Targa Resources Corp. Reports Record Third Quarter 2024 Results and Announces Expectations for a 33% Year-Over-Year Increase to its 2025 Common Dividend

Rhea-AI Summary

Targa Resources Corp. (TRGP) reported strong Q3 2024 results with net income of $387.4 million, up from $220.0 million in Q3 2023. The company achieved record adjusted EBITDA of $1.07 billion, compared to $840.2 million in Q3 2023. Key highlights include record Permian, NGL transportation, and fractionation volumes, completion of the Daytona NGL Pipeline expansion, and $168 million in stock repurchases during Q3. The company expects full-year 2024 adjusted EBITDA to exceed $4.05 billion and plans to increase its annual common dividend by 33% to $4.00 per share in 2025.

Positive

• Record Q3 adjusted EBITDA of $1.07 billion, up 27% year-over-year
• Net income increased 76% to $387.4 million vs Q3 2023
• Planned 33% dividend increase to $4.00 per share for 2025
• Credit rating upgrades by Fitch (to BBB) and Moody's (to Baa2)
• Record volumes across Permian, NGL transportation, and fractionation operations
• Full year 2024 adjusted EBITDA expected to exceed $4.05 billion

Negative

• Total revenues decreased 1% to $3.85 billion in Q3 2024
• Operating expenses increased 8% to $301.0 million
• Interest expense increased 6% to $184.9 million

Insights

Financial Analyst

Targa Resources delivered exceptional Q3 2024 results with record adjusted EBITDA of $1.07 billion, up 27% year-over-year. Key highlights include record volumes across Permian operations and significant infrastructure expansion. The planned 33% dividend increase to $4.00 per share for 2025 signals strong confidence in future cash flows. The company's balance sheet continues strengthening, evidenced by credit rating upgrades from both Fitch and Moody's. With $1.1 billion remaining in share repurchase authorization and strategic growth projects coming online, TRGP is well-positioned for sustained growth. The company's aggressive infrastructure expansion in the Permian Basin through new processing plants demonstrates strong customer demand and future volume growth potential.

Infrastructure Development Analyst

The strategic expansion of Targa's infrastructure assets is particularly noteworthy. The early completion of the Daytona NGL Pipeline, new 275 MMcf/d Greenwood II plant and 120 MBbl/d Train 10 fractionator significantly enhances operational capacity. The announcement of two additional 275 MMcf/d plants (Falcon II and East Driver) indicates strong customer demand and production growth in the Permian. These expansions are important for maintaining Targa's competitive advantage in the region and supporting future volume growth. The accelerated timeline for the East Pembrook plant completion demonstrates efficient project execution and should contribute to earlier revenue generation.

HOUSTON, Nov. 05, 2024 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRGP,” the “Company” or “Targa”) today reported third quarter 2024 results.

Third quarter 2024 net income attributable to Targa Resources Corp. was $387.4 million compared to $220.0 million for the third quarter of 2023. The Company reported adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“adjusted EBITDA”)⁽¹⁾ of $1,069.7 million for the third quarter of 2024 compared to $840.2 million for the third quarter of 2023.

Highlights

• Record adjusted EBITDA for the third quarter of $1.07 billion
• Record Permian, NGL transportation, and fractionation volumes during the third quarter
• Completed its Daytona NGL Pipeline expansion during the third quarter
• Repurchased approximately $168 million of common stock during the third quarter, and $647 million for the nine months ended September 30, 2024 at a weighted average price of $121.50
• Estimate full year 2024 adjusted EBITDA to be above the top end of $3.95 billion to $4.05 billion range
• In August and October, upgraded by Fitch to BBB and by Moody’s to Baa2
• In October, commenced operations at its new 275 million cubic feet per day (“MMcf/d”) Greenwood II plant in Permian Midland and its new 120 thousand barrels per day (“MBbl/d”) Train 10 fractionator in Mont Belvieu
• Announced two new 275 MMcf/d gas plants in the Permian
• Expect to recommend to Targa’s Board of Directors an annual common dividend per share of $4.00 in 2025, a 33% increase to 2024

On October 10, 2024, the Company declared a quarterly cash dividend of $0.75 per common share, or $3.00 per common share on an annualized basis, for the third quarter of 2024. Total cash dividends of approximately $164 million will be paid on November 15, 2024 on all outstanding shares of common stock to holders of record as of the close of business on October 31, 2024.

