Release Details

HOUSTON, Aug. 04, 2022 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported second quarter 2022 results.

Second Quarter 2022 Financial Results

Second quarter 2022 net income attributable to Targa Resources Corp. was $596.4 million (including a $435.9 million gain on the sale of an equity method investment attributable to the sale of Targa GCX Pipeline LLC) compared to $56.2 million for the second quarter of 2021.

The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”) of $666.4 million for the second quarter of 2022 compared to $460.0 million for the second quarter of 2021.

On July 14, 2022, Targa declared a quarterly dividend of $0.35 per share of its common stock for the second quarter of 2022, or $1.40 per share on an annualized basis. Total cash dividends of approximately $79 million will be paid on August 15, 2022 on all outstanding shares of common stock to holders of record as of the close of business on July 29, 2022.

The Company reported distributable cash flow and adjusted free cash flow for the second quarter of 2022 of $533.4 million and $334.1 million, respectively.

Second Quarter 2022 - Sequential Quarter over Quarter Commentary

Targa reported second quarter 2022 adjusted EBITDA of $666.4 million, representing a 6 percent increase when compared to the first quarter of 2022. The sequential increase in adjusted EBITDA was primarily attributable to higher realized commodity prices and higher Permian volumes across Targa’s Gathering and Processing (“G&P”) and Logistics and Transportation (“L&T”) systems, partially offset by lower marketing margin and higher operating expenses. Higher sequential adjusted operating margin in the G&P segment was driven by higher realized commodity prices and natural gas inlet volumes across Permian and Central. Permian natural gas inlet volumes averaged a record 3.1 billion cubic feet per day (“Bcf/d”) in the second quarter. In the L&T segment, the sequential decrease in segment adjusted operating margin was attributable to lower marketing and LPG export margin, offset by higher pipeline transportation and fractionation volumes. Marketing margin was lower due to fewer optimization opportunities and seasonality in the Company’s wholesale propane business while the decrease in LPG export margin was driven by higher fuel and power costs. NGL pipeline transportation and fractionation volumes achieved record levels during the second quarter primarily due to higher supply volumes from Targa’s Permian G&P systems and third parties. Higher operating expenses were attributable to increased activity levels and the acquisition of certain assets in South Texas in the second quarter, which resulted in increased labor costs, materials and chemicals.

Capitalization and Liquidity

The Company’s total consolidated debt as of June 30, 2022 was $7,460.8 million, net of $51.4 million of debt issuance costs and $6.4 million of unamortized discount, with $5,034.4 million of outstanding Targa Resources Partners LP’s (the “Partnership”) senior notes, $1.5 billion of outstanding TRGP senior notes, $550.0 million outstanding under the Company’s $2.75 billion senior revolving credit facility (the “TRGP Revolver”), $400.0 million outstanding under the Partnership’s accounts receivable securitization facility (the “Securitization Facility”), and $34.2 million of finance lease liabilities.

Total consolidated liquidity as of June 30, 2022 was approximately $2.3 billion, including $2.2 billion available under the TRGP Revolver and $154.0 million of cash.

Acquisition and Financing Update

In July 2022, Targa completed the acquisition of Lucid Energy Delaware, LLC (“Lucid”) for $3.55 billion. Lucid provides natural gas gathering, treating, and processing services in the Delaware Basin, and owns and operates 1,050 miles of natural gas pipelines and approximately 1.4 Bcf/d of cryogenic natural gas processing capacity in service or under construction located primarily in Eddy and Lea counties of New Mexico. Lucid’s Delaware Basin assets are integrated into Targa’s Permian Delaware operations.

Targa funded the acquisition with i) $1.5 billion in proceeds drawn under its 3-year term loan facility; ii) $1.25 billion from the Company’s underwritten public offering of senior notes that closed in July 2022; and iii) $800 million drawn on its $2.75 billion revolving credit facility.

In July 2022, the Company established an unsecured commercial paper note program (the “Commercial Paper Program”). Under the terms of the Commercial Paper Program, Targa 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.

Common Share Repurchases

During the second quarter of 2022, Targa repurchased 1,121,925 shares of its common stock at a weighted average price of $66.07 for a total net cost of $74.1 million. From July 1 through July 29, 2022, Targa repurchased 512,336 shares of its common stock at a weighted average price of $58.57 for a total net cost of $30.0 million. There was $214.7 million remaining under the Company’s $500 million common share repurchase program as of July 29, 2022.

