HOUSTON, Nov. 03, 2022 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE:TRGP) ("TRGP," the "Company" or "Targa") today reported third quarter 2022 results.

Third Quarter 2022 Financial Results

Third quarter 2022 net income attributable to Targa Resources Corp. was $193.1 million compared to $182.2 million for the third quarter of 2021.

The Company reported record adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items ("adjusted EBITDA") of $768.6 million for the third quarter of 2022 compared to $505.9 million for the third quarter of 2021.

On October 13, 2022, Targa declared a quarterly dividend of $0.35 per share of its common stock for the third quarter of 2022, or $1.40 per share on an annualized basis. Total cash dividends of approximately $79 million will be paid on November 15, 2022 on all outstanding shares of common stock to holders of record as of the close of business on October 31, 2022.

Targa repurchased 1,156,832 shares of its common stock during the third quarter of 2022 at a weighted average price of $63.06 for a total net cost of $72.9 million. There was $171.8 million remaining under the Company's $500 million common share repurchase program as of September 30, 2022.

The Company reported distributable cash flow and adjusted free cash flow for the third quarter of 2022 of $594.9 million and $290.8 million, respectively.

Third Quarter 2022 - Sequential Quarter over Quarter Commentary

Targa reported third quarter 2022 adjusted EBITDA of $768.6 million, representing a 15 percent increase when compared to the second quarter of 2022. The sequential increase in adjusted EBITDA was primarily attributable to higher volumes across Targa's Gathering and Processing ("G&P") and Logistics and Transportation ("L&T") systems, partially offset by lower natural gas liquids ("NGL") and condensate prices and higher operating expenses. Higher sequential adjusted operating margin in the G&P segment was driven by contributions from the Company's Delaware Basin acquisition, which closed with an accounting effective date of August 1, 2022, and higher natural gas inlet volumes across Permian, Central, and Badlands partially offset by lower volumes in SouthOK resulting from a contract expiration. Permian natural gas inlet volumes averaged a record 4.1 billion cubic feet per day ("Bcf/d") in the third quarter. In the L&T segment, the sequential increase in segment adjusted operating margin was attributable to higher pipeline transportation and fractionation volumes and higher marketing margin, partially offset by lower LPG export margin. NGL pipeline transportation and fractionation volumes achieved record levels during the third quarter primarily due to higher supply volumes from Targa's Permian G&P systems and third parties. Marketing margin was higher due to greater optimization opportunities while the decrease in LPG export margin was due to lower volumes. Higher operating expenses were attributable to the Delaware Basin acquisition, higher activity levels, and higher costs from the impacts of inflation.

Capitalization and Liquidity

In September 2022, the Company amended the accounts receivable securitization facility (the "Securitization Facility"), primarily to increase the size of the Securitization Facility from $400.0 million to $800.0 million and extend the Securitization Facility termination date to September 1, 2023.

The Company's total consolidated debt as of September 30, 2022 was $11,197.8 million, net of $66.5 million of debt issuance costs and $8.5 million of unamortized discount, with $7,784.4 million of outstanding senior notes, $1.5 billion outstanding under the Company's $1.5 billion term loan facility, $550.0 million outstanding under the Company's $2.75 billion senior revolving credit facility (the "TRGP Revolver"), $632.0 million outstanding under the Company's unsecured commercial paper note program, $750.0 million outstanding under the Securitization Facility and $56.4 million of finance lease liabilities.

Total consolidated liquidity as of September 30, 2022 was approximately $1.8 billion, including $1.5 billion available under the TRGP Revolver, $192.9 million of cash and $50.0 million available under the Securitization Facility.

Growth Projects Update

During the third quarter, Targa commenced operations at its new 275 million cubic feet per day ("MMcf/d") Legacy plant in Permian Midland and its new 230 MMcf/d Red Hills VI plant in Permian Delaware.

Construction continues on Targa's 275 MMcf/d Legacy II plant and 275 MMcf/d Greenwood plant in Permian Midland, its 275 MMcf/d Midway plant in Permian Delaware, and its 120 thousand barrels per day ("MBbl/d") Train 9 fractionator in Mont Belvieu.

In November 2022, 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 Delaware (the "Wildcat II plant"), which is expected to begin operations in the first quarter of 2024.