Targa repurchased 1,150,107 shares of its common stock during the third quarter of 2024 at a weighted average per share price of $146.02 for a total net cost of $167.9 million. As of September 30, 2024, there was $1.1 billion remaining under the Company’s Share Repurchase Programs.

Third Quarter 2024 - Sequential Quarter over Quarter Commentary

Targa reported record third quarter adjusted EBITDA of $1,069.7 million, representing a 9 percent increase compared to the second quarter of 2024. The sequential increase in adjusted EBITDA was attributable to higher volumes across Targa’s Gathering and Processing (“G&P”) and Logistics and Transportation (“L&T”) systems. In the G&P segment, higher sequential adjusted operating margin was attributable to record Permian natural gas inlet volumes, higher Badlands crude volumes, and higher fees. In the L&T segment, record NGL pipeline transportation and fractionation volumes, higher marketing margin and higher LPG export volumes drove the sequential increase in segment adjusted operating margin. Increasing NGL pipeline transportation and fractionation volumes were attributable to higher supply volumes from Targa’s Permian G&P systems and the start-up of Targa’s Daytona NGL Pipeline. Marketing margin increased due to greater optimization opportunities and higher LPG export volumes benefited from improved market conditions. Higher segment operating expenses were attributable to higher system volumes and expansions.

Capitalization and Liquidity

The Company’s total consolidated debt as of September 30, 2024 was $14,254.7 million, net of $91.6 million of debt issuance costs and $29.7 million of unamortized discount, with $12,534.4 million of outstanding senior notes, $951.0 million outstanding under the Commercial Paper Program, $600.0 million outstanding under the Securitization Facility, and $290.6 million of finance lease liabilities.

Total consolidated liquidity as of September 30, 2024 was approximately $1.9 billion, including $1.8 billion available under the TRGP Revolver and $127.2 million of cash.

Financing Update

In August 2024, Targa completed an underwritten public offering of $1.0 billion aggregate principal amount of its 5.500% Senior Notes due 2035 (the “5.500% Notes”), resulting in net proceeds of approximately $990.1 million. Targa used the net proceeds from the issuance to repay borrowings under the Commercial Paper Program, a portion of which were incurred to repay the remaining balance under the Term Loan Facility, and for general corporate purposes.

In August 2024, the Partnership amended its $600.0 million accounts receivable securitization facility (the “Securitization Facility”) to extend the termination date of the Securitization Facility to August 29, 2025.

In August 2024, Fitch Ratings Inc. (“Fitch”) upgraded the Company’s corporate investment grade credit rating to ‘BBB’ from ‘BBB-’. In October 2024, Moody’s Ratings (“Moody’s”) upgraded the Company’s corporate investment grade credit rating to ‘Baa2’ from ‘Baa3’.

Growth Projects Update

In the third quarter of 2024, Targa commenced operations on its Daytona NGL Pipeline ahead of schedule and under-budget. In October 2024, Targa commenced operations at its new 275 MMcf/d Greenwood II plant in Permian Midland and its new 120 MBbl/d Train 10 fractionator in Mont Belvieu. Targa expects to complete the reactivation of Gulf Coast Fractionators (“GCF”) in Mont Belvieu in November 2024. In its G&P segment, construction continues on Targa’s 275 MMcf/d Pembrook II and East Pembrook plants in Permian Midland and its 275 MMcf/d Bull Moose and Bull Moose II plants in Permian Delaware. In its L&T segment, construction continues on Targa’s 150 MBbl/d Train 11 fractionator in Mont Belvieu. Targa now expects to complete its East Pembrook plant ahead of schedule in the second quarter of 2026 and remains on-track to complete its other expansions as previously disclosed.

In November 2024, in response to increasing production and to meet the infrastructure needs of its customers, Targa announced the construction of a new 275 MMcf/d cryogenic natural gas processing plant in Permian Delaware (the “Falcon II plant”) and a new 275 MMcf/d cryogenic natural gas processing plant in Permian Midland (the “East Driver plant”). Falcon II and East Driver are expected to commence operations in the second and third quarters of 2026. 

