Targa Resources Corp. (Form: 10-Q, Received: 11/05/2020 14:25:37)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☑

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

☐

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File Number: 001-34991

TARGA RESOURCES CORP.

(Exact name of registrant as specified in its charter)

Delaware		20-3701075
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

811 Louisiana St, Suite 2100, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 584-1000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of exchange on which registered
Common Stock	TRGP	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☑	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

As of November 2, 2020, there were 229,013,171 shares of the registrant’s common stock, $0.001 par value, outstanding.

TABLE OF CONTENTS

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements		4

Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019		4

Consolidated Statements of Operations for the three and nine months ended September 30, 2020 and 2019		5

Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2020 and 2019		6

Consolidated Statements of Changes in Owners' Equity and Series A Preferred Stock for the three and nine months ended September 30, 2020 and 2019		7

Consolidated Statements of Cash Flows for the nine months ended September 30, 2020 and 2019		11

Notes to Consolidated Financial Statements		12

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		30

Item 3. Quantitative and Qualitative Disclosures About Market Risk		50

Item 4. Controls and Procedures		53

PART II—OTHER INFORMATION

Item 1. Legal Proceedings		54

Item 1A. Risk Factors		54

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		56

Item 3. Defaults Upon Senior Securities		56

Item 4. Mine Safety Disclosures		56

Item 5. Other Information		56

Item 6. Exhibits		57

SIGNATURES

Signatures		59

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Corp.’s (together with its subsidiaries, including Targa Resources Partners LP (the “Partnership” or “TRP”), “we,” “us,” “our,” “Targa,” “TRC,” or the “Company”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify 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, by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risks and uncertainties:

•

the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering and processing systems, oil supplies to our gathering systems and natural gas liquid supplies to our logistics and transportation facilities and our success in connecting our facilities to transportation services and markets;

•

the timing and extent of changes in natural gas, natural gas liquids, crude oil and other commodity prices, interest rates and demand for our services;

•

our ability to access the capital markets, which will depend on general market conditions, the credit ratings for the Partnership’s and our debt obligations, and demand for our common equity and the Partnership’s senior notes;

•

the impact of outbreaks of illnesses, pandemics (like COVID-19) or any other public health crises;

•

the amount of collateral required to be posted from time to time in our transactions;

•

our success in risk management activities, including the use of derivative instruments to hedge commodity price risks;

•

the level of creditworthiness of counterparties to various transactions with us;

•

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;

•

weather and other natural phenomena;

•

industry changes, including the impact of consolidations and changes in competition;

•

our ability to timely obtain and maintain necessary licenses, permits and other approvals;

•

our ability to grow through internal growth capital projects or acquisitions and the successful integration and future performance of such assets;

•

general economic, market and business conditions; and

•

the risks described in our Annual Report on Form 10-K for the year ended December 31, 2019 (“Annual Report”) and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

Additionally, while we have not been previously materially impacted by prior outbreaks of illnesses, pandemics or other public health crises, there are potential risks to us from the continued impact on global demand for commodities related to the COVID-19 pandemic. The COVID-19 pandemic reduced economic activity and the related demand for energy commodities, which contributed to weakened commodity prices compared to historical levels and price volatility during the nine months ended September 30, 2020 and is expected to continue to impact demand over the short-to-medium term.

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 (“Quarterly Report”) will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:

Bbl		Barrels (equal to 42 U.S. gallons)
BBtu		Billion British thermal units
Bcf		Billion cubic feet
Btu		British thermal units, a measure of heating value
/d		Per day
GAAP		Accounting principles generally accepted in the United States of America
gal		U.S. gallons
LIBOR		London Interbank Offered Rate
LPG		Liquefied petroleum gas
MBbl		Thousand barrels
MMBbl		Million barrels
MMBtu		Million British thermal units
MMcf		Million cubic feet
MMgal		Million U.S. gallons
NGL(s)		Natural gas liquid(s)
NYMEX		New York Mercantile Exchange
NYSE		New York Stock Exchange
SCOOP		South Central Oklahoma Oil Province
STACK		Sooner Trend, Anadarko, Canadian and Kingfisher

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES CORP.

CONSOLIDATED BALANCE SHEETS

	September 30, 2020			December 31, 2019
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	275.0		$	331.1
Trade receivables, net of allowances of $0.1 and $0.0 million at September 30, 2020 and December 31, 2019		609.8			855.0
Inventories		261.7			161.5
Assets from risk management activities		88.9			103.3
Deposits		110.1			35.4
Held for sale assets		62.2			137.7
Other current assets		36.7			34.3
Total current assets		1,444.4			1,658.3
Property, plant and equipment, net		12,292.8			14,548.5
Intangible assets, net		1,417.6			1,735.0
Long-term assets from risk management activities		79.5			35.5
Investments in unconsolidated affiliates		718.8			738.7
Other long-term assets		99.0			99.1
Total assets	$	16,052.1		$	18,815.1

LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY
Current liabilities:
Accounts payable	$	617.7		$	954.8
Accrued liabilities		69.5			114.4
Dividends payable		125.9			122.6
Interest payable		95.3			125.7
Accrued taxes		85.9			62.4
Liabilities from risk management activities		121.1			104.1
Current debt obligations		261.9			382.2
Held for sale liabilities		3.6			6.4
Total current liabilities		1,380.9			1,872.6
Long-term debt		7,652.2			7,440.2
Long-term liabilities from risk management activities		62.9			40.8
Deferred income taxes, net		131.1			434.2
Other long-term liabilities		307.0			305.6
Contingencies (see Note 13)
Series A Preferred 9.5% Stock, $1,000 per share liquidation preference, (1,200,000 shares authorized, 965,100 shares issued and outstanding), net of discount (see Note 7)		306.5			278.8
Owners' equity:
Targa Resources Corp. stockholders' equity:
Common stock ($0.001 par value, 300,000,000 shares authorized)		0.2			0.2
Issued Outstanding
September 30, 2020 234,745,594 233,517,921
December 31, 2019 233,852,810 232,843,526
Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, no shares issued and outstanding)		—			—
Additional paid-in capital		4,911.7			5,221.2
Retained earnings (deficit)		(1,927.1	)		(339.6	)
Accumulated other comprehensive income (loss)		(90.8	)		92.5
Treasury stock, at cost (1,227,673 shares as of September 30, 2020 and 1,009,284 shares as of December 31, 2019)		(59.0	)		(53.5	)
Total Targa Resources Corp. stockholders' equity		2,835.0			4,920.8
Noncontrolling interests		3,376.5			3,522.1
Total owners' equity		6,211.5			8,442.9
Total liabilities, Series A Preferred Stock and owners' equity	$	16,052.1		$	18,815.1

See notes to consolidated financial statements.

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
	(Unaudited)
	(In millions, except per share amounts)
Revenues:
Sales of commodities	$	1,840.8		$	1,594.2		$	4,900.8		$	5,254.8
Fees from midstream services		274.3			308.3			786.7			942.4
Total revenues		2,115.1			1,902.5			5,687.5			6,197.2
Costs and expenses:
Product purchases		1,303.2			1,328.1			3,346.8			4,415.7
Operating expenses		181.9			200.2			565.1			600.8
Depreciation and amortization expense		203.7			244.3			647.3			718.9
General and administrative expense		58.6			69.9			180.6			223.5
Impairment of long-lived assets		—			—			2,442.8			—
Other operating (income) expense		72.2			18.4			73.8			21.7
Income (loss) from operations		295.5			41.6			(1,568.9	)		216.6
Other income (expense):
Interest expense, net		(97.7	)		(89.1	)		(292.4	)		(241.8	)
Equity earnings (loss)		18.6			10.0			54.1			15.9
Gain (loss) from financing activities		(13.7	)		—			47.4			(1.4	)
Gain (loss) from sale of equity-method investment		—			65.8			—			65.8
Change in contingent considerations		—			—			—			(8.8	)
Other, net		1.4			—			2.2			—
Income (loss) before income taxes		204.1			28.3			(1,757.6	)		46.3
Income tax (expense) benefit		(31.9	)		3.8			286.6			10.0
Net income (loss)		172.2			32.1			(1,471.0	)		56.3
Less: Net income (loss) attributable to noncontrolling interests		102.9			79.4			116.5			152.7
Net income (loss) attributable to Targa Resources Corp.		69.3			(47.3	)		(1,587.5	)		(96.4	)
Dividends on Series A Preferred Stock		22.9			22.9			68.8			68.8
Deemed dividends on Series A Preferred Stock		9.5			8.4			27.7			24.4
Net income (loss) attributable to common shareholders	$	36.9		$	(78.6	)	$	(1,684.0	)	$	(189.6	)

Net income (loss) per common share - basic	$	0.16		$	(0.34	)	$	(7.22	)	$	(0.82	)
Net income (loss) per common share - diluted	$	0.16		$	(0.34	)	$	(7.22	)	$	(0.82	)
Weighted average shares outstanding - basic		233.4			232.7			233.2			232.4
Weighted average shares outstanding - diluted		233.8			232.7			233.2			232.4

See notes to consolidated financial statements.

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

		Three Months Ended September 30,
		2020											2019
		Pre-Tax				Related Income Tax			After Tax				Pre-Tax				Related Income Tax				After Tax
		(Unaudited)
		(In millions)
Net income (loss)								$		172.2										$		32.1
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value	$		(128.7	)	$		31.7			(97.0	)	$		118.2		$		(28.8	)			89.4
Settlements reclassified to revenues			(19.2	)			3.8			(15.4	)			(41.5	)			10.0				(31.5	)
Other comprehensive income (loss)			(147.9	)			35.5			(112.4	)			76.7				(18.8	)			57.9
Comprehensive income (loss)										59.8												90.0
Less: Comprehensive income (loss) attributable to noncontrolling interests										102.9												79.4
Comprehensive income (loss) attributable to Targa Resources Corp.								$		(43.1	)									$		10.6

		Nine Months Ended September 30,
		2020											2019
		Pre-Tax				Related Income Tax			After Tax				Pre-Tax				Related Income Tax				After Tax
		(Unaudited)
		(In millions)
Net income (loss)								$		(1,471.0	)									$		56.3
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value	$		(102.6	)	$		23.5			(79.1	)	$		167.8		$		(40.7	)			127.1
Settlements reclassified to revenues			(139.4	)			35.2			(104.2	)			(106.1	)			25.6				(80.5	)
Other comprehensive income (loss)			(242.0	)			58.7			(183.3	)			61.7				(15.1	)			46.6
Comprehensive income (loss)										(1,654.3	)											102.9
Less: Comprehensive income (loss) attributable to noncontrolling interests										116.5												152.7
Comprehensive income (loss) attributable to Targa Resources Corp.								$		(1,770.8	)									$		(49.8	)

See notes to consolidated financial statements.

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK

									Retained			Accumulated
						Additional			Earnings			Other			Treasury								Total			Series A
	Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(Unaudited)
	(In millions, except shares in thousands)

Balance, June 30, 2020		233,177		$	0.2	$	4,949.1		$	(1,996.4	)	$	21.6			1,116	$	(56.9	)	$	3,351.5		$	6,269.1		$	297.0
Compensation on equity grants		—			—		16.4			—			—			—		—			—			16.4			—
Distribution equivalent rights		—			—		1.9			—			—			—		—			—			1.9			—
Shares issued under compensation program		453			—		—			—			—			—		—			—			—			—
Shares and units tendered for tax withholding obligations		(112	)		—		—			—			—			112		(2.1	)		—			(2.1	)		—
Series A Preferred Stock dividends
Dividends - $23.75 per share		—			—		—			(22.9	)		—			—		—			—			(22.9	)		—
Dividends in excess of retained earnings		—			—		(22.9	)		22.9			—			—		—			—			—			—
Deemed dividends - accretion of beneficial conversion feature		—			—		(9.5	)		—			—			—		—			—			(9.5	)		9.5
Common stock dividends
Dividends - $0.10 per share		—			—		—			(23.3	)		—			—		—			—			(23.3	)		—
Dividends in excess of retained earnings		—			—		(23.3	)		23.3			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(113.1	)		(113.1	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			7.7			7.7			—
Non-cash allocation to noncontrolling interests		—			—		—			—			—			—		—			27.5			27.5			—
Other comprehensive income (loss)		—			—		—			—			(112.4	)		—		—			—			(112.4	)		—
Net income (loss)		—			—		—			69.3			—			—		—			102.9			172.2			—
Balance, September 30, 2020		233,518		$	0.2	$	4,911.7		$	(1,927.1	)	$	(90.8	)		1,228	$	(59.0	)	$	3,376.5		$	6,211.5		$	306.5

See notes to consolidated financial statements.

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK

									Retained			Accumulated
						Additional			Earnings			Other		Treasury								Total			Series A
	Common Stock					Paid in			(Accumulated			Comprehensive		Shares					Noncontrolling			Owner's			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)		Shares		Amount			Interests			Equity			Stock
	(Unaudited)
	(In millions, except shares in thousands)

Balance, June 30, 2019		232,476		$	0.2	$	5,687.8		$	(179.5	)	$	83.0		896	$	(49.2	)	$	3,396.8		$	8,939.1		$	261.7
Compensation on equity grants		—			—		16.1			—			—		—		—			—			16.1			—
Distribution equivalent rights		—			—		(3.7	)		—			—		—		—			—			(3.7	)		—
Shares issued under compensation program		412			—		—			—			—		—		—			—			—			—
Shares and units tendered for tax withholding obligations		(105	)		—		—			—			—		105		(3.9	)		—			(3.9	)		—
Series A Preferred Stock dividends
Dividends - $23.75 per share		—			—		—			(22.9	)		—		—		—			—			(22.9	)		—
Dividends in excess of retained earnings		—			—		(22.9	)		22.9			—		—		—			—			—			—
Deemed dividends - accretion of beneficial conversion feature		—			—		(8.4	)		—			—		—		—			—			(8.4	)		8.4
Common stock dividends
Dividends - $0.91 per share		—			—		—			(211.7	)		—		—		—			—			(211.7	)		—
Dividends in excess of retained earnings		—			—		(211.7	)		211.7			—		—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—		—		—			(90.0	)		(90.0	)		—
Contributions from noncontrolling interests		—			—		—			—			—		—		—			115.3			115.3			—
Other comprehensive income (loss)		—			—		—			—			57.9		—		—			—			57.9			—
Net income (loss)		—			—		—			(47.3	)		—		—		—			79.4			32.1			—
Balance, September 30, 2019		232,783		$	0.2	$	5,457.2		$	(226.8	)	$	140.9		1,001	$	(53.1	)	$	3,501.5		$	8,819.9		$	270.1

See notes to consolidated financial statements.