Growth Projects Update

Construction continues on Targa’s 275 million cubic feet per day (“MMcf/d”) Legacy I and Legacy II plants in Permian Midland and its 230 MMcf/d Red Hills VI plant and 275 MMcf/d Midway plant in Permian Delaware. Targa expects to complete Legacy I ahead of schedule and given the plant will be highly utilized when it begins full operations in late third quarter 2022, Targa announced today its plans to construct a new 275 MMcf/d plant in the Permian Midland (the “Greenwood plant”), which is expected to begin operations late in the fourth quarter of 2023.

To handle continued supply growth anticipated from Targa’s Permian G&P systems and third parties, Targa also announced today its plans to construct a new 120 thousand barrels per day (“MBbl/d”) fractionation train in Mont Belvieu, Texas (“Train 9”). Train 9 is expected to begin operations in the second quarter of 2024.

2022 Updated Financial Estimates

For full year 2022, Targa is increasing its estimated adjusted EBITDA range to between $2.85 billion and $2.95 billion to account for a partial year contribution from its recently completed Delaware Basin acquisition. Targa’s updated full year 2022 adjusted EBITDA outlook assumes NGL composite barrel prices average $1.05 per gallon, crude oil prices average $100 per barrel, and Waha natural gas prices average $6.00 per million British Thermal Units (“MMBtu”) for the second half of 2022.

Targa now estimates net growth capital expenditures for 2022 to be between $1.0 billion and $1.1 billion to account for today’s announcements of construction of the new Greenwood plant in Permian Midland and Train 9 in Mont Belvieu, coupled with incremental gathering and related infrastructure spend to support growth across the recently acquired Delaware Basin assets. 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 August 4, 2022 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/f6xgoadz. 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 June 30,																Six Months Ended June 30,
	2022				2021				2022 vs. 2021								2022				2021				2022 vs. 2021
	(In millions)
Revenues:
Sales of commodities	$	5,624.2			$	3,091.6			$	2,532.6				82	%		$	10,190.3			$	6,459.3			$	3,731.0			58	%
Fees from midstream services		431.6				324.3				107.3				33	%			824.6				589.4				235.2			40	%
Total revenues		6,055.8				3,415.9				2,639.9				77	%			11,014.9				7,048.7				3,966.2			56	%
Product purchases and fuel		5,047.3				2,709.0				2,338.3				86	%			9,251.5				5,545.3				3,706.2			67	%
Operating expenses		215.8				184.8				31.0				17	%			399.3				355.8				43.5			12	%
Depreciation and amortization expense		269.9				211.9				58.0				27	%			479.0				428.0				51.0			12	%
General and administrative expense		71.0				63.7				7.3				11	%			138.0				125.1				12.9			10	%
Other operating (income) expense		(0.1	)			0.7				(0.8	)			(114	%)			(0.6	)			4.6				(5.2	)		(113	%)
Income (loss) from operations		451.9				245.8				206.1				84	%			747.7				589.9				157.8			27	%
Interest expense, net		(81.2	)			(94.8	)			13.6				14	%			(174.7	)			(193.2	)			18.5			10	%
Equity earnings (loss)		1.4				12.8				(11.4	)			(89	%)			7.0				24.6				(17.6	)		(72	%)
Gain (loss) from financing activities		(33.8	)			(1.9	)			(31.9	)		NM					(49.6	)			(16.6	)			(33.0	)		199	%
Gain (loss) from sale of equity method investment		435.9				—				435.9				100	%			435.9				—				435.9			100	%
Other, net		0.5				0.1				0.4			NM					—				0.2				(0.2	)		(100	%)
Income tax (expense) benefit		(87.1	)			(6.6	)			(80.5	)		NM					(110.1	)			(21.6	)			(88.5	)	NM
Net income (loss)		687.6				155.4				532.2			NM					856.2				383.3				472.9			123	%
Less: Net income (loss) attributable to noncontrolling interests		91.2				99.2				(8.0	)			(8	%)			171.8				180.7				(8.9	)		(5	%)
Net income (loss) attributable to Targa Resources Corp.		596.4				56.2				540.2			NM					684.4				202.6				481.8			238	%
Premium on repurchase of noncontrolling interests, net of tax		—				—				—				—				53.1				—				53.1			100	%
Dividends on Series A Preferred Stock		8.2				21.8				(13.6	)			(62	%)			30.0				43.7				(13.7	)		(31	%)
Deemed dividends on Series A Preferred Stock		215.5				—				215.5				100	%			215.5				—				215.5			100	%
Net income (loss) attributable to common shareholders	$	372.7			$	34.4			$	338.3			NM				$	385.8			$	158.9			$	226.9			143	%
Financial data:
Adjusted EBITDA (1)	$	666.4			$	460.0			$	206.4				45	%		$	1,292.1			$	975.7			$	316.4			32	%
Distributable cash flow (1)		533.4				339.5				193.9				57	%			1,028.2				737.0				291.2			40	%
Adjusted free cash flow (1)		334.1				256.1				78.0				30	%			707.5				592.6				114.9			19	%

