
Discount over face value paid upon redemption	0	0	9.3
Write-off of debt issuance costs	0	0	(0.4)
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | 6.875% Senior Notes due 2029 [Member]
Debt Instrument [Line Items]
Discount over face value paid upon redemption	0	0	15.5
Write-off of debt issuance costs	0	0	(0.6)
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | 5.500% Senior Notes due 2030 [Member]
Debt Instrument [Line Items]
Discount over face value paid upon redemption	0	0	10.2
Write-off of debt issuance costs	0	0	(0.5)
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Previous TRGP Revolver and Partnership Revolver [Member]
Debt Instrument [Line Items]
Write-off of debt issuance costs	(0.8)	0	0
Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | 4.250% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Write-off of debt issuance costs	0	(1.9)	0
Targa Resources Partners LP [Member] | Targa Pipeline Partners L P | Senior Unsecured Notes [Member] | TPL Notes Due 2021 and 2023 [Member]
Debt Instrument [Line Items]
Discount over face value paid upon redemption	$ 0	$ 0.2	$ 0

Debt Obligations - Schedule of

Debt Obligations - Schedule of Contractual Maturities of Debt Obligations (Details) $ in Millions	Dec. 31, 2022 USD ($)
Contractual Obligation [Line Items]
Total	$ 11,374.7
2023	800
2024	0
2025	1,500
2026	0
2027	2,752.9
Thereafter	6,321.8
Securitization Facility | Targa Resources Partners LP [Member]
Contractual Obligation [Line Items]
Total	800
2023	800
2024	0
2025	0
2026	0
2027	0
Thereafter	0
Senior Unsecured Notes [Member] | Targa Resources Partners LP [Member]
Contractual Obligation [Line Items]
Total	5,034.4
2023	0
2024	0
2025	0
2026	0
2027	705.2
Thereafter	4,329.2
TRGP Revolver and Commercial Paper Program [Member] | Targa Resources Partners LP [Member]
Contractual Obligation [Line Items]
Total	1,298.7
2023	0
2024	0
2025	0
2026	0
2027	1,298.7
Thereafter	0
TRGP Senior Unsecured Notes [Member] | Targa Resources Partners LP [Member]
Contractual Obligation [Line Items]
Total	2,741.6
2023	0
2024	0
2025	0
2026	0
2027	749
Thereafter	1,992.6
Term Loan Facility [Member] | Targa Resources Partners LP [Member]
Contractual Obligation [Line Items]
Total	1,500
2023	0
2024	0
2025	1,500
2026	0
2027	0
Thereafter	$ 0

Debt Obligations - Subsequent E

Debt Obligations - Subsequent Event - Additional Information (Details) - Senior Unsecured Notes [Member] - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2023	Apr. 30, 2022	Feb. 28, 2021
Debt Instrument [Line Items]
Interest rate on fixed rate debt		4.20%	5.125%
Subsequent Event [Member]
Debt Instrument [Line Items]
Net proceeds from senior notes	$ 1,700
Senior Unsecured 6.125% Notes due 2033 [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued	$ 900
Interest rate on fixed rate debt	6.125%
Senior Unsecured 6.500% Notes due 2053 [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Aggregate principal amount issued	$ 850
Interest rate on fixed rate debt	6.50%

Other Long-term Liabilities - S

Other Long-term Liabilities - Schedule of Other Long-term Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Liabilities, Noncurrent [Abstract]
Deferred revenue	$ 198.8	$ 171.8	$ 168.5
Asset retirement obligations	97.9	72.1	$ 68.3
Operating lease liabilities	28.6	34.5
Other liabilities	15.9	23.2
Total other long-term liabilities	$ 341.2	$ 301.6

Other Long-term Liabilities - D

Other Long-term Liabilities - Deferred Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Deferred Revenue and Other [Abstract]
Deferred revenue	$ 198.8	$ 171.8	$ 168.5
Deferred revenue recognized related to gas gathering and processing agreement	7.5	$ 3.9	$ 3.8
Channelview Splitter [Member]
Deferred Revenue and Other [Abstract]
Deferred revenue	$ 129

Other Long-term Liabilities - C

Other Long-term Liabilities - Components of Deferred Revenue (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Deferred Revenue Arrangement [Line Items]
Total deferred revenue		$ 198.8	$ 171.8	$ 168.5
Splitter Agreement [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue		129	129
Gas Contract Amendment [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue		32.3	34.8
Contributions in Aid of Construction [Member]
Deferred Revenue Arrangement [Line Items]
Total deferred revenue	[1]	31.7
Other
Deferred Revenue Arrangement [Line Items]
Total deferred revenue		$ 5.8	$ 8
[1] Amount reflects additions of deferred revenue related to the Delaware Basin Acquisition.

Other Long-term Liabilities -_2

Other Long-term Liabilities - Changes in Deferred Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Liabilities, Noncurrent [Abstract]
Balance at beginning of period	$ 171.8	$ 168.5
Additions	34.5	7.2
Revenue recognized	(7.5)	(3.9)	$ (3.8)
Balance at end of period	$ 198.8	$ 171.8	$ 168.5

Other Long-term Liabilities -_3

Other Long-term Liabilities - Changes in Aggregate Asset Retirement Obligations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning of period		$ 72.1	$ 68.3
Additions	[1]	20.2
Accretion expense		4.8	4	$ 3.6
Change in cash flow estimate		0.8	(0.2)
End of period		$ 97.9	$ 72.1	$ 68.3
[1] Amount reflects additions of ARO related to the Delaware Basin Acquisition.

Leases - Additional Information

Leases - Additional Information (Details)	Dec. 31, 2022
Lessee Lease Description [Line Items]
Weighted-average remaining lease terms for operating leases	5 years
Weighted-average remaining lease terms for finance leases	7 years
Weighted-average discount rates for operating leases	4%
Weighted-average discount rates for finance leases	4.80%
Minimum [Member]
Lessee Lease Description [Line Items]
Remaining lease terms	1 year
Maximum [Member]
Lessee Lease Description [Line Items]
Remaining lease terms	10 years
Options to extend lease term	20 years

Leases - Summary of Balances of

Leases - Summary of Balances of Right of Use Assets and Liabilities of Finance Leases and Operating Leases (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Right-of-use assets
Operating leases, gross		$ 57.3	$ 50.8
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]		Other long-term assets	Other long-term assets
Finance leases, gross	[1]	$ 266.1	$ 55.6
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]		Property, plant and equipment, net	Property, plant and equipment, net
Current:
Operating leases		$ 14.4	$ 11.7
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]		Accrued liabilities	Accrued liabilities
Finance leases	[1]	$ 34.3	$ 12.8
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]		Liabilities, Current	Liabilities, Current
Non-current:
Operating leases		$ 28.6	$ 34.5
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]		Other long-term liabilities	Other long-term liabilities
Finance leases	[1]	$ 193	$ 13.7
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]		Long-term debt	Long-term debt
[1] The December 31, 2022 balance includes $ 171.2 million of assets and $ 167.0 million of liabilities related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended.