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK

									Retained			Accumulated
						Additional			Earnings			Other			Treasury								Total			Series A
	Common Stock					Paid in			(Accumulated			Comprehensive			Shares					Noncontrolling			Owner's			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)			Shares		Amount			Interests			Equity			Stock
	(Unaudited)
	(In millions, except shares in thousands)

Balance, December 31, 2019		232,844		$	0.2	$	5,221.2		$	(339.6	)	$	92.5			1,010	$	(53.5	)	$	3,522.1		$	8,442.9		$	278.8
Compensation on equity grants		—			—		49.5			—			—			—		—			—			49.5			—
Distribution equivalent rights		—			—		(3.5	)		—			—			—		—			—			(3.5	)		—
Shares issued under compensation program		892			—		—			—			—			—		—			—			—			—
Shares and units tendered for tax withholding obligations		(218	)		—		—			—			—			218		(5.5	)		—			(5.5	)		—
Series A Preferred Stock dividends
Dividends - $71.25 per share		—			—		—			(68.8	)		—			—		—			—			(68.8	)		—
Dividends in excess of retained earnings		—			—		(68.8	)		68.8			—			—		—			—			—			—
Deemed dividends - accretion of beneficial conversion feature		—			—		(27.7	)		—			—			—		—			—			(27.7	)		27.7
Common stock dividends																								—			—
Dividends - $1.11 per share		—			—		—			(259.0	)		—			—		—			—			(259.0	)		—
Dividends in excess of retained earnings		—			—		(259.0	)		259.0			—			—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—			—		—			(322.9	)		(322.9	)		—
Contributions from noncontrolling interests		—			—		—			—			—			—		—			33.3			33.3			—
Non-cash allocation to noncontrolling interests		—			—		—			—			—			—		—			27.5			27.5			—
Other comprehensive income (loss)		—			—		—			—			(183.3	)		—		—			—			(183.3	)		—
Net income (loss)		—			—		—			(1,587.5	)		—			—		—			116.5			(1,471.0	)		—
Balance, September 30, 2020		233,518		$	0.2	$	4,911.7		$	(1,927.1	)	$	(90.8	)		1,228	$	(59.0	)	$	3,376.5		$	6,211.5		$	306.5

See notes to consolidated financial statements.

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK

									Retained			Accumulated
						Additional			Earnings			Other		Treasury								Total			Series A
	Common Stock					Paid in			(Accumulated			Comprehensive		Shares					Noncontrolling			Owner's			Preferred
	Shares			Amount		Capital			Deficit)			Income (Loss)		Shares		Amount			Interests			Equity			Stock
	(Unaudited)
	(In millions, except shares in thousands)

Balance, December 31, 2018		231,791		$	0.2	$	6,154.9		$	(130.4	)	$	94.3		666	$	(39.6	)	$	1,391.4		$	7,470.8		$	245.7
Compensation on equity grants		—			—		49.0			—			—		—		—			—			49.0			—
Distribution equivalent rights		—			—		(10.5	)		—			—		—		—			—			(10.5	)		—
Shares issued under compensation program		1,327			—		—			—			—		—		—			—			—			—
Shares and units tendered for tax withholding obligations		(335	)		—		—			—			—		335		(13.5	)		—			(13.5	)		—
Series A Preferred Stock dividends
Dividends - $71.25 per share		—			—		—			(68.8	)		—		—		—			—			(68.8	)		—
Dividends in excess of retained earnings		—			—		(68.8	)		68.8			—		—		—			—			—			—
Deemed dividends - accretion of beneficial conversion feature		—			—		(24.4	)		—			—		—		—			—			(24.4	)		24.4
Common stock dividends
Dividends - $2.73 per share		—			—		—			(634.8	)		—		—		—			—			(634.8	)		—
Dividends in excess of retained earnings		—			—		(634.8	)		634.8			—		—		—			—			—			—
Distributions to noncontrolling interests		—			—		—			—			—		—		—			(181.1	)		(181.1	)		—
Contributions from noncontrolling interests		—			—		—			—			—		—		—			518.8			518.8			—
Sale of ownership interests in subsidiaries, net		—			—		(8.2	)		—			—		—		—			1,619.7			1,611.5			—
Other comprehensive income (loss)		—			—		—			—			46.6		—		—			—			46.6			—
Net income (loss)		—			—		—			(96.4	)		—		—		—			152.7			56.3			—
Balance, September 30, 2019		232,783		$	0.2	$	5,457.2		$	(226.8	)	$	140.9		1,001	$	(53.1	)	$	3,501.5		$	8,819.9		$	270.1

See notes to consolidated financial statements.

TARGA RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
	2020			2019
	(Unaudited)
	(In millions)
Cash flows from operating activities
Net income (loss)	$	(1,471.0	)	$	56.3
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		8.5			7.6
Compensation on equity grants		49.5			49.0
Depreciation and amortization expense		647.3			718.9
Impairment of long-lived assets		2,442.8			—
Accretion of asset retirement obligations		2.6			3.7
Deferred income tax expense (benefit)		(269.8	)		(10.0	)
Equity (earnings) loss of unconsolidated affiliates		(54.1	)		(15.9	)
Distributions of earnings received from unconsolidated affiliates		65.5			26.0
Risk management activities		(214.2	)		100.8
(Gain) loss on sale or disposition of business and assets		58.0			3.6
Write-downs of assets		13.5			17.9
(Gain) loss from financing activities		(47.4	)		1.4
(Gain) loss from sale of equity-method investment		—			(65.8	)
Change in contingent considerations		—			8.8
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets		168.7			98.4
Inventories		(115.8	)		(89.7	)
Accounts payable, accrued liabilities and other liabilities		(158.0	)		(4.2	)
Interest payable		(30.4	)		12.2
Net cash provided by operating activities		1,095.7			919.0
Cash flows from investing activities
Outlays for property, plant and equipment		(803.1	)		(2,434.1	)
Proceeds from sale of business and assets		135.9			2.7
Investments in unconsolidated affiliates		(2.2	)		(243.7	)
Proceeds from sale of equity-method investment		—			70.3
Return of capital from unconsolidated affiliates		10.7			1.1
Other, net		4.7			(16.3	)
Net cash used in investing activities		(654.0	)		(2,620.0	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facilities		1,460.0			2,630.0
Repayments of credit facilities		(1,360.0	)		(2,500.0	)
Proceeds from borrowings under accounts receivable securitization facility		476.4			770.0
Repayments of accounts receivable securitization facility		(596.4	)		(804.0	)
Proceeds from issuance of senior notes		1,000.0			1,500.0
Redemption of senior notes		(831.0	)		(749.4	)
Principal payments of finance leases		(9.3	)		(8.5	)
Costs incurred in connection with financing arrangements		(9.6	)		(25.2	)
Payment of contingent consideration		—			(317.1	)
Repurchase of shares and units under compensation plans		(5.5	)		(13.5	)
Sale of ownership interests in subsidiaries		—			1,619.7
Contributions from noncontrolling interests		33.3			518.8
Distributions to noncontrolling interests		(310.6	)		(98.9	)
Distributions to Partnership unitholders		(8.4	)		(8.4	)
Dividends paid to common and Series A preferred shareholders		(336.7	)		(718.3	)
Net cash provided by (used in) financing activities		(497.8	)		1,795.2
Net change in cash and cash equivalents		(56.1	)		94.2
Cash and cash equivalents, beginning of period		331.1			232.1
Cash and cash equivalents, end of period	$	275.0		$	326.3

See notes to consolidated financial statements.

TARGA RESOURCES CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

Note 1 — Organization and Operations

Our Organization

Targa Resources Corp. (“TRC”) is a publicly traded Delaware corporation formed in October 2005. Our common stock is listed on the New York Stock Exchange under the symbol “TRGP.” In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended to mean our consolidated business and operations. TRC controls the general partner of and owns all of the outstanding common units representing limited partner interests in Targa Resources Partners LP, referred to herein as the “Partnership” or “TRP.”

Our Operations

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.

See Note 18 – Segment Information for certain financial information regarding our business segments.

Note 2 — Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and do not include all information and disclosures required by GAAP. Therefore, this information should be read in conjunction with our consolidated financial statements and notes contained in our Annual Report. The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for a fair statement of the results of the interim periods reported. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods have been reclassified to conform to the current year presentation. Operating results for the three and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the year ending December 31, 2020.

Note 3 — Significant Accounting Policies

The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. Other than the updates noted below, there were no significant updates or revisions to our accounting policies during the nine months ended September 30, 2020.

Recent Accounting Pronouncements

Recently issued accounting pronouncements not yet adopted

Convertible Debt and Equity Instruments

In August 2020, the FASB issued ASU 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. The amendments in this update simplify the accounting for convertible debt instruments and convertible preferred stock by reducing the number of accounting models and embedded conversion features that can be recognized separately from the primary contract. These amendments also enhance transparency and improve disclosures for convertible instruments and earnings per share guidance. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2021, with early adoption permitted. This update permits the use of either the modified retrospective or full retrospective method of adoption. We are currently evaluating the effects of such amendments on our consolidated financial statements.

Recently adopted accounting pronouncements

Measurement of Credit Losses

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The amendments in this update modify the impairment model for financial instruments, including trade and other receivables, held-to-maturity debt securities and other instruments.

The amendments require entities to consider historical information, current conditions, and supportable forecasts to estimate expected credit losses, which may result in earlier recognition of losses. The amendments were effective for us on January 1, 2020 and were adopted by applying the modified retrospective transition approach. The adoption did not result in a cumulative effect adjustment to retained earnings on January 1, 2020. As a result of our adoption, see Accounting Policy Updates – Allowance for Doubtful Accounts below.

Accounting Policy Updates

Allowance for Doubtful Accounts

Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. We estimate the allowance for doubtful accounts through various procedures, including extensive review of our trade receivable balances by counterparty, assessing economic events and conditions, our historical experience with counterparties, the counterparty’s financial condition and the amount and age of past due accounts.

We continuously evaluate our ability to collect amounts owed to us. Receivables are considered past due if full payment is not received by the contractual due date. These procedures also include performing account reconciliations, dispute resolution and payment confirmation. We may involve our legal counsel to pursue the recovery of defaulted trade receivables.

As the financial condition of any counterparty changes, circumstances develop or additional information becomes available, adjustments to our allowance may be required.

Note 4 — Property, Plant and Equipment and Intangible Assets

	September 30, 2020			December 31, 2019			Estimated Useful Lives (In Years)
Gathering systems	$	9,125.2		$	8,976.8		5 to 20
Processing and fractionation facilities		6,138.3			5,143.0		5 to 25
Terminaling and storage facilities		1,514.8			1,495.5		5 to 25
Transportation assets		2,422.6			2,292.4		10 to 50
Other property, plant and equipment		123.9			184.1		3 to 50
Land		160.7			159.7		—
Construction in progress		697.5			1,576.5		—
Finance lease right-of-use assets		51.3			48.8
Property, plant and equipment		20,234.3			19,876.8
Accumulated depreciation, amortization and impairment		(7,941.5	)		(5,328.3	)
Property, plant and equipment, net	$	12,292.8		$	14,548.5

Intangible assets	$	2,643.5		$	2,643.5		10 to 20
Accumulated amortization and impairment		(1,225.9	)		(908.5	)
Intangible assets, net	$	1,417.6		$	1,735.0

During the preparation of the Company's first quarter 2019 consolidated financial statements, the Company identified an error related to depreciation expense on certain assets that should have been placed in-service during 2018. The Company does not believe this error is material to its previously issued historical consolidated financial statements for any of the periods impacted and accordingly, has not adjusted the historical financial statements. The Company recorded the cumulative impact of a one-time $12.5 million overstatement of depreciation expense during the first quarter of 2019.

During the three and nine months ended September 30, 2020, depreciation expense was $168.5 million and $538.5 million, respectively. During the three and nine months ended September 30, 2019, depreciation expense was $201.4 million and $590.1 million, respectively.

Asset Impairments

We review and evaluate our long-lived assets, including intangible assets, for impairment when events or changes in circumstances indicate that the related carrying amount of such assets may not be recoverable, and changes to our estimates could have an impact on our assessment of asset recoverability.

During the nine months ended September 30, 2020, global commodity prices declined due to factors that significantly impacted both demand and supply. As the COVID-19 pandemic spread, causing travel and other restrictions to be implemented globally, the demand for commodities declined. Additionally, the supply shock late in the first quarter from certain major oil producing nations increasing production also significantly contributed to the sharp drop in commodity prices. While these major oil and gas producing countries subsequently agreed to collectively decrease production and global economies are beginning to re-open, these events, combined with the outbreak of the COVID-19 pandemic, contributed to volatility and depressed commodity prices. The drop in commodity prices resulted in prompt reactions from some domestic producers, including significantly reducing capital budgets and resultant drilling activity and shutting-in production. Commodity prices remain weak relative to historical levels and have remained volatile as uncertainty around global commodity supply and demand continues due to the COVID-19 pandemic.

In the first quarter of 2020, we determined that indicators of impairment existed for certain asset groups reported primarily within our Gathering and Processing segment. For each asset group for which undiscounted future net cash flows were not sufficient to recover the net book value, fair value was determined through use of discounted estimated cash flows to measure the impairment loss.

The estimated cash flows used to assess recoverability of our long-lived assets and measure fair value of our asset groups are derived from current business plans, which are developed using near-term price and volume projections reflective of the current environment and management's projections for long-term average prices and volumes. In addition to near and long-term price assumptions, other key assumptions include volume projections, operating costs, timing of incurring such costs and the use of an appropriate discount rate. We believe our estimates and models used to determine fair value are similar to what a market participant would use.

The fair value measurement of our long-lived assets was based, in part, on significant inputs not observable in the market (as discussed above) and thus represents a Level 3 measurement. The significant unobservable inputs used include discount rates and terminal value exit multiples. We utilized a weighted average discount rate of 14.0% when deriving the fair value of the asset groups impaired during the first quarter of 2020. The weighted average discount rate and exit multiples reflect management’s best estimate of inputs a market participant would utilize.

In the first quarter of 2020, we recorded non-cash pre-tax impairments of $2,442.8 million primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our Mid-Continent operations and full impairment of our Coastal operations - all of which are in our Gathering and Processing segment. Our first quarter impairment assessment forecasted further decline in natural gas production across the Mid-Continent and Gulf of Mexico. The carrying value adjustments are included in Impairment of long-lived assets in our Consolidated Statements of Operations. There were no indicators of impairment identified during the second or third quarters of 2020.

Intangible Assets

Intangible assets consist of customer contracts and customer relationships acquired in prior business combinations. The fair value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers.

As a result of the triggering events and analysis described above, in the first quarter of 2020, we recognized a non-cash pre-tax impairment loss associated with certain intangible customer relationships for which undiscounted future net cash flows were not sufficient to recover the net book value.

The estimated annual amortization expense for intangible assets is approximately $144.0 million, $130.9 million, $122.7 million, $117.5 million and $113.7 million for each of the years 2020 through 2024, respectively.

The changes in our intangible assets are as follows:

Balance at December 31, 2019	$	1,735.0
Impairment		(208.6	)
Amortization		(108.8	)
Balance at September 30, 2020	$	1,417.6

Assets and Liabilities Held for Sale

In October 2020, we executed agreements to sell our assets in Channelview, Texas for approximately $58 million (the “October 2020 Sale”). As of September 30, 2020, we classified our assets as held for sale and measured the fair value of the disposal group using the expected sales price under a contract with a third party (an input within Level 3 of the fair value hierarchy). We recognized a loss of $58.3 million included within other operating (income) expense in our Consolidated Statements of Operations for the three and nine months ended September 30, 2020 to reduce the carrying value of our assets to their recoverable amounts.

The sale closed in October 2020, and we used the proceeds for general corporate purposes. The sale of the assets is included in our Logistics and Transportation segment and does not qualify for reporting as a discontinued operation, as its divestiture did not represent a strategic shift that would have a major effect on our operations or financial results.

