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 ~~June~~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: 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware		65-1295427
(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
9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units	NGLS/PA	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 ~~July~~November 312, 2020, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.

TABLE OF CONTENTS PART I—FINANCIAL INFORMATION
Item 1. Financial Statements		4
Consolidated Balance Sheets as of June 30, 2020 and December 31, 2019		4
Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019		4
Consolidated Statements of Operations for the three and six months ended June 30, 2020 and 2019		5
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 six months ended June 30, 2020 and 2019		6
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 for the three and six months ended June 30, 2020 and 2019		7
Consolidated Statements of Changes in Owners' Equity for the three and nine months ended September 30, 2020 and 2019		7
Consolidated Statements of Cash Flows for the six months ended June 30, 2020 and 2019		9
Consolidated Statements of Cash Flows for the nine months ended September 30, 2020 and 2019		9
Notes to Consolidated Financial Statements		10
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		2526
Item 3. Quantitative and Qualitative Disclosures About Market Risk		4244
Item 4. Controls and Procedures		4446
PART II—OTHER INFORMATION
Item 1. Legal Proceedings		4547
Item 1A. Risk Factors		4547
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		4648
Item 3. Defaults Upon Senior Securities		4648
Item 4. Mine Safety Disclosures		4649
Item 5. Other Information		4649
Item 6. Exhibits		4750
SIGNATURES
Signatures		4852

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” “TRP” or the “Partnership”) 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 our debt obligations and demand for our 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 ~~has~~ reduced economic activity and the related demand for energy commodities, which contributed to aweakened ~~sharp~~commodity ~~drop~~prices incompared ~~prices~~to inhistorical levels and price volatility during the ~~first~~nine ~~half~~months ofended 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 PARTNERS LP

CONSOLIDATED BALANCE SHEETS

					June 30, 2020			December 31, 2019
					September 30, 2020			December 31, 2019
					(Unaudited)
					(In millions)
ASSETS
Current assets:
Cash and cash equivalents					$	~~173~~248.60		$	291.1
Trade receivables, net of allowances of $0.1 and $0.0 million at June 30, 2020 and December 31, 2019						547.3			855.2
Trade receivables, net of allowances of $0.1 and $0.0 million at September 30, 2020 and December 31, 2019						609.8			855.2
Inventories						~~219~~261.37			161.5
Assets from risk management activities						~~122~~88.09			103.3
Deposits						95110.21			35.4
Held for sale assets						—62.2			137.7
Other current assets						3118.57			18.8
Total current assets						1,~~188~~399.94			1,603.0
Property, plant and equipment, net						12,~~417~~292.59			14,549.0
Intangible assets, net						1,~~452~~417.86			1,735.0
Long-term assets from risk management activities						4379.35			35.5
Investments in unconsolidated affiliates						~~724~~718.38			738.7
Other long-term assets						8986.54			83.3
Total assets					$	15,~~916~~994.36		$	18,744.5
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable					$	~~608~~617.72		$	~~977~~952.89
Accrued liabilities						7540.03			8850.7
Interest payable						144.3			125.4
Dividends payable						96.5			92.7
Distributions payable to noncontrolling interests						89.9			91.8
Interest payable						95.3			125.4
Accounts payable to Targa Resources Corp.						190.4			193.8
Accrued taxes						85.1			62.0
Liabilities from risk management activities						80.5			104.1
Accounts payable to Targa Resources Corp.						195.9			193.8
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,~~450~~516.79			1,970.2
Long-term debt						7,~~144~~217.62			7,005.2
Long-term liabilities from risk management activities						5262.9			40.8
Deferred income taxes, net						23.0			23.0
Other long-term liabilities						~~266~~261.23			260.0
Contingencies (see Note 11)
Owners' equity:
Series A preferred limited partners	Issued		Outstanding			120.6			120.6
June 30, 2020		5,000,000		5,000,000
September 30, 2020		5,000,000		5,000,000
December 31, 2019		5,000,000		5,000,000
Common limited partners	Issued		Outstanding			2,~~865~~921.23			5,022.7
June 30, 2020		275,168,410		275,168,410
September 30, 2020		275,168,410		275,168,410
December 31, 2019		275,168,410		275,168,410
General partner	Issued		Outstanding			~~733~~735.80			778.0
June 30, 2020		5,629,136		5,629,136
September 30, 2020		5,629,136		5,629,136
December 31, 2019		5,629,136		5,629,136
Accumulated other comprehensive income (loss)						28(119.45	)		122.5
						3,748.0			6,043.8
						3,657.4			6,043.8
Noncontrolling interests						3,~~230~~255.9			3,401.5
Total owners' equity						6,~~978~~913.93			9,445.3
Total liabilities and owners' equity					$	15,~~916~~994.36		$	18,744.5
See notes to consolidated financial statements.

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
	(Unaudited)
	(In millions)
Revenues:
Sales of commodities	$	1,~~280~~840.68		$	1,~~684~~594.2		$	34,~~060~~900.28		$	35,~~660~~254.78
Fees from midstream services		~~242~~274.93			~~311~~308.13			~~512~~786.27			~~634~~942.04
Total revenues		12,~~523~~115.51			1,~~995~~902.35			35,~~572~~687.45			46,~~294~~197.72
Costs and expenses:
Product purchases		~~860~~1,303.62			1,~~361~~328.61			23,~~043~~346.68			34,~~087~~415.67
Operating expenses		~~183~~181.49			~~210~~200.2			~~383~~565.31			~~400~~600.57
Depreciation and amortization expense		~~204~~203.57			~~237~~244.23			~~443~~647.63			~~474~~718.69
General and administrative expense		5856.63			6965.36			~~115~~171.57			~~146~~212.73
Impairment of long-lived assets		—			—			2,442.8			—
Other operating (income) expense		072.42			(018.24	)		173.68			321.37
Income (loss) from operations		~~216~~297.08			~~117~~45.29			(1,~~858~~560.0	)		~~182~~227.09
Other income (expense):
Interest expense, net		(94.39	)		(6984.52	)		(~~188~~283.10	)		(~~144~~229.92	)
Equity earnings (loss)		1418.96			310.20			3554.51			515.9
Gain (loss) from financing activities		21(13.87	)		—			6147.14			(1.4	)
Change in contingent considerations		—			0.8			—			(8.9	)
Gain (loss) from sale of equity-method investment		—			65.8			—			65.8
Other, net		0.8			—			0.8			—
Change in contingent considerations		—			—			—			(8.8	)
Income (loss) before income taxes		159.2			51.7			(1,948.7	)		32.7
Other, net		1.3			—			2.0			—
Income (loss) before income taxes		209.1			37.5			(1,739.5	)		70.2
Income tax (expense) benefit		—			—			—			—
Net income (loss)		~~159~~209.21			5137.75			(1,~~948~~739.75	)		3270.72
Less: Net income (loss) attributable to noncontrolling interests		93100.31			5676.36			8108.01			67144.73
Net income (loss) attributable to Targa Resources Partners LP	$	65109.90		$	(439.61	)	$	(1,~~956~~847.76	)	$	(3574.01	)
Net income attributable to preferred limited partners	$	2.8		$	2.8		$	58.64		$	58.64
Net income (loss) attributable to general partner		1.2.1			(0.19	)		(3937.42	)		(01.87	)
Net income (loss) attributable to common limited partners		61104.91			(741.30	)		(1,~~922~~818.98	)		(3980.8	)
Net income (loss) attributable to Targa Resources Partners LP	$	65109.90		$	(439.61	)	$	(1,~~956~~847.76	)	$	(3574.01	)

See notes to consolidated financial statements.

