EX-99.1

HOUSTON – August 3, 2023 - Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported second quarter 2023 results.

Second quarter 2023 net income attributable to Targa Resources Corp. was $329.3 million compared to $596.4 million for the second quarter of 2022. The Company recognized a $435.9 million gain from sale of an equity method investment in the second quarter of 2022.

•

Continue to estimate 2023 adjusted EBITDA(1) between $3.5 billion and $3.7 billion

•

Repurchased $149 million of common stock during the second quarter and $201 million for the six months ended June 30, 2023 at a weighted average price of $71.49

•

Announced two new Permian gas plants to meet the infrastructure needs of producers, with no change to 2023 growth capital expenditure estimate of $2.0 billion to $2.2 billion

•

Reported record Permian natural gas inlet volumes during the second quarter

•

Reported record NGL pipeline transportation volumes during the second quarter

•

Reported record NGL fractionation volumes during the second quarter

The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) of $789.1 million for the second quarter of 2023 compared to $666.4 million for the second quarter of 2022. The Company reported distributable cash flow and adjusted free cash flow for the second quarter of 2023 of $575.8 million and $(3.7) million, respectively.

On July 13, 2023, the Company declared a quarterly cash dividend of $0.50 per common share for the second quarter of 2023, or $2.00 per common share on an annualized basis. Total cash dividends of approximately $112 million will be paid on August 15, 2023 on all outstanding shares of common stock to holders of record as of the close of business on July 31, 2023.

Targa repurchased 2,088,062 shares of its common stock during the second quarter of 2023 at a weighted average per share price of $71.37 for a total net cost of $149.0 million. There was $942.7 million remaining under the Company’s $1.0 billion common share repurchase program as of June 30, 2023.

Targa reported second quarter 2023 adjusted EBITDA of $789.1 million, representing a 16 percent decrease when compared to the first quarter of 2023. The sequential decrease in adjusted EBITDA was predominantly attributable to lower optimization margin realized in Targa’s marketing and LPG export businesses, lower realized natural gas and NGL prices, and higher operating expenses, partially offset by higher volumes across Targa’s Gathering and Processing (“G&P”) and Logistics and Transportation (“L&T”) systems. In the G&P segment, lower sequential adjusted operating margin was attributable to lower realized natural gas and NGL prices, partially offset by record Permian natural gas inlet volumes and higher fees. The increase in natural gas inlet volumes in the Permian was attributable to continued high levels of producer activity. In the L&T segment, significantly lower marketing margin and lower LPG export volumes drove the sequential decrease in segment adjusted operating margin, partially offset by higher sequential pipeline transportation and fractionation volumes. Marketing margin was lower due to reduced seasonal optimization opportunities. LPG export volumes were lower due to less demand than the first quarter. Record NGL pipeline transportation and fractionation volumes were primarily due to higher supply volumes from Targa’s Permian G&P systems. Higher operating expenses were primarily attributable to increased activity levels and additional facilities placed into service.

The Company’s total consolidated debt as of June 30, 2023 was $12,398.8 million, net of $65.6 million of debt issuance costs and $40.8 million of unamortized discount, with $9,534.4 million of outstanding senior notes, $1.5 billion outstanding under the Company’s $1.5 billion term loan facility, $660.0 million outstanding under the Commercial Paper Program, $547.9 million outstanding under the Securitization Facility, and $262.9 million of finance lease liabilities.

Total consolidated liquidity as of June 30, 2023 was approximately $2.2 billion, including $2.1 billion available under the TRGP Revolver and $169.4 million of cash.

During the second quarter, Targa commenced full operations at its new 275 million cubic feet per day (“MMcf/d”) Legacy II plant in Permian Midland and commenced operations at its new 275 MMcf/d Midway plant in Permian Delaware.

In Permian Midland, construction continues on Targa’s 275 MMcf/d Greenwood plant. In Permian Delaware, Targa continues to advance its 275 MMcf/d Wildcat II and 230 MMcf/d Roadrunner II plants. In its L&T segment, construction continues on Targa’s 120 thousand barrel per day (“MBbl/d”) Train 9 fractionator and its 120 MBbl/d Train 10 fractionator in Mont Belvieu, Texas, and its Daytona NGL Pipeline. Targa remains on-track to complete these expansions as previously disclosed.