Leases - Summary of Balances _2

Leases - Summary of Balances of Right of Use Assets and Liabilities of Finance Leases and Operating Leases (Parenthetical) (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Finance Lease, Asset	[1]	$ 266.1	$ 55.6
Finance Lease, Liability		227.3
Compressor [Member] | Delaware Basin Acquisition
Lessee, Lease, Description [Line Items]
Finance Lease, Asset		171.2
Finance Lease, Liability		$ 167
[1] The December 31, 2022 balance includes $ 171.2 million of assets and $ 167.0 million of liabilities related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended.

Leases - Summary of Components

Leases - Summary of Components of Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lease cost
Operating lease cost	$ 17.7	$ 12.2	$ 11.6
Short-term lease cost	35	20.4	20.7
Variable lease cost	17.9	5.7	5.5
Finance lease cost
Amortization of right-of-use assets	20.3	13.3	13.6
Interest expense	3.5	1.1	1.4
Total lease cost	$ 94.4	$ 52.7	$ 52.8

Leases - Summary of Other Suppl

Leases - Summary of Other Supplemental Information Related to Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for operating leases	$ 18.8	$ 14.1	$ 12.3
Operating cash flows for finance leases	2.7	1	1.4
Financing cash flows for finance leases	$ 19.7	$ 12.5	$ 12.4

Leases - Summary of Maturities

Leases - Summary of Maturities of Lease Liabilities Under Non-cancellable Leases (Details) $ in Millions	Dec. 31, 2022 USD ($)
Leases [Abstract]
2023	$ 15.7
2024	9.9
2025	5.2
2026	4.5
2027	4
Thereafter	7.8
Total undiscounted cash flows	47.1
Less imputed interest	(4.1)
Total lease liabilities	$ 43
Operating Lease, Liability, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilities
2023	$ 42.5
2024	38.5
2025	37.1
2026	35.4
2027	30.9
Thereafter	80.9
Total undiscounted cash flows	265.3
Less imputed interest	(38)
Total lease liabilities	$ 227.3

Preferred Stock - Additional In

Preferred Stock - Additional Information (Details) - USD ($)		1 Months Ended			3 Months Ended	12 Months Ended
	May 03, 2022	Jan. 31, 2022	[1]	Dec. 31, 2020	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Class Of Stock [Line Items]
Preferred stock dividend paid						$ 51,800,000	$ 87,300,000	$ 91,700,000
Deemed dividends on Series A Preferred Stock						$ 215,500,000		$ 39,200,000
Preferred stock dividend per share							$ 23.75	$ 23.75
Repurchases of common stock (in shares)						3,412,354	756,478
Net carrying value of shares repurchased						$ 224,800,000	$ 40,000,000	$ 91,500,000
Series A Preferred Stock [Member]
Class Of Stock [Line Items]
Preferred stock, liquidation per share				$ 1,000		$ 1,000	$ 1,000	$ 1,000
Preferred stock, percentage of dividend						9.50%
Preferred stock dividend payment terms						fixed dividend payable quarterly 45 days after the end of each fiscal quarter
Preferred stock redemption premium percentage in sixth year						10%
Preferred stock redemption premium percentage in sixth year and thereafter						5%
Preferred stock, dividend	$ 8.87
Preferred stock, redemption date	May 03, 2022
Preferred stock, consideration paid	$ 973,400,000
Maximum number of common share would be issued upon conversion of preferred share						44,260,953
Deemed dividends on Series A Preferred Stock		$ 215,500,000			$ 215,500,000			$ 39,200,000	[1]
Repurchases of common stock (in shares)				45,800
Preferred Stock, redemption price	$ 1,050			$ 1,100				$ 1,100
Preferred Stock, liquidation preference multiplied percentage				110%				110%
Unpaid dividends	$ 8,200,000			$ 1,100,000
Net carrying value of shares repurchased	$ 223,700,000			$ 2,700,000
Series A Preferred Stock [Member] | Maximum [Member]
Class Of Stock [Line Items]
Incurrence of indebtedness other than stipulated fixed charge coverage						$ 2,750,000,000
[1] Includes $ 215.5 million and $ 1.6 million attributable to the full redemption and partial repurchase of Series A Preferred in 2022 and 2020, respectively. See Note 11 – Preferred Stock for further discussion.

Common Stock and Related Matt_3

Common Stock and Related Matters - Additional Information (Details) - USD ($)	1 Months Ended	3 Months Ended	12 Months Ended
	Jan. 31, 2022	Dec. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Oct. 31, 2020	Sep. 20, 2018	May 09, 2017
Securities Financing Transaction [Line Items]
Stock repurchase program, authorized amount						$ 500,000,000
Repurchases of common stock (in shares)			3,412,354	756,478
Shares purchased		7,884,171	11,896,829	7,884,171
Remaining share repurchase amount			$ 143,800,000
Weighted average price per share			$ 65.87	$ 52.81
Repurchase of common shares, Value			$ 224,800,000	$ 40,000,000
Common stock dividends, per share	$ 0.35	$ 1.40	$ 1.40	$ 0.40	$ 1.21
2017 ATM Program [Member]
Securities Financing Transaction [Line Items]
Amount of common stock authorized under equity distribution agreement								$ 750,000,000
Equity Distribution Agreement May 2017 [Member]
Securities Financing Transaction [Line Items]
Public offering of common shares (including underwriters' overallotment option)			0	0	0
Amount of common stock authorized under equity distribution agreement			$ 382,100,000
2018 ATM Program [Member]
Securities Financing Transaction [Line Items]
Amount of common stock authorized under equity distribution agreement							$ 750,000,000
Equity Distribution Agreement September 2018 [Member]
Securities Financing Transaction [Line Items]
Public offering of common shares (including underwriters' overallotment option)			0	0	0
Amount of common stock authorized under equity distribution agreement			$ 750,000,000

Common Stock and Related Matt_4

Common Stock and Related Matters - Dividends Declared And Or Paid (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	3 Months Ended												12 Months Ended
		Jan. 31, 2022	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Dividends Payable [Line Items]
Dividends Declared per Share of Common Stock		$ 0.35					$ 1.40								$ 1.40	$ 0.40	$ 1.21
Dividend Declared [Member]
Dividends Payable [Line Items]
Accrued preferred dividends payable date			Feb. 15, 2023	Nov. 15, 2022	Aug. 15, 2022	May 16, 2022	Feb. 15, 2022	Nov. 15, 2021	Aug. 16, 2021	May 14, 2021	Feb. 16, 2021	Nov. 16, 2020	Aug. 17, 2020	May 15, 2020
Total Common Dividends Declared			$ 80.5	$ 80.5	$ 80.7	$ 81.2	$ 81.4	$ 23.3	$ 23.3	$ 23.3	$ 23.3	$ 23.8	$ 23.7	$ 23.7
Amount of Common Dividends Paid or To Be Paid			79.3	79.2	79.3	79.8	80.1	22.9	22.9	22.9	22.9	23.3	23.3	23.3
Accrued Dividends	[1]		$ 1.2	$ 1.3	$ 1.4	$ 1.4	$ 1.3	$ 0.4	$ 0.4	$ 0.4	$ 0.4	$ 0.5	$ 0.4	$ 0.4	$ 1.2	$ 1.3	$ 0.4
Dividends Declared per Share of Common Stock			$ 0.35000	$ 0.35000	$ 0.35000	$ 0.35000	$ 0.35000	$ 0.10000	$ 0.10000	$ 0.10000	$ 0.10000	$ 0.10000	$ 0.10000	$ 0.10000
[1] Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Earnings per Common Share (Deta