In November 2022, supported by the growth in NGLs from Targa's underlying assets and future plant additions, Targa announced plans to construct the Daytona NGL Pipeline as an addition to Targa's existing common carrier Grand Prix NGL Pipeline system. The Daytona NGL Pipeline will transport NGLs from the Permian Basin and connect to the 30-inch diameter segment of Targa's Grand Prix NGL Pipeline in North Texas, where volumes will be transported to Targa's fractionation and storage complex in Mont Belvieu. The Daytona NGL Pipeline is expected to be in service by the end of 2024, at an estimated cost of approximately $650 million. Grand Prix Pipeline LLC (the "Grand Prix Joint Venture"), of which Targa owns 75% and Blackstone Energy Partners owns 25%, will own the Daytona NGL Pipeline and each member will fund their respective share of the pipeline's cost based on their ownership percentage. Targa is constructing and operating the Daytona NGL Pipeline. Targa expects to fund the construction of the Daytona NGL Pipeline through the utilization of operating cash flows and available liquidity.

2022 Outlook

While commodity prices were significantly lower in the third quarter than the assumptions underlying Targa's last provided financial estimates for 2022, there is no change to the Company's expectation to generate full year adjusted EBITDA between $2.85 billion and $2.95 billion.

Through September 30, 2022, Targa has spent $624.8 million on net growth capital expenditures and now estimates total net growth capital expenditures for 2022 to be between $1.1 billion and $1.2 billion including spending accelerated into 2022 for the new Wildcat II plant and the Daytona NGL Pipeline. Targa's estimate for 2022 net maintenance capital expenditures remains unchanged at approximately $150 million.

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.

Conference Call

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 November 3, 2022 to discuss its third 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/8vx55eqq. A webcast replay will be available at the link above approximately two hours after the conclusion of the event.

Targa Resources Corp. – Consolidated Financial Results of Operations

	Three Months Ended September 30,												Nine Months Ended September 30,
	2022			2021			2022 vs. 2021						2022			2021			2022 vs. 2021
	(In millions)
Revenues:
Sales of commodities	$	4,800.3		$	4,118.1		$	682.2			17	%	$	14,990.7		$	10,577.3		$	4,413.4			42	%
Fees from midstream services		559.8			341.6			218.2			64	%		1,384.3			930.9			453.4			49	%
Total revenues		5,360.1			4,459.7			900.4			20	%		16,375.0			11,508.2			4,866.8			42	%
Product purchases and fuel		4,306.3			3,614.7			691.6			19	%		13,557.8			9,159.8			4,398.0			48	%
Operating expenses		261.3			189.4			71.9			38	%		660.6			545.3			115.3			21	%
Depreciation and amortization expense		287.2			222.8			64.4			29	%		766.2			650.9			115.3			18	%
General and administrative expense		79.1			67.3			11.8			18	%		217.2			192.4			24.8			13	%
Other operating (income) expense		(3.8	)		(1.0	)		(2.8	)		280	%		(4.4	)		3.4			(7.8	)		(229	%)
Income (loss) from operations		430.0			366.5			63.5			17	%		1,177.6			956.4			221.2			23	%
Interest expense, net		(125.8	)		(91.0	)		(34.8	)		38	%		(300.5	)		(284.2	)		(16.3	)		6	%
Equity earnings (loss)		1.7			14.3			(12.6	)		(88	%)		8.7			38.9			(30.2	)		(78	%)
Gain (loss) from financing activities		—			—			—			—			(49.6	)		(16.6	)		(33.0	)		199	%
Gain (loss) from sale of equity method investment		—			—			—			—			435.9			—			435.9			100	%
Other, net		(14.6	)		0.2			(14.8	)	NM				(14.6	)		0.3			(14.9	)	NM
Income tax (expense) benefit		(12.0	)		(2.0	)		(10.0	)	NM				(122.0	)		(23.5	)		(98.5	)	NM
Net income (loss)		279.3			288.0			(8.7	)		(3	%)		1,135.5			671.3			464.2			69	%
Less: Net income (loss) attributable to noncontrolling interests		86.2			105.8			(19.6	)		(19	%)		258.0			286.5			(28.5	)		(10	%)
Net income (loss) attributable to Targa Resources Corp.		193.1			182.2			10.9			6	%		877.5			384.8			492.7			128	%
Premium on repurchase of noncontrolling interests, net of tax		—			—			—			—			53.1			—			53.1			100	%
Dividends on Series A Preferred Stock		—			21.8			(21.8	)		(100	%)		30.0			65.5			(35.5	)		(54	%)
Deemed dividends on Series A Preferred Stock		—			—			—			—			215.5			—			215.5			100	%
Net income (loss) attributable to common shareholders	$	193.1		$	160.4		$	32.7			20	%	$	578.9		$	319.3		$	259.6			81	%
Financial data:
Adjusted EBITDA (1)	$	768.6		$	505.9		$	262.7			52	%	$	2,060.8		$	1,481.4		$	579.4			39	%
Distributable cash flow (1)		594.9			383.9			211.0			55	%		1,623.2			1,120.7			502.5			45	%
Adjusted free cash flow (1)		290.8			297.2			(6.4	)		(2	%)		998.4			892.8			105.6			12	%