In August 2023, in response to increasing production and to meet the infrastructure needs of producers, Targa announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Greenwood II plant”) and the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Bull Moose plant”). The Greenwood II and Bull Moose plants are expected to begin operations in the fourth quarter of 2024 and in the second quarter of 2025, respectively.

While commodity prices are lower than the assumptions underlying Targa’s previously disclosed full year financial estimates for 2023, there is no change to Targa’s expectation to generate full year adjusted EBITDA between $3.5 billion and $3.7 billion for 2023. Targa’s estimate for 2023 total net growth capital expenditures remains unchanged at between $2.0 billion and $2.2 billion, inclusive of spending on the Greenwood II and Bull Moose plants. Targa’s estimate for 2023 net maintenance capital expenditures also remains unchanged at approximately $175 million. Please see the section of this release entitled “Non-GAAP Financial Measures” for a discussion of forward-looking estimated adjusted EBITDA and a reconciliation of such measure to its most directly comparable GAAP financial measure.

An earnings supplement presentation and an updated investor presentation are available under Events and Presentations in the Investors section of the Company’s website at www.targaresources.com/investors/events.

The Company will host a conference call for the investment community at 11:00 a.m. Eastern time (10:00 a.m. Central time) on August 3, 2023 to discuss its second quarter results. The conference call can be accessed via webcast under Events and Presentations in the Investors section of the Company’s website at www.targaresources.com/investors/events, or by going directly to https://edge.media-server.com/mmc/p/t7tn3qbg. A webcast replay will be available at the link above approximately two hours after the conclusion of the event.

(1)

Adjusted EBITDA is a non-GAAP financial measure and is discussed under “Non-GAAP Financial Measures.”

(1)

Adjusted EBITDA, distributable cash flow and adjusted free cash flow are non-GAAP financial measures and are discussed under “Non-GAAP Financial Measures.”

NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

The decrease in commodity sales reflects lower NGL, natural gas and condensate prices ($3,412.8 million), partially offset by higher natural gas, condensate and NGL volumes ($331.5 million) and the favorable impact of hedges ($371.7 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees including the impact of the acquisition of certain assets in the Delaware Basin, partially offset by lower export volumes.

The decrease in product purchases and fuel reflects lower NGL, natural gas and condensate prices, partially offset by higher natural gas, condensate and NGL volumes.

The increase in operating expenses is primarily due to increased activity and system expansions, the acquisition of certain assets in the Delaware Basin and South Texas, and higher costs attributable to inflation.

See “—Review of Segment Performance” for additional information on a segment basis.

The increase in depreciation and amortization expense is primarily due to the acquisition of certain assets in the Delaware Basin, partially offset by the shortening of the depreciable lives of certain assets that were idled in 2022.

The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs and professional fees.

The increase in interest expense, net is due to higher net borrowings primarily for the acquisition of certain assets in the Delaware Basin and the Grand Prix Transaction, and higher interest rates on the Securitization Facility, partially offset by higher capitalized interest resulting from higher growth capital investments.

During 2022, the Partnership redeemed its 5.875% Senior Notes due 2026 (the “5.875% Notes”) resulting in a net loss from financing activities.

During 2022, the Company completed the sale of Targa GCX Pipeline LLC to a third party (the “GCX Sale”) resulting in a gain from sale of an equity method investment.

The increase in income tax expense is primarily due to a smaller release of the valuation allowance in 2023 compared to 2022, partially offset by a decrease in pre-tax book income.

The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the Grand Prix Transaction and lower earnings allocated to the Company’s joint venture partner in WestTX.

The decrease in dividends on Series A Preferred Stock (“Series A Preferred”) is due to the full redemption of all of the Company’s issued and outstanding shares of Series A Preferred in May 2022.

The decrease in commodity sales reflects lower NGL, natural gas and condensate prices ($5,197.2 million), partially offset by higher NGL, natural gas and condensate volumes ($1,028.9 million) and the favorable impact of hedges ($917.7 million).

The decrease in product purchases and fuel reflects lower NGL, natural gas and condensate prices, partially offset by higher NGL, natural gas and condensate volumes.