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
	(Unaudited)
	(In millions)
Net income (loss)	$	~~159~~209.21		$	5137.75		$	(1,~~948~~739.75	)	$	3270.72
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value		(~~132~~128.97	)		88118.42			26(102.26	)		49167.68
Settlements reclassified to revenues		(6019.2	)		(4341.35	)		(~~120~~139.34	)		(64106.61	)
Other comprehensive income (loss)		(~~193~~147.19	)		4576.17			(94242.10	)		~~(15~~61.07	)
Comprehensive income (loss)		~~(33~~61.92	)		96114.82			(21,~~042~~981.85	)		17131.79
Less: Comprehensive income (loss) attributable to noncontrolling interests		93100.31			5676.36			8108.01			67144.73
Comprehensive income (loss) attributable to Targa Resources Partners LP	$	(~~127~~38.29	)	$	4037.56		$	(2,~~050~~089.86	)	$	(5012.04	)

See notes to consolidated financial statements.

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY

																Accumulated
	Limited					Limited					General					Other			Non-
	Partner					Partner					Partner					Comprehensive			controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Interests			Total
	(Unaudited)
	(In millions, except units in thousands)
Balance, March 31, 2020		5,000	$	120.6			275,168	$	2,803.6			5,629	$	732.6		$	221.5		$	3,225.6		$	7,103.9
Contributions from Targa Resources Corp.		—		—			—		49.0			—		1.0			—			—			50.0
Distributions to noncontrolling interests		—		—			—		—			—		—			—			(103.1	)		(103.1	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			15.1			15.1
Other comprehensive income (loss)		—		—			—		—			—		—			(193.1	)		—			(193.1	)
Net income (loss)		—		2.8			—		61.9			—		1.2			—			93.3			159.2
Distributions		—		(2.8	)		—		(49.3	)		—		(1.0	)		—			—			(53.1	)
Balance, June 30, 2020		5,000	$	120.6			275,168	$	2,865.2			5,629	$	733.8		$	28.4		$	3,230.9		$	6,978.9
Contributions from Targa Resources Corp.		—		—			—		—			—		—			—			—			—
Distributions to noncontrolling interests		—		—			—		—			—		—			—			(110.3	)		(110.3	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			7.7			7.7
Non-cash allocation to noncontrolling interests		—		—			—		—			—		—			—			27.5			27.5
Other comprehensive income (loss)		—		—			—		—			—		—			(147.9	)		—			(147.9	)
Net income (loss)		—		2.8			—		104.1			—		2.1			—			100.1			209.1
Distributions		—		(2.8	)		—		(48.0	)		—		(0.9	)		—			—			(51.7	)
Balance, September 30, 2020		5,000	$	120.6			275,168	$	2,921.3			5,629	$	735.0		$	(119.5	)	$	3,255.9		$	6,913.3

																Accumulated
	Limited					Limited					General					Other		Non-
	Partner					Partner					Partner					Comprehensive		controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)		Interests			Total
	(Unaudited)
	(In millions, except units in thousands)
Balance, March 31, 2019		5,000	$	120.6			275,168	$	5,961.0			5,629	$	797.1		$	64.8	$	1,460.4		$	8,403.9
Contributions from Targa Resources Corp.		—		—			—		186.2			—		3.8			—		—			190.0
Sale of ownership interests in subsidiaries		—		—			—		(10.5	)		—		(0.2	)		—		1,619.7			1,609.0
Distributions to noncontrolling interests		—		—			—		—			—		—			—		(66.9	)		(66.9	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—		206.7			206.7
Other comprehensive income (loss)		—		—			—		—			—		—			45.1		—			45.1
Net income (loss)		—		2.8			—		(7.3	)		—		(0.1	)		—		56.3			51.7
Distributions		—		(2.8	)		—		(426.3	)		—		(8.7	)		—		—			(437.8	)
Balance, June 30, 2019		5,000	$	120.6			275,168	$	5,703.1			5,629	$	791.9		$	109.9	$	3,276.2		$	10,001.7
Contributions from Targa Resources Corp.		—		—			—		9.8			—		0.2			—		—			10.0
Sale of ownership interests in subsidiaries		—		—			—		—			—		—			—		—			—
Distributions to noncontrolling interests		—		—			—		—			—		—			—		(87.2	)		(87.2	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—		115.3			115.3
Other comprehensive income (loss)		—		—			—		—			—		—			76.7		—			76.7
Net income (loss)		—		2.8			—		(41.0	)		—		(0.9	)		—		76.6			37.5
Distributions		—		(2.8	)		—		(234.8	)		—		(4.8	)		—		—			(242.4	)
Balance, September 30, 2019		5,000	$	120.6			275,168	$	5,437.1			5,629	$	786.4		$	186.6	$	3,380.9		$	9,911.6

See notes to consolidated financial statements.

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY

																Accumulated
	Limited					Limited					General					Other			Non-
	Partner					Partner					Partner					Comprehensive			controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Interests			Total
	(Unaudited)
	(In millions, except units in thousands)
Balance, December 31, 2019		5,000	$	120.6			275,168	$	5,022.7			5,629	$	778.0		$	122.5		$	3,401.5		$	9,445.3
Contributions from Targa Resources Corp.		—		—			—		49.0			—		1.0			—			—			50.0
Distributions to noncontrolling interests		—		—			—		—			—		—			—			(~~204~~314.35	)		(~~204~~314.35	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			2533.73			2533.73
Other comprehensive income (loss)		—		—			—		—			—		—			(94.1	)		—			(94.1	)
Non-cash allocation to noncontrolling interests		—		—			—		—			—		—			—			27.5			27.5
Net income (loss)		—	5.6				—		(1,922.9	)		—		(39.4	)		—			8.0			(1,948.7	)
Other comprehensive income (loss)		—		—			—		—			—		—			(242.0	)		—			(242.0	)
Distributions		—		(5.6	)		—		(283.6	)		—		(5.8	)		—			—			(295.0	)
Net income (loss)		—	8.4				—		(1,818.8	)		—		(37.2	)		—			108.1			(1,739.5	)
Balance, June 30, 2020		5,000	$	120.6			275,168	$	2,865.2			5,629	$	733.8		$	28.4		$	3,230.9		$	6,978.9
Distributions		—		(8.4	)		—		(331.6	)		—		(6.8	)		—			—			(346.8	)
Balance, September 30, 2020		5,000	$	120.6			275,168	$	2,921.3			5,629	$	735.0		$	(119.5	)	$	3,255.9		$	6,913.3