__________________

(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 or material.

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021

The increase in commodity sales reflects higher natural gas and condensate prices ($867.5 million) and higher NGL and natural gas volumes ($110.3 million), partially offset by lower NGL prices ($132.7 million) and the unfavorable impact of hedges ($159.7 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, and transportation and fractionation fees, partially offset by lower export volumes.

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

The increase in operating expenses is due to higher compensation and benefits, maintenance and rental costs primarily due to increased activity, system expansions, the acquisition of certain assets in the Delaware Basin and South Texas and 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 and the shortening of depreciable lives of certain assets that have been, or will be, idled, partially offset by a lower depreciable base associated with assets that were impaired during the fourth quarter of 2021.

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 primarily due to higher net borrowings, partially offset by higher capitalized interest resulting from higher growth capital investments.

The decrease in equity earnings is primarily due to the sale of Targa GCX Pipeline LLC to a third party (the "GCX Sale"), partially offset by lower losses resulting from the purchase of the Company's remaining interests in the two operated joint ventures in South Texas that the Company previously held as investments in unconsolidated affiliates.

The increase in income tax expense is primarily due to a lower return-to-provision benefit in 2022 compared to 2021.

The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the repurchase of the Company's development company joint ventures in January 2022 (the "DevCo JV Repurchase"), partially offset by accretion of noncontrolling interests in certain joint ventures in WestTX and higher income allocated to noncontrolling interest holders in the Grand Prix Joint Venture.

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 during 2022.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($4,224.4 million) and higher NGL and natural gas volumes ($611.7 million), partially offset by the unfavorable impact of hedges ($414.1 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, transportation and fractionation fees and export volumes.

The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL and natural gas volumes.

The increase in operating expenses is due to higher maintenance, compensation and benefits, and rental costs primarily due to increased activity, system expansions, the acquisition of certain assets in the Delaware Basin and South Texas and inflation, partially offset by the impact of a major winter storm that affected regions across Texas, New Mexico, Oklahoma and Louisiana during the first quarter of 2021.

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 South Texas and the Delaware Basin, shortening of the depreciable lives of certain assets that have been, or will be, idled and impact of system expansions on the Company's asset base, partially offset by a lower depreciable base associated with assets that were impaired during the fourth quarter of 2021.

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 primarily due to higher net borrowings and higher non-cash interest expense related to an increase in the mandatorily redeemable preferred interest liability, partially offset by change in fair value of the mandatorily redeemable preferred interest, higher capitalized interest resulting from higher growth capital investments and lower commitment fees.

The decrease in equity earnings is primarily due to the GCX Sale and lower earnings from the Company's investment in Little Missouri 4 LLC, partially offset by lower losses resulting from the purchase of the Company's remaining interests in the two operated joint ventures in South Texas that Targa previously held as investments in unconsolidated affiliates and lower losses from Gulf Coast Fractionators.

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 the 5.375% Senior Notes due 2027 and the 5.875% Senior Notes due 2026. These transactions resulted in a net loss from financing activities. During 2021, the Partnership redeemed its 5.125% Senior Notes due 2025 and the 4.250% Senior Notes due 2023. In addition, Targa Pipeline Partners LP redeemed its 4.750% Senior Notes due 2021 and the 5.875% Senior Notes due 2023. 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, partially offset by a larger release of the valuation allowance in 2022 compared to 2021.

The decrease in net income (loss) attributable to noncontrolling interests is primarily due to the DevCo JV Repurchase, partially offset by accretion of noncontrolling interests in certain joint ventures in WestTX and higher income allocated to noncontrolling interests holders in the Grand Prix Joint Venture, Centrahoma Processing, LLC, Carnero Joint Venture and Venice Energy Services, L.L.C.