See “—Review of Segment Performance” for additional information on a segment basis.

The increase in depreciation and amortization expense is primarily due to the acquisition of certain assets in the Delaware Basin and the impact of system expansions on the Company’s asset base, partially offset by the shortening of depreciable lives of certain assets that were idled in 2022.

The increase in general and administrative expense is primarily due to higher compensation and benefits, insurance costs and professional fees.

During 2022, the Company terminated the previous TRGP senior secured revolving credit facility and the Partnership’s senior secured revolving credit facility. In addition, the Partnership redeemed its 5.375% Senior Notes due 2027 and 5.875% Notes. These transactions resulted in a net loss from financing activities.

During 2022, the Company completed the GCX Sale resulting in a gain from sale of an equity method investment.

The increase in income tax expense is primarily due to an increase in pre-tax book income and a smaller release of the valuation allowance in 2023 compared to 2022.

The premium on repurchase of noncontrolling interests, net of tax is due to the Grand Prix Transaction in 2023 and the purchase of all of Stonepeak Infrastructure Partners’ interests in the Company’s development company joint ventures in 2022.

The decrease in dividends on Series A Preferred is due to the full redemption of all of the Company’s issued and outstanding shares of Series A Preferred in May 2022.

The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin and adjusted operating margin as important performance measures of the core profitability of its operations. These measures are key components of internal financial reporting and are reviewed for consistency and trend analysis. For a discussion of adjusted operating margin, see “Non-GAAP Financial Measures ― Adjusted Operating Margin.” Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation.

The Company operates in two primary segments: (i) Gathering and Processing; and (ii) Logistics and Transportation.

The 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.

The following table provides summary data regarding results of operations of this segment for the periods indicated:

(1)

Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

(2)

Plant natural gas inlet represents the Company’s undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than Badlands.

(3)

Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.

(4)

Permian Midland includes operations in WestTX, of which the Company owns a 72.8% undivided interest, and other plants that are owned 100% by the Company. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in the Company’s reported financials.

(5)

Includes operations from the acquisition of certain assets in the Delaware Basin for the period effective August 1, 2022.

(6)

Operations include facilities that are not wholly owned by the Company. SouthTX operating statistics include the impact of the acquisition of certain assets in South Texas for the period effective April 21, 2022.

(7)

Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant.

(8)

Average realized prices, net of fees, include the effect of realized commodity hedge gain/loss attributable to the Company’s equity volumes. The price is calculated using total commodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator, net of fees.

The following table presents the realized commodity hedge gain (loss) attributable to the Company’s equity volumes that are included in the adjusted operating margin of the Gathering and Processing segment:

(1)

The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.

The increase in adjusted operating margin was due to higher natural gas inlet volumes and higher fees resulting in increased margin predominantly in the Permian, partially offset by lower commodity prices. The increase in natural gas inlet volumes in the Permian was attributable to the acquisition of certain assets in the Delaware Basin during the third quarter of 2022, the addition of the Legacy I and Red Hills VI plants during the third quarter of 2022 and the Legacy II plant late in the first quarter of 2023, and continued strong producer activity. Natural gas inlet volumes in the Central region increased primarily due to the acquisition of certain assets in South Texas during the second quarter of 2022 and increased producer activity.

The increase in operating expenses was predominantly due to the acquisition of certain assets in the Delaware Basin. Additionally, higher volumes in the Permian, the addition of the Legacy I, Red Hills VI, Legacy II and Midway plants, and inflation impacts resulted in increased costs.

The increase in adjusted operating margin was due to higher natural gas inlet volumes and higher fees resulting in increased margin predominantly in the Permian, partially offset by lower commodity prices. The increase in natural gas inlet volumes in the Permian was attributable to the acquisition of certain assets in the Delaware Basin during the third quarter of 2022, the addition of the Legacy I and Red Hills VI plants during the third quarter of 2022 and the Legacy II plant late in the first quarter of 2023, and continued strong producer activity. Natural gas inlet volumes in the Central region increased due to the acquisition of certain assets in South Texas during the second quarter of 2022 and increased producer activity.