Earnings per Common Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		1 Months Ended		3 Months Ended	12 Months Ended
		Jan. 31, 2022		Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Common Share [Line Items]
Net income (loss) attributable to Targa Resources Corp.					$ 1,195.5	$ 71.2	$ (1,553.9)
Less: Premium on repurchase of noncontrolling interests, net of tax	[1]				53.2
Less: Deemed dividends on Series A Preferred					215.5		39.2
Net income (loss) attributable to common shareholders		$ (896.8)			$ 896.8	$ (16.1)	$ (1,684.8)
Weighted average shares outstanding - basic (in shares)					227.3	228.6	232.2
Dilutive effect of unvested stock awards	[2]				3.8
Weighted average shares outstanding - diluted (in shares)					231.1	228.6	232.2
Net income (loss) per common share - basic					$ 3.95	$ (0.07)	$ (7.26)
Net income (loss) per common share - diluted					$ 3.88	$ (0.07)	$ (7.26)
Series A Preferred Stock [Member]
Earnings Per Common Share [Line Items]
Less: Dividends on Series A Preferred	[3]	30				$ 87.3	$ 91.7
Less: Deemed dividends on Series A Preferred		$ 215.5	[4]	$ 215.5			$ 39.2	[4]
[1] Represents premium paid on the DevCo JV Repurchase. See Note 4 – Acquisitions and Divestitures. For the years ended December 31, 2021 and 2020, all unvested restricted stock awards and Series A Preferred were antidilutive because a net loss existed for each of those periods. Includes $ 8.2 million and $ 1.1 million attributable to the dividends paid upon the full redemption and partial repurchase of Series A Preferred in 2022 and 2020, respectively. Includes $ 215.5 million and $ 1.6 million attributable to the full redemption and partial repurchase of Series A Preferred in 2022 and 2020, respectively. See Note 11 – Preferred Stock for further discussion.

Earnings per Common Share (Pare

Earnings per Common Share (Parenthetical) (Details) - Series A Preferred Stock [Member] - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2022
Earnings Per Common Share [Line Items]
Dividends paid upon partial repurchase of shares	$ 1.1	$ 8.2
Deemed dividend on partial repurchase of shares	$ 1.6	$ 215.5

Earnings per Common Share - Sum

Earnings per Common Share - Summary of Potential Common Stock Equivalents Excluded from Determination of Diluted Earnings Per Share (Details) - shares shares in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Unvested Restricted Stock Awards [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive shares excluded from the determination of diluted earnings per share (in shares)			3.3	2.3
Series A Preferred Stock [Member]
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Anti-dilutive shares excluded from the determination of diluted earnings per share (in shares)	[1]	14.9	44.3	46.4
[1] The Series A Preferred had no mandatory redemption date, but was redeemable at our election for a 5 % premium to the liquidation preference subsequent to March 16, 2022 . In May 2022, we redeemed all of our issued and outstanding Series A Preferred at a redemption price of $ 1,050.00 per share, plus $ 8.87 per share, which is the amount of accrued and unpaid dividends from April 1, 2022 up to, but not including, the redemption date of May 3, 2022 . See Note 11 – Preferred Stock for further discussion.

Earnings per Common Share - S_2

Earnings per Common Share - Summary of Potential Common Stock Equivalents Excluded from Determination of Diluted Earnings Per Share (Parenthetical) (Details) - Series A Preferred Stock [Member] - $ / shares			12 Months Ended
	May 03, 2022	Mar. 17, 2022	Dec. 31, 2022	Dec. 31, 2020
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Preferred stock redemption premium percentage		5%
Preferred stock liquidation preference date			Mar. 16, 2022
Temporary equity, redemption price per share	$ 1,050			$ 1,100
Preferred stock dividends per share	$ 8.87
Temporary equity redemption date	May 03, 2022

Derivative Instruments and He_3

Derivative Instruments and Hedging Activities - Notional Volumes Of The Partnership's Commodity Derivative Contracts (Details) - Targa Resources Partners LP [Member]	12 Months Ended
	Dec. 31, 2022 MMBTU bbl
Swaps [Member] | Year 2023 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	175,687
Swaps [Member] | Year 2023 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	43,115
Swaps [Member] | Year 2024 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	105,377
Swaps [Member] | Year 2024 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	21,134
Swaps [Member] | Year 2025 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	28,334
Swaps [Member] | Year 2025 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	4,813
Swaps [Member] | Year 2026 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	0
Swaps [Member] | Year 2026 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Swaps [Member] | Year 2027 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	0
Swaps [Member] | Year 2027 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Basis Swaps [Member] | Year 2023 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	591,610
Basis Swaps [Member] | Year 2024 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	298,407
Basis Swaps [Member] | Year 2025 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	244,267
Basis Swaps [Member] | Year 2026 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	82,500
Basis Swaps [Member] | Year 2027 [Member] | Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU	25,000
Future [Member] | Year 2023 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	21,512
Future [Member] | Year 2024 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	383
Future [Member] | Year 2025 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Future [Member] | Year 2026 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Future [Member] | Year 2027 [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Options [Member] | Year 2023 [Member] | Condensate [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	6,427
Options [Member] | Year 2024 [Member] | Condensate [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	3,232
Options [Member] | Year 2025 [Member] | Condensate [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	853
Options [Member] | Year 2026 [Member] | Condensate [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0
Options [Member] | Year 2027 [Member] | Condensate [Member] | NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (in Bbl per day)	0

Derivative Instruments and He_4

Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Derivative assets	$ 204.4	$ 50.8
Derivative assets	179.9	43.1
Derivative assets	24.5	7.7
Derivative liabilities	(460.2)	(367.5)
Derivative liabilities	(320.1)	(258.2)
Derivative liabilities	(140.1)	(109.3)
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	182.9	31.7
Derivative liabilities	(124.7)	(336.9)
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	158.7	25.5
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Other Long-term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	24.2	6.2
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(93.8)	(252.6)
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Position [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(30.9)	(84.3)
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	21.5	19.1
Derivative liabilities	(335.5)	(30.6)
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	21.2	17.6
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Other Long-term Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	0.3	1.5
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(226.3)	(5.6)
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Position [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ (109.2)	$ (25)