The adjusted carrying amounts of the assets and liabilities held for sale as of September 30, 2020 are as follows:

	September 30, 2020
Current assets:
Property, plant and equipment, net of accumulated depreciation and estimated loss on sale	$	61.0
Other current assets		1.2
Total assets held for sale	$	62.2

Current liabilities:
Accounts payable and accrued liabilities	$	1.0
Other long-term obligations		2.6
Total liabilities held for sale	$	3.6

Note 5 — Debt Obligations

	September 30, 2020			December 31, 2019
Current:
Obligations of the Partnership: (1)
Accounts receivable securitization facility, due April 2021 (2)	$	250.0		$	370.0
Finance lease liabilities		11.9			12.2
Current debt obligations		261.9			382.2

Long-term:
TRC obligations:
TRC Senior secured revolving credit facility, variable rate, due June 2023 (3)		435.0			435.0
Obligations of the Partnership: (1)
Senior secured revolving credit facility, variable rate, due June 2023 (4)		100.0			—
Senior unsecured notes:
5¼% fixed rate, due May 2023		559.6			559.6
4¼% fixed rate, due November 2023		583.9			583.9
6¾% fixed rate, due March 2024		—			580.1
5⅛% fixed rate, due February 2025		481.0			500.0
5⅞% fixed rate, due April 2026		963.2			1,000.0
5⅜% fixed rate, due February 2027		468.1			500.0
6½% fixed rate, due July 2027		705.2			750.0
5% fixed rate, due January 2028		700.3			750.0
6⅞% fixed rate, due January 2029		679.3			750.0
5½% fixed rate, due March 2030		949.6			1,000.0
4⅞% fixed rate, due February 2031		1,000.0			—
TPL notes, 4¾% fixed rate, due November 2021 (5)		6.5			6.5
TPL notes, 5⅞% fixed rate, due August 2023 (5)		48.1			48.1
Unamortized premium		0.2			0.3
		7,680.0			7,463.5
Debt issuance costs, net of amortization		(48.5	)		(49.1	)
Finance lease liabilities		20.7			25.8
Long-term debt		7,652.2			7,440.2
Total debt obligations	$	7,914.1		$	7,822.4
Irrevocable standby letters of credit:
Letters of credit outstanding under the TRC Senior secured credit facility (3)	$	—		$	—
Letters of credit outstanding under the Partnership senior secured revolving credit facility (4)		35.3			88.2
	$	35.3		$	88.2

(1)	While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.

(2)

As of September 30, 2020, the Partnership had $250.0 million of qualifying receivables under its $250.0 million accounts receivable securitization facility (“Securitization Facility”), resulting in zero availability. During the second quarter of 2020, the Partnership amended the Securitization Facility to decrease the facility size from $400.0 million to $250.0 million to more closely align with our expectations for borrowing needs given commodity prices and to extend the facility termination date to April 21, 2021.

(3)	As of September 30, 2020, availability under TRC’s $670.0 million senior secured revolving credit facility (“TRC Revolver”) was $235.0 million.

(4)	As of September 30, 2020, availability under the Partnership’s $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $2,064.7 million.

(5)	“TPL” refers to Targa Pipeline Partners LP.

The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the nine months ended September 30, 2020:

	Range of Interest Rates Incurred	Weighted Average Interest Rate Incurred
TRC Revolver	1.9% - 3.5%	2.5%
TRP Revolver	1.9% - 6.0%	2.3%
Partnership's Securitization Facility	1.5% - 2.7%	2.0%

Compliance with Debt Covenants

As of September 30, 2020, we were in compliance with the covenants contained in our various debt agreements.

Senior Unsecured Notes Issuance

In August 2020, the Partnership issued $1.0 billion aggregate principal amount of 4⅞% Senior Notes due 2031 (the “August 2020 Offering”), resulting in net proceeds of $991.0 million. The 4⅞% Senior Notes due 2031 have substantially similar terms and covenants as our other series of Senior Notes. A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer (the “Tender Offer”) of the Partnership’s 6¾% Senior Notes due 2024 and redeem any 6¾% Senior Notes due 2024 that remained outstanding after consummation of the Tender Offer, with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facility. See “Debt Extinguishments and Repurchases” for further details of the concurrent tender offer.

Debt Extinguishments and Repurchases

Concurrent with the August 2020 Offering, the Partnership commenced the Tender Offer to purchase for cash, subject to certain terms and conditions, any and all of our outstanding 6¾% Senior Notes due 2024. We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million.

Subsequent to the closing of the Tender Offer in August 2020, the Partnership redeemed the 6¾% Senior Notes due 2024 for the remaining note balance of $318.0 million (the “2024 Note Redemption”). As a result of the Tender Offer and the 2024 Note Redemption, we recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs.

Debt Repurchases

The following table summarizes the Partnership’s senior note repurchases for the nine months ended September 30, 2020:

Debt Repurchased	Book Value		Payment			Gain (Loss)			Write-off of Debt Issuance Costs			Net Gain
5⅛% Senior Notes due 2025	$	19.0	$	(14.6	)	$	4.4		$	(0.1	)	$	4.3
5⅞% Senior Notes due 2026		36.8		(29.7	)		7.1			(0.2	)		6.9
5⅜% Senior Notes due 2027		31.9		(26.6	)		5.3			(0.2	)		5.1
6½% Senior Notes due 2027		44.8		(35.5	)		9.3			(0.4	)		8.9
5% Senior Notes due 2028		49.7		(38.0	)		11.7			(0.4	)		11.3
6⅞% Senior Notes due 2029		70.7		(55.2	)		15.5			(0.6	)		14.9
5½% Senior Notes due 2030		50.4		(40.2	)		10.2			(0.5	)		9.7
6¾% Senior Notes due 2024		580.1		(591.2	)		(11.1	)		(2.6	)		(13.7	)
	$	883.4	$	(831.0	)	$	52.4		$	(5.0	)	$	47.4

We or the Partnership may retire or purchase various series of the Partnership’s outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Contractual Obligations

The following table summarizes payment obligations for debt instruments after giving effect to the debt repurchases detailed above:


	Payments Due By Period
			Less Than						More Than
	Total		1 Year		1-3 Years		3-5 Years		5 Years
					(in millions)
Long-term debt obligations (1)	$	7,679.8	$	-	$	1,149.2	$	1,064.9	$	5,465.7
Interest on debt obligations (2)		2,754.7		411.3		807.1		657.6		878.7
	$	10,434.5	$	411.3	$	1,956.3	$	1,722.5	$	6,344.4

(1)	Represents scheduled future maturities of consolidated debt obligations for the periods indicated.

(2)	Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing September 30, 2020 rates for floating debt.

Subsequent Event

On November 2, 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023.

Note 6 — Other Long-term Liabilities

Other long-term liabilities are comprised of deferred revenue, asset retirement obligations and operating lease liabilities.

Deferred Revenue

We have certain long-term contractual arrangements for which we have received consideration that we are not yet able to recognize as revenue. The resulting deferred revenue will be recognized once all conditions for revenue recognition have been met.

Deferred revenue as of September 30, 2020 and December 31, 2019, was $169.4 million and $172.0 million, respectively, which includes $129.0 million of payments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co., in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter. In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is dependent on the outcome of current litigation with Vitol. Deferred revenue also includes nonmonetary consideration received in a 2015 amendment to a gas gathering and processing agreement and consideration received for other construction activities of facilities connected to our systems. See Part II—Item 1. Legal Proceedings for further details on the related litigation.

Note 7 — Preferred Stock

Preferred Stock Dividends

As of September 30, 2020, we have accrued cumulative preferred dividends of $22.9 million on our Series A Preferred Stock (“Series A Preferred”), which will be paid on November 13, 2020. During the three and nine months ended September 30, 2020, we paid $22.9 million and $68.8 million of dividends to preferred shareholders, and recorded deemed dividends of $9.5 million and $27.7 million attributable to accretion of the preferred discount resulting from beneficial conversion feature accounting. Such accretion is included in the book value of the Series A Preferred.

Note 8 — Common Stock and Related Matters

Common Stock Dividends

The following table details the dividends declared and/or paid by us to common shareholders for the nine months ended September 30, 2020:

Three Months Ended	Date Paid or To Be Paid		Total Common Dividends Declared			Amount of Common Dividends Paid or To Be Paid			Accrued Dividends (1)			Dividends Declared per Share of Common Stock
(In millions, except per share amounts)

September 30, 2020	November 16, 2020	$		23.8	$		23.3	$		0.5	$		0.10000
June 30, 2020	August 17, 2020			23.7			23.3			0.4			0.10000
March 31, 2020	May 15, 2020			23.7			23.3			0.4			0.10000
December 31, 2019	February 18, 2020			216.0			212.0			4.0			0.91000

(1)	Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Subsequent Event

In October 2020, our Board of Directors approved a share repurchase program (the “Share Repurchase Program”) for the repurchase of up to $500 million of our outstanding common stock. As of November 2, 2020, we have repurchased 4,505,507 shares at a weighted average price of $16.33 for a total net cost of $73.6 million. There is approximately $426 million remaining under the Share Repurchase Program. We may discontinue the Share Repurchase Program at any time and are not obligated to repurchase any specific dollar amount or number of shares.

Note 9 — Partnership Units and Related Matters

Distributions

We are entitled to receive all Partnership distributions from available cash on the Partnership’s common units after payment of preferred unit distributions each quarter.

The following table details the distributions declared and paid by the Partnership for the nine months ended September 30, 2020:

Three Months Ended	Date Paid or To Be Paid		Total Distributions			Distributions to Targa Resources Corp.
September 30, 2020	November 13, 2020	$		51.7	$		48.9
June 30, 2020	August 13, 2020			51.7			48.9
March 31, 2020	May 13, 2020			53.1			50.3
December 31, 2019	February 13, 2020			241.9			239.1

Contributions

All capital contributions to the Partnership continue to be allocated 98% to the limited partner and 2% to the general partner; however, no units will be issued for those contributions. For the nine months ended September 30, 2020, we made a total of $50.0 million in contributions to the Partnership.

Preferred Units

The Partnership’s issued and outstanding Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) rank senior to the Partnership’s common units with respect to the distribution rights. Distributions on the Partnership’s 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of the Partnership’s general partner. Distributions on the Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on the Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.

The Partnership paid $2.8 million and $8.4 million of distributions to the holders of Preferred Units (“Preferred Unitholders”) for the three and nine months ended September 30, 2020. The Preferred Units are reported as noncontrolling interests in our financial statements.

Subsequent Event

In October 2020, the board of directors of the general partner of the Partnership declared a cash distribution of $0.1875 per Preferred Unit, resulting in approximately $0.9 million in distributions that will be paid on November 16, 2020.

Note 10 — Earnings per Common Share

The following table sets forth a reconciliation of net income and weighted average shares outstanding (in millions) used in computing basic and diluted net income per common share:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2020		2019			2020			2019
Net income (loss) attributable to Targa Resources Corp.	$	69.3	$	(47.3	)	$	(1,587.5	)	$	(96.4	)
Less: Dividends on preferred stock		32.4		31.3			96.5			93.2
Net income (loss) attributable to common shareholders for basic earnings per share	$	36.9	$	(78.6	)	$	(1,684.0	)	$	(189.6	)

Weighted average shares outstanding		233.4		232.7			233.2			232.4
Dilutive effect of unvested stock awards (1)		0.4		—			—			—
Weighted average shares outstanding – diluted		233.8		232.7			233.2			232.4

Net income (loss) available per common share - basic and diluted	$	0.16	$	(0.34	)	$	(7.22	)	$	(0.82	)

(1)

For the three months ended September 30, 2020, on a weighted average basis, 2.3 million unvested restricted stock awards, 0.5 million unvested performance stock units and 46.5 million Series A Preferred Stock were antidilutive, and accordingly, were excluded from the diluted earnings per common share calculation. For all other periods presented above, all unvested restricted stock awards, unvested performance stock units, and Series A Preferred Stock were antidilutive because a net loss existed for those respective periods.

Note 11 — Derivative Instruments and Hedging Activities

The primary purposes of our commodity risk management activities are to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have entered into derivative instruments to hedge the commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices and are designated as cash flow hedges for accounting purposes.

The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations.

We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.

We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.

At September 30, 2020, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2020		2021		2022		2023		2024		2025
Natural Gas	Swaps	MMBtu/d		168,317		166,216		90,600		33,350		-		-
Natural Gas	Basis Swaps	MMBtu/d		445,084		471,168		295,390		250,000		90,000		5,000
NGL	Swaps	Bbl/d		30,909		29,261		16,848		2,627		-		-
NGL	Futures	Bbl/d		52,685		25,526		-		-		-		-
Condensate	Swaps	Bbl/d		5,190		4,872		2,125		515		-		-

Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair value of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:

		Fair Value as of September 30, 2020				Fair Value as of December 31, 2019
	Balance Sheet	Derivative		Derivative		Derivative		Derivative
	Location	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	58.4	$	116.1	$	102.1	$	11.6
	Long-term		14.0		62.8		33.7		6.4
Total derivatives designated as hedging instruments		$	72.4	$	178.9	$	135.8	$	18.0
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	30.5	$	5.0	$	1.2	$	92.5
	Long-term		65.5		0.1		1.8		34.4
Total derivatives not designated as hedging instruments		$	96.0	$	5.1	$	3.0	$	126.9
Total current position		$	88.9	$	121.1	$	103.3	$	104.1
Total long-term position			79.5		62.9		35.5		40.8
Total derivatives		$	168.4	$	184.0	$	138.8	$	144.9

The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows:

		Gross Presentation								Pro Forma Net Presentation
September 30, 2020		Asset		Liability			Collateral			Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	80.3	$	(121.1	)	$	60.1		$	31.5	$	(12.2	)
	Counterparties without offsetting positions - assets		8.6		-			-			8.6		-
	Counterparties without offsetting positions - liabilities		-		-			-			-		-
			88.9		(121.1	)		60.1			40.1		(12.2	)
Long Term Position
	Counterparties with offsetting positions or collateral		63.4		(62.6	)		-			26.3		(25.5	)
	Counterparties without offsetting positions - assets		16.1		-			-			16.1		-
	Counterparties without offsetting positions - liabilities		-		(0.3	)		-			-		(0.3	)
			79.5		(62.9	)		-			42.4		(25.8	)
Total Derivatives
	Counterparties with offsetting positions or collateral		143.7		(183.7	)		60.1			57.8		(37.7	)
	Counterparties without offsetting positions - assets		24.7		-			-			24.7		-
	Counterparties without offsetting positions - liabilities		-		(0.3	)		-			-		(0.3	)
		$	168.4	$	(184.0	)	$	60.1		$	82.5	$	(38.0	)

		Gross Presentation								Pro Forma Net Presentation
December 31, 2019		Asset		Liability			Collateral			Asset		Liability
Current Position
	Counterparties with offsetting positions or collateral	$	99.8	$	(85.0	)	$	(4.9	)	$	56.0	$	(46.1	)
	Counterparties without offsetting positions - assets		3.5		-			-			3.5		-
	Counterparties without offsetting positions - liabilities		-		(19.1	)		-			-		(19.1	)
			103.3		(104.1	)		(4.9	)		59.5		(65.2	)
Long Term Position
	Counterparties with offsetting positions or collateral		33.3		(40.5	)		-			18.1		(25.3	)
	Counterparties without offsetting positions - assets		2.2		-			-			2.2		-
	Counterparties without offsetting positions - liabilities		-		(0.3	)		-			-		(0.3	)
			35.5		(40.8	)		-			20.3		(25.6	)
Total Derivatives
	Counterparties with offsetting positions or collateral		133.1		(125.5	)		(4.9	)		74.1		(71.4	)
	Counterparties without offsetting positions - assets		5.7		-			-			5.7		-
	Counterparties without offsetting positions - liabilities		-		(19.4	)		-			-		(19.4	)
		$	138.8	$	(144.9	)	$	(4.9	)	$	79.8	$	(90.8	)

Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of the Partnership’s senior secured lenders. Some of our hedges are futures contracts executed through brokers that clear the hedges through an exchange. We maintain a margin deposit with the brokers in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within Deposits on our Consolidated Balance Sheets and is not offset against the fair value of our derivative instruments.

The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of $15.6 million as of September 30, 2020. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.