The increase in operating expenses was predominantly due to the acquisition of certain assets in South Texas and the Delaware Basin. Additionally, higher volumes in the Permian, the addition of the Legacy I, Red Hills VI and Legacy II plants, and inflation impacts resulted in increased costs.

The 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 the Company’s other businesses. The Logistics and Transportation segment also includes Grand Prix NGL Pipeline, which connects the Company’s gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with the Company’s Downstream facilities in Mont Belvieu, Texas. The associated assets are generally connected to and supplied in part by the Company’s Gathering and Processing segment and, except for the pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

The following table provides summary data regarding results of operations of this segment for the periods indicated:

(1)

Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

(2)

Represents the total quantity of mixed NGLs that earn a transportation margin.

(3)

Export volumes represent the quantity of NGL products delivered to third-party customers at the Company’s Galena Park Marine Terminal that are destined for international markets.

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin and higher marketing margin, partially offset by lower LPG export margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from the Company’s Permian Gathering and Processing systems and higher fees. Marketing margin increased due to greater optimization opportunities. LPG export margin decreased due to lower volumes.

The increase in operating expenses was primarily due to higher equipment rentals and higher compensation and benefits.

The increase in adjusted operating margin was due to higher marketing margin, higher pipeline transportation and fractionation margin and higher LPG export margin. Marketing margin increased due to greater optimization opportunities. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from the Company’s Permian Gathering and Processing systems and higher fees. LPG export margin increased primarily due to lower fuel and power costs.

The increase in operating expenses was due to higher compensation and benefits, higher taxes and higher equipment rentals.

Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. The Company has entered into derivative instruments to hedge the commodity price associated with a portion of the Company’s future commodity purchases and sales and natural gas transportation basis risk within the Company’s Logistics and Transportation segment.

Targa Resources Corp. is a leading provider of midstream services and is one of the largest independent midstream infrastructure companies in North America. The Company owns, operates, acquires and develops a diversified portfolio of complementary domestic midstream infrastructure assets and its operations are critical to the efficient, safe and reliable delivery of energy across the United States and increasingly to the world. The Company’s assets connect natural gas and NGLs to domestic and international markets with growing demand for cleaner fuels and feedstocks. 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.

For more information, please visit the Company’s website at www.targaresources.com.

This press release includes the Company’s non-GAAP financial measures: adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment). The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures.

The Company utilizes non-GAAP measures to analyze the Company’s performance. Adjusted EBITDA, distributable cash flow, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Additionally, because the Company’s non-GAAP measures exclude some, but not all, items that affect income and segment operating margin, and are defined differently by different companies within the Company’s industry, the Company’s definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of the Company’s non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into the Company’s decision-making processes.

The Company defines adjusted operating margin for the Company’s segments as revenues less product purchases and fuel. It is impacted by volumes and commodity prices as well as by the Company’s contract mix and commodity hedging program.

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service fees related to natural gas and crude oil gathering, treating and processing; and

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revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and the Company’s equity volume hedge settlements.

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service fees (including the pass-through of energy costs included in certain fee rates);

•

NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change.

The adjusted operating margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.

Adjusted operating margin for the Company’s segments provides useful information to investors because it is used as a supplemental financial measure by management and by external users of the Company’s financial statements, including investors and commercial banks, to assess:

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the financial performance of the Company’s assets without regard to financing methods, capital structure or historical cost basis;

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the Company’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

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the viability of capital expenditure projects and acquisitions and the overall rates of return on alternative investment opportunities.

Management reviews adjusted operating margin and operating margin for the Company’s segments monthly as a core internal management process. The Company believes that investors benefit from having access to the same financial measures that management uses in evaluating the Company’s operating results. The reconciliation of the Company’s adjusted operating margin to the most directly comparable GAAP measure is presented under “Review of Segment Performance.”

The Company defines adjusted EBITDA as Net income (loss) attributable to Targa Resources Corp. before interest, income taxes, depreciation and amortization, and other items that the Company believes should be adjusted consistent with the Company’s core operating performance. The adjusting items are detailed in the adjusted EBITDA reconciliation table and its footnotes. Adjusted EBITDA is used as a supplemental financial measure by the Company and by external users of the Company’s financial statements such as investors, commercial banks and others to measure the ability of the Company’s assets to generate cash sufficient to pay interest costs, support the Company’s indebtedness and pay dividends to the Company’s investors.

