Release Details

HOUSTON, Feb. 20, 2020 (GLOBE NEWSWIRE) -- Targa Resources Corp. (NYSE: TRGP) (“TRC”, the “Company” or “Targa”) today reported fourth quarter and full year 2019 results.

Fourth Quarter and Full Year 2019 Financial Results

Fourth quarter 2019 net income (loss) attributable to Targa Resources Corp. was ($112.8) million compared to ($106.4) million for the fourth quarter of 2018. The fourth quarter of 2019 included a pre-tax non-cash loss of $229.0 million from the impairment of property, plant and equipment from a continuing decline in natural gas production across the Barnett Shale in North Texas and Gulf of Mexico due to the sustained low commodity price environment. The fourth quarter of 2018 included a pre-tax non-cash loss of $210.0 million from the impairment of goodwill. For the full year 2019, net income (loss) attributable to Targa Resources Corp. was ($209.2) million compared to $1.6 million for 2018.

The Company reported record adjusted earnings before interest, income taxes, depreciation and amortization, and other non-cash items (“Adjusted EBITDA”) of $465.2 million for the fourth quarter of 2019 compared to $332.8 million for the fourth quarter of 2018. For the full year 2019, Adjusted EBITDA was a record $1,435.5 million compared to $1,291.1 million for 2018 (see the section of this release entitled “Targa Resources Corp. - Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, distributable cash flow, gross margin and operating margin, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”)).

On January 16, 2020, TRC declared a quarterly dividend of $0.91 per share of its common stock for the three months ended December 31, 2019, or $3.64 per share on an annualized basis. Total cash dividends of approximately $212.0 million were paid on February 18, 2020 on all outstanding shares of common stock to holders of record as of the close of business on January 31, 2020. Also on January 16, 2020, TRC declared a quarterly cash dividend of $23.75 per share of its Series A Preferred Stock. Total cash dividends of approximately $22.9 million were paid on February 14, 2020 on all outstanding shares of Series A Preferred Stock to holders of record as of the close of business on January 31, 2020.

The Company reported distributable cash flow for the fourth quarter of 2019 of $327.8 million compared to total common dividends paid of $212.0 million and total Series A Preferred Stock dividends paid of $22.9 million, resulting in dividend coverage of 1.4 times. For the full year 2019, distributable cash flow of $947.2 million resulted in dividend coverage of approximately 1.0 times on total common and total Series A Preferred Stock dividends paid with respect to 2019.

Fourth Quarter 2019 - Sequential Quarter over Quarter Commentary

Fourth quarter 2019 Adjusted EBITDA of $465.2 million increased approximately 33 percent over the third quarter of 2019, driven by meaningful contributions from recently completed growth projects and favorable market conditions in both Targa’s Logistics and Transportation and Gathering and Processing (“G&P”) segments. Targa also benefited from approximately $35 million of certain one-time items during the fourth quarter, which included adjustments to certain operating and general and administrative expense estimates and partner related reimbursements. Strong financial performance in the Logistics and Transportation segment was led by the first full quarter of operations from Targa’s Grand Prix NGL Pipeline (“Grand Prix”), as the pipeline’s throughput into Mont Belvieu averaged 266 thousand barrels per day during the fourth quarter. Fractionation volumes in the fourth quarter increased as Targa’s fractionation complex in Mont Belvieu resumed operating at a high utilization rate following completed maintenance in the third quarter. Liquefied petroleum gas (“LPG”) export volumes in the fourth quarter increased as Targa’s recently completed enhancement projects increased its flexibility and loading capabilities at its Galena Park facilities. Targa’s marketing businesses outperformed in the fourth quarter due to optimization of liquids and gas arrangements. Higher results in the G&P segment were attributable to strong volume performance in the Permian region and the Badlands, combined with higher average commodity price realizations.

Capitalization and Liquidity

The Company’s total consolidated debt as of December 31, 2019 was $7,822.4 million including $435.0 million outstanding under TRC’s $670.0 million senior secured revolving credit facility. The consolidated debt included $7,387.4 million of Targa Resources Partners LP’s (“TRP” or the “Partnership”) debt, net of $49.1 million of debt issuance costs, with $370.0 million outstanding under TRP’s accounts receivable securitization facility, $7,028.5 million of outstanding TRP senior notes, net of unamortized premiums, and $38.0 million of finance lease liabilities.

Total consolidated liquidity of the Company as of December 31, 2019, including $331.1 million of cash, was over $2.7 billion. As of December 31, 2019, TRC had available borrowing capacity under its senior secured revolving credit facility of $235.0 million. TRP had $88.2 million in letters of credit outstanding under its $2.2 billion senior secured revolving credit facility, resulting in available senior secured revolving credit facility capacity of $2,111.8 million. In addition to the availability under its senior secured revolving credit facility, the Partnership also had $30.0 million of availability under its accounts receivable securitization facility.

Financing and Asset Sales Update

In November 2019, the Partnership issued $1.0 billion aggregate principal amount of 5½ percent Senior Notes due March 2030, resulting in net proceeds of $990.8 million. The net proceeds from the issuance were used to repay borrowings under its credit facilities and for general partnership purposes.