2024 and 2025 Outlook

Targa’s adjusted EBITDA and growth capital projections are trending higher than previously estimated from the acceleration of spending on infrastructure to handle additional volume growth. The Company is in the middle of its planning process, and consistent with previous years, Targa plans to detail its full year 2025 operational and financial outlook in February 2025 in conjunction with its fourth quarter 2024 earnings announcement. For 2024, the Company estimates full year adjusted EBITDA to be above the top end of its $3.95 billion to $4.05 billion range. Targa continues to anticipate a meaningful inflection in 2025 adjusted free cash flow generation relative to 2024.

Capital Allocation Update

For the first quarter of 2025, Management intends to recommend to Targa’s Board of Directors an increase to its common dividend to $1.00 per common share or $4.00 per common share annualized. The recommended common dividend per share increase, if approved, would be effective for the first quarter of 2025 and payable in May 2025. Beyond 2025, Targa expects to be in position to continue to provide meaningful annual increases to its common dividend. For the nine months ended September 30, 2024, Targa has repurchased 5,322,367 shares of common stock at a weighted average per share price of $121.50 for a total net cost of $646.7 million. Targa expects to continue to be in position to opportunistically repurchase its stock going forward with approximately $1.1 billion remaining under its common Share Repurchase Programs.

An earnings supplement presentation and 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 5, 2024 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/yf8cw4hf/. 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.”}

Targa Resources Corp. – Consolidated Financial Results of Operations 

	Three Months Ended September 30,																Nine Months Ended September 30,
	2024				2023				2024 vs. 2023								2024				2023				2024 vs. 2023
	(In millions)
Revenues:
Sales of commodities	$	3,217.0			$	3,374.3			$	(157.3	)			(5	%)		$	10,126.2			$	10,314.0			$	(187.8	)		(2	%)
Fees from midstream services		634.8				522.3				112.5				22	%			1,850.0				1,506.8				343.2			23	%
Total revenues		3,851.8				3,896.6				(44.8	)			(1	%)			11,976.2				11,820.8				155.4			1	%
Product purchases and fuel		2,365.0				2,690.0				(325.0	)			(12	%)			7,780.4				7,777.9				2.5			—
Operating expenses		301.0				277.7				23.3				8	%			869.7				808.4				61.3			8	%
Depreciation and amortization expense		355.4				331.3				24.1				7	%			1,044.5				988.2				56.3			6	%
General and administrative expense		102.6				90.0				12.6				14	%			287.4				253.4				34.0			13	%
Other operating (income) expense		(0.4	)			2.5				(2.9	)			(116	%)			(0.7	)			2.0				(2.7	)		(135	%)
Income (loss) from operations		728.2				505.1				223.1				44	%			1,994.9				1,990.9				4.0			—
Interest expense, net		(184.9	)			(175.1	)			(9.8	)			6	%			(589.5	)			(509.8	)			(79.7	)		16	%
Equity earnings (loss)		2.2				3.0				(0.8	)			(27	%)			7.9				6.2				1.7			27	%
Gain (loss) from financing activities		—				—				—				—				(0.8	)			—				(0.8	)		(100	%)
Other, net		(0.4	)			(0.1	)			(0.3	)		NM					1.1				(4.9	)			6.0			122	%
Income tax (expense) benefit		(97.0	)			(53.9	)			(43.1	)			80	%			(274.1	)			(260.7	)			(13.4	)		5	%
Net income (loss)		448.1				279.0				169.1				61	%			1,139.5				1,221.7				(82.2	)		(7	%)
Less: Net income (loss) attributable to noncontrolling interests		60.7				59.0				1.7				3	%			178.5				175.4				3.1			2	%
Net income (loss) attributable to Targa Resources Corp.		387.4				220.0				167.4				76	%			961.0				1,046.3				(85.3	)		(8	%)
Premium on repurchase of noncontrolling interests, net of tax		—				—				—				—				—				490.7				(490.7	)		(100	%)
Net income (loss) attributable to common shareholders	$	387.4			$	220.0			$	167.4				76	%		$	961.0			$	555.6			$	405.4			73	%
Financial data:
Adjusted EBITDA (1)	$	1,069.7			$	840.2			$	229.5				27	%		$	3,020.3			$	2,570.1			$	450.2			18	%
Adjusted cash flow from operations (1)		884.6				667.2				217.4				33	%			2,431.7				2,060.6				371.1			18	%
Adjusted free cash flow (1)		124.2				8.6				115.6			NM					84.2				319.1				(234.9	)		(74	%)
_________________________
(1)     Adjusted EBITDA, adjusted cash flow from operations 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.