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 during 2022.

Review of Segment Performance

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.

Gathering and Processing Segment

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:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2022		2021		2022 vs. 2021					2022		2021		2022 vs. 2021
		(In millions, except operating statistics and price amounts)
Operating margin	$	564.6	$	361.4	$	203.2		56	%	$	1,437.0	$	938.2	$	498.8		53	%
Operating expenses		176.6		122.8		53.8		44	%		434.5		343.1		91.4		27	%
Adjusted operating margin	$	741.2	$	484.2	$	257.0		53	%	$	1,871.5	$	1,281.3	$	590.2		46	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)		2,307.2		2,044.7		262.5		13	%		2,172.3		1,878.9		293.4		16	%
Permian Delaware (5)		1,784.8		842.7		942.1		112	%		1,254.6		805.9		448.7		56	%
Total Permian		4,092.0		2,887.4		1,204.6					3,426.9		2,684.8		742.1

SouthTX (6)		335.5		180.5		155.0		86	%		256.9		184.0		72.9		40	%
North Texas		177.7		180.7		(3.0	)	(2	%)		176.1		179.2		(3.1	)	(2	%)
SouthOK (6)		400.4		420.6		(20.2	)	(5	%)		422.7		402.6		20.1		5	%
WestOK		212.8		219.4		(6.6	)	(3	%)		209.1		211.6		(2.5	)	(1	%)
Total Central		1,126.4		1,001.2		125.2					1,064.8		977.4		87.4

Badlands (6) (7)		144.8		135.2		9.6		7	%		133.1		137.8		(4.7	)	(3	%)
Total Field		5,363.2		4,023.8		1,339.4					4,624.8		3,800.0		824.8

Coastal		539.1		527.1		12.0		2	%		564.7		598.3		(33.6	)	(6	%)

Total		5,902.3		4,550.9		1,351.4		30	%		5,189.5		4,398.3		791.2		18	%
NGL production, MBbl/d (3)
Permian Midland (4)		332.6		293.8		38.8		13	%		314.8		270.3		44.5		16	%
Permian Delaware (5)		219.2		119.8		99.4		83	%		161.8		109.3		52.5		48	%
Total Permian		551.8		413.6		138.2					476.6		379.6		97.0

SouthTX (6)		36.4		24.2		12.2		50	%		30.1		22.6		7.5		33	%
North Texas		20.5		21.0		(0.5	)	(2	%)		19.8		20.2		(0.4	)	(2	%)
SouthOK (6)		48.1		52.1		(4.0	)	(8	%)		51.4		48.8		2.6		5	%
WestOK		14.8		15.7		(0.9	)	(6	%)		15.4		16.2		(0.8	)	(5	%)
Total Central		119.8		113.0		6.8					116.7		107.8		8.9

Badlands (6)		18.0		16.2		1.8		11	%		15.8		16.0		(0.2	)	(1	%)
Total Field		689.6		542.8		146.8					609.1		503.4		105.7

Coastal		31.7		28.0		3.7		13	%		35.1		34.5		0.6		2	%

Total		721.3		570.8		150.5		26	%		644.2		537.9		106.3		20	%
Crude oil, Badlands, MBbl/d		122.2		140.8		(18.6	)	(13	%)		118.9		138.7		(19.8	)	(14	%)
Crude oil, Permian, MBbl/d		30.3		34.1		(3.8	)	(11	%)		29.9		35.3		(5.4	)	(15	%)
Natural gas sales, BBtu/d (3)		2,458.1		2,319.9		138.2		6	%		2,288.4		2,162.5		125.9		6	%
NGL sales, MBbl/d (3)		436.1		412.6		23.5		6	%		433.8		384.7		49.1		13	%
Condensate sales, MBbl/d		15.5		15.4		0.1		1	%		15.2		15.3		(0.1	)	(1	%)
Average realized prices - inclusive of hedges (8):
Natural gas, $/MMBtu		6.71		3.51		3.20		91	%		5.71		2.85		2.86		100	%
NGL, $/gal		0.77		0.69		0.08		12	%		0.82		0.56		0.26		46	%
Condensate, $/Bbl		96.41		64.41		32.00		50	%		92.25		56.86		35.39		62	%

__________________

(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 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 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.