																Accumulated
	Limited					Limited					General					Other			Non-
	Partner					Partner					Partner					Comprehensive			controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Interests			Total
	(Unaudited)
	(In millions, except units in thousands)
Balance, December 31, 2018		5,000	$	120.6			275,168	$	6,227.2			5,629	$	802.6		$	124.9		$	1,270.8		$	8,546.1
Contributions from Targa Resources Corp.		—		—			—		~~186~~196.20			—		34.80			—			—			~~190~~200.0
Sale of ownership interests in subsidiaries		—		—			—		(10.5	)		—		(0.2	)		—			1,619.7			1,609.0
Distributions to noncontrolling interests		—		—			—		—			—		—			—			(85172.56	)		(85172.56	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			~~403~~518.57			~~403~~518.57
Other comprehensive income (loss)		—		—			—		—			—		—			~~(15~~61.07	)		—			~~(15~~61.07	)
Net income (loss)		—		58.64			—		(3980.8	)		—		(01.87	)		—			67144.73			3270.72
Distributions		—		(58.64	)		—		(~~660~~894.08	)		—		(1318.53	)		—			—			(~~679~~921.15	)
Balance, June 30, 2019		5,000	$	120.6			275,168	$	5,703.1			5,629	$	791.9		$	109.9		$	3,276.2		$	10,001.7
Balance, September 30, 2019		5,000	$	120.6			275,168	$	5,437.1			5,629	$	786.4		$	186.6		$	3,380.9		$	9,911.6

See notes to consolidated financial statements.

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Six Months Ended June 30,
			Nine Months Ended September 30,
		~~2020~~	2020			2019
	~~(Unaudited)~~	(Unaudited)
	~~(In millions)~~	(In millions)
Cash flows from operating activities
Net income (loss)		$	~~(1,948.7~~$	)(1,739.5	)	$	3270.72
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense			~~5.0~~	7.6			4.6.8
Depreciation and amortization expense			~~443.6~~	647.3			~~474~~718.69
Impairment of long-lived assets			~~2,442.8~~	2,442.8			—
Accretion of asset retirement obligations			~~1.7~~	2.6			2.3.7
Equity (earnings) loss of unconsolidated affiliates			~~(35.5~~	)(54.1	)		(515.9	)
Distributions of earnings received from unconsolidated affiliates			~~44.5~~	65.5			1426.40
Risk management activities			~~(125.9~~	)(214.2	)		0100.18
(Gain) loss on sale or disposition of assets			—				3.1
(Gain) loss on sale or disposition of business and assets				58.0			3.6
(Gain) loss from financing activities			(61.1	)			1.4
Write-downs of assets				13.5			17.9
Change in contingent considerations			—				8.9
(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			~~240.1~~	170.0			~~198~~108.20
Inventories			~~(56.7~~	)(115.8	)		(7689.7	)
Accounts payable, accrued liabilities and other liabilities			~~(262.1~~	)(151.3	)		(~~154~~9.15	)
Interest payable			~~18.9~~	(30.1	)		4112.42
Net cash provided by operating activities			~~706.6~~	1,054.9			~~545~~897.04
Cash flows from investing activities
Outlays for property, plant and equipment			~~(615.9~~	)(803.1	)		(12,~~750~~433.58	)
Proceeds from sale of business and assets			~~134.8~~	135.9			2.47
Investments in unconsolidated affiliates			~~(1.4~~	)(2.2	)		(~~194~~243.87	)
Return of capital from unconsolidated affiliates			6.9				0.1
Proceeds from sale of equity-method investment							70.3
Other, net			3.5				(19.1	)
Return of capital from unconsolidated affiliates				10.7			1.1
Net cash used in investing activities			(472.1	)			(1,961.9	)
Other, net				4.7			(16.3	)
Net cash used in investing activities				(654.0	)		(2,619.7	)
Cash flows from financing activities
Debt obligations:
Proceeds from borrowings under credit facility			~~1,240.0~~	1,460.0			12,~~320~~180.0
Repayments of credit facility			~~(800.0~~	)(1,360.0	)		(12,~~830~~050.0	)
Proceeds from borrowings under accounts receivable securitization facility			~~226.4~~	476.4			~~742~~770.90
Repayments of accounts receivable securitization facility			~~(346.4~~	)(596.4	)		(~~724~~804.60	)
Proceeds from issuance of senior notes			—	1,000.0			1,500.0
Redemption of senior notes			~~(239.8~~	)(831.0	)		(749.4	)
Principal payments of finance leases			~~(6.2~~	)(9.3	)		(58.5	)
Costs incurred in connection with financing arrangements			~~(0.5~~	)(9.6	)		(25.1	)
Payment of contingent consideration			—	—			(317.1	)
Sale of ownership interests in subsidiaries			—	—			1,619.7
Contributions from general partner			~~1.0~~	1.0			34.80
Contributions from TRC			~~49.0~~	49.0			~~186~~196.20
Contributions from noncontrolling interests			~~25.7~~	33.3			~~403~~518.57
Distributions to noncontrolling interests			~~(206.2~~	)(310.6	)		(3598.9	)
Distributions to unitholders			~~(295.0~~	)(346.8	)		(~~679~~921.15	)
Net cash provided by (used in) financing activities			~~(352.0~~	)(444.0	)		1,~~409~~813.49
Net change in cash and cash equivalents			~~(117.5~~	)(43.1	)		(791.56	)
Cash and cash equivalents, beginning of period			~~291.1~~	291.1			203.3
Cash and cash equivalents, end of period		$	~~173.6~~$	248.0		$	~~195~~294.89

See notes to consolidated financial statements.

TARGA RESOURCES PARTNERS LP

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 Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TRP,” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.

Our common units are wholly owned by TRC and no longer publicly traded as a result of TRC’s acquisition of our outstanding common units that it and its subsidiaries did not already own in 2016.

The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS/PA.”

Our Operations

We are 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 1415 – Segment Information for certain financial information regarding our business segments.

The employees supporting our operations are employed by Targa. Our consolidated financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services.