The following tables reflect amounts recorded in Other comprehensive income (“OCI”) and amounts reclassified from OCI to revenue for the periods indicated:

	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow	Three Months Ended September 30,					Nine Months Ended September 30,
Hedging Relationships	2020			2019		2020			2019
Commodity contracts	$	(128.7	)	$	118.2	$	(102.6	)	$	167.8

	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended September 30,				Nine Months Ended September 30,
Location of Gain (Loss)	2020		2019		2020		2019
Revenues	$	19.2	$	41.5	$	139.4	$	106.1

Based on valuations as of September 30, 2020, we expect to reclassify commodity hedge-related deferred losses of $(106.0) million included in accumulated other comprehensive income into earnings before income taxes through the end of 2023, with $(57.2) million of losses to be reclassified over the next twelve months.

Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the three and nine months ended September 30, 2020, the unrealized mark-to-market gains are primarily attributable to favorable movements in natural gas forward basis prices, as compared to our hedged positions.

	Location of Gain	Gain (Loss) Recognized in Income on Derivatives
Derivatives Not Designated	Recognized in Income on	Three Months Ended September 30,					Nine Months Ended September 30,
as Hedging Instruments	Derivatives	2020		2019			2020		2019
Commodity contracts	Revenue	$	90.0	$	(103.3	)	$	197.9	$	(113.8	)

See Note 12 – Fair Value Measurements and Note 18 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

Note 12 — Fair Value Measurements

Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.

Fair Value of Derivative Financial Instruments

Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold.

The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at September 30, 2020, a net liability position of $15.6 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $(136.8) million. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $106.1 million.

Fair Value of Other Financial Instruments

Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:

•

The TRC Revolver, TRP Revolver, and the Partnership’s Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and

•

The Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the debt.

Contingent consideration liabilities related to business acquisitions are carried at fair value until the end of the related earn-out period.

Fair Value Hierarchy

We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:

•

Level 1 – observable inputs such as quoted prices in active markets;

•

Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and

•

Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.

The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:

	September 30, 2020
	Carrying		Fair Value
	Value		Total		Level 1		Level 2		Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)	$	168.4	$	168.4	$	—	$	168.4	$	—
Liabilities from commodity derivative contracts (1)		184.0		184.0		—		183.7		0.3
TPL contingent consideration (2)		2.3		2.3		—		—		2.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		275.0		275.0		—		—		—
TRC Revolver		435.0		435.0		—		435.0		—
TRP Revolver		100.0		100.0		—		100.0		—
Partnership's Senior unsecured notes		7,145.0		7,206.0		—		7,206.0		—
Partnership's Securitization Facility		250.0		250.0		—		250.0		—

	December 31, 2019
	Carrying		Fair Value
	Value		Total		Level 1		Level 2		Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)	$	136.5	$	136.5	$	—	$	136.2	$	0.3
Liabilities from commodity derivative contracts (1)		142.6		142.6		—		142.0		0.6
TPL contingent consideration (2)		2.3		2.3		—		—		2.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		331.1		331.1		—		—		—
TRC Revolver		435.0		435.0		—		435.0		—
TRP Revolver		—		—		—		—		—
Partnership's Senior unsecured notes		7,028.5		7,376.9		—		7,376.9		—
Partnership's Securitization Facility		370.0		370.0		—		370.0		—

(1)

The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 11 –Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.

(2)	We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value.

Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets

We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable market prices or implied volatilities for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods.

The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.

The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives were (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable was immaterial. As of September 30, 2020, we had three commodity swap and option contracts categorized as Level 3.

The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs are not observable; therefore, the entire valuation of the contingent consideration is categorized in Level 3.

The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

	Commodity
	Derivative Contracts			Contingent
	Asset/(Liability)			Consideration
Balance, December 31, 2019	$	(0.3	)	$	(2.3	)
New Level 3 derivative instruments		(0.5	)		—
Transfers out of Level 3 (1)		0.3			—
Unrealized gain/(loss) included in OCI		0.2			—
Balance, September 30, 2020	$	(0.3	)	$	(2.3	)

(1)	Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Nonfinancial assets and liabilities, such as long-lived assets, are measured at fair value on a nonrecurring basis upon impairment. In the first quarter of 2020, we recorded non-cash pre-tax impairments of $2,442.8 million. The impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems associated with our Mid-Continent operations and full impairment of our Coastal operations. For disclosures related to valuation techniques, see Note 4 – Property, Plant and Equipment and Intangible Assets.

The techniques described above may produce a fair value calculation that may not be indicative or reflective of future fair values. Furthermore, while we believe our valuation techniques are appropriate and consistent with other market participants, the use of different techniques or assumptions to determine fair value of certain financial and nonfinancial assets and liabilities could result in a different fair value measurement at the reporting date.

Note 13 — Contingencies

Legal Proceedings

We and the Partnership are parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We and the Partnership are also parties to various proceedings with governmental environmental agencies, including but not limited to the U.S. Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Environmental Quality, which assert monetary sanctions for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business. See Part II—Item 1. Legal Proceedings for further details.

Note 14 — Revenue

Fixed consideration allocated to remaining performance obligations

The following table presents the estimated minimum revenue related to unsatisfied performance obligations at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements, with remaining contract terms ranging from 1 to 19 years.

	2020				2021				2022 and after
Fixed consideration to be recognized as of September 30, 2020	$	140.7			$	518.1			$	2,858.8

Based on the optional exemptions we elected to apply, the amounts presented in the table above exclude remaining performance obligations for (i) variable consideration for which the allocation exception is met and (ii) contracts with an original expected duration of one year or less.

For disclosures related to disaggregated revenue, see Note 18 – Segment Information.

Note 15 — Income Taxes

The Company records income taxes using an estimated annual effective tax rate (“ETR”) and recognizes specific events discretely as they occur. We have concluded that the annual ETR is a reliable estimate considering recent economic and financial market effects of decreased commodity prices and demand destruction due to the COVID-19 pandemic. We regularly evaluate the realizable tax benefits of deferred tax assets and record a valuation allowance, if required, based on an estimate of the amount of deferred tax assets that we believe does not meet the more-likely-than-not criteria of being realized.

We established a valuation allowance against our deferred tax assets during the nine months ended September 30, 2020, primarily due to the tax consequences of the impairment of long-lived assets. See Note 4 – Property Plant and Equipment and Intangible Assets. The Company recognized the valuation allowance as an ordinary item in its estimated annual ETR. After the valuation allowance, we have a net deferred tax liability of $131.1 million. We will continue to evaluate the sufficiency of the valuation allowance based on current and expected earnings and other factors and adjust accordingly. The valuation allowance decreased by approximately $15.5 million from June 30, 2020.

Note 16 — Other Operating (Income) Expense

Other operating (income) expense is comprised of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
(Gain) loss on sale of disposition of business and assets (1)	$	58.0	$	0.5	$	58.0	$	3.6
Write-down of assets (2)		13.5		17.9		13.5		17.9
Other		0.7		—		2.3		0.2
	$	72.2	$	18.4	$	73.8	$	21.7

(1)

In October 2020, we recognized a loss of $58.3 million for the three and nine months ended September 30, 2020 to reduce the carrying value of our assets in Channelview, Texas in connection with the October 2020 Sale. See Note 4 – Property, Plant and Equipment and Intangible Assets for further details.

(2)	Related to the write-down of certain assets to their recoverable amounts.

Note 17 — Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2020			2019
Cash:
Interest paid, net of capitalized interest (1)	$	315.9		$	228.4
Income taxes (received), net of payments		(44.4	)		0.3
Non-cash investing activities:
Impact of capital expenditure accruals on property, plant and equipment, net		(194.7	)		(150.9	)
Transfers from materials and supplies inventory to property, plant and equipment		1.9			21.7
Non-cash financing activities:
Changes in accrued distributions to noncontrolling interests		3.9			73.8

(1)	Interest capitalized on major projects was $31.1 million and $50.5 million for the nine months ended September 30, 2020 and 2019.

Note 18 — Segment Information

We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided.

Our 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 purchase and sale, 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.

Our 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 our other businesses. The Logistics and Transportation segment also includes the Grand Prix NGL pipeline (“Grand Prix”), as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline transporting volumes from West Texas to the Gulf Coast. Grand Prix connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

Other contains the mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.

Reportable segment information is shown in the following tables:

	Three Months Ended September 30, 2020
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	135.7	$	1,616.5	$	88.6	$	—		$	1,840.8
Fees from midstream services		126.2		148.1		—		—			274.3
		261.9		1,764.6		88.6		—			2,115.1
Intersegment revenues
Sales of commodities		611.9		37.4		—		(649.3	)		—
Fees from midstream services		1.7		8.5		—		(10.2	)		—
		613.6		45.9		—		(659.5	)		—
Revenues	$	875.5	$	1,810.5	$	88.6	$	(659.5	)	$	2,115.1
Operating margin	$	261.0	$	280.4	$	88.6	$	—		$	630.0
Other financial information:
Total assets (1)	$	8,929.4	$	6,841.2	$	78.2	$	203.3		$	16,052.1
Goodwill	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	63.6	$	69.0	$	—	$	4.0		$	136.6

(1)

Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.

	Three Months Ended September 30, 2019
	Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	292.3	$	1,403.1	$	(101.2	)	$	—		$	1,594.2
Fees from midstream services		173.0		135.3		—			—			308.3
		465.3		1,538.4		(101.2	)		—			1,902.5
Intersegment revenues
Sales of commodities		534.0		34.9		—			(568.9	)		—
Fees from midstream services		1.9		7.4		—			(9.3	)		—
		535.9		42.3		—			(578.2	)		—
Revenues	$	1,001.2	$	1,580.7	$	(101.2	)	$	(578.2	)	$	1,902.5
Operating margin	$	246.5	$	228.9	$	(101.2	)	$	—		$	374.2
Other financial information:
Total assets (1)	$	12,326.5	$	6,475.0	$	2.9		$	114.1		$	18,918.5
Goodwill	$	46.6	$	—	$	—		$	—		$	46.6
Capital expenditures	$	230.3	$	301.2	$	—		$	10.8		$	542.3

(1)	Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.

	Nine Months Ended September 30, 2020
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	512.9	$	4,172.0	$	215.9	$	—		$	4,900.8
Fees from midstream services		354.5		432.2		—		—			786.7
		867.4		4,604.2		215.9		—			5,687.5
Intersegment revenues
Sales of commodities		1,444.3		140.1		—		(1,584.4	)		—
Fees from midstream services		4.9		23.8		—		(28.7	)		—
		1,449.2		163.9		—		(1,613.1	)		—
Revenues	$	2,316.6	$	4,768.1	$	215.9	$	(1,613.1	)	$	5,687.5
Operating margin	$	753.7	$	806.0	$	215.9	$	—		$	1,775.6
Other financial information:
Total assets (1)	$	8,929.4	$	6,841.2	$	78.2	$	203.3		$	16,052.1
Goodwill	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	218.0	$	375.5	$	—	$	16.8		$	610.3

(1)	Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.

	Nine Months Ended September 30, 2019
	Gathering and Processing		Logistics and Transportation		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	847.4	$	4,508.5	$	(101.1	)	$	—		$	5,254.8
Fees from midstream services		549.1		393.3		—			—			942.4
		1,396.5		4,901.8		(101.1	)		—			6,197.2
Intersegment revenues
Sales of commodities		1,896.5		117.0		—			(2,013.5	)		—
Fees from midstream services		5.3		20.1		—			(25.4	)		—
		1,901.8		137.1		—			(2,038.9	)		—
Revenues	$	3,298.3	$	5,038.9	$	(101.1	)	$	(2,038.9	)	$	6,197.2
Operating margin	$	716.8	$	565.0	$	(101.1	)	$	—		$	1,180.7
Other financial information:
Total assets (1)	$	12,326.5	$	6,475.0	$	2.9		$	114.1		$	18,918.5
Goodwill	$	46.6	$	—	$	—		$	—		$	46.6
Capital expenditures	$	1,068.7	$	1,197.5	$	—		$	38.7		$	2,304.9

(1)	Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.

The following table shows our consolidated revenues disaggregated by product and service for the periods presented:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2020		2019			2020		2019
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas	$	351.1	$	305.3		$	893.9	$	934.2
NGL		1,312.9		1,160.5			3,382.0		3,752.4
Condensate and crude oil		54.4		178.7			217.8		488.4
Petroleum products		13.2		11.5			69.8		87.5
		1,731.6		1,656.0			4,563.5		5,262.5
Non-customer revenue:
Derivative activities - Hedge		19.2		41.5			139.4		106.1
Derivative activities - Non-hedge (1)		90.0		(103.3	)		197.9		(113.8	)
		109.2		(61.8	)		337.3		(7.7	)
Total sales of commodities		1,840.8		1,594.2			4,900.8		5,254.8

Fees from midstream services:
Revenue recognized from contracts with customers:
Gathering and processing		123.7		171.6			347.1		543.7
NGL transportation, fractionation and services		43.8		45.8			116.7		122.0
Storage, terminaling and export		96.6		84.6			285.5		254.7
Other		10.2		6.3			37.4		22.0
Total fees from midstream services		274.3		308.3			786.7		942.4

Total revenues	$	2,115.1	$	1,902.5		$	5,687.5	$	6,197.2

(1)	Represents derivative activities that are not designated as hedging instruments under ASC 815.

The following table shows a reconciliation of reportable segment operating margin to income (loss) before income taxes for the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Gathering and Processing operating margin	$	261.0		$	246.5		$	753.7		$	716.8
Logistics and Transportation operating margin		280.4			228.9			806.0			565.0
Other operating margin		88.6			(101.2	)		215.9			(101.1	)
Depreciation and amortization expense		(203.7	)		(244.3	)		(647.3	)		(718.9	)
General and administrative expense		(58.6	)		(69.9	)		(180.6	)		(223.5	)
Impairment of long-lived assets		—			—			(2,442.8	)		—
Interest expense, net		(97.7	)		(89.1	)		(292.4	)		(241.8	)
Equity earnings (loss)		18.6			10.0			54.1			15.9
Gain (loss) on sale or disposition of business and assets		(58.0	)		(0.5	)		(58.0	)		(3.6	)
Write-down of assets		(13.5	)		(17.9	)		(13.5	)		(17.9	)
Gain (loss) from financing activities		(13.7	)		—			47.4			(1.4	)
Gain (loss) from sale of equity-method investment		—			65.8			—			65.8
Change in contingent considerations		—			—			—			(8.8	)
Other, net		0.7			—			(0.1	)		(0.2	)
Income (loss) before income taxes	$	204.1		$	28.3		$	(1,757.6	)	$	46.3

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2019 (“Annual Report”), as well as the unaudited consolidated financial statements and notes hereto included in this Quarterly Report on Form 10-Q.

Overview

Targa Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream services and is one of the largest independent midstream infrastructure companies in North America. We own, operate, acquire, and develop a diversified portfolio of complementary domestic midstream infrastructure assets.

Our Operations

We are engaged primarily 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.

To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as the Downstream Business).

Our Gathering and Processing segment includes assets used in the gathering and purchase and sale 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 purchase and sale, 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.

Our 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 our other businesses. The Logistics and Transportation segment also includes the Grand Prix NGL pipeline (“Grand Prix”), as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline transporting volumes from West Texas to the Gulf Coast. Grand Prix connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas. The associated assets, including these pipelines, are generally connected to and supplied in part by our 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.

Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.

Recent Developments

Response to Current Market Conditions

During the nine months ended September 30, 2020, global commodity prices declined due to factors that significantly impacted both supply and demand. As the COVID-19 pandemic spread and travel and other restrictions were implemented globally, the demand for commodities declined substantially. Additionally, certain major oil producing nations significantly increased their oil and gas production late in the first quarter which further contributed to the surplus production of commodities. Despite these nations subsequently agreeing to reduce global commodity supplies and global economies beginning to re-open, commodity prices remain weak relative to historical levels and continue to remain volatile. Reduced economic activity due to the COVID-19 pandemic, combined with uncertainty around global commodity supply and demand, has contributed to depressed crude oil, condensate, NGL and natural gas prices.