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023

The decrease in commodity sales reflects lower natural gas and NGL prices ($504.7 million) and the unfavorable impact of hedges ($49.2 million), partially offset by higher NGL volumes ($400.0 million).

The increase in fees from midstream services is primarily due to higher gas gathering and processing fees, higher transportation fees and higher export volumes, partially offset by lower fractionation fees.

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

The increase in operating expenses is primarily due to higher labor and maintenance costs as a result of increased activity and system expansions, partially offset by lower taxes.

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 that have been placed in service since September 30, 2023.

The increase in general and administrative expense is primarily due to higher compensation and benefits.

The increase in interest expense, net, is due to higher borrowings, partially offset by an increase in capitalized interest.

The increase in income tax expense is primarily due to an increase in pre-tax book income.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

Commodity sales are relatively flat reflecting lower natural gas prices ($1,051.9 million) and the unfavorable impact of hedges ($559.2 million), offset by higher NGL, natural gas and condensate volumes ($1,369.1 million), and higher NGL and condensate prices ($53.9 million).

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

Product purchases and fuel are relatively flat reflecting higher NGL and natural gas volumes, offset by lower natural gas prices.

The increase in operating expenses is primarily due to higher labor and rental costs as a result of increased activity and system expansions.

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 that have been placed in service since September 30, 2023, partially offset by the shortening of depreciable lives of certain assets that were idled in the second quarter of 2023 and subsequently shut down in the third quarter of 2023.

The increase in general and administrative expense is primarily due to higher compensation and benefits.

The increase in interest expense, net, is due to recognition of cumulative interest on a 2024 legal ruling associated with the Splitter Agreement and higher borrowings, partially offset by an increase in capitalized interest.

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

The premium on repurchase of noncontrolling interests, net of tax is due to the acquisition of Blackstone Energy Partners’ 25% interest in the Grand Prix Joint Venture in 2023.

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.