During the first quarter of 2020, the Company closed on the sale of its Permian Delaware crude gathering and storage business for approximately $134 million. Targa continues to evaluate and execute asset sales to reduce leverage and focus on its core operations and as previously disclosed, the Company has engaged Jefferies LLC to evaluate the potential divestiture of its crude gathering business in the Permian Midland, which includes crude gathering and storage assets. The sale process is ongoing and the potential divestiture is predicated on third party valuations adequately capturing the Company's forward growth expectations for the assets. No assurance can be made that a sale will be consummated.

2020 Operational and Financial Expectations

Targa estimates that 2020 average Field Gathering and Processing natural gas inlet volumes will increase approximately 10 percent over 2019 average Field G&P natural gas inlet volumes. In the Permian Basin, Targa estimates average G&P natural gas inlet volumes will increase approximately 20 percent over 2019 Permian G&P average natural gas inlet volumes. In the Badlands, Targa estimates 2020 average natural gas volumes and average crude gathered volumes will be higher than average 2019 volumes. Targa estimates that these volume increases will be partially offset by modestly lower volumes in the Central region. In its Logistics and Transportation segment, Targa estimates Grand Prix volume deliveries into Mont Belvieu to average between 275 to 300 thousand barrels per day, and expects both full year 2020 average fractionation volumes and LPG exports to be higher over 2019.

For 2020, Targa estimates full year Adjusted EBITDA to be between $1,625 million and $1,750 million, with the midpoint of the range representing an 18 percent increase over full year 2019 Adjusted EBITDA. Targa’s full year Adjusted EBITDA outlook assumes natural gas liquids (“NGL”) composite barrel prices average $0.45 per gallon, crude oil prices average $52 per barrel and Henry Hub and Waha natural gas prices average $2.00 and $0.50 per million British Thermal Units (“MMbtu”) for the year. Targa expects approximately 80 percent of its margin to be fee-based in 2020.     

Targa’s estimate for 2020 net growth capital expenditures remains unchanged from its previous estimate range of $1.2 billion to $1.3 billion, based on announced projects and other identified spending, with the midpoint of the range representing a 45 percent decrease over full year 2019 net growth capital expenditures. Net maintenance capital expenditures for 2020 are estimated to be approximately $150 million.

Management Succession Update

As announced on July 25, 2019, and effective on March 1, 2020, Matthew J. Meloy, current President, will become Chief Executive Officer and will be elected to the Board of Directors. Joe Bob Perkins, current Chief Executive Officer, will remain as a member of the management team and will become Executive Chairman of the Board of Directors. James W. Whalen, current Executive Chairman, will retire from the management team and will continue to serve on the Board of Directors.

Also effective March 1, 2020 and continuing the succession and transition in leadership contemplated under Targa’s ongoing management succession plan developed with and approved by Targa’s Board of Directors, Regina L. Gregory will become Executive Vice President, General Counsel and Secretary. Paul W. Chung, current Executive Vice President, General Counsel and Secretary, will remain as a member of the management team and will become Executive Vice President and Senior Legal Advisor.