Derivative Instruments and He_5

Derivative Instruments and Hedging Activities - Pro Forma Impact Of Offsetting Assets (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative Asset [Abstract]
Derivative assets	$ 204.4	$ 50.8
Pro forma net presentation, asset, current	$ 44.9	$ 4.2
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration]	Derivative Asset Before Effects Of Master Netting Arrangements Current	Derivative Asset Before Effects Of Master Netting Arrangements Current
Pro forma net presentation, asset, noncurrent	$ 7.3	$ 0.3
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Derivative Asset Before Effects Of Master Netting Arrangements Noncurrent	Derivative Asset Before Effects Of Master Netting Arrangements Noncurrent
Pro forma net presentation, asset, total	$ 52.2	$ 4.5
Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Derivative assets	186.7	46.6
Pro forma net presentation, asset	34.5	0.3
Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Derivative assets	17.7	4.2
Pro forma net presentation, asset, current	17.7	3.9
Pro forma net presentation, asset, noncurrent		0.3
Pro forma net presentation, asset, total	17.7	4.2
Current Assets from Risk Management Activities [Member]
Derivative Asset [Abstract]
Derivative assets	179.9	43.1
Current Assets from Risk Management Activities [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Derivative assets	162.2	39.2
Pro forma net presentation, asset	27.2	0.3
Current Assets from Risk Management Activities [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Derivative assets		3.9
Other Long-term Assets [Member]
Derivative Asset [Abstract]
Derivative assets	24.5	7.7
Other Long-term Assets [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Derivative assets	24.5	7.4
Pro forma net presentation, asset	$ 7.3
Other Long-term Assets [Member] | Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Derivative assets		$ 0.3

Derivative Instruments and He_6

Derivative Instruments and Hedging Activities - Pro Forma Impact Of Offsetting Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative Liability [Abstract]
Gross liability	$ (460.2)	$ (367.5)
Pro forma net presentation, liability, current	$ (172.9)	$ (214.3)
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration]	Derivative Liability Before Effects Of Master Netting Arrangements Current	Derivative Liability Before Effects Of Master Netting Arrangements Current
Pro forma net presentation, liability, noncurrent	$ (100.5)	$ (98.8)
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Derivative Liability Before Effects Of Master Netting Arrangements Noncurrent	Derivative Liability Before Effects Of Master Netting Arrangements Noncurrent
Pro forma net presentation, liability, total	$ (273.4)	$ (313.1)
Counterparties with Offsetting Positions or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(454.1)	(337)
Pro forma net presentation, liability, current	(169.5)	(198)
Pro forma net presentation, liability, noncurrent	(97.8)	(84.6)
Pro forma net presentation, liability, total	(267.3)	(282.6)
Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	(6.1)	(30.5)
Pro forma net presentation, liability, current	(3.4)	(16.3)
Pro forma net presentation, liability, noncurrent	(2.7)	(14.2)
Pro forma net presentation, liability, total	(6.1)	(30.5)
Current Liabilities from Risk Management Activities [Member]
Derivative Liability [Abstract]
Gross liability	(320.1)	(258.2)
Current Liabilities from Risk Management Activities [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	(316.7)	(241.9)
Current Liabilities from Risk Management Activities [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	3.4	(16.3)
Long-Term Liabilities from Risk Management Activities [Member]
Derivative Liability [Abstract]
Gross liability	140.1	(109.3)
Long-Term Liabilities from Risk Management Activities [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Liability [Abstract]
Gross liability	137.4	(95.1)
Long-Term Liabilities from Risk Management Activities [Member] | Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	$ (2.7)	$ (14.2)

Derivative Instruments and He_7

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Collateral (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative Asset [Abstract]
Gross collateral	$ 34.6	$ 8.1
Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	34.6	8.1
Current Assets from Risk Management Activities [Member]
Derivative Asset [Abstract]
Gross collateral	12.2	5
Current Assets from Risk Management Activities [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	12.2	5
Other Long-term Assets [Member]
Derivative Asset [Abstract]
Gross collateral	22.4	3.1
Other Long-term Assets [Member] | Counterparties with Offsetting Positions or Collateral [Member]
Derivative Asset [Abstract]
Gross collateral	$ 22.4	$ 3.1

Derivative Instruments and He_8

Derivative Instruments and Hedging Activities - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Estimated fair value of derivative instruments, net liability	$ (255.8)
Amount expected to reclassify commodity hedge related deferred losses to earnings before income taxes	(63.4)
Amount of deferred gains to be reclassified into earnings before income taxes over next twelve months	(70.1)
Loss contigency reduction of maximum loss due to counterparty credit risk by master netting provision	19.1
Derivative liability	273.4	$ 313.1
Derivative collateral amount	31.4
Credit Risk [Member]
Derivative [Line Items]
Derivative liability	266.7
Minimum [Member]
Derivative [Line Items]
Loss contigency estimate of possible loss	1.9
Maximum [Member]
Derivative [Line Items]
Loss contigency estimate of possible loss	$ 16.4

Derivative Instruments and He_9

Derivative Instruments and Hedging Activities - Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from OCI into income (effective portion)	$ 373	$ 417.3	$ (90.8)
Derivative Instrument, Gain (Loss) Reclassified from AOCI into Income, Effective Portion, Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues	Revenues	Revenues
Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in OCI on derivatives (effective portion)	$ 373	$ 417.3	$ (90.8)
Commodity Contracts [Member] | Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on derivatives	(381.7)	(73.3)	206.1
Cash Flow Hedging [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in OCI on derivatives (effective portion)	$ (5.6)	$ (534.6)	$ (218.3)

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) Derivative	Dec. 31, 2021 USD ($) Derivative	Dec. 31, 2020 USD ($)
Fair Value Disclosures [Abstract]
Estimated fair value of derivative instruments, net liability	$ 255.8
Derivative fair value of net liability if commodity price increases by 10 percent	455.3
Derivative fair value of net liability if commodity price decreases by 10 percent	$ 56.3
Derivative contract categorized as Level 3 | Derivative	0	0
Non-cash pre-tax impairments		$ 452.3	$ 2,442.8