________________

^{(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 June 30, 2022 Compared to Three Months Ended June 30, 2021 

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($2,506.1 million) and higher NGL and natural gas volumes ($98.0 million), partially offset by the unfavorable impact of hedges ($66.5 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, and transportation and fractionation fees.

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 was due to higher labor and maintenance costs primarily due to increased activity, system expansions 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 impact of system expansions on the Company’s asset base and the shortening of the depreciable lives of certain assets that have been, or will be, idled.

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

The decrease in interest expense, net is primarily due to higher non-cash interest income related to a decrease in the mandatorily redeemable preferred interest liability.

The decrease in equity earnings is primarily due to the sale of Targa GCX Pipeline LLC to a third party (the “GCX Sale”) and lower earnings from the Company’s investment in Little Missouri 4 LLC, partially offset by lower losses from the Company’s investments in T2 Eagle Ford Gathering Company L.L.C., Gulf Coast Fractionators and T2 LaSalle Gathering Company L.L.C.

During 2022, the Partnership redeemed the 5.875% Senior Notes due 2026 (the “5.875% Notes”), resulting in a net loss from financing activities. During 2021, the Partnership redeemed the 4.250% Senior Notes due 2023 (the “4.250% Notes”), resulting 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.

During 2022, Targa redeemed in full all of the Company’s issued and outstanding shares of Series A Preferred Stock (“Series A Preferred”). 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. Dividends on Series A Preferred decreased as a result of the redemption.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($3,890.3 million) and higher NGL and natural gas volumes ($100.0 million), partially offset by the unfavorable impact of hedges ($254.5 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, 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 was due to higher labor and maintenance costs primarily due to increased activity, system expansions and inflation, partially offset by lower taxes and 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 system expansions on the Company’s asset base and the shortening of the 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 decrease in interest expense, net is primarily due to higher non-cash interest income related to a decrease in the mandatorily redeemable preferred interest liability, lower interest rates on debt and higher capitalized interest.

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 from the Company’s investments in T2 Eagle Ford Gathering Company L.L.C., Gulf Coast Fractionators and T2 LaSalle Gathering Company L.L.C.

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 5.875% Notes. 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% Notes. 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.

During 2022, Targa redeemed in full all of the Company’s issued and outstanding shares of Series A Preferred. 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. Dividends on Series A Preferred decreased as a result of the redemption.