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:

	Three Months Ended September 30, 2022								Three Months Ended September 30, 2021
	(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)		20.3	$	(3.58	)	$	(72.7	)		20.5	$	(1.52	)	$	(31.2	)
NGL (MMgal)		194.9		(0.25	)		(49.4	)		150.4		(0.35	)		(52.4	)
Crude oil (MBbl)		0.6		(26.83	)		(16.1	)		0.5		(18.80	)		(9.4	)
						$	(138.2	)						$	(93.0	)

__________________

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

	Nine Months Ended September 30, 2022								Nine Months Ended September 30, 2021
	(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)		54.5	$	(2.91	)	$	(158.8	)		56.6	$	(1.01	)	$	(57.2	)
NGL (MMgal)		529.7		(0.39	)		(205.2	)		420.0		(0.24	)		(99.3	)
Crude oil (MBbl)		1.6		(38.31	)		(61.3	)		1.6		(11.38	)		(18.2	)
						$	(425.3	)						$	(174.7	)

__________________

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

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021

The increase in adjusted operating margin was due to higher natural gas inlet volumes, higher realized commodity prices and higher fees resulting in increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to both the acquisition of certain assets in the Delaware Basin and increased producer activity supported by the addition of the Legacy Plant during the third quarter of 2022. 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 volumes in the Badlands and the Coastal region was attributable to increased producer activity.

The increase in operating expenses was predominantly due to the acquisition of certain assets in South Texas and the Delaware Basin in the second and third quarters of 2022. Additionally, higher volumes in the Permian, the addition of the Legacy plant in the third quarter of 2022, a full quarter of operations at the Heim plant in 2022 and inflation impacts resulted in increased costs primarily in compensation and benefits, rentals, materials, taxes and chemicals.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

The increase in adjusted operating margin was due to higher realized commodity prices, higher natural gas inlet volumes and higher fees resulting in increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to both the acquisition of certain assets in the Delaware Basin and increased producer activity supported by the addition of the Legacy and Heim plants during the third quarter of 2022 and 2021, respectively. Natural gas 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 decrease in volumes in the Badlands was attributable to the impacts of winter weather, while lower volumes in the Coastal region were due to lower producer activity.

The increase in operating expenses was predominantly due to the acquisition of certain assets in South Texas and the Delaware Basin in the second and third quarters of 2022. Additionally, higher volumes in the Permian, the addition of the Legacy and Heim plants in the third quarter of 2022 and 2021, and inflation impacts resulted in increased costs primarily in compensation and benefits, materials, chemicals, contract labor, rentals and taxes.

Logistics and Transportation Segment

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:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2022		2021		2022 vs. 2021					2022		2021		2022 vs. 2021
	(In millions, except operating statistics)
Operating margin	$	340.2	$	280.7	$	59.5		21	%	$	1,014.6	$	920.5	$	94.1	10	%
Operating expenses		84.5		67.3		17.2		26	%		225.8		204.1		21.7	11	%
Adjusted operating margin	$	424.7	$	348.0	$	76.7		22	%	$	1,240.4	$	1,124.6	$	115.8	10	%
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)		499.5		416.5		83.0		20	%		484.0		383.8		100.2	26	%
Fractionation volumes		742.1		662.0		80.1		12	%		727.5		617.5		110.0	18	%
Export volumes (3)		276.1		293.2		(17.1	)	(6	%)		319.6		305.7		13.9	5	%
NGL sales		825.0		792.1		32.9		4	%		868.1		817.6		50.5	6	%

__________________

(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.

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021

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 primarily due to higher fuel and power costs and lower volumes.

The increase in operating expenses was due to higher repairs and maintenance and higher compensation and benefits.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, partially offset by lower marketing margin. Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from the Company's Permian Gathering and Processing systems and higher fees. Higher optimization margin attributable to the winter storm resulted in higher marketing margin in 2021.

The increase in operating expenses was primarily due to higher repairs and maintenance and higher compensation and benefits, partially offset by lower taxes.

Other

	Three Months Ended September 30,								Nine Months Ended September 30,
	2022			2021		2022 vs. 2021			2022			2021			2022 vs. 2021
	(In millions)
Operating margin	$	(112.2	)	$	13.5	$	(125.7	)	$	(294.9	)	$	(55.6	)	$	(239.3	)
Adjusted operating margin	$	(112.2	)	$	13.5	$	(125.7	)	$	(294.9	)	$	(55.6	)	$	(239.3	)

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.