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,
	2024					2023					2024 vs. 2023									2024					2023					2024 vs. 2023
		(In millions, except operating statistics and price amounts)
Operating margin	$		584.3			$		505.0			$		79.3				16	%		$		1,713.4			$		1,545.9			$		167.5				11	%
Operating expenses			203.7					189.6					14.1				7	%				597.2					560.8					36.4				6	%
Adjusted operating margin	$		788.0			$		694.6			$		93.4				13	%		$		2,310.6			$		2,106.7			$		203.9				10	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2) (3)
Permian Midland (4)			3,082.0					2,566.9					515.1				20	%				2,898.8					2,474.1					424.7				17	%
Permian Delaware			2,900.2					2,485.4					414.8				17	%				2,785.2					2,513.7					271.5				11	%
Total Permian			5,982.2					5,052.3					929.9				18	%				5,684.0					4,987.8					696.2				14	%
SouthTX (5)			329.9					394.4					(64.5	)			(16	%)				324.8					373.9					(49.1	)			(13	%)
North Texas			184.2					212.0					(27.8	)			(13	%)				186.8					205.2					(18.4	)			(9	%)
SouthOK (5)			348.5					394.6					(46.1	)			(12	%)				355.7					391.2					(35.5	)			(9	%)
WestOK			215.5					206.2					9.3				5	%				213.6					207.1					6.5				3	%
Total Central			1,078.1					1,207.2					(129.1	)			(11	%)				1,080.9					1,177.4					(96.5	)			(8	%)
Badlands (5) (6)			145.4					128.3					17.1				13	%				138.8					129.6					9.2				7	%
Total Field			7,205.7					6,387.8					817.9				13	%				6,903.7					6,294.8					608.9				10	%
Coastal			402.1					535.6					(133.5	)			(25	%)				464.3					532.4					(68.1	)			(13	%)
Total			7,607.8					6,923.4					684.4				10	%				7,368.0					6,827.2					540.8				8	%
NGL production, MBbl/d (3)
Permian Midland (4)			450.6					373.1					77.5				21	%				422.6					357.4					65.2				18	%
Permian Delaware			377.4					322.5					54.9				17	%				349.7					325.3					24.4				8	%
Total Permian			828.0					695.6					132.4				19	%				772.3					682.7					89.6				13	%
SouthTX (5)			30.6					42.3					(11.7	)			(28	%)				33.9					42.1					(8.2	)			(19	%)
North Texas			22.0					24.2					(2.2	)			(9	%)				22.5					23.8					(1.3	)			(5	%)
SouthOK (5)			28.4					46.4					(18.0	)			(39	%)				33.3					44.2					(10.9	)			(25	%)
WestOK			17.0					12.3					4.7				38	%				14.7					12.6					2.1				17	%
Total Central			98.0					125.2					(27.2	)			(22	%)				104.4					122.7					(18.3	)			(15	%)
Badlands (5)			18.3					15.5					2.8				18	%				17.0					15.5					1.5				10	%
Total Field			944.3					836.3					108.0				13	%				893.7					820.9					72.8				9	%
Coastal			33.9					40.6					(6.7	)			(17	%)				35.8					37.9					(2.1	)			(6	%)
Total			978.2					876.9					101.3				12	%				929.5					858.8					70.7				8	%
Crude oil, Badlands, MBbl/d			122.4					101.6					20.8				20	%				105.4					105.6					(0.2	)			—
Crude oil, Permian, MBbl/d			26.7					27.2					(0.5	)			(2	%)				27.4					27.4					—				—
Natural gas sales, BBtu/d (3)			2,842.9					2,758.2					84.7				3	%				2,779.2					2,668.4					110.8				4	%
NGL sales, MBbl/d (3)			581.5					508.8					72.7				14	%				550.1					487.4					62.7				13	%
Condensate sales, MBbl/d			17.3					17.0					0.3				2	%				19.2					18.7					0.5				3	%
Average realized prices (7):
Natural gas, $/MMBtu			0.09					2.03					(1.94	)			(96	%)				0.54					1.97					(1.43	)			(73	%)
NGL, $/gal			0.44					0.46					(0.02	)			(4	%)				0.45					0.46					(0.01	)			(2	%)
Condensate, $/Bbl			77.20					70.07					7.13				10	%				75.60					74.20					1.40				2	%
_________________________
(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) 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, 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:

		Three Months Ended September 30, 2024												Three Months Ended September 30, 2023
		(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)			9.4			$	2.53			$	23.8				15.0			$	0.62			$	9.3
NGL (MMgal)			102.8				0.08				8.2				166.0				0.04				7.2
Crude oil (MBbl)			0.6				(0.67	)			(0.4	)			0.6				(13.17	)			(7.9	)
										$	31.6											$	8.6

		Nine Months Ended September 30, 2024												Nine Months Ended September 30, 2023
		(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)			35.6			$	1.94			$	69.2				50.0			$	1.24			$	62.2
NGL (MMgal)			348.9				0.04				14.9				515.0				0.07				34.4
Crude oil (MBbl)			1.4				(5.57	)			(7.8	)			1.8				(7.17	)			(12.9	)
										$	76.3											$	83.7
_________________________
(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, 2024 Compared to Three Months Ended September 30, 2023

The increase in adjusted operating margin was primarily due to higher natural gas inlet volumes and higher fees in the Permian, partially offset by lower natural gas prices. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Greenwood I and Wildcat II plants during the fourth quarter of 2023, the Roadrunner II plant during the second quarter of 2024, and continued strong producer activity. The increase in Badlands crude was due to higher production.

The increase in operating expenses was primarily due to higher volumes in the Permian and the addition of the Greenwood I, Wildcat II and Roadrunner II plants in the Permian.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

The increase in adjusted operating margin was primarily due to higher natural gas inlet volumes and higher fees in the Permian, partially offset by lower natural gas prices. The increase in natural gas inlet volumes in the Permian was attributable to the addition of the Legacy II plant during the first quarter of 2023, the Midway plant during the second quarter of 2023, the Greenwood I and Wildcat II plants during the fourth quarter of 2023, the Roadrunner II plant during the second quarter of 2024, and continued strong producer activity.

The increase in operating expenses was primarily due to higher volumes in the Permian and the addition of the Legacy II, Midway, Greenwood I, Wildcat II and Roadrunner II plants.