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 ~~six~~nine months ended ~~June~~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 ~~six~~nine months ended ~~June~~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

	June 30, 2020			December 31, 2019			Estimated Useful Lives (In Years)
	September 30, 2020			December 31, 2019			Estimated Useful Lives (In Years)
Gathering systems	$	9,~~117~~125.81		$	8,976.8		5 to 20
Processing and fractionation facilities		56,~~666~~131.27			5,137.0		5 to 25
Terminaling and storage facilities		1,~~498~~514.78			1,495.5		5 to 25
Transportation assets		2,~~316~~422.36			2,292.4		10 to 50
Other property, plant and equipment		~~196~~123.27			183.9		3 to 2550
Land		~~159~~160.27			159.7		—
Construction in progress		~~1,304~~697.28			1,576.5		—
Finance lease right-of-use assets		51.03			48.8
Property, plant and equipment		20,~~309~~227.67			19,870.6
Accumulated depreciation, amortization and impairment		(7,~~892~~934.18	)		(5,321.6	)
Property, plant and equipment, net	$	12,~~417~~292.59		$	14,549.0
Intangible assets	$	2,643.5		$	2,643.5		10 to 20
Accumulated amortization and impairment		(1,~~190~~225.79	)		(908.5	)
Intangible assets, net	$	1,~~452~~417.86		$	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 ~~six~~nine months ended ~~June~~September 30, 2020, depreciation expense was $~~169~~168.35 million and $~~370~~538.05 million, respectively. During the three and ~~six~~nine months ended ~~June~~September 30, 2019, depreciation expense was $~~194~~201.34 million and $~~388~~590.71 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 ~~first~~nine ~~half~~months ofended 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 ~~in the first half of 2020~~. 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 ~~quarter~~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		(73108.68	)
Balance at June 30, 2020	$	1,452.8
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

	June 30, 2020			December 31, 2019
	September 30, 2020			December 31, 2019
Current:
Accounts receivable securitization facility, due April 2021 (1)	$	250.0		$	370.0
Finance lease liabilities		11.9			12.2
Current debt obligations		261.9			382.2
Long-term:
Senior secured revolving credit facility, variable rate, due June 2023 (2)		~~440~~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~~—			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 (3)		6.5			6.5
TPL notes, 5⅞% fixed rate, due August 2023 (3)		48.1			48.1
Unamortized premium		0.2			0.3
		7,165.1			7,028.5
		7,245.0			7,028.5
Debt issuance costs, net of amortization		(4348.75	)		(49.1	)
Finance lease liabilities		2320.27			25.8
Long-term debt		7,~~144~~217.62			7,005.2
Total debt obligations	$	7,~~406~~479.51		$	7,387.4
Irrevocable standby letters of credit outstanding (2)	$	5635.83		$	88.2

(1) As of ~~June~~September 30, 2020, we had $250.0 million of qualifying receivables under our $250.0 million accounts receivable securitization facility (“Securitization Facility”), resulting in zero availability. During the second quarter of 2020, we 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.

(2) As of ~~June~~September 30, 2020, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $12,~~703~~064.27 million.

(3)

“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 ~~six~~nine months ended ~~June~~September 30, 2020:

	Range of Interest Rates Incurred	Weighted Average Interest Rate Incurred
TRP Revolver	1.9% - 6.0%	2.53%
Securitization Facility	1.5% - 2.7%	2.10%

Compliance with Debt Covenants

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

13Senior Unsecured Notes Issuance

In August 2020, we 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 our 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 TRP Revolver. See “Debt Extinguishments and Repurchases” for further details of the concurrent tender offer.

Debt Extinguishments and Repurchases

Concurrent with the August 2020 Offering, we 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, we 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

~~During~~The ~~the~~following ~~six~~table ~~months~~summarizes ~~ended June 30, 2020, we repurchased a portion of~~ our ~~outstanding~~ senior ~~notes~~note onrepurchases for the ~~open~~nine ~~market~~months asended ~~follows~~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
	$	303.3	$	(239.8	)	$	63.5		$	(2.4	)	$	61.1
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 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.

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,~~164~~244.98

~~1,006~~714.12

1,~~693~~064.19

45,465.7

Interest on debt obligations (2)

2,~~475~~729.03

~~397~~402.80

~~792~~791.60

~~600~~657.76

~~683~~878.97

9,~~639~~974.91

~~397~~402.80

1,~~798~~505.72

21,~~293~~722.85

56,~~149~~344.64

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

(12) Represents ~~scheduled~~interest ~~future~~expense ~~maturities~~on ofdebt ~~consolidated~~obligations based on both fixed debt ~~obligations~~interest ~~for~~rates ~~the~~and ~~periods~~prevailing ~~indicated~~September 30, 2020 rates for floating debt.

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

On November 2, 2020, we redeemed the $559.6 million remaining balance of our 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 June 30, 2020 and December 31, 2019, was $170.3 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.15

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 — Partnership Units and Related Matters

Distributions

TRC is entitled to receive all Partnership distributions after payment of preferred unit distributions each quarter.

14The following table details the distributions declared and paid by us for the nine months ended September 30, 2020:

The following table details the distributions declared and paid by us for the six months ended June 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

Three Months Ended	Date Paid or To Be Paid		Total Distributions			Distributions to Targa Resources Corp.
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 us continue to be allocated 98% to the limited partner and 2% to our general partner; however, no units will be issued for those contributions. ~~During~~For the ~~second~~nine ~~quarter~~months ofended September 30, 2020, TRC made ~~contributions~~a tototal us of $50.0 million in contributions to us.

Preferred Units

Our Preferred Units rank senior to our common units with respect to the distribution rights. Distributions on our 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 our general partner. Distributions on our 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 our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.

We paid $2.8 million and $58.64 million of distributions to the holders of Preferred Units (“Preferred Unitholders”) for the three and ~~six~~nine months ended ~~June~~ September 30, 2020.

Subsequent Event

In ~~July~~October 2020, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit, resulting in approximately $0.9 million in distributions that will be paid on ~~August~~November 1716, 2020.