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 February 20, 2020 to discuss fourth quarter and full year 2019 results and present its 2020 outlook. The conference call can be accessed via webcast through the Events and Presentations section of Targa’s website at www.targaresources.com, by going directly to https://edge.media-server.com/mmc/p/c8rc77dw or by dialing 877-881-2598. The conference ID number for the dial-in is 1191436. Please dial in ten minutes prior to the scheduled start time. 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 December 31,															Year Ended December 31,
	2019				2018				2019 vs. 2018							2019				2018				2019 vs. 2018
	(In millions)
Revenues:
Sales of commodities	$	2,139.1			$	2,297.4			$	(158.3	)		(7	%)		$	7,393.8			$	9,278.7			$	(1,884.9	)		(20	%)
Fees from midstream services		334.8				300.4				34.4			11	%			1,277.3				1,205.3				72.0			6	%
Total revenues		2,473.9				2,597.8				(123.9	)		(5	%)			8,671.1				10,484.0				(1,812.9	)		(17	%)
Product purchases		1,702.8				2,008.6				(305.8	)		(15	%)			6,118.5				8,238.2				(2,119.7	)		(26	%)
Gross margin (1)		771.1				589.2				181.9			31	%			2,552.6				2,245.8				306.8			14	%
Operating expenses		192.1				183.3				8.8			5	%			792.9				722.0				70.9			10	%
Operating margin (1)		579.0				405.9				173.1			43	%			1,759.7				1,523.8				235.9			15	%
Depreciation and amortization expense		252.7				208.7				44.0			21	%			971.6				815.9				155.7			19	%
General and administrative expense		57.2				80.0				(22.8	)		(29	%)			280.7				256.9				23.8			9	%
Impairment of property, plant and equipment		229.0				—				229.0			—				243.2				—				243.2			—
Impairment of goodwill		—				210.0				(210.0	)		(100	%)			—				210.0				(210.0	)		(100	%)
Other operating (income) expense		63.8				(12.2	)			76.0			NM				71.3				3.5				67.8			NM
Income (loss) from operations		(23.7	)			(80.6	)			56.9			71	%			192.9				237.5				(44.6	)		(19	%)
Interest expense, net		(96.0	)			(61.6	)			(34.4	)		(56	%)			(337.8	)			(185.8	)			(152.0	)		(82	%)
Equity earnings (loss)		23.1				0.9				22.2			NM				39.0				7.3				31.7			NM
Gain (loss) from financing activities		—				—				—			—				(1.4	)			(2.0	)			0.6			30	%
Gain (loss) from sale of equity-method investment		3.5				—				3.5			—				69.3				—				69.3			—
Change in contingent considerations		—				20.9				(20.9	)		(100	%)			(8.7	)			8.8				(17.5	)		(199	%)
Other income (expense), net		0.1				0.1				—			—				—				0.1				(0.1	)		(100	%)
Income tax (expense) benefit		77.9				32.3				45.6			141	%			87.9				(5.5	)			93.4			NM
Net income (loss)		(15.1	)			(88.0	)			72.9			83	%			41.2				60.4				(19.2	)		(32	%)
Less: Net income (loss) attributable to noncontrolling interests		97.7				18.4				79.3			NM				250.4				58.8				191.6			NM
Net income (loss) attributable to Targa Resources Corp.		(112.8	)			(106.4	)			(6.4	)		(6	%)			(209.2	)			1.6				(210.8	)		NM
Dividends on Series A Preferred Stock		22.9				22.9				—			—				91.7				91.7				—			—
Deemed dividends on Series A Preferred Stock		8.7				7.7				1.0			13	%			33.1				29.2				3.9			13	%
Net income (loss) attributable to common shareholders	$	(144.4	)		$	(137.0	)		$	(7.4	)		(5	%)		$	(334.0	)		$	(119.3	)		$	(214.7	)		(180	%)
Financial data:
Adjusted EBITDA (1)	$	465.2			$	332.8			$	132.4			40	%		$	1,435.5			$	1,291.1			$	144.4			11	%
Distributable cash flow (1)		327.8				214.0				113.8			53	%			947.2				942.4				4.8			—
Growth capital expenditures (2)		359.7				962.7				(603.0	)		(63	%)			2,566.8				3,192.7				(625.9	)		(20	%)
Maintenance capital expenditures (3)		40.2				54.6				(14.4	)		(26	%)			141.7				135.0				6.7			5	%

__________________
(1)	Gross margin, operating margin, Adjusted EBITDA, and distributable cash flow are non-GAAP financial measures and are discussed under “Targa Resources Corp. – Non-GAAP Financial Measures.”
(2)	Growth capital expenditures, net of contributions from noncontrolling interests, were $2,201.7 million and $2,612.8 million for the years ended December 31, 2019 and 2018. Net contributions to investments in unconsolidated affiliates were $80.0 million and $113.4 million for the years ended December 31, 2019 and 2018.
(3)	Maintenance capital expenditures, net of contributions from noncontrolling interests, were $134.9 million and $127.9 million for the years ended December 31, 2019 and 2018.
NM	NM  Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

Three Months Ended December 31, 2019 Compared to Three Months Ended December 31, 2018

The decrease in commodity sales reflects lower NGL and natural gas prices ($673.7 million) and lower crude marketing volumes ($36.9 million) partially offset by higher NGL, condensate and natural gas volumes ($523.9 million) and higher condensate prices ($28.1 million). The increase in fees from midstream services was primarily due to higher export, transportation and storage fees.

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

Higher operating margin and gross margin in 2019 reflect increased segment results for both Gathering and Processing and Logistics and Transportation. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense increased primarily due to higher depreciation related to major growth projects placed in service, including additional processing plants and associated infrastructure in the Permian Basin, Grand Prix and Train 6.

General and administrative expense decreased primarily due to lower compensation and benefits costs and lower professional services, partially offset by higher insurance costs.

The impairment of property, plant and equipment in 2019 included a partial impairment of gas processing facilities and gathering systems associated with the North Texas and Coastal operations in the Company’s Gathering and Processing segment, and an asset write-down associated with certain treating units within the same segment. The impairment resulted from a continuing decline in natural gas production across the Barnett Shale in North Texas and Gulf of Mexico due to the sustained low commodity price environment. The Company did not recognize any impairments of property, plant and equipment in 2018.

The Company did not record any goodwill impairment charges for 2019 as the fair values of all reporting units exceeded their accounting carrying values. The Company recognized impairments of goodwill totaling $210.0 million during the three months ended December 2018 related to the remaining goodwill associated with the acquisition of Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively the “Atlas mergers”).

Other operating (income) expense in 2019 consisted primarily of a loss associated with the sale of the Company’s crude gathering and storage business in Permian Delaware. The 2018 gain consisted primarily of the gain on exchange of a portion of the Company’s Versado gathering system, partially offset by the loss on disposal of the benzene saturation component of the Company’s LSNG hydrotreater.

Higher interest expense, net, in 2019 was primarily due to higher average borrowings and lower capitalized interest resulting from the commencement of operations of Grand Prix.

Equity earnings increased in 2019 primarily due to increased earnings from Gulf Coast Express Pipeline LLC (“GCX”) and Little Missouri 4 LLC (“Little Missouri 4”), resulting from the commencement of operations of GCX Pipeline and LM4 Plant in the third quarter.