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 Company’s Downstream facilities 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,
	2024					2023					2024 vs. 2023								2024					2023					2024 vs. 2023
	(In millions, except operating statistics)
Operating margin	$		619.2			$		457.4			$		161.8			35	%		$		1,699.0			$		1,394.4			$		304.6			22	%
Operating expenses			98.1					88.8					9.3			10	%				273.5					247.9					25.6			10	%
Adjusted operating margin	$		717.3			$		546.2			$		171.1			31	%		$		1,972.5			$		1,642.3			$		330.2			20	%
Operating statistics MBbl/d (1):
NGL pipeline transportation volumes (2)			829.2					660.2					169.0			26	%				777.0					606.4					170.6			28	%
Fractionation volumes			953.8					793.4					160.4			20	%				884.7					782.3					102.4			13	%
Export volumes (3)			403.9					349.3					54.6			16	%				412.3					341.9					70.4			21	%
NGL sales			1,162.0					997.9					164.1			16	%				1,136.1					984.1					152.0			15	%
________________________
(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, 2024 Compared to Three Months Ended September 30, 2023

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, higher marketing margin, and higher LPG export margin.  Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems and the addition of Train 9 during the second quarter of 2024. Marketing margin increased due to greater optimization opportunities.  LPG export margin increased due to higher volumes as the company benefited from the completion of its export expansion during the third quarter of 2023 and the Houston Ship Channel allowing night-time vessel transits, partially offset by maintenance and required inspections.

The increase in operating expenses was due to higher system volumes, higher compensation and benefits, higher taxes and the addition of Train 9 during the second quarter of 2024.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

The increase in adjusted operating margin was due to higher pipeline transportation and fractionation margin, higher marketing margin, and higher LPG export margin.  Pipeline transportation and fractionation volumes benefited from higher supply volumes primarily from our Permian Gathering and Processing systems and the addition of Train 9 during the second quarter of 2024. Marketing margin increased due to greater optimization opportunities. LPG export margin increased due to higher volumes as the company benefited from the completion of its export expansion during the third quarter of 2023 and the Houston Ship Channel allowing night-time vessel transits, partially offset by maintenance and required inspections. 

The increase in operating expenses was due to higher system volumes, higher compensation and benefits, higher repairs and maintenance, higher taxes, and the addition of Train 9 during the second quarter of 2024.

Other

		Three Months Ended September 30,												Nine Months Ended September 30,
		2024				2023				2024 vs. 2023				2024				2023				2024 vs. 2023
		(In millions)
Operating margin		$	(17.7	)		$	(33.5	)		$	15.8			$	(86.3	)		$	294.3			$	(380.6	)
Adjusted operating margin		$	(17.7	)		$	(33.5	)		$	15.8			$	(86.3	)		$	294.3			$	(380.6	)

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 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, adjusted cash flow from operations, 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, adjusted cash flow from operations, adjusted free cash flow and adjusted operating margin (segment) are non-GAAP measures. The GAAP measures most directly comparable to these non-GAAP measures are income (loss) from operations, Net income (loss) attributable to Targa Resources Corp. and segment operating margin. These non-GAAP measures should not be considered as an alternative to GAAP measures and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of 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.