Note 8 — 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 ~~June~~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		~~167~~168,~~230~~317		166,216		8690,~~100~~600		2033,~~000~~350		-		-
Natural Gas	Basis Swaps	MMBtu/d		~~416~~445,~~374~~084		~~450~~471,~~566~~168		295,390		250,000		90,000		5,000
NGL	Swaps	Bbl/d		30,~~814~~909		2329,~~729~~261		1216,~~371~~848		-2,627		-		-
NGL	Futures	Bbl/d		3952,~~370~~685		1225,~~288~~526		-		-		-		-
Condensate	Swaps	Bbl/d		5,190		54,~~864~~872		12,~~610~~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 June 30, 2020				Fair Value as of December 31, 2019
		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	$	9958.24	$	74116.61	$	102.1	$	11.6
	Long-term		3614.10		3262.68		33.7		6.4
Total derivatives designated as hedging instruments		$	~~135~~72.34	$	~~107~~178.29	$	135.8	$	18.0
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	2230.85	$	5.90	$	1.2	$	92.5
	Long-term		765.25		200.31		1.8		34.4
Total derivatives not designated as hedging instruments		$	3096.0	$	265.21	$	3.0	$	126.9
Total current position		$	~~122~~88.09	$	80121.51	$	103.3	$	104.1
Total long-term position			4379.35		5262.9		35.5		40.8
Total derivatives		$	~~165~~168.34	$	~~133~~184.40	$	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~~	Gross Presentation										~~Pro Forma Net Presentation~~	Pro Forma Net Presentation
June 30, 2020		Asset			Liability				Collateral				Asset			Liability
September 30, 2020			Asset			Liability				Collateral				Asset			Liability
Current Position
	Counterparties with offsetting positions or collateral	$	~~108.9~~$	80.3	$	~~(80.5~~$	)(121.1	)	$	~~48.2~~$	60.1		$	~~76.6~~$	31.5	$	-$	(12.2	)
	Counterparties without offsetting positions - assets		~~13.1~~	8.6		-	-			-	-			~~13.1~~	8.6		-	-
	Counterparties without offsetting positions - liabilities		-	-		-	-			-	-			-	-		-	-
			122.0			(80.5	)			48.2				89.7			-
				88.9			(121.1	)			60.1				40.1			(12.2	)
Long Term Position
	Counterparties with offsetting positions or collateral		~~31.5~~	63.4		~~(49.3~~	)(62.6	)		-	-			~~6.6~~	26.3		~~(24.4~~	)(25.5	)
	Counterparties without offsetting positions - assets		~~11.8~~	16.1		-	-			-	-			~~11.8~~	16.1		-	-
	Counterparties without offsetting positions - liabilities		-	-		~~(3.6~~	)(0.3	)		-	-			-	-		~~(3.6~~	)(0.3	)
			43.3			(52.9	)			-				18.4			(28.0	)
				79.5			(62.9	)			-				42.4			(25.8	)
Total Derivatives
	Counterparties with offsetting positions or collateral		~~140.4~~	143.7		~~(129.8~~	)(183.7	)		~~48.2~~	60.1			~~83.2~~	57.8		~~(24.4~~	)(37.7	)
	Counterparties without offsetting positions - assets		~~24.9~~	24.7		-	-			-	-			~~24.9~~	24.7		-	-
	Counterparties without offsetting positions - liabilities		-	-		~~(3.6~~	)(0.3	)		-	-			-	-		~~(3.6~~	)(0.3	)
		$	~~165.3~~$	168.4	$	~~(133.4~~$	)(184.0	)	$	~~48.2~~$	60.1		$	~~108.1~~$	82.5	$	~~(28.0~~$	)(38.0	)
		~~Gross Presentation~~	Gross Presentation										~~Pro Forma Net Presentation~~	Pro Forma Net Presentation
December 31, 2019		~~Asset~~	Asset		~~Liability~~	Liability			~~Collateral~~	Collateral			~~Asset~~	Asset		~~Liability~~	Liability
Current Position
	Counterparties with offsetting positions or collateral	$	~~99.8~~$	99.8	$	~~(85.0~~$	)(85.0	)	$	~~(4.9~~$	)(4.9	)	$	~~56.0~~$	56.0	$	~~(46.1~~$	)(46.1	)
	Counterparties without offsetting positions - assets		~~3.5~~	3.5		-	-			-	-			~~3.5~~	3.5		-	-
	Counterparties without offsetting positions - liabilities		-	-		~~(19.1~~	)(19.1	)		-	-			-	-		~~(19.1~~	)(19.1	)
			~~103.3~~	103.3		~~(104.1~~	)(104.1	)		~~(4.9~~	)(4.9	)		~~59.5~~	59.5		~~(65.2~~	)(65.2	)
Long Term Position
	Counterparties with offsetting positions or collateral		~~33.3~~	33.3		~~(40.5~~	)(40.5	)		-	-			~~18.1~~	18.1		~~(25.3~~	)(25.3	)
	Counterparties without offsetting positions - assets		~~2.2~~	2.2		-	-			-	-			~~2.2~~	2.2		-	-
	Counterparties without offsetting positions - liabilities		-	-		~~(0.3~~	)(0.3	)		-	-			-	-		~~(0.3~~	)(0.3	)
			~~35.5~~	35.5		~~(40.8~~	)(40.8	)		-	-			~~20.3~~	20.3		~~(25.6~~	)(25.6	)
Total Derivatives
	Counterparties with offsetting positions or collateral		~~133.1~~	133.1		~~(125.5~~	)(125.5	)		~~(4.9~~	)(4.9	)		~~74.1~~	74.1		~~(71.4~~	)(71.4	)
	Counterparties without offsetting positions - assets		~~5.7~~	5.7		-	-			-	-			~~5.7~~	5.7		-	-
	Counterparties without offsetting positions - liabilities		-	-		~~(19.4~~	)(19.4	)		-	-			-	-		~~(19.4~~	)(19.4	)
		$	~~138.8~~$	138.8	$	~~(144.9~~$	)(144.9	)	$	~~(4.9~~$	)(4.9	)	$	~~79.8~~$	79.8	$	~~(90.8~~$	)(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 our 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 ~~asset~~liability of $3115.96 million as of ~~June~~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 ~~June~~September 30,					~~Six~~Nine Months Ended ~~June~~September 30,
Hedging Relationships	2020			2019		2020			2019
Commodity contracts	$	(~~132~~128.97	)	$	88118.42	$	26(102.26	)	$	49167.68

	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended June 30,				Six Months Ended June 30,
Location of Gain (Loss)	2020		2019		2020		2019
Revenues	$	60.2	$	43.3	$	120.3	$	64.6

Based on valuations as of June 30, 2020, we expect to reclassify commodity hedge-related deferred gains of $29.8 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2023, with $26.3 million of gains to be reclassified over the next twelve months.

	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

~~Our~~Based ~~consolidated~~on ~~earnings~~valuations ~~are~~as ~~also~~of ~~affected~~September 30, by2020, ~~the~~we ~~use~~expect ~~of the mark-~~to~~-market~~ ~~method~~reclassify ofcommodity ~~accounting for derivative instruments that do not qualify for~~ hedge-related ~~accounting~~deferred orlosses ~~that~~of ~~have not been designated as hedges~~$(106.0) ~~The~~million ~~changes~~included in ~~fair~~accumulated ~~value~~other ofcomprehensive ~~these~~income ~~instruments~~into ~~are~~earnings ~~recorded~~before onincome ~~the~~taxes ~~balance sheet and~~ through ~~earnings~~the ~~rather~~end ~~than~~of ~~being~~2023, ~~deferred~~with ~~until the anticipated transaction settles~~$(57.2) ~~The~~million ~~use~~ of ~~mark-to-market~~losses ~~accounting for financial instruments can cause non-cash earnings volatility due~~ to ~~changes~~be inreclassified ~~the~~over ~~underlying commodity price indices. For~~ the ~~three~~next ~~and~~twelve ~~six~~ months ~~ended June 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 June 30,					Six Months Ended June 30,
as Hedging Instruments	Derivatives	2020		2019			2020		2019
Commodity contracts	Revenue	$	8.1	$	(1.1	)	$	107.8	$	(10.5	)

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.

See Note 9 – Fair Value Measurements and Note 14 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

	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 9 – Fair Value Measurements and Note 15 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

Note 9 — 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 ~~June~~September 30, 2020, a net ~~asset~~liability position of $3115.96 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 $(86136.58) 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 $~~150~~106.71 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 TRP Revolver and the Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and

•

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:

		June 30, 2020
		September 30, 2020
					Fair Value
		Carrying 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)		$	~~164~~168.04		$	~~164~~168.04		$	—		$	~~164~~168.04		$	—
Liabilities from commodity derivative contracts (1)			~~132~~184.10			~~132~~184.10			—			~~132~~183.17			—0.3
TPL contingent consideration (2)			2.3			2.3			—			—		~~2.3~~	2.3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents			~~173~~248.60			~~173~~248.60			—			—			—
TRP Revolver			~~440~~100.0			~~440~~100.0			—			~~440~~100.0			—
Senior unsecured notes			67,~~725~~145.10			67,~~627~~206.20			—			67,~~627~~206.20			—
Securitization Facility			250.0			250.0			—			250.0			—
	December 31, 2019
				Fair Value
		Carrying 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			291.1			291.1			—			—			—
TRP Revolver			—			—			—			—			—
Senior unsecured notes			7,028.5			7,376.9			—			7,376.9			—
Securitization Facility			370.0			370.0			—			370.0			—

18(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 8 – 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.