Furthermore, the decline in commodity prices led many exploration and production companies to reduce planned capital expenditures for drilling and production activities and also led to some companies shutting in wells in the first half of 2020. Such price and activity declines negatively impacted our operations by (i) reducing investments by third parties in the development of new oil and gas reserves, therefore reducing volumes coming onto our systems in the future, (ii) decreasing volumes processed in our facilities and transported on our pipelines and (iii) reducing the prices we receive from the sale of commodities. While commodity prices remain low relative to historical levels and uncertainties associated with the impacts of COVID-19 continue, production from wells that were previously shut-in during the first half of 2020 across our operating areas has largely resumed. Though energy demand has begun to recover compared to the first half of 2020, the pace and scope of recovery is uncertain at this time and may extend beyond 2020.

These circumstances have caused significant market volatility and business disruption. In our Gathering and Processing areas of operation, producers have reduced their drilling activity to varying degrees, which may lead to lower volume growth in the near term and reduced demand for our services. Producer activity also generates demand in our Downstream Business for transportation, fractionation, storage and other fee-based services, which may decrease in the near term.

There has been, and we believe will continue to be, significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. Due to the recent volatility in commodity prices, we are uncertain of what pricing and market demand will be throughout 2020, and, as a result, demand for our services may decrease. Across our operations, particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered. The significant level of margin we derive from fee-based arrangements, combined with our hedging arrangements, helps to mitigate our exposure to commodity price movements. For additional information regarding our hedging activities, see “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

Due to the significant decline in commodity prices and the increased volatility in the broader market, the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all has been negatively impacted. In these conditions, investors may be more likely to limit the amounts of their investments as well as seek more restrictive terms and higher costs on any financing. While these effects have increased the costs of debt and equity financing for the Company and others in our industry, we believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures through the remainder of 2020 and beyond.

In a response to current market conditions, in the first quarter of 2020, we announced that our Board of Directors approved a reduction in the Company’s quarterly common dividend to $0.10 per share for the quarter ended March 31, 2020 from $0.91 per share in the previous quarter. This reduction provided for approximately $755 million of additional annual direct cash flow, resulting in significant free cash flow available to reduce debt. We also reduced our estimated 2020 net growth capital expenditures to about $700 million from our previously disclosed ranges of $700 million to $800 million in the first quarter of 2020 and $1.2 billion to $1.3 billion in the fourth quarter of 2019. The vast majority of spending is for major ongoing growth capital projects where the capital is already predominantly spent. We continue to work through numerous internal initiatives to respond to current market conditions, including identifying and implementing cost reduction measures such as reducing or deferring non-essential operating and general and administrative expenses.

We believe that our long-term strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows even in a low commodity price environment. Geographic, business and customer diversity enhances our ability to generate sufficient cash flows to fund our requirements. Our assets are positioned in strategic oil and gas producing areas across multiple basins and provide services under attractive contract terms to a diverse mix of customers across our operational areas. Our contract portfolio has attractive rates and term characteristics, including a significant fee-based component, especially in our Downstream Business. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices.

We are currently experiencing no material issues with potential workforce disruptions, and we remain focused on safeguarding employee health and safety and ensuring safe and reliable operations in response to COVID-19. Additionally, we are currently experiencing no material supply chain disruptions as a result of the COVID-19 pandemic, and our relationships with our major customers continues to be strong. However, if any of these circumstances change, our business could be adversely affected. Further, as there is significant uncertainty around the breadth and duration of the disruptions to global markets related to the aforementioned current events, we are unable to determine the extent that these events could materially impact our future financial position, operations and/or cash flows.

Gathering and Processing Segment Expansion

Permian Midland Processing Expansion

In November 2020, we announced the transfer of an existing cryogenic natural gas processing plant from our North Texas

system to our Permian Midland system. The former Longhorn Plant will be relocated to, and installed in Reagan County, Texas, in 2021 as a new 200 MMcf/d cryogenic natural gas processing plant (the “Heim Plant”). The Heim Plant will process natural gas production from the Permian Basin and is expected to begin operations in the fourth quarter of 2021.

In August 2019, we announced that we began construction of a new 250 MMcf/d cryogenic natural gas processing plant in the Midland Basin, the Gateway Plant, which commenced operations in the third quarter of 2020.

Permian Delaware Processing Expansions

In March 2018, we announced that we entered into long-term fee-based agreements with an investment grade energy company for natural gas gathering and processing services in the Delaware Basin and for downstream transportation, fractionation and other related services. The agreements are underpinned by the customer's dedication of significant acreage within a large, well-defined area in the Delaware Basin. In addition to high-pressure rich gas gathering pipelines and a natural gas processing plant, the Falcon Plant, which were placed into service in 2019, we commenced operations of a second 250 MMcf/d cryogenic natural gas processing plant, the Peregrine Plant, in the second quarter of 2020.

We provide NGL transportation services on Grand Prix and fractionation services at our Mont Belvieu complex for a majority of the NGLs from the Falcon and Peregrine Plants.

Logistics and Transportation Segment Expansion

Grand Prix NGL Pipeline Extension

In February 2019, we announced an extension to our Grand Prix NGL pipeline system (the “Central Oklahoma Extension”), which will extend from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with The Williams Companies, Inc. (“Williams”) Bluestem Pipeline, linking the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. The Central Oklahoma Extension is expected to be operational by the end of the fourth quarter of 2020. Transportation volumes on the Central Oklahoma Extension accrue solely to Targa’s benefit and are not included in Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), a consolidated subsidiary of which Targa owns a 56% interest.

Fractionation Expansion

In November 2018, we announced plans to construct two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7” and “Train 8”). Train 7 commenced operations in the first quarter of 2020 and Train 8 commenced operations in the third quarter of 2020. In January 2019, Williams committed to Targa significant volumes which Targa will transport on Grand Prix and fractionate at Targa’s Mont Belvieu facilities (including Train 7). Williams was also granted an option to purchase a 20% equity interest in the fractionation train, which was originally wholly owned by Targa. Williams exercised its initial option and executed a joint venture agreement with us with respect to Train 7 in the second quarter of 2019. Certain fractionation-related infrastructure for Train 7, such as storage caverns and brine handling, will be funded and owned 100% by Targa.

LPG Export Expansion

In February 2019, we announced plans to further expand our LPG export capabilities of propane and butanes at our Galena Park Marine Terminal by increasing refrigeration capacity and associated load rates. With the additional infrastructure, we increased our effective export capacity up to 15 MMBbl per month in the third quarter of 2020, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors.

Asset Sales

In October 2020, we executed agreements to sell our assets in Channelview, Texas for approximately $58 million (the “October 2020 Sale”). The sale closed in the fourth quarter of 2020.

In November 2019, we executed agreements to sell our crude and storage business in Permian Delaware for approximately $134 million. The sale closed in the first quarter of 2020.

Financing Activities

On November 2, 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023.

redemption payments for the Partnership’s 6¾% Senior Notes due 2024 (the “6¾% Notes”), with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facility.

We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million and redeemed the remaining aggregate principal amount of the 6¾% Notes, which totaled $318.0 million. We recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs.

We or the Partnership may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

In the second quarter of 2020, we amended the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) to decrease the facility size from $400.0 million to $250.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2021.

Share Repurchase Program

Corporation Tax Matters

On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act was signed into law. The CARES Act provides corporate taxpayers an expanded five-year net operating loss carryback period for losses earned in tax years 2018 through 2020. Additionally, the CARES Act allows corporate taxpayers to request an immediate refund of alternative minimum tax credits. We requested a cash refund from the Internal Revenue Service (“IRS”) of approximately $44 million related to the CARES Act provisions and received the refund in the second quarter of 2020.

The IRS notified us on April 3, 2019, that it will examine Targa’s federal income tax returns (Form 1120) for 2014, 2015 and 2016. We are cooperating with the IRS in the audit process and do not anticipate material changes in prior year taxable income.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.

How We Evaluate Our Operations

The profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

Our profitability is also impacted by fee-based contracts. Our growing capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our downstream facilities, continued focus on adding fee-based margin to our existing and future gathering and processing contracts, as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability.

Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: gross margin, operating margin, Adjusted EBITDA, distributable cash flow and free cash flow.

Throughput Volumes, Facility Efficiencies and Fuel Consumption

Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.

In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets and our NGL pipelines. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

Operating Expenses

Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period.

Capital Expenditures

Our capital expenditures are classified as growth capital expenditures, business acquisitions, and maintenance capital expenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance revenues. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations.

Capital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approval.

Non-GAAP Measures

We utilize non-GAAP measures to analyze our performance. Gross margin, operating margin, Adjusted EBITDA, distributable cash flow, and free cash flow are non-GAAP measures. The GAAP measure most directly comparable to these non-GAAP measures is net income (loss) attributable to TRC. These non-GAAP measures should not be considered as an alternative to GAAP net income attributable to TRC and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect net income, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the

limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes.

Gross Margin

We define gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program.

Gathering and Processing segment gross 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 payments, natural gas and crude oil purchases, and our equity volume hedge settlements.

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

We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our 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 our financial statements, including investors and commercial banks, to assess:

•

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

•

our 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.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) attributable to TRC before interest, income taxes, depreciation and amortization, and other items that we believe should be adjusted consistent with our 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 us and by external users of our financial statements such as investors, commercial banks and others to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors.

Distributable Cash Flow and Free Cash Flow

We define 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). We define free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends or retirement of debt.

Our Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
	(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin
Net income (loss) attributable to TRC	$	69.3		$	(47.3	)	$	(1,587.5	)	$	(96.4	)
Net income (loss) attributable to noncontrolling interests		102.9			79.4			116.5			152.7
Net income (loss)		172.2			32.1			(1,471.0	)		56.3
Depreciation and amortization expense		203.7			244.3			647.3			718.9
General and administrative expense		58.6			69.9			180.6			223.5
Impairment of long-lived assets		—			—			2,442.8			—
Interest (income) expense, net		97.7			89.1			292.4			241.8
Equity (earnings) loss		(18.6	)		(10.0	)		(54.1	)		(15.9	)
Income tax expense (benefit)		31.9			(3.8	)		(286.6	)		(10.0	)
(Gain) loss on sale or disposition of business and assets		58.0			0.5			58.0			3.6
Write-down of assets		13.5			17.9			13.5			17.9
(Gain) loss from sale of equity-method investment		—			(65.8	)		—			(65.8	)
(Gain) loss from financing activities		13.7			—			(47.4	)		1.4
Change in contingent considerations		—			—			—			8.8
Other, net		(0.7	)		—			0.1			0.2
Operating margin		630.0			374.2			1,775.6			1,180.7
Operating expenses		181.9			200.2			565.1			600.8
Gross margin	$	811.9		$	574.4		$	2,340.7		$	1,781.5

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
	(In millions)
Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Free Cash Flow
Net income (loss) attributable to TRC	$	69.3		$	(47.3	)	$	(1,587.5	)	$	(96.4	)
Income attributable to TRP preferred limited partners		2.8			2.8			8.4			8.4
Interest (income) expense, net		97.7			89.1			292.4			241.8
Income tax expense (benefit)		31.9			(3.8	)		(286.6	)		(10.0	)
Depreciation and amortization expense		203.7			244.3			647.3			718.9
Impairment of long-lived assets		—			—			2,442.8			—
(Gain) loss on sale or disposition of business and assets		58.0			0.5			58.0			3.6
Write-down of assets		13.5			17.9			13.5			17.9
(Gain) loss from sale of equity-method investment		—			(65.8	)		—			(65.8	)
(Gain) loss from financing activities (1)		13.7			—			(47.4	)		1.4
Equity (earnings) loss		(18.6	)		(10.0	)		(54.1	)		(15.9	)
Distributions from unconsolidated affiliates and preferred partner interests, net		28.2			14.0			81.6			33.4
Change in contingent considerations		—			—			—			8.8
Compensation on equity grants		16.4			16.1			49.5			49.0
Risk management activities		(88.3	)		100.7			(214.2	)		100.8
Severance and related benefits (2)		—			—			6.5			—
Noncontrolling interests adjustments (3)		(9.2	)		(8.9	)		(211.7	)		(25.6	)
TRC Adjusted EBITDA	$	419.1		$	349.6		$	1,198.5		$	970.3
Distributions to TRP preferred limited partners		(2.8	)		(2.8	)		(8.4	)		(8.4	)
Interest expense on debt obligations (4)		(98.2	)		(88.0	)		(289.5	)		(247.0	)
Cash tax refund		—			—			44.4			—
Maintenance capital expenditures		(27.3	)		(31.0	)		(67.7	)		(101.5	)
Noncontrolling interests adjustments of maintenance capital expenditures		3.9			2.1			1.6			6.0
Distributable Cash Flow	$	294.7		$	229.9		$	878.9		$	619.4
Growth capital expenditures, net (5)		(105.4	)		(448.4	)		(518.5	)		(1,946.2	)
Free Cash Flow	$	189.3		$	(218.5	)	$	360.4		$	(1,326.8	)

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

(2)	Represents one-time severance and related benefit expense related to our cost reduction measures.

(3)	Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling interests).

(4)	Excludes amortization of interest expense.

(5)	Represents growth capital expenditures, net of contributions from noncontrolling interests and net contributions to investments in unconsolidated affiliates.

The Company has completed a number of announced growth capital projects since early 2019, and this has resulted in lower growth capital expenditures in 2020 and a transition to free cash flow. The following table details construction and project completion timing of our announced major growth capital projects:

Three Months Ended

March 31, 2019

June 30, 2019

September 30, 2019

December 31, 2019

March 31, 2020

June 30, 2020

September 30, 2020

Major Growth Capital Project (1):

Gathering & Processing:

Hopson Plant (2)

Falcon Plant (3)

Pembrook Plant (2)

Little Missouri 4 Plant (4)

Peregrine Plant (3)

Gateway Plant (2)

Logistics & Transportation:

Train 6

Grand Prix NGL Pipeline

Gulf Coast Express Pipeline

Train 7

Train 8

LPG Export Expansion

Grand Prix Central OK Extension

(1)	"UC" and "C" indicates under construction and project completed, respectively, as of the end of the period presented above.

(2)	Part of our Permian Midland operating area.

(3)	Part of our Permian Delaware operating area.

(4)	Part of our Badlands operating area.