During 2019, the Company closed on the sale of an equity-method investment that resulted in a gain during the fourth quarter of $3.5 million.

During 2019, the Permian Acquisition contingent consideration earn-out period ended and resulted in a final payment in May. During 2018, the Company recorded income of $20.9 million resulting primarily from a decrease in fair value of the contingent consideration liability.

The increase in income tax benefit during 2019 was due to a higher pre-tax loss, additional benefits from an accrual to actual adjustment for the state income tax provision and higher deductions related to share-based awards vesting during 2019.

Net income attributable to noncontrolling interests was higher in 2019 due to the sale of ownership interests in Targa Badlands and increased earnings allocated to interests holders in Grand Prix, GCX, and Train 6.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

The decrease in commodity sales reflects lower NGL and natural gas prices ($3,296.9 million) and lower petroleum products volumes due to the sale of certain Petroleum Logistics terminals in the fourth quarter of 2018 ($63.8 million), partially offset by higher NGL, crude marketing, natural gas, and condensate volumes ($1,433.4 million) and the favorable impact of hedges ($68.0 million). Fees from midstream services increased primarily due to higher export and crude gathering fees.

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

Higher operating margin and gross margin in 2019 reflect increased segment results for both Gathering and Processing and Logistics and Transportation. See “Review of Segment Performance” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense increased primarily due to higher depreciation related to major growth projects placed in service, including additional processing plants and associated infrastructure in the Permian Basin and Grand Prix.

General and administrative expense increased primarily due to higher compensation and benefits costs and higher information technology costs resulting from increased staffing levels, and higher insurance costs.

The impairment of property, plant and equipment in 2019 included a partial impairment of gas processing facilities and gathering systems associated with the North Texas and Coastal operations in the Company’s Gathering and Processing segment, and an asset write-down associated with certain treating units within the same segment. The impairment resulted from the continuing decline in natural gas production across the Barnett Shale in North Texas and Gulf of Mexico due to the sustained low commodity price environment. The Company did not recognize any impairments of property, plant and equipment in 2018.

The Company did not record any goodwill impairment charges for the year ended December 31, 2019, as the fair values of all reporting units exceeded their accounting carrying values. The Company recognized impairments of goodwill totaling $210.0 million during 2018 related to the remaining goodwill associated with the Atlas mergers.

Other operating (income) expense in 2019 consisted primarily of a loss associated with the sale of the Company’s crude gathering and storage business in Permian Delaware. The 2018 expense consisted primarily of the loss on sale of certain Petroleum Logistics terminals and the loss on disposal of the benzene saturation component of the Company’s LSNG hydrotreater, partially offset by the gain on sale of the Company’s inland marine barge business and the gain on exchange of a portion of the Company’s Versado gathering system.

Higher interest expense, net, in 2019 was primarily due to higher average borrowings, partially offset by higher capitalized interest related to the Company’s major growth investments. During 2018, the Company recognized non-cash interest income resulting from a decrease in the estimated redemption value of the mandatorily redeemable interests, primarily attributable to the February 2018 amendments to such arrangements.

Equity earnings increased in 2019 primarily due to earnings from GCX and Little Missouri 4, resulting from the commencement of operations of GCX Pipeline and LM4 Plant in the third quarter.

During 2019, the Company closed on the sale of an equity-method investment that resulted in a gain of $69.3 million.

In 2019, the Company recorded expense of $8.7 million resulting from an increase in the value of the Permian Acquisition contingent consideration liability. The increase was primarily attributable to the elimination of discounting and an increase in actual gross margin through the end of the earn-out period. The earn-out period ended and resulted in a final payment in May 2019. During 2018, the Company recorded income of $8.8 million resulting from the decrease in fair value of the contingent consideration. The decrease was primarily attributable to lower forecasted volumes for the remainder of the earn-out period, partially offset by a shorter discount period.

During 2019 the Company recorded income tax benefit from pre-tax loss, whereas in 2018 the Company recorded income tax expense due to pre-tax income. Other factors attributable to the change were additional benefits from an accrual to actual adjustment for the state income tax provision and higher deductions related to share-based awards vesting during 2019.

Net income attributable to noncontrolling interests was higher in 2019 due to the sale of ownership interests in Targa Badlands and increased earnings allocated to interests holders in Grand Prix, GCX, and Train 6.

Review of Segment Performance

The following discussion of segment performance includes inter-segment activities. The Company views segment operating margin and gross 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 operating margin and gross margin, see “Targa Resources Corp. ― Non-GAAP Financial Measures ― Operating Margin” and “Targa Resources Corp. ― Non-GAAP Financial Measures ― Gross 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.

In the fourth quarter of 2019, we renamed the Logistics and Marketing segment as “Logistics and Transportation.” The updated name better describes the business composition and activity of the segment given the recent completion of Grand Prix. The change in naming convention did not impact previously reported results for the segment.