	December 31, 2019
				Fair Value
		Carrying 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			291.1			291.1			—			—			—
TRP Revolver			—			—			—			—			—
Senior unsecured notes			7,028.5			7,376.9			—			7,376.9			—
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 8– 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 June 30, 2020, we had no commodity swap and option contracts categorized as Level 3.20

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	)
	Transfers out of Level 3 (1)		0.3			—
New Level 3 derivative instruments			(0.5	)		—
Balance, June 30, 2020		$	—		$	(2.3	)
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 10 — Related Party Transactions – Targa

Relationship with Targa

We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.

Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than costs attributable to Targa’s status as a separate reporting company. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay.

The following table summarizes transactions with Targa:

	Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Targa billings of payroll and related costs included in operating expenses	$	6659.65	$	61.6	$	~~132~~191.27	$	~~115~~177.73
Targa allocation of general and administrative expense		5651.03		6159.15		~~108~~159.58		~~128~~188.84
Cash distributions to Targa based on general partner and limited partner ownership		5048.38		~~435~~239.06		~~289~~338.43		~~673~~913.51
Cash contributions from Targa related to limited partner ownership (1)		~~49.0~~—		~~186~~9.28		49.0		~~186~~196.20
Cash contributions from Targa to maintain its 2% general partner ownership		~~1.0~~—		30.82		1.0		34.80

____________________________________________________________________________________________________________

(1)	The cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to general partner. See Note 7 – Partnership Units and Related Matters.

Note 11 – Contingencies

Legal Proceedings

We are a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We are also a party 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 12 – Revenue

Fixed consideration allocated to remaining performance obligations

The following table ~~includes~~presents the estimated minimum revenue ~~expected to be recognized in the future~~ related to unsatisfied performance obligations ~~that are unsatisfied (or partially unsatisfied)~~ at the end of the reporting period, and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments, ~~and~~ 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 June 30, 2020	$	270.6	$	515.0	$	3,202.7
Fixed consideration to be recognized as of September 30, 2020	$	140.7	$	518.1	$	2,858.8

20Based 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.

InFor ~~accordance~~disclosures ~~with~~related ~~the optional exemptions that we elected~~ to ~~apply,~~disaggregated the amounts presented in the table above exclude variable consideration for which the allocation exception is met and consideration associated with performance obligations of short-term contracts. In addition, consideration from contracts for which we recognize revenue ~~at the amount that we have the right to invoice for services performed is also excluded from the table above~~, ~~with~~see ~~the~~Note ~~exception~~15 of– ~~any~~Segment ~~fixed consideration attributable to such contracts~~Information. The nature of the performance obligations for which the consideration has been excluded is consistent with the performance obligations described within our revenue recognition accounting policy; the estimated remaining duration of such contracts primarily ranges from 1 to 19 years. In addition, variability exists in the consideration excluded due to the unknown quantity and composition of volumes to be serviced or sold as well as fluctuations in the market price of commodities to be received as consideration or sold over the applicable remaining contract terms. Such variability is resolved at the end of each future month or quarter.

~~For~~Note ~~disclosures~~13 ~~related~~— toOther ~~disaggregated~~Operating ~~revenue,~~(Income) ~~see Note 14 – Segment Information.~~Expense

~~Note~~Other 13operating —(income) ~~Supplemental~~expense ~~Cash~~is ~~Flow~~comprised ~~Information~~of the following:

	Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020		2019
Cash:
(Gain) loss on sale of disposition of business and assets (1)	$	58.0		$	0.5		$	58.0	$	3.6
Interest paid, net of capitalized interest (1)	$	165.3		$	106.2
Write-down of assets (2)		13.5			17.9			13.5		17.9
Income taxes paid, net of refunds		0.1			(1.7	)
Other		0.7			—			2.3		0.2
Non-cash investing activities:
	$	72.2		$	18.4		$	73.8	$	21.7
Impact of capital expenditure accruals on property, plant and equipment, net		(143.9	)		(4.3	)
Transfers from materials and supplies inventory to property, plant and equipment		1.8			16.4
Non-cash financing activities:
Changes in accrued distributions to noncontrolling interests	$	(1.9	)	$	49.6

~~__________________~~(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.

(12) ~~Interest~~Related ~~capitalized~~to ~~on major projects was $22.5 million and $36.1 million for~~ the ~~six~~write-down ~~months~~of ~~ended~~certain ~~June~~assets ~~30,~~to ~~2020~~their ~~and~~recoverable ~~2019~~amounts.

Note 14 — ~~Segment~~Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2020			2019
Cash:
Interest paid, net of capitalized interest (1)	$	306.3		$	216.6
Income taxes paid, net of refunds		0.1			(1.7	)
Non-cash investing activities:
Impact of capital expenditure accruals on property, plant and equipment, net		(194.7	)		(150.6	)
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 15 — 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”), ~~which~~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 June 30, 2020
	Three Months Ended September 30, 2020
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	~~133~~135.57	$	1,~~136~~616.35	$	1088.86	$	—		$	1,~~280~~840.68
Fees from midstream services		~~110~~126.02		~~132~~148.91		—		—			~~242~~274.93
		243.5		1,269.2		10.8		—			1,523.5
		261.9		1,764.6		88.6		—			2,115.1
Intersegment revenues
Sales of commodities		~~389~~611.29		4637.14		—		(~~435~~649.3	)		—
Fees from midstream services		1.57		78.35		—		(810.82	)		—
		390.7		53.4		—		(444.1	)		—
		613.6		45.9		—		(659.5	)		—
Revenues	$	~~634~~875.25	$	1,~~322~~810.65	$	1088.86	$	(~~444~~659.15	)	$	12,~~523~~115.51
Operating margin	$	~~237~~261.20	$	~~231~~280.54	$	1088.86	$	—		$	~~479~~630.50
Other financial information:
Total assets (1)	$	98,~~124~~929.24	$	6,~~697~~841.2	$	2278.02	$	72145.98		$	15,~~916~~994.36
Goodwill	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	3763.16	$	~~127~~69.90	$	—	$	4.60		$	~~169~~136.6

(1)	Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver.