Consolidated Results of Operations

The following table and discussion is a summary of our consolidated results of operations:

	Three Months Ended September 30,												Nine Months Ended September 30,
	2020			2019			2020 vs. 2019						2020			2019			2020 vs. 2019
	(In millions)
Revenues:
Sales of commodities	$	1,840.8		$	1,594.2		$	246.6			15	%	$	4,900.8		$	5,254.8		$	(354.0	)		(7	%)
Fees from midstream services		274.3			308.3			(34.0	)		(11	%)		786.7			942.4			(155.7	)		(17	%)
Total revenues		2,115.1			1,902.5			212.6			11	%		5,687.5			6,197.2			(509.7	)		(8	%)
Product purchases		1,303.2			1,328.1			(24.9	)		(2	%)		3,346.8			4,415.7			(1,068.9	)		(24	%)
Gross margin (1)		811.9			574.4			237.5			41	%		2,340.7			1,781.5			559.2			31	%
Operating expenses		181.9			200.2			(18.3	)		(9	%)		565.1			600.8			(35.7	)		(6	%)
Operating margin (1)		630.0			374.2			255.8			68	%		1,775.6			1,180.7			594.9			50	%
Depreciation and amortization expense		203.7			244.3			(40.6	)		(17	%)		647.3			718.9			(71.6	)		(10	%)
General and administrative expense		58.6			69.9			(11.3	)		(16	%)		180.6			223.5			(42.9	)		(19	%)
Impairment of long-lived assets		—			—			—			—			2,442.8			—			2,442.8			—
Other operating (income) expense		72.2			18.4			53.8			292	%		73.8			21.7			52.1			240	%
Income (loss) from operations		295.5			41.6			253.9		NM				(1,568.9	)		216.6			(1,785.5	)	NM
Interest expense, net		(97.7	)		(89.1	)		(8.6	)		(10	%)		(292.4	)		(241.8	)		(50.6	)		(21	%)
Equity earnings (loss)		18.6			10.0			8.6			86	%		54.1			15.9			38.2			240	%
Gain (loss) from financing activities		(13.7	)		—			(13.7	)		—			47.4			(1.4	)		48.8		NM
Gain (loss) from sale of equity-method investment		—			65.8			(65.8	)		(100	%)		—			65.8			(65.8	)		(100	%)
Change in contingent considerations		—			—			—			—			—			(8.8	)		8.8			100	%
Other, net		1.4			—			1.4			—			2.2			—			2.2			—
Income tax (expense) benefit		(31.9	)		3.8			(35.7	)	NM				286.6			10.0			276.6		NM
Net income (loss)		172.2			32.1			140.1		NM				(1,471.0	)		56.3			(1,527.3	)	NM
Less: Net income (loss) attributable to noncontrolling interests		102.9			79.4			23.5			30	%		116.5			152.7			(36.2	)		(24	%)
Net income (loss) attributable to Targa Resources Corp.		69.3			(47.3	)		116.6			247	%		(1,587.5	)		(96.4	)		(1,491.1	)	NM
Dividends on Series A Preferred Stock		22.9			22.9			—			—			68.8			68.8			—			—
Deemed dividends on Series A Preferred Stock		9.5			8.4			1.1			13	%		27.7			24.4			3.3			14	%
Net income (loss) attributable to common shareholders	$	36.9		$	(78.6	)	$	115.5			147	%	$	(1,684.0	)	$	(189.6	)	$	(1,494.4	)	NM
Financial data:
Adjusted EBITDA (1)	$	419.1		$	349.6		$	69.5			20	%	$	1,198.5		$	970.3		$	228.2			24	%
Distributable cash flow (1)		294.7			229.9			64.8			28	%		878.9			619.4			259.5			42	%
Free cash flow (1)		189.3			(218.5	)		407.8		NM				360.4			(1,326.8	)		1,687.2		NM

(1)	Gross margin, operating margin, Adjusted EBITDA, distributable cash flow and free cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.”

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, 2020 Compared to Three Months Ended September 30, 2019

The increase in commodity sales reflects higher NGL and natural gas prices ($133.5 million), higher NGL, condensate and petroleum products volumes ($100.7 million) and the favorable impact of hedges ($171.0 million), partially offset by lower crude marketing and natural gas volumes ($128.9 million) and lower condensate and petroleum product prices ($29.6 million).

The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, and lower gas processing volumes, partially offset by increased export and terminaling and storage volumes.

The decrease in product purchases reflects lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, and lower natural gas volumes, partially offset by higher NGL and natural gas prices.

Higher operating margin and gross margin in 2020 reflect increased segment results for Gathering and Processing and Logistics and Transportation. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense decreased primarily due to a lower depreciable base associated with assets that were impaired during the first quarter of 2020 and the sale of the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including Train 7 and the additional processing plants and associated infrastructure in the Permian Basin.

General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by an increase in insurance costs.

Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of our assets in Channelview, Texas in connection with the October 2020 Sale and write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts.

Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.

The increase in equity earnings is primarily due to higher earnings from our investments in GCX and Little Missouri 4 LLC (“Little Missouri 4”), partially offset by lower earnings from Gulf Coast Fractionators LP (“GCF”).

During the third quarter of 2020, the Partnership redeemed the 6¾% Senior Notes due 2024, resulting in a $13.7 million net loss from financing activities.

During the third quarter of 2019, the Partnership closed on the sale of an equity-method investment that resulted in the recognition of a gain of $65.8 million.

The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a decrease in valuation allowance.

Net income attributable to noncontrolling interests was higher in 2020 primarily due to income allocated to noncontrolling interest holders in the Grand Prix Joint Venture, Targa GCX Pipeline LLC (“GCX DevCo JV”) and the Centrahoma Joint Venture.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

The decrease in commodity sales reflects lower NGL, condensate, natural gas and petroleum product prices ($1,112.5 million) and lower crude marketing volumes ($254.7 million), partially offset by higher NGL, condensate, natural gas and petroleum product volumes ($664.3 million), the favorable impact of hedges ($345.1 million) and higher crude marketing prices ($3.8 million).

The decrease in product purchases reflects lower NGL, condensate, natural gas and petroleum product prices, as well as lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, partially offset by higher NGL, condensate, natural gas and petroleum product volumes.

General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by an increase in insurance costs.

The impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems in the first quarter of 2020 associated with our Mid-Continent operations and full impairment of our Coastal operations - all of which are in our Gathering and Processing segment. Based on then-current market conditions, our first quarter impairment assessment projected further decline in natural gas production across the Mid-Continent and Gulf of Mexico. We did not recognize any impairments of long-lived assets during the nine months ended September 30, 2019. We may identify additional triggering events in the future, which will require additional evaluations of the recoverability of the carrying value of our long-lived assets and may result in future impairments.

Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings.

The increase in equity earnings is primarily due to higher earnings from our investments in GCX and Little Missouri 4, partially offset by lower earnings from GCF.

During the nine months ended September 30, 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024, paying $831.0 million plus accrued interest to repurchase $883.4 million of the notes, resulting in a $47.4 million net gain from financing activities.

During the third quarter of 2019, the Partnership closed on the sale of an equity-method investment that resulted in the recognition of a gain of $65.8 million.

The increase in income tax benefit is primarily due to a higher pre-tax book loss and benefit of a net operating loss carryback from the CARES Act.

Net income attributable to noncontrolling interests was lower in 2020 primarily due to the allocation of impairment losses recognized during the first quarter of 2020 to noncontrolling interest holders, partially offset by higher income allocated to noncontrolling interest holders in Targa Badlands LLC (“Targa Badlands”), the DevCo Joint Ventures and the Grand Prix Joint Venture.

Results of Operations—By Reportable Segment

Our operating margins by reportable segment are:

	Gathering and Processing		Logistics and Transportation		Other			Consolidated Operating Margin
	(In millions)
Three Months Ended:
September 30, 2020	$	261.0	$	280.4	$	88.6		$	630.0
September 30, 2019		246.5		228.9		(101.2	)		374.2

Nine Months Ended:
September 30, 2020	$	753.7	$	806.0	$	215.9		$	1,775.6
September 30, 2019		716.8		565.0		(101.1	)		1,180.7

Gathering and Processing Segment

	Three Months Ended September 30,									Nine Months Ended September 30,
	2020		2019		2020 vs. 2019					2020		2019		2020 vs. 2019
	(In millions, except operating statistics and price amounts)
Gross margin	$	362.9	$	366.7	$	(3.8	)	(1	%)	$	1,071.4	$	1,092.0	$	(20.6	)	(2	%)
Operating expenses		101.9		120.2		(18.3	)	(15	%)		317.7		375.2		(57.5	)	(15	%)
Operating margin	$	261.0	$	246.5	$	14.5		6	%	$	753.7	$	716.8	$	36.9		5	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)		1,811.5		1,513.9		297.6		20	%		1,722.1		1,421.3		300.8		21	%
Permian Delaware		758.1		629.4		128.7		20	%		712.4		552.2		160.2		29	%
Total Permian		2,569.6		2,143.3		426.3					2,434.5		1,973.5		461.0

SouthTX (5)		233.6		328.6		(95.0	)	(29	%)		261.5		335.3		(73.8	)	(22	%)
North Texas		197.8		228.2		(30.4	)	(13	%)		206.3		227.6		(21.3	)	(9	%)
SouthOK (6)		386.9		590.8		(203.9	)	(35	%)		463.3		606.1		(142.8	)	(24	%)
WestOK		233.6		329.2		(95.6	)	(29	%)		258.7		335.2		(76.5	)	(23	%)
Total Central		1,051.9		1,476.8		(424.9	)				1,189.8		1,504.2		(314.4	)

Badlands (7),(8)		137.0		120.8		16.2		13	%		136.1		103.4		32.7		32	%
Total Field		3,758.5		3,740.9		17.6					3,760.4		3,581.1		179.3

Coastal		522.8		764.9		(242.1	)	(32	%)		672.9		779.9		(107.0	)	(14	%)

Total		4,281.3		4,505.8		(224.5	)	(5	%)		4,433.3		4,361.0		72.3		2	%
NGL production, MBbl/d (3)
Permian Midland (4)		253.0		216.5		36.5		17	%		247.6		199.8		47.8		24	%
Permian Delaware		105.3		82.3		23.0		28	%		97.1		71.4		25.7		36	%
Total Permian		358.3		298.8		59.5					344.7		271.2		73.5

SouthTX (5)		29.2		41.5		(12.3	)	(30	%)		28.7		44.0		(15.3	)	(35	%)
North Texas		23.7		27.3		(3.6	)	(13	%)		24.5		26.9		(2.4	)	(9	%)
SouthOK (6)		45.9		69.5		(23.6	)	(34	%)		54.6		65.4		(10.8	)	(17	%)
WestOK		19.3		19.2		0.1		1	%		21.2		22.4		(1.2	)	(5	%)
Total Central		118.1		157.5		(39.4	)				129.0		158.7		(29.7	)

Badlands (8)		17.0		14.0		3.0		21	%		16.3		12.2		4.1		34	%
Total Field		493.4		470.3		23.1					490.0		442.1		47.9

Coastal		32.5		45.4		(12.9	)	(28	%)		41.5		47.0		(5.5	)	(12	%)

Total		525.9		515.7		10.2		2	%		531.5		489.1		42.4		9	%
Crude oil, Badlands, MBbl/d		146.4		164.3		(17.9	)	(11	%)		160.4		167.0		(6.6	)	(4	%)
Crude oil, Permian, MBbl/d (9)		44.6		95.2		(50.6	)	(53	%)		45.3		86.1		(40.8	)	(47	%)
Natural gas sales, BBtu/d (3),(10)		2,032.3		2,056.6		(24.3	)	(1	%)		2,079.3		2,011.2		68.1		3	%
NGL sales, MBbl/d (3),(10)		389.5		398.0		(8.5	)	(2	%)		406.0		382.4		23.6		6	%
Condensate sales, MBbl/d		13.6		11.0		2.6		24	%		16.1		12.2		3.9		32	%
Average realized prices - inclusive of hedges (11):
Natural gas, $/MMBtu		1.34		1.13		0.21		19	%		1.10		1.31		(0.21	)	(16	%)
NGL, $/gal		0.29		0.28		0.01		4	%		0.24		0.35		(0.11	)	(31	%)
Condensate, $/Bbl		43.49		50.23		(6.74	)	(13	%)		38.56		49.49		(10.93	)	(22	%)

(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 quarter and the denominator is the number of calendar days during the quarter.

(2)	Plant natural gas inlet represents our 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 we own 72.8%, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.

(5)	SouthTX includes the Raptor Plant, of which we own a 50% interest through the Carnero Joint Venture. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(6)	SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants that are owned 100% by us. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(7)	Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 Plant.

(8)	As of April 3, 2019, Targa owns 55% of Targa Badlands, prior to which we owned a 100% interest. Targa Badlands is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

(9)	Permian crude oil volumes reflect the sale of the Delaware crude system, which was effective December 1, 2019.

(10)

Natural gas and NGL sales statistics in 2020 include statistics related to new commercial arrangements effective in January 2020, which resulted in a change from net presentation as “Fees from midstream services” to gross presentation as “Sales of commodities” and “Product purchases”. This change in presentation did not result in an impact to our operating or gross margin.

(11)	Average realized prices include the effect of realized commodity hedge gain/loss attributable to our 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 volumes as the denominator.

The following table presents the realized commodity hedge gain/loss attributable to our equity volumes that are included in the gross margin of Gathering and Processing segment:

	Three Months Ended September 30, 2020						Three Months Ended September 30, 2019
	(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)		17.5	$	0.20	$	3.5		18.8	$	1.07		$	20.1
NGL (MMgal)		126.4		0.08		10.5		110.0		0.17			18.5
Crude oil (MBbl)		0.5		16.75		8.0		0.4		(1.76	)		(0.7	)
					$	22.0						$	37.9

	Nine Months Ended September 30, 2020						Nine Months Ended September 30, 2019
	(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)		50.6	$	0.55	$	27.7		47.0	$	1.29		$	60.6
NGL (MMgal)		322.1		0.15		49.7		252.1		0.11			27.9
Crude oil (MBbl)		1.4		19.72		27.7		1.1		(2.28	)		(2.6	)
					$	105.1						$	85.9

(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, 2020 Compared to Three Months Ended September 30, 2019

Gathering and Processing segment gross margin contributions, attributable to higher system volumes and fee-based margin in the Permian region, were offset by lower volumes in the Central region and lower realized hedge gains. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity. In the Badlands, natural gas purchased 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. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019.

Operating expenses were lower due to cost reduction measures that resulted in decreases in compensation and benefits, contract labor and chemicals, despite the addition of the Peregrine and Gateway processing facilities in the Permian.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Gathering and Processing segment gross margin contributions, attributable to higher inlet volumes and fee-based margin in the Permian region and Badlands and higher realized hedge gains, were offset by lower commodity prices and lower Central region volumes. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity. In the Badlands, natural gas purchased 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. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019.

Operating expenses were lower due to cost reduction measures that resulted in decreases in contract labor, chemicals and compression rentals and lower ad valorem taxes, despite the addition of the Peregrine and Gateway processing facilities in the Permian.

Logistics and Transportation Segment

		Three Months Ended September 30,								Nine Months Ended September 30,
		2020		2019		2020 vs. 2019				2020		2019		2020 vs. 2019
	(In millions, except operating statistics and price amounts)
Gross margin		$	362.0	$	310.4	$	51.6	17	%	$	1,057.0	$	792.4	$	264.6		33	%
Operating expenses (1)			81.6		81.5		0.1	0	%		251.0		227.4		23.6		10	%
Operating margin		$	280.4	$	228.9	$	51.5	22	%	$	806.0	$	565.0	$	241.0		43	%
Operating statistics MBbl/d (2):
Fractionation volumes (3)			589.5		508.8		80.7	16	%		598.0		492.8		105.2		21	%
Export volumes (4)			308.5		239.2		69.3	29	%		277.2		228.1		49.1		22	%
Pipeline throughput (5)			300.9		131.8		169.1	128	%		273.0		44.4		228.6	NM
NGL sales			724.1		672.1		52.0	8	%		721.6		620.9		100.7		16	%

(1)	Effective January 1, 2020, pursuant to amendments to contractual arrangements with our partners, our share of operating expenses associated with GCF, an investment in an unconsolidated affiliate, are included in operating expenses.

(2)	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.

(3)	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.

(4)	Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.

(5)	Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix to Mont Belvieu.

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, 2020 Compared to Three Months Ended September 30, 2019

The increase in Logistics and Transportation segment gross margin was primarily due to higher NGL transportation and fractionation margin and higher LPG export margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to higher 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 7 in the first quarter of 2020 and Train 8 late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by expansion of our LPG export capabilities. Marketing margin decreased primarily due to less optimization margin realized in our marketing businesses.