Gathering and Processing Segment

The Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. 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 results of commodity derivative activities related to the Company's equity volume hedges that are designated as accounting hedges are now reported in the Gathering and Processing segment. These hedge activities were previously reported in Other. The Company's prior period segment information has been updated to reflect the change. There was no impact to the Company's Consolidated Statements of Operations.

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

	Three Months Ended December 31,															Year Ended December 31,
	2019				2018				2019 vs. 2018							2019				2018				2019 vs. 2018
Gross margin	$	403.9			$	365.4			$	38.5			11	%		$	1,496.0			$	1,377.5			$	118.5			9	%
Operating expenses		114.2				110.4				3.8			3	%			489.6				438.3			51.3				12	%
Operating margin	$	289.7			$	255.0			$	34.7			14	%		$	1,006.4			$	939.2			$	67.2			7	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)		1,638.9				1,260.7				378.2			30	%			1,489.1				1,141.2				347.9			30	%
Permian Delaware		740.7				477.8				262.9			55	%			599.7				443.9				155.8			35	%
Total Permian		2,379.6				1,738.5				641.1							2,088.8				1,585.1				503.7
SouthTX (5)		279.4				365.4				(86.0	)		(24	%)			321.2				389.6				(68.4	)		(18	%)
North Texas		224.9				247.4				(22.5	)		(9	%)			226.9				244.1				(17.2	)		(7	%)
SouthOK (6)		606.1				574.1				32.0			6	%			606.1				555.7				50.4			9	%
WestOK		315.3				354.0				(38.7	)		(11	%)			330.2				351.6				(21.4	)		(6	%)
Total Central		1,425.7				1,540.9				(115.2	)						1,484.4				1,541.0				(56.6	)
Badlands (7), (8)		156.2				90.4				65.8			73	%			116.7				85.1				31.6			37	%
Total Field		3,961.5				3,369.8				591.7							3,689.9				3,211.2			478.7
Coastal		698.6				731.1				(32.5	)		(4	%)			748.3				726.2				22.1			3	%
Total		4,660.1				4,100.9				559.2			14	%			4,438.2				3,937.4				500.8			13	%
NGL production, MBbl/d (3)
Permian Midland (4)		236.7				169.2				67.5			40	%			209.1				153.4				55.7			36	%
Permian Delaware		99.7				58.9				40.8			69	%			78.6				53.5				25.1			47	%
Total Permian		336.4				228.1				108.3							287.7				206.9				80.8
SouthTX (5)		34.4				47.0				(12.6	)		(27	%)			41.6				51.1				(9.5	)		(19	%)
North Texas		26.3				28.2				(1.9	)		(7	%)			26.8				28.1				(1.3	)		(5	%)
SouthOK (6)		72.1				57.6				14.5			25	%			67.1				54.7				12.4			23	%
WestOK		19.3				22.4				(3.1	)		(14	%)			21.6				20.5				1.1			5	%
Total Central		152.1				155.2				(3.1	)						157.1				154.4				2.7
Badlands (8)		18.3				11.8				6.5			55	%			13.8				10.8				3.0			28	%
Total Field		506.8				395.1				111.7							458.6				372.1			86.5
Coastal		46.1				45.9				0.2			—				46.8				43.6				3.2			7	%
Total		552.9				441.0				111.9			25	%			505.4				415.7				89.7			22	%
Crude oil gathered, Badlands, MBbl/d		189.0				167.3				21.7			13	%			172.6				146.8				25.8			18	%
Crude oil gathered, Permian, MBbl/d (9)		74.9				68.2				6.7			10	%			83.3				64.9				18.4			28	%
Natural gas sales, BBtu/d (3)		2,048.6				2,006.4				42.2			2	%			2,020.6				1,867.9				152.7			8	%
NGL sales, MBbl/d (3)		420.1				336.4				83.7			25	%			391.9				317.6				74.3			23	%
Condensate sales, MBbl/d		22.3				12.1				10.2			84	%			14.7				12.6				2.1			17	%
Average realized prices - inclusive of hedges (10):
Natural gas, $/MMBtu		1.48				1.91				(0.43	)		(21	%)			1.35				2.05				(0.70	)		(33	%)
NGL, $/gal		0.32				0.53				(0.22	)		(40	%)			0.34				0.62				(0.28	)		(50	%)
Condensate, $/Bbl		55.44				45.69				9.75			21	%			51.46				51.04				0.42			1	%

__________________
(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 year and the denominator is the number of calendar days during the year.
(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%, 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)	SouthTX includes the Raptor Plant, of which the Company owns a 50% interest through the Carnero Joint Venture. SouthTX also includes the Silver Oak II Plant, of which the Company owned a 100% interest until it was contributed to the Carnero Joint Venture in May 2018. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials.
(6)	SouthOK includes the Centrahoma Joint Venture, of which the Company owns 60%, and other plants that are owned 100% by the Company. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials.
(7)	Badlands natural gas inlet represents the total wellhead gathered volume, and includes the Targa-gathered volumes processed at the LM4 Plant.
(8)	As of April 3, 2019, Targa owns 55% of Targa Badlands, prior to which the Company owned a 100% interest. Targa Badlands is a consolidated subsidiary and its financial results are presented on a gross basis in the Company’s reported financials.
(9)	Permian crude oil gathered volumes reflect the sale of the Delaware crude gathering system, which was effective December 1, 2019.
(10)	Average realized prices include the effect of realized commodity hedge gain/loss attributable to the Company's equity volumes, previously shown in Other. 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 gross margin of Gathering and Processing segment:

		Three Months Ended December 31, 2019												Three Months Ended December 31, 2018
		(In millions, except volumetric data and price amounts)
		Volume Settled				Price Spread (1)				Gain (Loss)				Volume Settled				Price Spread (1)				Gain (Loss)
Natural gas (BBtu)			15.9			$	0.83			$	13.1				14.9			$	1.08			$	16.1
NGL (MMgal)			117.6				0.09				10.1				81.1				(0.11	)			(8.7	)
Crude oil (MBbl)			0.4				(2.10	)			(0.9	)			0.5				(5.21	)			(2.7	)
										$	22.3											$	4.7
		Year Ended December 31, 2019												Year Ended December 31, 2018
		(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)			62.9			$	1.17			$	73.7				63.5			$	0.82			$	51.9
NGL (MMgal)			369.7				0.10				38.0				367.4				(0.16	)			(58.4	)
Crude oil (MBbl)			1.5				(2.29	)			(3.5	)			2.0				(11.25	)			(22.7	)
										$	108.2											$	(29.2	)

__________________
(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 December 31, 2019 Compared to Three Months Ended December 31, 2018

The increase in gross margin was primarily due to higher volumes in the Permian and Badlands, partially offset by lower Central volumes and lower realized NGL and natural gas prices. NGL production and NGL sales increased primarily due to higher inlet volumes and increased NGL recoveries. Natural gas sales increased primarily due to higher inlet volumes. In the Permian, natural gas inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019. In the Badlands, natural gas gathered volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. Total crude oil gathered volumes increased in both the Permian and the Badlands due to production from new wells.

Operating expenses increased in the Coastal region due to costs associated with the demolition of facilities and general maintenance, while expenses increased in the Permian primarily due to gas plant and system expansions.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

The increase in gross margin was primarily due to higher volumes in the Permian and Badlands, partially offset by lower Central volumes and realized prices. NGL production and NGL sales increased primarily due to higher inlet volumes and increased NGL recoveries. Natural gas sales increased primarily due to higher inlet volumes. In the Permian, natural gas inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019. In the Badlands, natural gas gathered volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the LM4 Plant in the third quarter of 2019. Total crude oil gathered volumes increased in both the Permian and the Badlands due to production from new wells.

The increase in operating expenses was primarily driven by gas plant and system expansions in the Permian region.

Equity volume hedges

The Gathering and Processing segment contains the results of commodity derivative activities related to hedges of equity volumes that are included in gross margin. The primary purpose of the Company’s commodity risk management activities is to mitigate a portion of the impact of commodity prices on the Company’s operating cash flow.

The Company has entered into derivative instruments to hedge the commodity price associated with a portion of the Company’s expected natural gas, NGL and condensate equity volumes in the Company’s Gathering and Processing operations that result from percent of proceeds/liquids processing arrangements. Because the Company is essentially forward-selling a portion of the Company’s future plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

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, which integrates 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, including these pipelines, 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 December 31,															Year Ended December 31,
		2019				2018				2019 vs. 2018								2019				2018			2019 vs. 2018
	(In millions, except operating statistics and price amounts)
Gross margin		$	381.2			$	223.7			$	157.5			70	%		$	1,173.9			$	876.8			$	297.1			34	%
Operating expenses			79.2				73.0				6.2			8	%			306.7				284.3				22.4			8	%
Operating margin		$	302.0			$	150.7			$	151.3			100	%		$	867.2			$	592.5			$	274.7			46	%
Operating statistics MBbl/d (1):
Fractionation volumes (2)			596.7				449.6				147.1			33	%			519.0				426.7				92.3			22	%
Export volumes (3)			267.1				213.2				53.9			25	%			237.9				203.4				34.5			17	%
Pipeline throughput (4)			266.4				—				266.4			—				100.4				—				100.4			—
NGL sales			740.3				570.8				169.5			30	%			651.0				537.9				113.1			21	%
Average realized prices:
NGL realized price, $/gal		$	0.51			$	0.70			$	(0.19	)		(29	%)		$	0.51			$	0.77			$	(0.26	)		(38	%)

__________________
(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 year and the denominator is the number of calendar days during the year.
(2)	Fractionation contracts include pricing terms composed of base fees and fuel and power components that vary with the cost of energy. As such, the Logistics and Transportation segment results include effects of variable energy costs that impact both gross margin and operating expenses. Fractionation volumes for 2019 reflect volumes delivered and fractionated, whereas fractionation volumes for 2018 and 2017 reflect volumes delivered and settled under fractionation contracts.
(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.
(4)	Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix, which commenced full operations in the third quarter of 2019, to Mont Belvieu.