Fair Value Measurements - Break

Fair Value Measurements - Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts		$ 52.2	$ 4.5
Derivative Asset, Statement of Financial Position [Extensible Enumeration]		Assets	Assets
Liabilities from commodity derivative contracts		$ 273.4	$ 313.1
Derivative Liability, Statement of Financial Position [Extensible Enumeration]		Liabilities, Current	Liabilities, Current
Carrying Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts	[1]	$ 201.6	$ 46.6
Liabilities from commodity derivative contracts	[1]	457.4	363.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		219	158.5
Carrying Value [Member] | TRGP Revolver and Commercial Paper Program [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		1,298.7
Carrying Value [Member] | TRGP Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		2,741.6
Carrying Value [Member] | Term Loan Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		1,500
Carrying Value [Member] | Securitization Facility
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		800	150
Carrying Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		5,034.4	6,465.7
Fair Value [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts	[1]	201.6	46.6
Liabilities from commodity derivative contracts	[1]	457.4	363.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		219	158.5
Fair Value [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts	[1]	0	0
Liabilities from commodity derivative contracts	[1]	0	0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		0	0
Fair Value [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts	[1]	201.6	46.6
Liabilities from commodity derivative contracts	[1]	457.4	363.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		0	0
Fair Value [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts	[1]	0	0
Liabilities from commodity derivative contracts	[1]	0	0
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		0	0
Fair Value [Member] | TRGP Revolver and Commercial Paper Program [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		1,298.7
Fair Value [Member] | TRGP Revolver and Commercial Paper Program [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		0
Fair Value [Member] | TRGP Revolver and Commercial Paper Program [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		1,298.7
Fair Value [Member] | TRGP Revolver and Commercial Paper Program [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		0
Fair Value [Member] | TRGP Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		2,452.6
Fair Value [Member] | TRGP Senior Unsecured Notes [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		0
Fair Value [Member] | TRGP Senior Unsecured Notes [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		2,452.6
Fair Value [Member] | TRGP Senior Unsecured Notes [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		0
Fair Value [Member] | Term Loan Facility [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		1,500
Fair Value [Member] | Term Loan Facility [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		0
Fair Value [Member] | Term Loan Facility [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		1,500
Fair Value [Member] | Term Loan Facility [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		0
Fair Value [Member] | Securitization Facility
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		800	150
Fair Value [Member] | Securitization Facility | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		0	0
Fair Value [Member] | Securitization Facility | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		800	150
Fair Value [Member] | Securitization Facility | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		0	0
Fair Value [Member] | Senior Unsecured Notes [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		4,711.3	6,924.5
Fair Value [Member] | Senior Unsecured Notes [Member] | Level 1 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		0	0
Fair Value [Member] | Senior Unsecured Notes [Member] | Level 2 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		4,711.3	6,924.5
Fair Value [Member] | Senior Unsecured Notes [Member] | Level 3 [Member]
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Long-term debt		$ 0	$ 0
[1] The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 14 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes .

Related Party Transactions - Su

Related Party Transactions - Summary of Transactions with Unconsolidated Affiliates (Details) - Targa Resources Partners LP [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Related Party Transaction [Line Items]
Revenues		$ 9.7	$ 15	$ 17.7
Product purchases and fuel		(29.7)	(71.3)	(73.1)
Operating expenses		(5.3)	(6.1)	(19.6)
General and administrative expenses		(0.9)	(0.8)	(0.8)
Gulf Coast Fractionators LP [Member]
Related Party Transaction [Line Items]
Revenues				0.4
Operating expenses		(1.7)	(1.1)	(16)
T2 Joint Ventures [Member]
Related Party Transaction [Line Items]
Revenues	[1]	1.2	4.4	4.5
Operating expenses	[1]	(0.7)	(2.3)	(1.2)
Cayenne [Member]
Related Party Transaction [Line Items]
Product purchases and fuel		(4.7)	(4.8)	(5.9)
Operating expenses		(0.3)	(0.2)	(0.2)
GCX [Member]
Related Party Transaction [Line Items]
Revenues	[2]			0.2
Product purchases and fuel	[2]	(25)	(66.5)	(67.2)
Little Missouri 4 [Member]
Related Party Transaction [Line Items]
Revenues		8.5	10.6	12.6
Operating expenses		(2.6)	(2.5)	(2.2)
General and administrative expenses		$ (0.9)	$ (0.8)	$ (0.8)
[1] Following the closing of the South Texas Acquisition in April 2022, the T2 Joint Ventures are 100 % owned and consolidated by Targa. Following the closing of the GCX Sale in May 2022, Targa no longer has an ownership interest in GCX.

Related Party Transactions - _2

Related Party Transactions - Summary of Transactions with Unconsolidated Affiliates (Parenthetical) (Details)	Apr. 30, 2022
Targa Resources Partners Lp [Member] | South Texas Acquisition [Member] | T2 Joint Ventures [Member]
Related Party Transaction [Line Items]
Ownership Percentage	100%

Commitments (Details)

Commitments (Details) - Land Sites and Rights-of-Way [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Future non-cancelable commitments related to certain contractual obligations for each of the next five fiscal years and in aggregate thereafter [Abstract]
In Aggregate	[1]	$ 247.6
2023	[1]	6.9
2024	[1]	6.7
2025	[1]	7.4
2026	[1]	9.4
2027	[1]	8.6
Thereafter	[1]	208.6
Total expenses on non-cancelable commitments		$ 5.8	$ 5.9	$ 6.5
[1] Land site lease and rights of way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual.

Contingencies - Additional Info

Contingencies - Additional Information (Details) - USD ($) $ in Millions			12 Months Ended
	Oct. 15, 2020	Dec. 26, 2018	Dec. 31, 2022
Loss Contingencies [Line Items]
Cumulative interest on award			$ 42.6
Vitol [Member]
Loss Contingencies [Line Items]
Lawsuit filing date		December 26, 2018
Award date	October 15, 2020
Recovery seeking	$ 129	$ 129
Damages awarded	$ 10.5

Revenue - Additional Informatio

Revenue - Additional Information (Details) - Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01	Dec. 31, 2022
Minimum [Member]
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Remaining duration of contracts	1 year
Maximum [Member]
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Remaining duration of contracts	17 years

Revenue - Estimated Minimum Rev

Revenue - Estimated Minimum Revenue Expected to be Recognized in Future Related to Unsatisfied Performance Obligations (Details) - Fixed Price Contract [Member] $ in Millions	Dec. 31, 2022 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2023-01-01
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Fixed consideration to be recognized	$ 449.9
Remaining duration of contracts	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2024-01-01
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Fixed consideration to be recognized	$ 451.4
Remaining duration of contracts	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2025-01-01
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items]
Fixed consideration to be recognized	$ 2,163
Remaining duration of contracts

Other Operating (Income) Expe_3

Other Operating (Income) Expense (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Income and Expenses [Abstract]
(Gain) loss on sale or disposition of assets	[1]	$ (9.6)	$ 2	$ 58.4
Write-downs of assets	[2]	9.8	10.3	55.6
Other		0	0.1	2.6
Total other operating (income) expense		$ 0.2	$ 12.4	$ 116.6
[1] Primarily related to the sale of assets in Channelview, Texas in 2020. See Note 4 – Acquisitions and Divestitures for further discussion regarding these sales. Related to the write-down of certain assets to their recoverable amounts.

Income Taxes - Components of Fe

Income Taxes - Components of Federal and State Income Tax Provisions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income tax (expense) benefit:
Current expense (benefit)	$ 6.7	$ 2.7	$ (15.4)
Deferred expense (benefit)	125.1	12.1	(232.7)
Total income tax expense (benefit)	$ 131.8	$ 14.8	$ (248.1)

Income Taxes - Components of De

Income Taxes - Components of Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets:
Net operating loss		$ 1,568.5	$ 1,411.3
Disallowed business interest expense carryforward		10.3	3.8
Deferred tax assets before valuation allowance		1,578.8	1,415.1
Valuation allowance		(36.9)	(214.4)
Deferred tax assets		1,541.9	1,200.7
Deferred tax liabilities:
Investments	[1]	(1,842)	(1,323)
Property, plant, and equipment		(4.2)	(4.1)
Other		(23.4)	(9.6)
Deferred tax liabilities		(1,869.6)	(1,336.7)
Net deferred tax asset (liability)		(327.7)	(136)
Net deferred tax asset (liability)
Federal		(290.5)	(106.7)
State		(37.2)	(29.3)
Net deferred tax asset (liability)		$ (327.7)	$ (136)
[1] Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of our investment in the Partnership.