Adjusted Cash Flow from Operations and Adjusted Free Cash Flow

The Company defines adjusted cash flow from operations as adjusted EBITDA less cash interest expense on debt obligations and cash tax (expense) benefit. The Company defines adjusted free cash flow as adjusted cash flow from operations less maintenance capital expenditures (net of any reimbursements of project costs) and growth capital expenditures, net of contributions from noncontrolling interest and contributions to investments in unconsolidated affiliates. Adjusted cash flow from operations 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, adjusted cash flow from operations and adjusted free cash flow for the periods indicated:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2024				2023				2024				2023
	(In millions)
Reconciliation of Net income (loss) attributable to Targa Resources Corp. to Adjusted EBITDA, Adjusted Cash Flow from Operations and Adjusted Free Cash Flow
Net income (loss) attributable to Targa Resources Corp.	$	387.4			$	220.0			$	961.0			$	1,046.3
Interest (income) expense, net		184.9				175.1				589.5				509.8
Income tax expense (benefit)		97.0				53.9				274.1				260.7
Depreciation and amortization expense		355.4				331.3				1,044.5				988.2
(Gain) loss on sale or disposition of assets		(1.0	)			(0.9	)			(2.7	)			(3.9	)
Write-down of assets		2.7				3.4				4.0				6.0
(Gain) loss from financing activities		—				—				0.8				—
Equity (earnings) loss		(2.2	)			(3.0	)			(7.9	)			(6.2	)
Distributions from unconsolidated affiliates		4.4				5.3				16.6				14.1
Compensation on equity grants		17.7				15.7				47.4				45.7
Risk management activities		17.7				33.5				86.3				(294.3	)
Noncontrolling interests adjustments (1)		1.6				(1.0	)			2.6				(3.2	)
Litigation expense (2)		4.1				6.9				4.1				6.9
Adjusted EBITDA	$	1,069.7			$	840.2			$	3,020.3			$	2,570.1
Interest expense on debt obligations (3)		(181.2	)			(172.1	)			(578.5	)			(500.9	)
Cash taxes		(3.9	)			(0.9	)			(10.1	)			(8.6	)
Adjusted Cash Flow from Operations	$	884.6			$	667.2			$	2,431.7			$	2,060.6
Maintenance capital expenditures, net (4)		(62.0	)			(65.0	)			(167.1	)			(153.0	)
Growth capital expenditures, net (4)		(698.4	)			(593.6	)			(2,180.4	)			(1,588.5	)
Adjusted Free Cash Flow	$	124.2			$	8.6			$	84.2			$	319.1
_________________________
(1) Noncontrolling interest portion of depreciation and amortization expense.
(2) Litigation expense includes charges related to litigation resulting from the major winter storm in February 2021 that the Company considers outside the ordinary course of its business and/or not reflective of its ongoing core operations. The Company may incur such charges from time to time, and the Company believes it is useful to exclude such charges because it does not consider them reflective of its ongoing core operations and because of the generally singular nature of the claims underlying such litigation.
(3) Excludes amortization of interest expense. The nine months ended September 30, 2024 includes $55.8 million of interest expense associated with the Splitter Agreement ruling.
(4) Represents capital expenditures, net of contributions from noncontrolling interests and includes contributions to investments in unconsolidated affiliates

The following table presents a reconciliation of estimated net income of the Company to estimated adjusted EBITDA for 2024:

		2024E
		(In millions)
Reconciliation of Estimated Net Income Attributable to Targa Resources Corp. to
Estimated Adjusted EBITDA
Net income attributable to Targa Resources Corp.		$	1,370.0
Interest expense, net (1)			765.0
Income tax expense			375.0
Depreciation and amortization expense			1,370.0
Equity earnings			(5.0	)
Distributions from unconsolidated affiliates			20.0
Compensation on equity grants			65.0
Risk management and other			90.0
Noncontrolling interests adjustments (2)			—
Estimated Adjusted EBITDA		$	4,050.0
_________________________
(1) Includes $55.8 million of interest expense associated with the Splitter Agreement ruling.
(2) Noncontrolling interest portion of depreciation and amortization expense.

Regulation FD Disclosures

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

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, including statements regarding our projected financial performance, capital spending and payment of future dividends. 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, actions by the Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC oil producing countries, 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 timing and success of our completion of capital projects and business development efforts, the expected growth of volumes on our systems, the impact of pandemics or any other public health crises, commodity price volatility due to ongoing or new global conflicts, 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, 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.

Targa Investor Relations
InvestorRelations@targaresources.com
(713) 584-1133

FAQ

What was Targa Resources (TRGP) Q3 2024 net income?

Targa Resources reported Q3 2024 net income of $387.4 million, compared to $220.0 million in Q3 2023, representing a 76% increase.

How much will TRGP increase its dividend in 2025?

Targa Resources plans to increase its annual common dividend by 33% to $4.00 per share in 2025, up from $3.00 per share in 2024.

What was TRGP's adjusted EBITDA for Q3 2024?

Targa Resources reported record Q3 2024 adjusted EBITDA of $1.069 billion, a 27% increase from $840.2 million in Q3 2023.

How much stock did TRGP repurchase in Q3 2024?

Targa Resources repurchased approximately $168 million of common stock during Q3 2024 at a weighted average price of $146.02 per share.