Three Months Ended December 31, 2019 Compared to Three Months Ended December 31, 2018

The increase in Logistics and Transportation gross margin was primarily due to higher NGL transportation and fractionation volumes and higher LPG export volumes. Segment gross margin increased due to higher NGL transportation and fractionation margin, higher marketing margin, and higher LPG export margin. NGL transportation and fractionation margin increased due to volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes as a result of the commencement of operations of Train 6 in the second quarter of 2019, partially offset by fewer short-term, high-fee fractionation contracts and less favorable system product gains. Marketing margin increased due to optimization of liquids and gas arrangements. LPG export margin increased due to higher volumes.

Operating expenses increased due to higher taxes, higher compensation and benefits primarily attributable to Grand Prix and Train 6 operations that commenced in 2019, and higher maintenance, partially offset by lower fuel and power costs.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

The increase in Logistics and Transportation gross margin was primarily due to higher NGL transportation and fractionation volumes and higher LPG export volumes. Segment gross margin increased due to higher NGL transportation and fractionation margin, higher marketing margin, and higher LPG export margin, partially offset by the sale of certain Petroleum Logistics terminals in the fourth quarter of 2018. NGL transportation and fractionation margin increased due to volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes as a result of the commencement of operations of Train 6 in the second quarter of 2019, partially offset by fewer short-term high-fee fractionation contracts in 2019 and less favorable system product gains. Marketing margin increased due to optimization of liquids and gas arrangements. LPG export margin increased primarily due to higher volumes.

Operating expenses increased due to higher compensation and benefits and higher taxes primarily attributable to Grand Prix and Train 6 operations that commenced in 2019, higher maintenance, and higher fuel and power costs that are largely passed through to customers.

Other

		Three Months Ended December 31,												Year Ended December 31,
		2019				2018				2019 vs 2018				2019				2018				2019 vs 2018
		(In millions)
Gross margin		$	(12.7	)		$	0.4			$	(13.1	)		$	(113.9	)		$	(7.9	)		$	(106.0	)
Operating margin		$	(12.7	)		$	0.4			$	(13.1	)		$	(113.9	)		$	(7.9	)		$	(106.0	)

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 energy companies in North America. The Company owns, operates, acquires and develops a diversified portfolio of complementary midstream energy assets. The Company is primarily engaged in the business of: gathering, compressing, treating, processing, transporting and selling natural gas; transporting, storing, fractionating, treating and selling NGLs and NGL products, including services to LPG exporters; and gathering, storing, terminaling and selling crude oil.

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

Targa Resources Corp. - Non-GAAP Financial Measures

This press release includes the Company’s non-GAAP financial measures: Adjusted EBITDA, distributable cash flow, gross margin and operating margin. The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. The Company’s non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities or any other GAAP measure of liquidity or financial performance.

Adjusted EBITDA

The Company defines Adjusted EBITDA as net income (loss) attributable to TRC 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 its financial statements such as investors, commercial banks and others. The economic substance behind the Company’s use of Adjusted EBITDA is to measure the ability of its assets to generate cash sufficient to pay interest costs, support its indebtedness and pay dividends to its investors.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) attributable to TRC. Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in the Company’s industry, its definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Distributable Cash Flow

The Company defines distributable cash flow as Adjusted EBITDA less distributions to TRP preferred limited partners, cash interest expense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs).

Distributable cash flow is a significant performance metric used by the Company and by external users of the Company’s financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by it (prior to the establishment of any retained cash reserves by the Company’s board of directors) to the cash dividends the Company expects to pay its shareholders. Using this metric, management and external users of its financial statements can quickly compute the coverage ratio of estimated cash flows to cash dividends. Distributable cash flow is also an important financial measure for the Company’s shareholders since it serves as an indicator of the Company’s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Company is generating cash flow at a level that can sustain or support an increase in its quarterly dividend rates.

Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income (loss) attributable to TRC. Distributable cash flow should not be considered as an alternative to GAAP net income (loss) available to common and preferred shareholders. It has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in the Company’s industry, the Company’s definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into the Company’s decision-making processes.

The following table presents a reconciliation of net income attributable to TRC to Adjusted EBITDA and Distributable Cash Flow for the periods indicated:

		Three Months Ended December 31,								Year Ended December 31,
		2019				2018				2019				2018
		(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA and Distributable Cash Flow
Net income (loss) attributable to TRC		$	(112.8	)		$	(106.4	)		$	(209.2	)		$	1.6
Income attributable to TRP preferred limited partners			2.9				2.9				11.3				11.3
Interest (income) expense, net (1)			96.0				61.6				337.8				185.8
Income tax expense (benefit)			(77.9	)			(32.3	)			(87.9	)			5.5
Depreciation and amortization expense			252.7				208.7				971.6				815.9
Impairment of property, plant and equipment			229.0				—				243.2				—
Impairment of goodwill			—				210.0				—				210.0
(Gain) loss on sale or disposition of business and assets			63.8				(14.4	)			71.1				(0.1	)
(Gain) loss from sale of equity-method investment			(3.5	)			—				(69.3	)			—
(Gain) loss from financing activities (2)			—				—				1.4				2.0
Equity (earnings) loss			(23.1	)			(0.9	)			(39.0	)			(7.3	)
Distributions from unconsolidated affiliates and preferred partner interests, net			27.8				10.1				61.2				31.5
Change in contingent considerations			(0.1	)			(20.9	)			8.7				(8.8	)
Compensation on equity grants			11.3				15.6				60.3				56.3
Risk management activities			12.0				0.2				112.8				8.5
Noncontrolling interests adjustments (3)			(12.9	)			(1.4	)			(38.5	)			(21.1	)
TRC Adjusted EBITDA (4)		$	465.2			$	332.8			$	1,435.5			$	1,291.1
Distributions to TRP preferred limited partners			(2.9	)			(2.9	)			(11.3	)			(11.3	)
Splitter Agreement (5)			—				—				—				43.0
Interest expense on debt obligations (6)			(95.1	)			(66.8	)			(342.1	)			(252.5	)
Maintenance capital expenditures			(40.2	)			(54.6	)			(141.7	)			(135.0	)
Noncontrolling interests adjustments of maintenance capital expenditures			0.8				5.5				6.8				7.1
Distributable Cash Flow		$	327.8			$	214.0			$	947.2			$	942.4