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 June 30,																			Six Months Ended June 30,
	2022					2021					2022 vs. 2021									2022					2021					2022 vs. 2021
		(In millions, except operating statistics and price amounts)
Operating margin	$		474.7			$		301.2			$		173.5				58	%		$		872.3			$		576.6			$		295.7				51	%
Operating expenses			141.4					115.1					26.3				23	%				258.0					220.5					37.5				17	%
Adjusted operating margin	$		616.1			$		416.3			$		199.8				48	%		$		1,130.3			$		797.1			$		333.2				42	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)			2,132.0					1,929.7					202.3				10	%				2,103.7					1,794.7					309.0				17	%
Permian Delaware			993.3					836.2					157.1				19	%				985.1					787.2					197.9				25	%
Total Permian			3,125.3					2,765.9					359.4									3,088.8					2,581.9					506.9
SouthTX (5)			271.2					194.9					76.3				39	%				216.9					185.7					31.2				17	%
North Texas			175.3					181.4					(6.1	)			(3	%)				175.3					178.4					(3.1	)			(2	%)
SouthOK (5)			460.4					411.4					49.0				12	%				434.0					393.4					40.6				10	%
WestOK			212.0					212.5					(0.5	)			—					207.2					207.6					(0.4	)			—
Total Central			1,118.9					1,000.2					118.7									1,033.4					965.1					68.3
Badlands (5) (6)			129.4					143.4					(14.0	)			(10	%)				127.2					139.1					(11.9	)			(9	%)
Total Field			4,373.6					3,909.5					464.1									4,249.4					3,686.1					563.3
Coastal			553.6					616.6					(63.0	)			(10	%)				577.7					634.5					(56.8	)			(9	%)
Total			4,927.2					4,526.1					401.1				9	%				4,827.1					4,320.6					506.5				12	%
NGL production, MBbl/d (3)
Permian Midland (4)			310.6					279.4					31.2				11	%				305.7					258.4					47.3				18	%
Permian Delaware			135.8					111.7					24.1				22	%				132.8					104.1					28.7				28	%
Total Permian			446.4					391.1					55.3									438.5					362.5					76.0
SouthTX (5)			33.5					25.8					7.7				30	%				26.9					21.7					5.2				24	%
North Texas			19.6					20.4					(0.8	)			(4	%)				19.4					19.8					(0.4	)			(2	%)
SouthOK (5)			55.8					50.4					5.4				11	%				53.1					47.1					6.0				13	%
WestOK			16.6					17.0					(0.4	)			(2	%)				15.8					16.5					(0.7	)			(4	%)
Total Central			125.5					113.6					11.9									115.2					105.1					10.1
Badlands (5)			14.7					16.2					(1.5	)			(9	%)				14.7					15.9					(1.2	)			(8	%)
Total Field			586.6					520.9					65.7									568.4					483.5					84.9
Coastal			36.7					35.7					1.0				3	%				36.9					37.8					(0.9	)			(2	%)
Total			623.3					556.6					66.7				12	%				605.3					521.3					84.0				16	%
Crude oil, Badlands, MBbl/d			111.8					138.9					(27.1	)			(20	%)				117.2					137.6					(20.4	)			(15	%)
Crude oil, Permian, MBbl/d			28.8					36.7					(7.9	)			(22	%)				29.7					35.8					(6.1	)			(17	%)
Natural gas sales, BBtu/d (3)			2,277.1					2,207.5					69.6				3	%				2,202.1					2,082.4					119.7				6	%
NGL sales, MBbl/d (3)			440.4					391.9					48.5				12	%				432.7					370.5					62.2				17	%
Condensate sales, MBbl/d			15.7					15.2					0.5				3	%				15.0					15.2					(0.2	)			(1	%)
Average realized prices - inclusive of hedges (7):
Natural gas, $/MMBtu			6.12					2.45					3.67				150	%				5.15					2.48					2.67				108	%
NGL, $/gal			0.89					0.51					0.38				75	%				0.84					0.49					0.35				71	%
Condensate, $/Bbl			103.10					59.06					44.04				75	%				90.06					52.97					37.09				70	%

____________________

^{(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)     Operations include facilities that are not wholly owned by the Company.
(6)     Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant.
(7)   Average realized prices 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 June 30, 2022												Three Months Ended June 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)			16.7			$	(3.29	)		$	(54.9	)			18.1			$	(0.71	)		$	(12.8	)
NGL (MMgal)			164.4				(0.47	)			(77.9	)			133.8				(0.18	)			(24.4	)
Crude oil (MBbl)			0.5				(51.00	)			(25.5	)			0.5				(12.69	)			(6.7	)
										$	(158.3	)										$	(43.9	)

_____________________

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

		Six Months Ended June 30, 2022												Six Months Ended June 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)			34.2			$	(2.52	)		$	(86.1	)			36.1			$	(0.72	)		$	(26.0	)
NGL (MMgal)			334.8				(0.47	)			(155.8	)			269.6				(0.17	)			(46.9	)
Crude oil (MBbl)			1.0				(45.20	)			(45.2	)			1.1				(8.32	)			(8.9	)
										$	(287.1	)										$	(81.8	)

____________________

^{(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 June 30, 2022 Compared to Three Months Ended June 30, 2021 

The increase in adjusted operating margin was due to higher realized commodity prices, natural gas inlet volumes and fees resulting in increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to increased producer activity and the addition of a new 200 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “Heim Plant”) during the third quarter of 2021. 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 decrease in volumes in the Badlands was attributable to the impacts of winter weather, while lower volumes in the Coastal region were due to continued low producer activity.

The increase in operating expenses was due to higher activity levels in the Permian, the addition of the Heim Plant in the third quarter of 2021, the acquisition of certain assets in South Texas in the second quarter of 2022 and inflation impacts, which resulted in increased labor costs, materials and chemicals.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

The increase in adjusted operating margin was due to higher realized commodity prices, natural gas inlet volumes and fees resulting in increased margin predominantly in the Permian. The increase in natural gas inlet volumes in the Permian was attributable to increased producer activity and the addition of the Heim Plant during the third quarter of 2021. 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 decrease in volumes in the Badlands was attributable to the impacts of winter weather, while lower volumes in the Coastal region were due to continued low producer activity.