	Three Months Ended June 30, 2019
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	298.4	$	1,378.8	$	7.0	$	—		$	1,684.2
Fees from midstream services		176.2		134.9		—		—			311.1
		474.6		1,513.7		7.0		—			1,995.3
Intersegment revenues
Sales of commodities		539.7		43.6		—		(583.3	)		—
Fees from midstream services		1.5		7.0		—		(8.5	)		—
		541.2		50.6		—		(591.8	)		—
Revenues	$	1,015.8	$	1,564.3	$	7.0	$	(591.8	)	$	1,995.3
Operating margin	$	232.1	$	184.4	$	7.0	$	—		$	423.5
Other financial information:
Total assets (1)	$	12,144.4	$	5,994.7	$	19.0	$	94.6		$	18,252.7
Goodwill	$	46.6	$	—	$	—	$	—		$	46.6
Capital expenditures	$	420.8	$	425.5	$	—	$	10.8		$	857.1

	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		$	53.9		$	18,858.3
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 cash, prepaids and debt issuance costs for our TRP Revolver.

	Six Months Ended June 30, 2020
	Nine Months Ended September 30, 2020
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	~~377~~512.39	$	24,~~555~~172.70	$	~~127~~215.29	$	—		$	34,~~060~~900.28
Fees from midstream services		~~228~~354.25		~~284~~432.02		—		—			~~512~~786.27
		605.5		2,839.7		127.2		—			3,572.4
		867.4		4,604.2		215.9		—			5,687.5
Intersegment revenues
Sales of commodities		~~832~~1,444.43		~~102~~140.71		—		(~~935.~~1,584.4	)		—
Fees from midstream services		34.39		1523.48		—		(1828.7	)		—
		835.7		118.1		—		(953.8	)		—
		1,449.2		163.9		—		(1,613.1	)		—
Revenues	$	12,~~441~~316.26	$	24,~~957~~768.81	$	~~127~~215.29	$	(~~953~~1,613.81	)	$	35,~~572~~687.45
Operating margin	$	~~492~~753.87	$	~~525~~806.50	$	~~127~~215.29	$	—		$	1,~~145~~775.56
Other financial information:
Total assets (1)	$	98,~~124~~929.24	$	6,~~697~~841.2	$	2278.02	$	72145.98		$	15,~~916~~994.36
Goodwill	$	45.2	$	—	$	—	$	—		$	45.2
Capital expenditures	$	~~154~~218.60	$	~~306~~375.35	$	—	$	1216.98		$	~~473~~610.83

(1)	Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver.

	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		$	53.9		$	18,858.3
Goodwill	$	46.6	$	—	$	—		$	—		$	46.6
Capital expenditures	$	1,068.7	$	1,197.5	$	—		$	38.7		$	2,304.9

	Six Months Ended June 30, 2019
	Gathering and Processing		Logistics and Transportation		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	555.1	$	3,105.6	$	—	$	—		$	3,660.7
Fees from midstream services		376.1		257.9		—		—			634.0
		931.2		3,363.5		—		—			4,294.7
Intersegment revenues
Sales of commodities		1,362.5		82.1		—		(1,444.6	)		—
Fees from midstream services		3.3		12.5		—		(15.8	)		—
		1,365.8		94.6		—		(1,460.4	)		—
Revenues	$	2,297.0	$	3,458.1	$	—	$	(1,460.4	)	$	4,294.7
Operating margin	$	470.3	$	336.3	$	—	$	—		$	806.6
Other financial information:
Total assets (1)	$	12,144.4	$	5,994.7	$	19.0	$	94.6		$	18,252.7
Goodwill	$	46.6	$	—	$	—	$	—		$	46.6
Capital expenditures	$	838.5	$	896.3	$	—	$	27.8		$	1,762.6

(1)	Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver.

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

	Three Months Ended June 30,					Six Months Ended June 30,
	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	$	~~269~~351.71	$	~~217~~305.63		$	~~542~~893.89	$	~~628~~934.92
NGL		~~908~~1,312.29		1,~~195~~160.5			23,~~069~~382.50		23,~~591~~752.94
Condensate and crude oil		2754.64		~~172~~178.17			~~163~~217.38		~~309~~488.84
Petroleum products		613.82		5611.85			5669.58		7687.05
		1,212.3		1,642.0			2,832.1		3,606.6
		1,731.6		1,656.0			4,563.5		5,262.5
Non-customer revenue:
Derivative activities - Hedge		6019.2		4341.35			~~120~~139.34		64106.61
Derivative activities - Non-hedge (1)		890.10		(1103.13	)		~~107~~197.89		(10113.58	)
		68.3		42.2			228.1		54.1
		109.2		(61.8	)		337.3		(7.7	)
Total sales of commodities		1,~~280~~840.68		1,~~684~~594.2			34,~~060~~900.28		35,~~660~~254.78
Fees from midstream services:
Revenue recognized from contracts with customers:
Gathering and processing		~~107~~123.47		~~177~~171.56			~~223~~347.31		~~371~~543.97
NGL transportation, fractionation and services		3243.98		4045.18			72116.87		76122.30
Storage, terminaling and export		8996.16		9084.46			~~188~~285.85		~~170~~254.07
Other		1310.52		36.13			2737.34		1522.80
Total fees from midstream services		~~242~~274.93		~~311~~308.13			~~512~~786.27		~~634~~942.04
Total revenues	$	12,~~523~~115.51	$	1,~~995~~902.35		$	35,~~572~~687.45	$	46,~~294~~197.72

(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 June 30,						Six Months Ended June 30,
	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	$	~~237~~261.20		$	~~232~~246.15		$	~~492~~753.87		$	~~470~~716.38
Logistics and Transportation operating margin		~~231~~280.54			~~184~~228.49			~~525~~806.50			~~336~~565.30
Other operating margin		1088.86			7(101.02	)		~~127~~215.29			—(101.1	)
Depreciation and amortization expense		(~~204~~203.57	)		(~~237~~244.23	)		(~~443~~647.63	)		(~~474~~718.69	)
General and administrative expense		(5856.63	)		(6965.36	)		(~~115~~171.57	)		(~~146~~212.73	)
Impairment of long-lived assets		—			—			(2,442.8	)		—
Interest expense, net		(94.39	)		(6984.52	)		(~~188~~283.10	)		(~~144~~229.92	)
Equity earnings (loss)		1418.96			310.20			3554.51			515.9
Gain (loss) on sale or disposition of business and assets		0(58.70	)		(0.25	)		-(58.0	)		(3.16	)
Gain (loss) from financing activities		21.8			—			61.1			(1.4	)
Write-down of assets		(13.5	)		(17.9	)		(13.5	)		(17.9	)
Change in contingent considerations		—			0.8			—			(8.9	)
Gain (loss) from financing activities		(13.7	)		—			47.4			(1.4	)
Other, net		(0.3	)		—			(0.8	)		(0.2	)
Gain (loss) from sale of equity-method investment		—			65.8			—			65.8
Income (loss) before income taxes	$	159.2		$	51.7		$	(1,948.7	)	$	32.7
Change in contingent considerations		—			—			—			(8.8	)
Other, net		0.6			—			(0.3	)		(0.1	)
Income (loss) before income taxes	$	209.1		$	37.5		$	(1,739.5	)	$	70.2

2425

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 Partners LP (“we,” “our,” the “Partnership” or “TRP”) is a Delaware limited partnership formed in October 2006 by Targa Resources Corp. (“TRC” or “Targa”). Our common units were listed on the NYSE under the symbol “NGLS” prior to TRC’s acquisition on February 17, 2016 of all our outstanding common units that it and its subsidiaries did not already own. Our 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS/PA.”