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)		3 Months Ended	12 Months Ended
	Mar. 27, 2020	Jun. 30, 2020	Dec. 31, 2022	Dec. 31, 2021	Aug. 16, 2022	Dec. 31, 2020
Operating Loss Carryforwards [Line Items]
Income tax examination, description			On October 6, 2021 and April 7, 2022, we received notice from the IRS that it intends to audit three direct and indirectly wholly-owned subsidiaries of the Company (Targa Resources Partners LP, Targa Downstream LLC and Targa Midstream Services LLC) treated as partnerships for federal tax purposes for the 2019 and 2020 tax years.
Tax examination, year under examination			2019 2020
Additional income tax expense				$ 23,300,000
Total net operating loss carryforwards			$ 6,800,000,000
Maximum percentage of taxable income allowed to offset by net operating loss carryforwards per year			80%
Tax-effected valuation allowance			$ 36,900,000	$ 214,400,000
Increase (decrease) in valuation allowance			(177,500,000)
Uncertain tax reserves			0
Federal [Member]
Operating Loss Carryforwards [Line Items]
Tax-effected valuation allowance			6,400,000			$ 194,200,000
State [Member]
Operating Loss Carryforwards [Line Items]
Tax-effected valuation allowance			30,500,000
Expire Between 2036 and 2037 [Member]
Operating Loss Carryforwards [Line Items]
Total net operating loss carryforwards			1,400,000,000
No Expiration Period [Member]
Operating Loss Carryforwards [Line Items]
Total net operating loss carryforwards			$ 5,400,000,000
CARES Act [Member]
Operating Loss Carryforwards [Line Items]
CARES Act, tax period description			The CARES Act provided corporate taxpayers an expanded five-year net operating loss (“NOL”) carryback period for losses generated in tax years 2018 through 2020.
CARES Act [Member] | Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
CARES Act, provisions	$ 44,000,000
Income taxes refund received, alternative minimum tax, CARES Act		$ 44,000,000
CARES Act [Member] | Tax Years 2018 through 2020 [Member]
Operating Loss Carryforwards [Line Items]
CARES Act, expanded net operating loss carryback period for losses earned	5 years
Inflation Reduction Act [Member]
Operating Loss Carryforwards [Line Items]
Excise tax percentage on stock buybacks and tax incentives					1%
Corporate alternative minimum tax percentage					15%
Average annual adjusted financial statement income					$ 1,000,000,000
Maximum [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards expiry date			Dec. 31, 2037
Minimum [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards expiry date			Dec. 31, 2036

Income Taxes - Income Tax Recon

Income Taxes - Income Tax Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income tax reconciliation:
Income (loss) before income taxes	$ 1,663.2	$ 436.9	$ (1,573.1)
Less: Net income attributable to noncontrolling interest	(335.9)	(350.9)	(228.9)
Income attributable to Targa Resources Corp. before income taxes	$ 1,327.3	$ 86	$ (1,802)
Federal statutory income tax rate	21%	21%	21%
Provision for federal income taxes	$ 278.7	$ 18.1	$ (378.4)
Valuation allowance	(177.5)	(46.2)	194.2
State income taxes, net of federal tax benefit	33.6	(5.4)	(51.2)
CARES Act NOL carryback	0	0	(16.9)
State tax provision error correction	0	23.3	0
Return-to-provision	(0.6)	(1.3)	0
Change in statutory income tax rate	(1.7)	21	0
Permanent adjustments	5.6	4.1	4.5
Stock compensation shortfall/(windfall)	(6.3)	1.4	0
Other, net	0	(0.2)	(0.3)
Total income tax expense (benefit)	$ 131.8	$ 14.8	$ (248.1)

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash:
Interest paid, net of capitalized interest	[1]	$ 401.3	$ 356	$ 374.1
Income taxes (received) paid, net		1.6	1.3	43.7
Non-cash investing activities:
Change in deadstock commodity inventory		(3.8)	(15)	5.3
Transfers from materials and supplies inventory to property, plant and equipment			2.4	2.1
Change in ARO liability and property, plant and equipment due to revised cash flow estimate and additions		0.8	(0.2)	(1.8)
Non-cash financing activities:
Non-cash distributions to noncontrolling interests	[2]	64.2
Changes in accrued distributions to noncontrolling interests		(26.1)	(50.9)	(5.2)
Reduction of owner's equity related to accrued dividends on unvested equity awards under share compensation arrangements		7.1	3.1	5.4
Accretion of deemed dividends on Series A Preferred		215.5		37.6
Lease liabilities arising from recognition of right-of-use assets:
Operating lease		9.7	20.1	13.2
Finance lease	[3]	220.7	24.7	6
Retained Earnings [Member]
Non-cash investing activities:
Impact of capital expenditure accruals on property, plant and equipment, net		$ 60.1	$ 53	$ (226.9)
[1] Interest capitalized on major projects was $ 16.3 million, $ 4.1 million and $ 33.0 million for the years ended December 31, 2022, 2021 and 2020 . Represents the transfer of an undivided interest in certain gas gathering and processing facilities to a joint owner upon Targa's recovery of a specified payout amount for our initial full funding of the facilities. The December 31, 2022 balance includes $ 171.2 million related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended.

Supplemental Cash Flow Inform_4

Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Interest capitalized on major projects		$ 16.3	$ 4.1	$ 33
Finance Lease, Asset	[1]	266.1	$ 55.6
Compressor [Member] | Delaware Basin Acquisition
Lessee, Lease, Description [Line Items]
Finance Lease, Asset		$ 171.2
[1] The December 31, 2022 balance includes $ 171.2 million of assets and $ 167.0 million of liabilities related to compressor leases from the Delaware Basin Acquisition that were subsequently amended and extended.