The Company defines distributable cash flow as adjusted EBITDA less cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). The Company defines adjusted free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and adjusted free cash flow are performance measures used by the Company and by external users of the Company’s financial statements, such as investors, commercial banks and research analysts, to assess the Company’s ability to generate cash earnings (after servicing the Company’s debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends, retirement of debt or redemption of other financing arrangements.

The following table presents a reconciliation of Net income (loss) attributable to Targa Resources Corp. to adjusted EBITDA, distributable cash flow and adjusted free cash flow for the periods indicated:

(1)

Gains or losses on debt repurchases or early debt extinguishments.

(2)

Noncontrolling interest portion of depreciation and amortization expense.

(4)

Represents capital expenditures, net of contributions from noncontrolling interests and includes net contributions to investments in unconsolidated affiliates.

The following table presents a reconciliation of estimated net income of the Company to estimated adjusted EBITDA for 2023:

(1)

Noncontrolling interest portion of depreciation and amortization expense.

We use any of the following to comply with our disclosure obligations under Regulation FD: press releases, SEC filings, public conference calls, or our website. We routinely post important information on our website at www.targaresources.com, including information that may be deemed to be material. We encourage investors and others interested in the company to monitor these distribution channels for material disclosures.

Certain statements in this release are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, are forward-looking statements, including statements regarding our projected financial performance and capital spending. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Company’s control, which could cause results to differ materially from those expected by management of the Company. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas, natural gas liquids and crude oil, the impact of pandemics or any other public health crises, commodity price volatility due to ongoing or new global conflicts, actions by the Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC oil producing countries, the impact of disruptions in the bank and capital markets, including those resulting from lack of access to liquidity for banking and financial services firms, the timing and success of business development efforts and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Company’s filings with the Securities and Exchange Commission, including its most recent Annual Report on Form 10-K, and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The Company does not undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Contact the Company’s investor relations department by email at InvestorRelations@targaresources.com or by phone at (713) 584-1133.


	Three Months Ended June 30,												Six Months Ended June 30,
	2023			2022			2023 vs. 2022						2023			2022			2023 vs. 2022
	(In millions)
Revenues:
Sales of commodities	$	2,914.6		$	5,624.2		$	(2,709.6	)		(48	%)	$	6,939.7		$	10,190.3		$	(3,250.6	)		(32	%)
Fees from midstream services		489.1			431.6			57.5			13	%		984.5			824.6			159.9			19	%
Total revenues		3,403.7			6,055.8			(2,652.1	)		(44	%)		7,924.2			11,014.9			(3,090.7	)		(28	%)
Product purchases and fuel		2,068.9			5,047.3			(2,978.4	)		(59	%)		5,088.0			9,251.5			(4,163.5	)		(45	%)
Operating expenses		272.6			215.8			56.8			26	%		530.7			399.3			131.4			33	%
Depreciation and amortization expense		332.1			269.9			62.2			23	%		656.9			479.0			177.9			37	%
General and administrative expense		81.0			71.0			10.0			14	%		163.4			138.0			25.4			18	%
Other operating (income) expense		—			(0.1	)		0.1			100	%		(0.6	)		(0.6	)		—			—
Income (loss) from operations		649.1			451.9			197.2			44	%		1,485.8			747.7			738.1			99	%
Interest expense, net		(166.6	)		(81.2	)		(85.4	)		105	%		(334.7	)		(174.7	)		(160.0	)		92	%
Equity earnings (loss)		3.4			1.4			2.0			143	%		3.2			7.0			(3.8	)		(54	%)
Gain (loss) from financing activities		—			(33.8	)		33.8			100	%		—			(49.6	)		49.6			100	%
Gain (loss) from sale of equity method investment		—			435.9			(435.9	)		(100	%)		—			435.9			(435.9	)		(100	%)
Other, net		(2.0	)		0.5			(2.5	)	NM				(4.9	)		—			(4.9	)		(100	%)
Income tax (expense) benefit		(96.4	)		(87.1	)		(9.3	)		11	%		(206.7	)		(110.1	)		(96.6	)		88	%
Net income (loss)		387.5			687.6			(300.1	)		(44	%)		942.7			856.2			86.5			10	%
Less: Net income (loss) attributable to noncontrolling interests		58.2			91.2			(33.0	)		(36	%)		116.4			171.8			(55.4	)		(32	%)
Net income (loss) attributable to Targa Resources Corp.		329.3			596.4			(267.1	)		(45	%)		826.3			684.4			141.9			21	%
Premium on repurchase of noncontrolling interests, net of tax		—			—			—			—			490.7			53.1			437.6		NM
Dividends on Series A Preferred Stock		—			8.2			(8.2	)		(100	%)		—			30.0			(30.0	)		(100	%)
Deemed dividends on Series A Preferred Stock		—			215.5			(215.5	)		(100	%)		—			215.5			(215.5	)		(100	%)
Net income (loss) attributable to common shareholders	$	329.3		$	372.7		$	(43.4	)		(12	%)	$	335.6		$	385.8		$	(50.2	)		(13	%)
Financial data:
Adjusted EBITDA (1)	$	789.1		$	666.4		$	122.7			18	%	$	1,729.7		$	1,292.1		$	437.6			34	%
Distributable cash flow (1)		575.8			533.4			42.4			8	%		1,305.2			1,028.2			277.0			27	%
Adjusted free cash flow (1)		(3.7	)		334.1			(337.8	)		(101	%)		310.3			707.5			(397.2	)		(56	%)