__________________
(1)	Includes the change in estimated redemption value of the mandatorily redeemable preferred interests.
(2)	Gains or losses on debt repurchases, amendments, exchanges or early debt extinguishments.
(3)	Noncontrolling interest portion of depreciation and amortization expense.
(4)	Beginning in the second quarter of 2019, the Company revised the Company’s reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA to exclude the Splitter Agreement adjustment previously included in the comparative periods presented herein. For all comparative periods presented, the Company’s Adjusted EBITDA measure previously included the Splitter Agreement adjustment, which represented the recognition of the annual cash payment received under the condensate splitter agreement ratably over four quarters. The effect of these revisions reduced TRC’s Adjusted EBITDA by $43.0 million for the three months ended December 31, 2018, and $75.2 million for the year ended December 31, 2018. There was no impact to Distributable Cash Flow.
(5)	In Distributable Cash Flow, Splitter Agreement represents the annual cash payment in the period received.
(6)	Excludes amortization of interest expense.

Gross Margin

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

Gathering and Processing segment gross margin consists primarily of:

• revenues from the sale of natural gas, condensate, crude oil and NGLs less producer payments, other natural gas and crude oil purchases, and the Company’s equity volumes hedge settlements; and
  
  
• service fees related to natural gas and crude oil gathering, treating and processing.

Logistics and Transportation segment gross margin consists primarily of:

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

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

Operating Margin

The Company defines operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of the Company’s operations.

Management reviews business segment gross margin and operating margin 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 its operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures 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 acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income (loss) attributable to TRC. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of the Company’s results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in the Company’s industry, the Company’s definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility.

Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

The following table presents a reconciliation of net income of the Company to operating margin and gross margin for the periods indicated:

		Three Months Ended December 31,								Year Ended December 31,
		2019				2018				2019				2018
		(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin
Net income (loss) attributable to TRC		$	(112.8	)		$	(106.4	)		$	(209.2	)		$	1.6
Net income (loss) attributable to noncontrolling interests			97.7				18.4				250.4				58.8
Net income (loss)			(15.1	)			(88.0	)			41.2				60.4
Depreciation and amortization expense			252.7				208.7				971.6				815.9
General and administrative expense			57.2				80.0				280.7				256.9
Impairment of property, plant and equipment			229.0				—				243.2				—
Impairment of goodwill			—				210.0				—				210.0
Interest (income) expense, net			96.0				61.6				337.8				185.8
Equity (earnings) loss			(23.1	)			(0.9	)			(39.0	)			(7.3	)
Income tax expense (benefit)			(77.9	)			(32.3	)			(87.9	)			5.5
(Gain) loss on sale or disposition of business and assets			63.8				(14.4	)			71.1				(0.1	)
(Gain) loss from sale of equity-method investment			(3.5	)			—				(69.3	)			—
(Gain) loss from financing activities			—				—				1.4				2.0
Change in contingent considerations			(0.1	)			(20.9	)			8.7				(8.8	)
Other, net			—				2.1				0.2				3.5
Operating margin			579.0				405.9				1,759.7				1,523.8
Operating expenses			192.1				183.3				792.9				722.0
Gross margin		$	771.1			$	589.2			$	2,552.6			$	2,245.8

The following table presents a reconciliation of estimated net income of the Company to estimated Adjusted EBITDA for 2020:

			2020E
		(In millions)
Reconciliation of Estimated Net Income attributable to TRC to Estimated Adjusted EBITDA
Net income attributable to TRC		$		203.0
Income attributable to TRP preferred limited partners				11.0
Interest expense, net				420.0
Income tax expense (benefit)			44.0
Depreciation and amortization expense				1,030.0
Equity (earnings) loss				(70.0	)
Distributions from unconsolidated affiliates and preferred partner interests, net				100.0
Compensation on equity grants				70.0
Risk management activities and other				(60.0	)
Noncontrolling interest adjustments (1)				(60.0	)
TRC Estimated Adjusted EBITDA		$		1,688.0

__________________
(1)	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 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 Annual Report on Form 10-K for the year ended December 31, 2018, 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
Senior Director, Finance & Investor Relations

Jennifer Kneale
Chief Financial Officer

Source: Targa Resources Corp.