Compensation Plans - Additional

Compensation Plans - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	May 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock compensation expense		$ 57.5	$ 59.2	$ 66.3
Unrecognized compensation expense		$ 88.8
Remaining weighted average vesting periods of unrecognized compensation expenses		2 years 3 months 18 days
Employer matching contribution percent		100%
Defined Contribution Plan, Plans Name [Extensible Enumeration]		http://www.targaresources.com/#FourZeroOneKPlansMember
Percentage of employees' gross pay for which employer contributes matching contribution		5%
Percentage of additional contribution per employee made by employer		3%
Percentage of contributions made in cash		100%
Contributions to defined contribution plan		$ 26.6	21.8	16.2
Accounting Standard Update 2016-09 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Tax deficiencies of dividends on share-based compensation recognized as income tax expenses		$ 6.7	$ 1.6	$ 2
Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vested (in shares)	472,265
Shares withheld to satisfy tax withholding obligations	165,203
PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected volatility, minimum		80%	80%	32%
Expected volatility, maximum		80%	80%	32%
PSUs [Member] | Subsequent Event [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vested (in shares)	728,417
Shares withheld to satisfy tax withholding obligations	272,681
Director Grants [Member] | Subsequent Event [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vested (in shares)	31,117
Shares withheld to satisfy tax withholding obligations	0
2010 TRC Stock Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair values of share-based awards vested		$ 93	$ 73.8	$ 62.7
Cash dividends paid for the vested awards		$ 9.6	$ 8.7	$ 9.4
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | 2022 Compensation Cycle [Member] | Third Year [Member] | Executive Management | Subsequent Event [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in shares)	140,020
Vesting date	2026-01
2010 TRC Stock Incentive Plan [Member] | PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding (in shares)		769,917	867,209
Granted (in shares)		173,011
Granted (in dollars per shares)		$ 108.55
Vesting period of awards		3 years
Expected term of grant date fair value		3 years
Vested (in shares)		256,524
2010 TRC Stock Incentive Plan [Member] | PSUs [Member] | 2021 Compensation Cycle [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting date		2025-01
2010 TRC Stock Incentive Plan [Member] | PSUs [Member] | 2020 Compensation Cycle [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in shares)		173,011	319,320	291,365
Vesting date			2024-01
2010 TRC Stock Incentive Plan [Member] | PSUs [Member] | 2019 Compensation Cycle [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting date				2023-01
2010 TRC Stock Incentive Plan [Member] | PSUs [Member] | 2022 Compensation Cycle [Member] | Executive Management | Subsequent Event [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in shares)	140,020
Vesting date	2026-01
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units In Lieu Of Bonus [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in shares)				81,336	95,687
Granted (in dollars per shares)				$ 41.39	$ 42.83
2010 TRC Stock Incentive Plan [Member] | Unvested Restricted Stock Awards [Member] | Outside Directors [Member] | Subsequent Event [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in shares)	23,518
Vesting date	2024-01
2010 TRGP Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Total number of units authorized (in shares)						15,000,000
Total number of units available (in shares)						5,000,000
Total number of additional units available (in shares)						10,000,000
2010 TRGP Plan [Member] | Restricted Stock Units (RSUs) [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in shares)		943,352	848,630	1,299,592
Granted (in dollars per shares)		$ 63.87	$ 37.94	$ 24.64
2010 TRGP Plan [Member] | Restricted Stock Units (RSUs) [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period of awards		1 year
2010 TRGP Plan [Member] | Restricted Stock Units (RSUs) [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period of awards		6 years
2010 TRGP Plan [Member] | Director Grants [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted (in shares)		31,117	67,591	31,621
Granted (in dollars per shares)		$ 56.32	$ 30.33	$ 39.85

Compensation Plans - 2010 TRC S

Compensation Plans - 2010 TRC Stock Incentive Plan (Details) - 2010 TRC Stock Incentive Plan [Member] - Restricted Stock and Restricted Stock Units [Member]	12 Months Ended
	Dec. 31, 2022 $ / shares shares
Nonvested, number of shares [Roll Forward]
Outstanding, beginning of period (in shares) | shares	3,690,828
Granted (in shares) | shares	974,469
Forfeited (in shares) | shares	(83,372)
Vested (in shares) | shares	(1,353,507)
Outstanding, end of period (in shares) | shares	3,228,418
Weighted-average grant-date fair value [Roll Forward]
Outstanding, beginning period (in dollars per share) | $ / shares	$ 37.42
Granted (in dollars per shares) | $ / shares	63.63
Forfeited (in dollars per share) | $ / shares	38.80
Vested (in dollars per share) | $ / shares	44.12
Outstanding, end of period (in dollars per share) | $ / shares	$ 42.60

Compensation Plans - Summary of

Compensation Plans - Summary of PSUs Under 2010 TRC Stock Incentive Plan (Details) - 2010 TRC Stock Incentive Plan [Member] - PSUs [Member]	12 Months Ended
	Dec. 31, 2022 $ / shares shares
Nonvested, number of shares [Roll Forward]
Outstanding, beginning of period (in shares) | shares	867,209
Granted (in shares) | shares	173,011
Vested (in shares) | shares	(256,524)
Forfeited (in shares) | shares	(13,779)
Outstanding, end of period (in shares) | shares	769,917
Weighted-average grant-date fair value [Roll Forward]
Outstanding, beginning period (in dollars per share) | $ / shares	$ 63.24
Granted (in dollars per shares) | $ / shares	108.55
Forfeited (in dollars per share) | $ / shares	74.75
Vested (in dollars per share) | $ / shares	64.46
Outstanding, end of period (in dollars per share) | $ / shares	$ 72.81

Segment Information - Additiona

Segment Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 2022 Segment
Segment Reporting [Abstract]
Number of reportable segments	2