Operating expenses were flat, despite the operations of a number of system expansions, including Grand Prix, additional incremental fractionation capacity and expansion of our LPG export capabilities. Lower fuel and power costs and cost reduction measures that resulted in lower compensation and maintenance were offset by increased taxes primarily attributable to Grand Prix and the inclusion of our share of operating expenses associated with GCF.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

The increase in Logistics and Transportation segment gross margin was primarily due to higher NGL transportation and fractionation margin and higher LPG export margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to higher 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, Train 7 in the first quarter of 2020 and Train 8 late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by expansion of our LPG export capabilities. Marketing margin decreased due to less optimization margin realized in our marketing businesses.

Operating expenses were higher primarily due to the inclusion of our share of operating expenses associated with GCF, increased costs attributable to our fractionation and LPG export expansions, higher taxes primarily attributable to Grand Prix and to additional incremental fractionation capacity, and higher maintenance primarily attributable to Grand Prix, partially offset by lower fuel and power costs.

Other

	Three Months Ended September 30,							Nine Months Ended September 30,
	2020		2019			2020 vs. 2019		2020		2019			2020 vs. 2019
	(In millions)							(In millions)
Gross margin	$	88.6	$	(101.2	)	$	189.8	$	215.9	$	(101.1	)	$	317.0
Operating margin	$	88.6	$	(101.2	)	$	189.8	$	215.9	$	(101.1	)	$	317.0

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. We have entered into derivative instruments to hedge the commodity price associated with a portion of our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Transportation segment. See further details of our risk management program in “Item 3. – Quantitative and Qualitative Disclosures About Market Risk.”

Our Liquidity and Capital Resources

As of September 30, 2020, we had $275.0 million of “Cash and cash equivalents,” on our Consolidated Balance Sheets. We believe our cash position, our cash flows from operating activities and remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”) are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership’s liquidity, subject to the limitations set forth in the Partnership Agreement and any restrictions contained in the covenants of the Partnership’s debt agreements, as well as the ability to contribute capital to the Partnership, subject to any restrictions contained in the covenants of our debt agreements.

On a consolidated basis, our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing or repaying our indebtedness, meeting our collateral requirements and to pay dividends declared by our board of directors will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, please see “Recent Developments – Response to Current Market Conditions”.

We are entitled to the entirety of distributions made by the Partnership on its equity interests, other than those made to the TRP Preferred Unitholders. The actual amount we declare as distributions depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems relevant.

The Partnership’s debt agreements and obligations to its Preferred Unitholders may restrict or prohibit the payment of distributions if the Partnership is in default, threat of default or arrears. If the Partnership cannot make distributions to us, we may be limited in our ability, or unable, to pay dividends on our common stock. In addition, so long as any shares of our Preferred Units are outstanding, certain common stock distribution limitations exist.

On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRC Revolver, the TRP Revolver, and the Partnership’s Securitization Facility and access to debt and equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

Short-term Liquidity

Our short-term liquidity on a consolidated basis as of November 2, 2020, was:

	November 2, 2020
	(In millions)
	TRC			TRP			Consolidated Total
Cash on hand	$	19.3		$	252.3		$	271.6
Total availability under the TRC Revolver		670.0			—			670.0
Total availability under the TRP Revolver		—			2,200.0			2,200.0
Total availability under the Partnership's Securitization Facility		—			250.0			250.0
		689.3			2,702.3			3,391.6

Less: Outstanding borrowings under the TRC Revolver		(485.0	)		—			(485.0	)
Outstanding borrowings under the TRP Revolver		—			(600.0	)		(600.0	)
Outstanding borrowings under the Partnership's Securitization Facility		—			(250.0	)		(250.0	)
Outstanding letters of credit under the TRP Revolver		—			(37.5	)		(37.5	)
Total liquidity	$	204.3		$	1,814.8		$	2,019.1

Other potential capital resources associated with our existing arrangements include:

•

Our right to request an additional $200 million in commitment increases under the TRC Revolver, subject to the terms therein. The TRC Revolver matures on June 29, 2023.

•

Our right to request an additional $500 million in commitment increases under the TRP Revolver, subject to the terms therein. The TRP Revolver matures on June 29, 2023.

In the second quarter of 2020, we amended the Partnership’s Securitization Facility to decrease the facility size from $400.0 million to $250.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2021.

A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. These letters of credit reflect our non-investment grade status, as assigned to us by Moody’s and S&P. They also reflect certain counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels and valuation, which we closely manage; (iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Partnership’s Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth capital projects.

Working capital as of September 30, 2020 increased $277.8 million compared to December 31, 2019. The increase was primarily attributable to higher inventory balances, lower current maturities of debt from payments on our Securitization Facility and lower payables for capital expenditures and product purchases, partially offset by lower receivables resulting from lower commodity prices.

Based on our anticipated levels of operations and absent any disruptive events, we believe that our internally generated cash flow, borrowings available under the TRC Revolver, the TRP Revolver and the Partnership’s Securitization Facility and proceeds from debt and equity offerings, as well as joint ventures and/or asset sales, should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and quarterly cash dividends for at least the next twelve months.

Long-term Financing

In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”), which committed a maximum of approximately $960 million of capital to the DevCo JVs.

As of September 30, 2020, total contributions from Stonepeak to the DevCo JVs were $911.4 million. As of September 30, 2020, total contributions from funds managed by Blackstone Energy Partners (“Blackstone”) to the Grand Prix Joint Venture were $341.3 million. These contributions from Stonepeak and Blackstone are included in noncontrolling interests.

From time to time, we issue long-term debt securities, which we refer to as senior notes. Our senior notes issued to date, generally have similar terms other than interest rates, maturity dates and redemption premiums. As of September 30, 2020 and December 31, 2019, the aggregate principal amount outstanding of our senior notes and other various long-term debt obligations, including unamortized premiums, debt issuance costs and non-current liabilities of finance leases, was $7,652.2 million and $7,440.2 million, respectively.

We consolidate the debt of the Partnership with that of our own; however, we do not have the contractual obligation to make interest or principal payments with respect to the debt of the Partnership. Our debt obligations do not restrict the ability of the Partnership to make distributions to us. Our Credit Agreement has restrictions and covenants that may limit our ability to pay dividends to our stockholders. See Note 5 – Debt Obligations for more information regarding our debt obligations.

The majority of our debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRC Revolver, the TRP Revolver and the Partnership’s Securitization Facility. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of September 30, 2020, we did not have any interest rate hedges.

In 2019, we closed on the sale of a 45% interest in Targa Badlands to GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “GSO”) for $1.6 billion in cash. Growth capital of Targa Badlands after the sale is funded on a pro rata ownership basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to GSO and Targa, with GSO having a priority right on such MQDs. Additionally, GSO’s capital contributions would have a liquidation preference upon a sale of Targa Badlands. Targa Badlands is a discrete entity and the assets and credit of Targa Badlands are not available to satisfy the debts and other obligations of Targa or its other subsidiaries. As of September 30, 2020, the contributions from GSO were $74.0 million.

In a response to current market conditions as described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments,” in the first quarter of 2020, our Board of Directors approved a reduction in the Company’s quarterly common dividend to $0.10 per share for the quarter ended March 31, 2020 from $0.91 per share in the previous quarter. This reduction provided for approximately $755 million of additional annual direct cash flow, resulting in significant free cash flow available to reduce debt.

On November 2, 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023.

In the third quarter of 2020, the Partnership issued $1.0 billion of 4⅞% Senior Notes due 2031, resulting in net proceeds of $991.0 million. A portion of the net proceeds from the issuance were used to fund the Tender Offer and redemption payments for the 6¾% Notes, with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facility.

Additionally, during the first half of 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, paying $239.8 million plus accrued interest to repurchase $303.3 million of the notes. The repurchases resulted in a $61.1 million net gain, which included the write-off of $2.4 million in related debt issuance costs. We or the Partnership may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 5 - Debt Obligations to our consolidated financial statements. For information about our interest rate risk, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

Compliance with Debt Covenants

As of September 30, 2020, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

Cash Flow

Cash Flows from Operating Activities

Nine Months Ended September 30,
2020		2019		2020 vs. 2019
(In millions)
$	1,095.7	$	919.0	$	176.7

The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs, natural gas and other petroleum commodities, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude oil, (iii) changes in payables and accruals related to major growth capital projects, and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.

Net cash provided by operations increased in 2020 compared to 2019 primarily due to higher operating margin and an increase in cash distributions received from unconsolidated affiliates, partially offset by an increase in interest payments as a result of higher average borrowings.

Cash Flows from Investing Activities

Nine Months Ended September 30,
2020			2019			2020 vs. 2019
(In millions)
$	(654.0	)	$	(2,620.0	)	$	1,966.0

Cash used in investing activities decreased in 2020 compared to 2019, primarily due to lower outlays for property, plant and equipment of $1,631.0 million, resulting from the completion of construction of Grand Prix, Train 6, Train 7, and additional processing plants and associated infrastructure in the Permian Basin in 2019 and early 2020. The change is also attributable to proceeds of $134.1 million received from the sale of our Delaware crude system and a $241.5 million decrease in our contributions to unconsolidated affiliates primarily due to the completion of GCX Pipeline in 2019.

Cash Flows from Financing Activities

	Nine Months Ended September 30,
	2020			2019
	(In millions)
Source of Financing Activities, net
Dividends and distributions	$	(345.1	)	$	(726.7	)
Contributions from (distributions to) noncontrolling interests		(277.3	)		419.9
Debt, including financing costs		130.1			812.9
Sale of ownership interests in subsidiaries		—			1,619.7
Payment of contingent consideration		—			(317.1	)
Other		(5.5	)		(13.5	)
Net cash provided by financing activities	$	(497.8	)	$	1,795.2

In 2020, net cash used in financing activities is primarily due to payments of dividends to our common and Series A preferred shareholders, and net distributions to noncontrolling interests, partially offset by a net increase of debt outstanding. Our distributions to noncontrolling interests are higher than our contributions from noncontrolling interests in 2020, primarily due to completion of major growth capital projects in 2019. Our debt outstanding increased primarily due to the issuance of the 4⅞% Senior Notes due 2031 that resulted in cash proceeds of $991.0 million, partially offset by repurchasing a portion of our outstanding senior notes through open market purchases and the Tender Offer and redemption payments for the 6¾% Notes for a total of $831.0 million.

In 2019, we realized a net source of cash from financing activities primarily due to the sale of ownership interests in Targa Badlands and Train 7, net increase of debt outstanding and net contributions from noncontrolling interests. The result was partially offset by payments of dividends and distributions, as well as the final contingent consideration payment associated with our 2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin. The issuance of 6½% Senior Notes due 2027 and 6⅞% Senior Notes due January 2029, partially offset by the redemption of 4⅛% Senior Notes due November 2019 contributed to the net increase of debt outstanding. The contributions from noncontrolling interests were primarily from Stonepeak and Blackstone to fund growth capital projects.

Common Stock Dividends

The following table details the dividends on common stock declared and/or paid by us for the nine months ended September 30, 2020:

Three Months Ended	Date Paid or To Be Paid		Total Common Dividends Declared			Amount of Common Dividends Paid or To Be Paid			Accrued Dividends (1)			Dividends Declared per Share of Common Stock
(In millions, except per share amounts)

September 30, 2020	November 16, 2020	$		23.8	$		23.3	$		0.5	$		0.10000
June 30, 2020	August 17, 2020			23.7			23.3			0.4			0.10000
March 31, 2020	May 15, 2020			23.7			23.3			0.4			0.10000
December 31, 2019	February 18, 2020			216.0			212.0			4.0			0.91000

(1)	Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.

Preferred Stock Dividends

Our Series A Preferred has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of each fiscal quarter.

Cash dividends of $68.8 million were paid to holders of the Series A Preferred during the nine months ended September 30, 2020. As of September 30, 2020, cash dividends accrued for our Series A Preferred were $22.9 million, which will be paid on November 13, 2020.

Capital Expenditures

The following table details cash outlays for capital projects for the nine months ended September 30, 2020 and 2019:

	Nine Months Ended September 30,
	2020			2019
	(In millions)
Capital expenditures:
Growth (1)	$	542.6		$	2,203.4
Maintenance (2)		67.7			101.5
Gross capital expenditures		610.3			2,304.9

Transfers from materials and supplies inventory to property, plant and equipment		(1.9	)		(21.7	)
Change in capital project payables and accruals, net		194.7			150.9
Cash outlays for capital projects	$	803.1		$	2,434.1

(1)

Growth capital expenditures, net of contributions from noncontrolling interests, were $518.0 million and $1,870.8 million for the nine months ended September 30, 2020 and 2019. Net contributions to investments in unconsolidated affiliates were $0.5 million and $75.4 million for the nine months ended September 30, 2020 and 2019.

(2)

Maintenance capital expenditures, net of contributions from noncontrolling interests, were $66.1 million and $95.5 million for the nine months ended September 30, 2020 and 2019.

We currently estimate that in 2020 we will invest approximately $700 million in growth capital expenditures, net of noncontrolling interests, and net contributions to investments in unconsolidated affiliates for announced projects. We expect that 2020 maintenance capital expenditures, net of noncontrolling interests, will be approximately $110 million.

Total growth capital expenditures were lower for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019, primarily due to lower spending on growth capital investments, as a significant portion of our major projects began full service in 2019, including Grand Prix, Train 6 and additional processing plants and associated infrastructure in the Permian

Basin. Total maintenance capital expenditures were lower for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019, primarily due to timing of maintenance projects.

Off-Balance Sheet Arrangements

As of September 30, 2020, there were $44.9 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our customers.

Risk Management

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all our commodity derivatives with major financial institutions or major energy companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, and transportation basis risk through 2025. Market conditions may also impact our ability to enter into future commodity derivative contracts.

Commodity Price Risk

A portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of commodities as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of September 30, 2020, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation segment by entering into derivative instruments. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.

When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The fair value of our natural gas and NGL hedges are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.

A majority of these commodity price hedges are documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in commodity prices relative to the fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing the Partnership’s senior secured indebtedness that ranks equal in right of payment with liens granted in favor of the Partnership’s senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.

We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas, NGL or crude oil prices. Unlike bilateral hedges, we are not subject to counterparty credit risks when using futures on futures exchanges.

These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls).

To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. The sensitivity analysis measures the change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does not reflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement impact on the fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a corresponding gain or loss on the hedged item under hedge accounting. The fair values of our derivative instruments are also influenced by changes in market volatility for option contracts and the discount rates used to determine the present values.

The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of September 30, 2020:

	Fair Value			Result of 10% Price Decrease		Result of 10% Price Increase
Natural gas	$	7.8		$	49.7	$	(33.6	)
NGLs		(55.1	)		11.0		(121.2	)
Crude oil		31.7			45.4		18.0
Total	$	(15.6	)	$	106.1	$	(136.8	)

The table above contains all derivative instruments outstanding as of the stated date for the purpose of hedging commodity price risk, which we are exposed to due to our equity volumes and future commodity purchases and sales, as well as basis differentials related to our gas transportation arrangements.

Our operating revenues increased (decreased) by $109.2 million and $(61.8) million during the three months ended September 30, 2020 and 2019 and $337.3 million and $(7.7) million during the nine months ended September 30, 2020 and 2019, as a result of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in other comprehensive income until the underlying hedged transactions settle. We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.

The estimated fair value of our risk management position has moved from a net liability position of $6.1 million at December 31, 2019 to a net liability position of $15.6 million at September 30, 2020. The fixed prices we currently expect to receive on derivative contracts are below the aggregate forward prices for commodities related to those contracts, creating this net liability position.

Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRC Revolver, the TRP Revolver and the Securitization Facility. Additionally, on and after November 1, 2020, distributions on the Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus 7.71%. As of September 30, 2020, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRC Revolver, the TRP Revolver and the Securitization Facility, and distributions owed on the Preferred Units, will also increase. As of September 30, 2020, the Partnership had $350.0 million in outstanding variable rate borrowings under the TRP Revolver and the Securitization Facility, and we had outstanding variable rate borrowings of $435.0 million under the TRC Revolver. A hypothetical change of 100 basis points in the rates of our variable interest rate debt and the Partnership’s Preferred Units accumulating at an annual floating rate would impact the Partnership’s annual interest expense by $3.5 million and Preferred Unit distributions by $1.3 million and our consolidated annual interest expense by $7.9 million based on our September 30, 2020 debt balances.

Counterparty Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the International Swap Dealers Association agreements with our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by $67.0 million as of September 30, 2020. The range of losses attributable to our individual counterparties as of September 30, 2020 would be between $1.7 million and $16.9 million, depending on the counterparty in default.

Customer Credit Risk

We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring credit enhancements when necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.

We have an active credit management process, which is focused on controlling loss exposure due to bankruptcies or other liquidity issues of counterparties. Our allowance for doubtful accounts was $0.1 million and $0.0 million as of September 30, 2020 and December 31, 2019. Changes in the allowance for doubtful accounts were not material for the three and nine months ended September 30, 2020.

No customer comprised 10% or greater than our consolidated revenues during the three months ended September 30, 2020. During the nine months ended September 30, 2019, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 10% of our consolidated revenues.

During the three and nine months ended September 30, 2019, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 11% and 12% of our consolidated revenues.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of September 30, 2020, the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting that occurred during the quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, during our most recent fiscal quarter.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

On December 26, 2018, Vitol Americas Corp. (“Vitol”) filed a lawsuit in the 80^th District Court of Harris County, Texas against Targa Channelview LLC, a subsidiary of the Company (“Targa Channelview”), seeking recovery of $129.0 million in payments made to Targa Channelview, additional monetary damages, attorneys’ fees and costs. Vitol alleges that Targa Channelview breached an agreement, dated December 27, 2015, for crude oil and condensate between Targa Channelview and Noble Americas Corp. (the “Splitter Agreement”), which provided for Targa Channelview to construct a crude oil and condensate splitter (the “Splitter”) adjacent to a barge dock owned by Targa Channelview to provide services contemplated by the Splitter Agreement. In January 2018, Vitol acquired Noble Americas Corp. and on December 23, 2018, Vitol voluntarily elected to terminate the Splitter Agreement claiming that Targa Channelview failed to timely achieve start-up of the Splitter. Vitol’s lawsuit also alleges Targa Channelview made a series of misrepresentations about the capability of the barge dock that would service crude oil and condensate volumes to be processed by the Splitter and Splitter products. Vitol seeks return of $129.0 million in payments made to Targa Channelview prior to the start-up of the Splitter, as well as additional damages. On the same date that Vitol filed its lawsuit, Targa Channelview filed a lawsuit against Vitol seeking a judicial determination that Vitol’s sole and exclusive remedy was Vitol’s voluntarily termination of the Splitter Agreement and, as a result, Vitol was not entitled to the return of any prior payments under the Splitter Agreement or other damages as alleged. Targa also seeks recovery of its attorneys’ fees and costs in the lawsuit.

On October 15, 2020, the District Court awarded Vitol $129 million (plus interest) following a bench trial. In addition, the District Court awarded Vitol $10.5 million in damages for losses and demurrage on crude oil that Vitol purchased for start-up efforts. The Company plans to contest the award and is preparing an appeal to the Court of Appeals in Houston, Texas.

Additional information required for this item is provided in Note 13 – Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.

Item 1A. Risk Factors.

For an in-depth discussion of our risk factors, see “Part I—Item 1A. Risk Factors” of our Annual Report in addition to the risk factors discussed below. All of these risks and uncertainties, including those risks discussed below, could adversely affect our business, financial condition and/or results of operations.

Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, and decreases in these prices could adversely affect our results of operations and financial condition.

Our operations can be affected by the level of natural gas, NGL and crude oil prices and the relationship between these prices. The prices of crude oil, natural gas and NGLs have been volatile, and we expect this volatility to continue. Our future cash flows may be materially adversely affected if we experience significant, prolonged price deterioration. The markets and prices for crude oil, natural gas and NGLs depend upon factors beyond our control. These factors include supply and demand for these commodities, which fluctuates with changes in market and economic conditions, and other factors, including:

•

the impact of seasonality and weather;

•

general economic conditions and economic conditions impacting our primary markets;

•

the economic conditions of our customers;

•

the level of domestic crude oil and natural gas production and consumption;

•

the availability of imported natural gas, liquefied natural gas, NGLs and crude oil;

•

actions taken by major foreign oil and gas producing nations;

•

the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs;

•

the availability of domestic storage for crude oil;

•

the availability and marketing of competitive fuels and/or feedstocks;

•

the impact of energy conservation efforts;

•

stockholder activism and activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil and natural gas; and

•

the extent of governmental regulation and taxation, including those related to the prorationing of oil and gas production.

Additionally, we have been and may continue to be adversely affected by the continued impact on global demand for commodities related to the COVID-19 pandemic. The COVID-19 pandemic has reduced economic activity and the related demand for energy commodities. These effects, combined with a period of increased production from major oil producing nations and decreasing

availability of crude oil storage has contributed to lower commodity prices compared to historical levels in 2020 to date and is expected to continue to impact demand over the short-to-medium-term.

Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. Under these arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index-based price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and cash flows increase or decrease, whichever is applicable, as the prices of natural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”

As further discussed in Note 4 – Property, Plant and Equipment and Intangible Assets and Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations, the global decline in commodity prices due to both demand and supply disruptions was a significant contributing factor to the non-cash impairment charges totaling $2,442.8 million for the nine months ended September 30, 2020.

The widespread outbreak of the COVID-19 pandemic or any other public health crisis that impacts the global demand for commodities may have material adverse effects on our business, financial position, results of operations and/or cash flows.

We face risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of our control and could significantly disrupt our operations and adversely affect our financial condition. For example, the recent global spread of COVID-19 has caused business disruption, including disruption to the oil and gas industry. The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets. The full extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for crude oil, natural gas and natural gas liquids (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations.

The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will also depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while we expect this matter will continue to disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.

Refer to Note 4 – Property, Plant and Equipment and Intangible Assets and in Management's Discussion and Analysis of Financial Condition and Results of Operations, for further discussion.

Our future tax liability may be greater than expected if our net operating loss (“NOL”) carryforwards are limited, we do not generate expected deductions, or tax authorities challenge certain of our tax positions.

As of December 31, 2019, we have U.S. federal NOL carryforwards of $5.1 billion, some of which expire between 2036 to 2037 while others have no expiration date. We expect to be able to utilize these NOL carryforwards and generate deductions to offset our future taxable income. This expectation is based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital, and the current expectation that our NOL carryforwards will not become subject to future limitations under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”).

Section 382 generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of our stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change were to occur, utilization of our NOLs carryforwards would be subject to an annual limitation under Section 382, determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section 382, subject to certain adjustments.

While we expect to be able to utilize our NOL carryforwards and generate deductions to offset our future taxable income, in the event that deductions are not generated as expected, one or more of our tax positions are successfully challenged by the IRS (in a tax audit or otherwise), or our NOL carryforwards are subject to future limitations under Section 382, our future tax liability may be greater than expected.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Recent Sales of Unregistered Securities.

None.

Repurchase of Equity by Targa Resources Corp. or Affiliated Purchasers.

Period	Total number of shares withheld (1)			Average price per share		Total number of shares purchased as part of publicly announced plans		Maximum approximate dollar value of shares that may yet be purchased under the plan (2)
July 1, 2020 - July 31, 2020		12,088	$		19.01		—		—
August 1, 2020 - August 31, 2020		99,356	$		18.31		—		—
September 1, 2020 - September 30, 2020		—	$		—		—		—

(1)	Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers, directors and key employees that arose upon the lapse of restrictions on restricted stock.

(2)

In October 2020, our Board of Directors approved the Share Repurchase Program for the repurchase of up to $500 million of our outstanding common stock. As of November 2, 2020, we have repurchased 4,505,507 shares at a weighted average price of $16.33 for a total net cost of $73.6 million. There is approximately $426 million remaining under the Share Repurchase Program. We may discontinue the Share Repurchase Program at any time and are not obligated to repurchase any specific dollar amount or number of shares.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Number		Description

3.1		Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).

3.2		Certificate of Designations of Series A Preferred Stock of Targa Resources Corp., filed with the Secretary of State of the State of Delaware on March 16, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K/A filed March 17, 2016 (File No. 001-34991)).

3.3		Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.2 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).

3.4		First Amendment to the Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed January 15, 2016 (File No. 001-34991)).

3.5		Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).

3.6		Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).

3.7		Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP, effective December 1, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 21, 2016 (File No. 001-33303)).

3.8		Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 12, 2017 (File No. 001-33303)).

3.9		Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).

4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).

4.2		Indenture dated as of August 18, 2020 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed August 21, 2020).

4.3		Registration Rights Agreement dated as of August 18, 2020 among the Issuers, the Guarantors and Wells Fargo Securities, LLC, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed August 21, 2020).

10.1		Purchase Agreement dated as of August 11, 2020, among the Issuers, the Guarantors and Wells Fargo Securities, LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed August 17, 2020).

10.2*		Supplemental Indenture dated September 17, 2020 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.3*		Supplemental Indenture dated September 17, 2020 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.4*		Supplemental Indenture dated September 17, 2020 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.5*		Supplemental Indenture dated September 17, 2020 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

Number		Description

10.6*		Supplemental Indenture dated September 17, 2020 to Indenture dated October 17, 2017, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.7*		Supplemental Indenture dated September 17, 2020 to Indenture dated April 12, 2018, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.8*		Supplemental Indenture dated September 17, 2020 to Indenture dated January 17, 2019, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.9*		Supplemental Indenture dated September 17, 2020 to Indenture dated November 27, 2019, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.10*		Supplemental Indenture dated September 17, 2020 to Indenture dated August 18, 2020, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

31.1*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		Inline XBRL Instance Document – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document

101.SCH*		Inline XBRL Taxonomy Extension Schema Document

101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document

104*		The cover page from this Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, formatted in Inline XBRL (included with Exhibit 101 attachments).

*	Filed herewith

**	Furnished herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Targa Resources Corp.
	(Registrant)

Date: November 5, 2020	By:	/s/ Jennifer R. Kneale
		Jennifer R. Kneale
		Chief Financial Officer
		(Principal Financial Officer)

Exhibit 10.2

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”), dated as of September 17, 2020, among the party identified under the caption “Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 25, 2012 providing for the issuance of 5 1/4% Senior Notes due 2023 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including but not limited to Article 10 thereof.

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary and the Issuers.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY

TARGA GULF COAST NGL PIPELINE LLC

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By: /s/ Alejandro Hoyos

Authorized Signatory

Signature Page to Supplemental Indenture (October 25, 2012 Indenture)

Exhibit 10.3

SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of May 14, 2013 providing for the issuance of 4 1/4% Senior Notes due 2023 (the “Notes”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY

TARGA GULF COAST NGL PIPELINE LLC

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By: /s/ Alejandro Hoyos

Authorized Signatory

Signature Page to Supplemental Indenture (May 14, 2013 Indenture)

Exhibit 10.4

SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of September 14, 2015 providing for the issuance of 6 3/4% Senior Notes due 2024 (the “Notes”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages to follow

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY

Targa Gulf Coast NGL Pipeline LLC

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By: /s/ Alejandro Hoyos

Authorized Signatory

Signature Page to Supplemental Indenture (September 14, 2015 Indenture)

Exhibit 10.5

SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 6, 2016 providing for the issuance of 5 1/8% Senior Notes due 2025 and 5 3/8% Senior Notes due 2027 (collectively, the “Notes”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY

targa GULF COAST NGL PIPELINE LLC

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By: /s/ Alejandro Hoyos

Authorized Signatory

Signature Page to Supplemental Indenture (October 6, 2016 Indenture)

Exhibit 10.6

SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 17, 2017 providing for the issuance of 5% Senior Notes due 2028 (the “Notes”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY

Targa GULF COAST NGL PIPELINE LLC

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (October 17, 2017 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (October 17, 2017 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By: /s/ Alejandro Hoyos

Authorized Signatory

Signature Page to Supplemental Indenture (October 17, 2017 Indenture)

Exhibit 10.7

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”), dated as of September 17, 2020 among the party identified under the caption “Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of April 12, 2018 providing for the issuance of 5 7/8% Senior Notes due 2026 (the “Notes”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY

targa GULF COAST NGL PIPELINE LLC

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (April 12, 2018 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (April 12, 2018 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By: /s/ Alejandro Hoyos

Authorized Signatory

Signature Page to Supplemental Indenture (April 12, 2018 Indenture)

Exhibit 10.8

SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of January 17, 2019 providing for the issuance of 6 1/2% Senior Notes due 2027 and 6 7/8% Senior Notes due 2029 (collectively, the “Notes”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY

targa GULF COAST NGL PIPELINE LLC

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (January 17, 2019 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (January 17, 2019 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By: /s/ Alejandro Hoyos

Authorized Signatory

Signature Page to Supplemental Indenture (January 17, 2019 Indenture)

Exhibit 10.9

SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of November 27, 2019 providing for the issuance of 5 1/2% Senior Notes due 2030 (the “Notes”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY

Targa GULF COAST NGL PIPELINE LLC

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (November 27, 2019 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (November 27, 2019 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By: /s/ Alejandro Hoyos

Authorized Signatory

Signature Page to Supplemental Indenture (November 27, 2019 Indenture)

Exhibit 10.10

SUPPLEMENTAL INDENTURE

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of August 18, 2020 providing for the issuance of 4 7/8% Senior Notes due 2031 (the “Notes”);

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY

Targa GULF COAST NGL PIPELINE LLC

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (August 18, 2020 Indenture)

ISSUERS

TARGA RESOURCES PARTNERS LP

By: Targa Resources GP LLC, its general partner

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

TARGA RESOURCES PARTNERS FINANCE CORPORATION

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title:

Chief Financial Officer

Signature Page to Supplemental Indenture (August 18, 2020 Indenture)

TRUSTEE

U.S. BANK NATIONAL ASSOCIATION,

as Trustee

By: /s/ Alejandro Hoyos

Authorized Signatory

Signature Page to Supplemental Indenture (August 18, 2020 Indenture)

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Matthew J. Meloy, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Targa Resources Corp. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2020

By: /s/ Matthew J. Meloy

Name: Matthew J. Meloy

Title: Chief Executive Officer of Targa Resources Corp.

(Principal Executive Officer)

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Jennifer R. Kneale, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Targa Resources Corp. (the “registrant”);

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2020

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title: Chief Financial Officer of Targa Resources Corp.

(Principal Financial Officer)

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Targa Resources Corp., for the three months ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Matthew J. Meloy, as Chief Executive Officer of Targa Resources Corp., hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Targa Resources Corp.

By: /s/ Matthew J. Meloy

Name: Matthew J. Meloy

Title: Chief Executive Officer of Targa Resources Corp.

Date: November 5, 2020

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Targa and will be retained by Targa and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Targa Resources Corp. for the three months ended September 30, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Jennifer R. Kneale, as Chief Financial Officer of Targa Resources Corp., hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to her knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Targa Resources Corp.

By: /s/ Jennifer R. Kneale

Name: Jennifer R. Kneale

Title: Chief Financial Officer of

Targa Resources Corp.

Date: November 5, 2020