The increase in operating expenses was due to higher activity levels in the Permian, the addition of the Heim Plant in the third quarter of 2021, the acquisition of certain assets in South Texas in the second quarter of 2022 and inflation impacts, which resulted in increased labor costs, materials and chemicals.

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 June 30,																				Six Months Ended June 30,
	2022					2021					2022 vs. 2021										2022					2021					2022 vs. 2021
	(In millions, except operating statistics)
Operating margin	$		322.3			$		291.4			$		30.9			11		%			$		674.5			$		640.1			$		34.4			5		%
Operating expenses			74.4					70.7					3.7			5		%					141.3					136.5					4.8			4		%
Adjusted operating margin	$		396.7			$		362.1			$		34.6			10		%			$		815.8			$		776.6			$		39.2			5		%
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)			492.3					391.7					100.6			26		%					476.1					367.2					108.9			30		%
Fractionation volumes			737.2					643.7					93.5			15		%					720.1					595.0					125.1			21		%
Export volumes (3)			342.6					340.6					2.0			1		%					341.7					312.1					29.6			9		%
NGL sales			906.9					833.8					73.1			9		%					890.0					830.6					59.4			7		%

_______________________

^{(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 June 30, 2022 Compared to Three Months Ended June 30, 2021 

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

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

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021 

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation volumes and higher LPG export 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. LPG export margin increased due to higher volumes and fees, partially offset by higher fuel and power costs. 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 partially offset by lower taxes.

Other

		Three Months Ended June 30,												Six Months Ended June 30,
		2022				2021				2022 vs. 2021				2022				2021				2022 vs. 2021
		(In millions)
Operating margin		$	(4.5	)		$	(70.5	)		$	66.0			$	(182.7	)		$	(69.1	)		$	(113.6	)
Adjusted operating margin		$	(4.5	)		$	(70.5	)		$	66.0			$	(182.7	)		$	(69.1	)		$	(113.6	)

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 400.

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 June 30,											Six Months Ended June 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.	$		596.4			$		56.2			$		684.4			$		202.6
Interest (income) expense, net			81.2					94.8					174.7					193.2
Income tax expense (benefit)			87.1					6.6					110.1					21.6
Depreciation and amortization expense			269.9					211.9					479.0					428.0
(Gain) loss on sale or disposition of assets			(0.6	)				(0.4	)				(1.6	)				(0.2	)
Write-down of assets			0.5					1.1					1.0					4.7
(Gain) loss from financing activities (1)			33.8					1.9					49.6					16.6
(Gain) loss from sale of equity method investment			(435.9	)				—					(435.9	)				—
Equity (earnings) loss			(1.4	)				(12.8	)				(7.0	)				(24.6	)
Distributions from unconsolidated affiliates and preferred partner interests, net			6.8					26.9					19.3					60.2
Compensation on equity grants			13.8					15.0					27.3					29.9
Risk management activities			4.5					69.7					182.7					68.2
Noncontrolling interests adjustments (2)			10.3					(10.9	)				8.5					(24.5	)
Adjusted EBITDA	$		666.4			$		460.0			$		1,292.1			$		975.7
Interest expense on debt obligations (3)			(90.7	)				(95.5	)				(182.2	)				(194.2	)
Maintenance capital expenditures, net (4)			(39.7	)				(24.2	)				(77.4	)				(43.2	)
Cash taxes			(2.6	)				(0.8	)				(4.3	)				(1.3	)
Distributable Cash Flow	$		533.4			$		339.5			$		1,028.2			$		737.0
Growth capital expenditures, net (4)			(199.3	)				(83.4	)				(320.7	)				(144.4	)
Adjusted Free Cash Flow	$		334.1			$		256.1			$		707.5			$		592.6

___________________

^{(1)    Gains or losses on debt repurchases or early debt extinguishments.
(2)    Noncontrolling interest portion of depreciation and amortization expense.
(3)    Excludes amortization of interest 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 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 such as COVID-19, commodity price volatility due to ongoing conflict in Ukraine, actions by the Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC oil producing countries, the timing and success of business development efforts, expected benefits relating to the Delaware Basin acquisition and their impact on the Company’s results of operations, 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

Source: Targa Resources Corp.