Segment Information - Revenues

Segment Information - Revenues and Operating Margin (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Revenues		$ 20,929.8	$ 16,949.8	$ 8,260.3
Sales of Commodities [Member]
Revenues:
Revenues		19,066	15,602.5	7,171
Fees from Midstream Services [Member]
Revenues:
Revenues		1,863.8	1,347.3	1,089.3
Gathering and Processing [Member]
Revenues:
Revenues		11,247	7,425.5	3,326.8
Operating margin	[1]	1,981	1,325.3	1,017.7
Logistics and Transportation [Member]
Revenues:
Revenues		19,742.1	16,159.7	7,120.9
Operating margin	[1]	1,456.3	1,264.3	1,128
Other [Member]
Revenues:
Revenues		(302.4)	(115.9)	229.7
Operating margin	[1]	(302.4)	(115.9)	229.7
Corporate and Eliminations [Member]
Revenues:
Revenues		(9,756.9)	(6,519.5)	(2,417.1)
Operating Segments [Member]
Revenues:
Revenues		20,929.8	16,949.8	8,260.3
Operating Segments [Member] | Sales of Commodities [Member]
Revenues:
Revenues		19,066	15,602.5	7,171
Operating Segments [Member] | Fees from Midstream Services [Member]
Revenues:
Revenues		1,863.8	1,347.3	1,089.3
Operating Segments [Member] | Gathering and Processing [Member]
Revenues:
Revenues		2,077	1,354.1	1,147.1
Operating Segments [Member] | Gathering and Processing [Member] | Sales of Commodities [Member]
Revenues:
Revenues		919.7	606.8	659.9
Operating Segments [Member] | Gathering and Processing [Member] | Fees from Midstream Services [Member]
Revenues:
Revenues		1,157.3	747.3	487.2
Operating Segments [Member] | Logistics and Transportation [Member]
Revenues:
Revenues		19,155.2	15,711.6	6,883.5
Operating Segments [Member] | Logistics and Transportation [Member] | Sales of Commodities [Member]
Revenues:
Revenues		18,448.7	15,111.6	6,281.4
Operating Segments [Member] | Logistics and Transportation [Member] | Fees from Midstream Services [Member]
Revenues:
Revenues		706.5	600	602.1
Operating Segments [Member] | Other [Member]
Revenues:
Revenues		(302.4)	(115.9)	229.7
Operating Segments [Member] | Other [Member] | Sales of Commodities [Member]
Revenues:
Revenues		(302.4)	(115.9)	229.7
Intersegment Eliminations [Member] | Gathering and Processing [Member]
Revenues:
Revenues		9,170	6,071.4	2,179.7
Intersegment Eliminations [Member] | Gathering and Processing [Member] | Sales of Commodities [Member]
Revenues:
Revenues		9,169.4	6,067.9	2,173.2
Intersegment Eliminations [Member] | Gathering and Processing [Member] | Fees from Midstream Services [Member]
Revenues:
Revenues		0.6	3.5	6.5
Intersegment Eliminations [Member] | Logistics and Transportation [Member]
Revenues:
Revenues		586.9	448.1	237.4
Intersegment Eliminations [Member] | Logistics and Transportation [Member] | Sales of Commodities [Member]
Revenues:
Revenues		541.7	409.5	205.9
Intersegment Eliminations [Member] | Logistics and Transportation [Member] | Fees from Midstream Services [Member]
Revenues:
Revenues		45.2	38.6	31.5
Intersegment Eliminations [Member] | Corporate and Eliminations [Member]
Revenues:
Revenues		(9,756.9)	(6,519.5)	(2,417.1)
Intersegment Eliminations [Member] | Corporate and Eliminations [Member] | Sales of Commodities [Member]
Revenues:
Revenues		(9,711.1)	(6,477.4)	(2,379.1)
Intersegment Eliminations [Member] | Corporate and Eliminations [Member] | Fees from Midstream Services [Member]
Revenues:
Revenues		$ (45.8)	$ (42.1)	$ (38)
[1] Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.

Segment Information - Other Fin

Segment Information - Other Financial Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other financial information [Abstract]
Total assets		$ 19,560	$ 15,208.2
Goodwill		45.2	45.2
Operating Segments [Member]
Other financial information [Abstract]
Total assets	[1]	19,560	15,208.2	$ 15,875.7
Goodwill		45.2	45.2	45.2
Capital expenditures		1,394.4	560.5	726.8
Operating Segments [Member] | Gathering and Processing [Member]
Other financial information [Abstract]
Total assets	[1]	12,133.6	7,998.1	8,743.5
Goodwill		45.2	45.2	45.2
Capital expenditures		918.1	471.7	293.9
Operating Segments [Member] | Logistics and Transportation [Member]
Other financial information [Abstract]
Total assets	[1]	7,175.7	7,041.9	6,860
Capital expenditures		453	78.1	414
Operating Segments [Member] | Other [Member]
Other financial information [Abstract]
Total assets	[1]		14	86.3
Operating Segments [Member] | Corporate and Eliminations [Member]
Other financial information [Abstract]
Total assets	[1]	250.7	154.2	185.9
Capital expenditures		$ 23.3	$ 10.7	$ 18.9
[1] Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.

Segment Information - Summary o

Segment Information - Summary of Consolidated Revenues Disaggregated by Product and Service (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenue from External Customer [Line Items]
Revenue recognized		$ 19,820.7	$ 16,093.1	$ 6,874.1
Non-customer revenue		(754.7)	(490.6)	296.9
Total revenues		20,929.8	16,949.8	8,260.3
Derivative Activities - Hedge [Member]
Revenue from External Customer [Line Items]
Non-customer revenue		(373)	(417.3)	90.8
Derivative Activities - Non-hedge [Member]
Revenue from External Customer [Line Items]
Non-customer revenue	[1]	(381.7)	(73.3)	206.1
Natural Gas [Member]
Revenue from External Customer [Line Items]
Revenue recognized		5,470.2	3,523.9	1,359
NGL [Member]
Revenue from External Customer [Line Items]
Revenue recognized		13,785.2	12,210.8	5,181.3
Condensate and Crude Oil [Member]
Revenue from External Customer [Line Items]
Revenue recognized		565.3	358.4	264
Petroleum Products [Member]
Revenue from External Customer [Line Items]
Revenue recognized				69.8
Gathering and Processing [Member]
Revenue from External Customer [Line Items]
Revenue recognized		1,137.2	730.3	476
Sales of Commodities [Member]
Revenue from External Customer [Line Items]
Total revenues		19,066	15,602.5	7,171
Other [Member]
Revenue from External Customer [Line Items]
Revenue recognized		69.3	46.7	48.3
NGL Transportation, Fractionation and Services [Member]
Revenue from External Customer [Line Items]
Revenue recognized		285.1	190.6	163.1
Storage Terminaling and Export [Member]
Revenue from External Customer [Line Items]
Revenue recognized		372.2	379.7	401.9
Fees from Midstream Services [Member]
Revenue from External Customer [Line Items]
Revenue recognized		1,863.8	1,347.3	1,089.3
Total revenues		$ 1,863.8	$ 1,347.3	$ 1,089.3
[1] Represents derivative activities that are not designated as hedging instruments under ASC 815.

Segment Information - Reconcili

Segment Information - Reconciliation of Reportable Segment Operating Margin to Income (Loss) Before Income Taxes (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended	12 Months Ended
		Dec. 31, 2021	Mar. 31, 2020	Jun. 30, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Depreciation and amortization expense					$ (1,096)	$ (870.6)	$ (865.1)
General and administrative expense					(309.7)	(273.2)	(254.6)
Impairment of long-lived assets		$ (452.3)	$ (2,442.8)			(452.3)	(2,442.8)
interest income (expense)					(446.1)	(387.9)	(391.3)
Equity earnings (loss)					9.1	(23.9)	72.6
Gain (loss) on sale or disposition of assets	[1]				9.6	(2)	(58.4)
Write-down of assets	[2]				(9.8)	(10.3)	(55.6)
Gain (loss) from financing activities				$ 61.1	(49.6)	(16.6)	45.6
Gain (loss) from sale of equity-method investment					435.9
Other, net					(15.1)		1.1
Income (loss) before income taxes					1,663.2	436.9	(1,573.1)
Gathering and Processing [Member]
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Operating margin	[3]				1,981	1,325.3	1,017.7
Logistics and Transportation [Member]
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Operating margin	[3]				1,456.3	1,264.3	1,128
Other [Member]
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Operating margin	[3]				$ (302.4)	$ (115.9)	$ 229.7
[1] Primarily related to the sale of assets in Channelview, Texas in 2020. See Note 4 – Acquisitions and Divestitures for further discussion regarding these sales. Related to the write-down of certain assets to their recoverable amounts. Operating margin is calculated by subtracting Product purchases and fuel and Operating expenses from Revenues.