	Three Months Ended June 30,										Six Months Ended June 30,
	2023			2022		2023 vs. 2022					2023		2022		2023 vs. 2022
		(In millions, except operating statistics and price amounts)
Operating margin	$		502.5	$	474.7	$	27.8		6	%	$	1,040.9	$	872.3	$	168.6		19	%
Operating expenses			189.8		141.4		48.4		34	%		371.2		258.0		113.2		44	%
Adjusted operating margin	$		692.3	$	616.1	$	76.2		12	%	$	1,412.1	$	1,130.3	$	281.8		25	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2) (3)
Permian Midland (4)			2,504.3		2,132.0		372.3		17	%		2,426.9		2,103.7		323.2		15	%
Permian Delaware (5)			2,560.8		993.3		1,567.5		158	%		2,528.1		985.1		1,543.0		157	%
Total Permian			5,065.1		3,125.3		1,939.8		62	%		4,955.0		3,088.8		1,866.2		60	%

SouthTX (6)			371.0		271.2		99.8		37	%		363.5		216.9		146.6		68	%
North Texas			208.0		175.3		32.7		19	%		201.8		175.3		26.5		15	%
SouthOK (6)			395.0		460.4		(65.4	)	(14	%)		389.5		434.0		(44.5	)	(10	%)
WestOK			211.0		212.0		(1.0	)	—			207.6		207.2		0.4		—
Total Central			1,185.0		1,118.9		66.1		6	%		1,162.4		1,033.4		129.0		12	%

Badlands (6) (7)			128.9		129.4		(0.5	)	—			130.3		127.2		3.1		2	%
Total Field			6,379.0		4,373.6		2,005.4		46	%		6,247.7		4,249.4		1,998.3		47	%

Coastal			552.1		553.6		(1.5	)	—			530.7		577.7		(47.0	)	(8	%)

Total			6,931.1		4,927.2		2,003.9		41	%		6,778.4		4,827.1		1,951.3		40	%
NGL production, MBbl/d (3)
Permian Midland (4)			363.6		310.6		53.0		17	%		349.4		305.7		43.7		14	%
Permian Delaware (5)			367.9		135.8		232.1		171	%		355.4		132.8		222.6		168	%
Total Permian			731.5		446.4		285.1		64	%		704.8		438.5		266.3		61	%

SouthTX (6)			45.6		33.5		12.1		36	%		42.0		26.9		15.1		56	%
North Texas			24.3		19.6		4.7		24	%		23.7		19.4		4.3		22	%
SouthOK (6)			47.3		55.8		(8.5	)	(15	%)		43.1		53.1		(10.0	)	(19	%)
WestOK			12.5		16.6		(4.1	)	(25	%)		12.8		15.8		(3.0	)	(19	%)
Total Central			129.7		125.5		4.2		3	%		121.6		115.2		6.4		6	%