About Targa Resources Corp.

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.

Targa is a FORTUNE 500 company and is included in the S&P 500.

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

Non-GAAP Financial Measures

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.

Adjusted Operating Margin

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.

Gathering and Processing adjusted operating margin consists primarily of:

service fees related to natural gas and crude oil gathering, treating and processing; and
revenues from the sale of natural gas, condensate, crude oil and NGLs less producer settlements, fuel and transport and the Company's equity volume hedge settlements.

Logistics and Transportation adjusted operating margin consists primarily of:

service fees (including the pass-through of energy costs included in certain fee rates);
system product gains and losses; and
NGL and natural gas sales, less NGL and natural gas purchases, fuel, third-party transportation costs and the net inventory change.

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

Adjusted operating margin for 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:

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

Adjusted EBITDA

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.

Distributable Cash Flow and Adjusted Free Cash Flow

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:

	Three Months Ended September 30,							Nine Months Ended September 30,
	2022			2021			2022				2021
	(In millions)
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Distributable Cash Flow and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.	$	193.1		$	182.2		$		877.5		$	384.8
Interest (income) expense, net		125.8			91.0				300.5			284.2
Income tax expense (benefit)		12.0			2.0				122.0			23.5
Depreciation and amortization expense		287.2			222.8				766.2			650.9
(Gain) loss on sale or disposition of assets		(6.5	)		(1.5	)			(8.1	)		(1.7	)
Write-down of assets		2.7			0.5				3.7			5.0
(Gain) loss from financing activities (1)		—			—				49.6			16.6
(Gain) loss from sale of equity method investment		—			—				(435.9	)		—
Transaction costs related to business acquisitions (2)		20.3			—				20.3			—
Equity (earnings) loss		(1.7	)		(14.3	)			(8.7	)		(38.9	)
Distributions from unconsolidated affiliates and preferred partner interests, net		2.4			28.2				21.7			88.4
Compensation on equity grants		14.4			14.7				41.8			44.6
Risk management activities		112.2			(12.6	)			295.0			55.6
Noncontrolling interests adjustments (3)		6.7			(7.1	)			15.2			(31.6	)
Adjusted EBITDA	$	768.6		$	505.9		$		2,060.8		$	1,481.4
Interest expense on debt obligations (4)		(123.0	)		(91.6	)			(305.2	)		(285.8	)
Maintenance capital expenditures, net (5)		(49.4	)		(29.6	)			(126.8	)		(72.9	)
Cash taxes		(1.3	)		(0.8	)			(5.6	)		(2.0	)
Distributable Cash Flow	$	594.9		$	383.9		$		1,623.2		$	1,120.7
Growth capital expenditures, net (5)		(304.1	)		(86.7	)			(624.8	)		(227.9	)
Adjusted Free Cash Flow	$	290.8		$	297.2		$		998.4		$	892.8

__________________

(1) Gains or losses on debt repurchases or early debt extinguishments.

(2) Includes financial advisory, legal and other professional fees, and other one-time transaction costs.

(3) Noncontrolling interest portion of depreciation and amortization expense.

(4) Excludes amortization of interest expense.

(5) 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 2022:

	2022E
	(In millions)
Reconciliation of Estimated Net Income attributable to Targa Resources Corp. to
Estimated Adjusted EBITDA
Net income attributable to Targa Resources Corp.	$	1,245.0
Interest expense, net		400.0
Income tax expense		340.0
Depreciation and amortization expense		1,050.0
Gain from sale of equity method investment		(440.0	)
Equity earnings		(14.0	)
Loss from financing activities (1)		50.0
Distributions from unconsolidated affiliates and preferred partner interests, net		40.0
Compensation on equity grants		55.0
Risk management and other		180.0
Noncontrolling interests adjustments (2)		(6.0	)
Estimated Adjusted EBITDA	$	2,900.0

(1) Losses on debt repurchases or early debt extinguishments.

(2) Noncontrolling interest portion of depreciation and amortization expense.

Forward-Looking Statements

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. 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 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.

Sanjay Lad

Vice President, Finance & Investor Relations

Jennifer Kneale

Chief Financial Officer

Targa Resources Corp. Reports Third Quarter 2022 Financial Results