Badlands (6)			15.6		14.7		0.9		6	%		15.5		14.7		0.8		5	%
Total Field			876.8		586.6		290.2		49	%		841.9		568.4		273.5		48	%

Coastal			36.8		36.7		0.1		—			36.5		36.9		(0.4	)	(1	%)

Total			913.6		623.3		290.3		47	%		878.4		605.3		273.1		45	%
Crude oil, Badlands, MBbl/d			104.7		111.8		(7.1	)	(6	%)		107.7		117.2		(9.5	)	(8	%)
Crude oil, Permian, MBbl/d			29.4		28.8		0.6		2	%		27.5		29.7		(2.2	)	(7	%)
Natural gas sales, BBtu/d (3)			2,672.6		2,277.1		395.5		17	%		2,622.8		2,202.1		420.7		19	%
NGL sales, MBbl/d (3)			493.8		440.4		53.4		12	%		476.6		432.7		43.9		10	%
Condensate sales, MBbl/d			24.0		15.7		8.3		53	%		21.9		15.0		6.9		46	%
Average realized prices (8):
Natural gas, $/MMBtu			1.29		6.12		(4.83	)	(79	%)		1.94		5.15		(3.21	)	(62	%)
NGL, $/gal			0.41		0.89		(0.48	)	(54	%)		0.47		0.84		(0.37	)	(44	%)
Condensate, $/Bbl			69.52		103.10		(33.58	)	(33	%)		68.09		90.06		(21.97	)	(24	%)


	Three Months Ended June 30, 2023								Three Months Ended June 30, 2022
	(In millions, except volumetric data and price amounts)
	Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)			Gain (Loss)
Natural gas (BBtu)		15.3	$	1.73		$	26.4			16.7	$	(3.29	)	$	(54.9	)
NGL (MMgal)		164.9		0.11			17.7			164.4		(0.47	)		(77.9	)
Crude oil (MBbl)		0.6		(3.67	)		(2.2	)		0.5		(51.00	)		(25.5	)
						$	41.9							$	(158.3	)


	Six Months Ended June 30, 2023								Six Months Ended June 30, 2022
	(In millions, except volumetric data and price amounts)
	Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)			Gain (Loss)
Natural gas (BBtu)		35.0	$	1.51		$	52.9			34.2	$	(2.52	)	$	(86.1	)
NGL (MMgal)		349.0		0.08			27.2			334.8		(0.47	)		(155.8	)
Crude oil (MBbl)		1.2		(4.17	)		(5.0	)		1.0		(45.20	)		(45.2	)
						$	75.1							$	(287.1	)


	Three Months Ended June 30,								Six Months Ended June 30,
	2023		2022		2023 vs. 2022				2023		2022		2023 vs. 2022
	(In millions, except operating statistics)
Operating margin	$	408.0	$	322.3	$	85.7		27%	$	937.1	$	674.5	$	262.6		39%
Operating expenses		82.5		74.4		8.1		11%		159.0		141.3		17.7		13%
Adjusted operating margin	$	490.5	$	396.7	$	93.8		24%	$	1,096.1	$	815.8	$	280.3		34%
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)		620.7		492.3		128.4		26%		579.0		476.1		102.9		22%
Fractionation volumes		794.4		737.2		57.2		8%		776.7		720.1		56.6		8%
Export volumes (3)		303.2		342.6		(39.4	)	(12%)		338.1		341.7		(3.6	)	(1%)
NGL sales		947.0		906.9		40.1		4%		977.1		890.0		87.1		10%


	2023E
	(In millions)
Reconciliation of Estimated Net Income Attributable to Targa Resources Corp. to
Estimated Adjusted EBITDA
Net income attributable to Targa Resources Corp.	$	1,440.0
Interest expense, net		700.0
Income tax expense		400.0
Depreciation and amortization expense		1,320.0
Equity earnings		(10.0	)
Distributions from unconsolidated affiliates		25.0
Compensation on equity grants		60.0
Risk management and other		(330.0	)
Noncontrolling interests adjustments (1)		(5.0	)
Estimated Adjusted EBITDA	$	3,600.0