Targa Resources GP LLC, our general partner, is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa.

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.

2526

Recent Developments

Response to Current Market Conditions

During the ~~first~~nine ~~half~~months ofended 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 ~~beginning~~and ~~with~~global ~~May~~economies ~~2020~~beginning ~~production~~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 ~~recent substantial~~ decline in commodity prices ~~has~~ 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 ~~impact~~impacted our operations by (i) reducing investments by third parties in the development of new oil and gas reserves, therefore ~~potentially~~ 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, ~~in certain areas of our operations like the Permian Basin,~~ production from wells that were previously shut-in during the ~~second~~first ~~quarter~~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 ~~approximately~~ about $700 million from our previously disclosed ranges of $700 million to $800 million ~~from~~ ~~our~~in ~~previously~~the ~~disclosed~~first ~~range~~quarter of 2020 and $1.2 billion to $1.3 billion, ~~which~~in ~~represents a 40 percent reduction at~~ the ~~midpoint~~fourth quarter of ~~both ranges~~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.

2627

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 ~~August~~November ~~2019~~2020, we announced ~~that~~the wetransfer ~~began~~of ~~construction~~an ofexisting 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 ~~250~~200 MMcf/d cryogenic natural gas processing plant in(the “Heim Plant”). The Heim Plant will process natural gas production from the ~~Midland~~Permian Basin, ~~the~~and ~~Gateway~~is ~~Plant,~~expected ~~which~~to ~~began~~begin operations in the ~~third~~fourth quarter of ~~2020~~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 ~~completed~~operational inby the ~~first~~end of the fourth quarter of ~~2021~~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 ~~began~~commenced operations ~~late~~ in the first quarter of 2020. and Train 8 iscommenced ~~expected to begin~~ operations atin the ~~end of 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 ~~early~~ 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 ~~November~~October ~~2019~~2020, we executed agreements to sell our ~~crude~~assets ~~gathering and storage business~~ in ~~Permian~~Channelview, ~~Delaware~~Texas for approximately $~~134~~58 million (the “October 2020 Sale”). The sale closed in the ~~first~~fourth quarter of 2020.

27In 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

~~During~~On ~~the~~November ~~first~~2, ~~half of~~ 2020, we ~~repurchased~~redeemed ~~a portion of our outstanding senior notes on~~ the ~~open market, paying~~ $~~239~~559.86 million ~~plus~~remaining ~~accrued~~balance ~~interest to repurchase $303.3 million~~ of ~~the~~our ~~notes. The~~5¼% ~~repurchases~~Senior ~~resulted~~Notes indue ~~a $61~~2023.~~1 million net gain, which included the write-off of $2.4 million in related debt issuance costs.~~

In the third quarter of 2020, we 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 concurrent cash tender offer (the “Tender Offer”) and redemption payments for our 6¾% Senior Notes due 2024 (the “6¾% Notes”), with the remainder used for repayment of borrowings under the TRP Revolver.

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.

Additionally, during the first half of 2020, we repurchased a portion of our 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.

In the second quarter of 2020, we amended our 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.

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 ~~fee-related~~ 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 ~~unit fees due to~~ 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, and Adjusted EBITDA.

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 and Adjusted EBITDA are non-GAAP measures. The GAAP measure most directly comparable to these non-GAAP measures is net income (loss) attributable to TRP. These non-GAAP measures should not be considered as an alternative to GAAP net income attributable to TRP 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, ~~other~~ 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 TRP 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 make distributions to holders of our equity interests.

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 June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
	(In millions)
Reconciliation of Net Income (Loss) to Operating Margin and Gross Margin
Net income (loss)	$	~~159~~209.21		$	5137.75		$	(1,~~948~~739.75	)	$	3270.72
Depreciation and amortization expense		~~204~~203.57			~~237~~244.23			~~443~~647.63			~~474~~718.69
General and administrative expense		5856.63			6965.36			~~115~~171.57			~~146~~212.73
Impairment of long-lived assets		—			—			2,442.8			—
Interest (income) expense, net		94.39			6984.52			~~188~~283.10			~~144~~229.92
Equity (earnings) loss		(1418.96	)		(310.20	)		(3554.51	)		(515.9	)
(Gain) loss on sale or disposition of assets		(0.7	)		(0.2	)		—			3.1
(Gain) loss on sale or disposition of business and assets		58.0			0.5			58.0			3.6
(Gain) loss from financing activities		(21.8	)		—			(61.1	)		1.4
Write-down of assets		13.5			17.9			13.5			17.9
Change in contingent considerations		—			(0.8	)		—			8.9
(Gain) loss from sale of equity-method investment		—			(65.8	)		—			(65.8	)
Other, net		0.3			—			0.8			0.2
(Gain) loss from financing activities		13.7			—			(47.4	)		1.4
Operating margin		479.5			423.5			1,145.5			806.6
Change in contingent considerations		—			—			—			8.8
Operating expenses		183.4			210.2			383.3			400.5
Other, net		(0.6	)		—			0.3			0.2
Gross margin	$	662.9		$	633.7		$	1,528.8		$	1,207.1
Operating margin		630.0			374.2			1,775.6			1,180.8
Operating expenses		181.9			200.2			565.1			600.7
Gross margin	$	811.9		$	574.4		$	2,340.7		$	1,781.5

	Three Months Ended June 30,								Six Months Ended June 30,
		Three Months Ended September 30,								Nine Months Ended September 30,
	~~2020~~	2020			~~2019~~	2019			~~2020~~	2020			~~2019~~	2019
	~~(In millions)~~	(In millions)
Reconciliation of Net Income (Loss) attributable to TRP to Adjusted EBITDA
Net income (loss) attributable to TRP	$	~~65.9~~$	109.0		$	~~(4.6~~$	)(39.1	)	$	~~(1,956.7~~$	)(1,847.6	)	$	~~(35.0~~$	)(74.1	)
Interest (income) expense, net		~~94.3~~	94.9			~~69.5~~	84.2			~~188.1~~	283.0			~~144.9~~	229.2
Depreciation and amortization expense		~~204.5~~	203.7			~~237.2~~	244.3			~~443.6~~	647.3			~~474.6~~	718.9
Impairment of long-lived assets		—	—			—	—			~~2,442.8~~	2,442.8			—	—
(Gain) loss on sale or disposition of assets		(0.7	)			(0.2	)			—				3.1
(Gain) loss on sale or disposition of business and assets			58.0				0.5				58.0				3.6
(Gain) loss from financing activities (1)		(21.8	)			—				(61.1	)			1.4
Write-down of assets			13.5				17.9				13.5				17.9
Equity (earnings) loss		(14.9	)			(3.2	)			(35.5	)			(5.9	)
(Gain) loss from sale of equity-method investment			—				(65.8	)			—				(65.8	)
Distributions from unconsolidated affiliates and preferred partner interests, net		27.7				12.6				53.4				19.4
(Gain) loss from financing activities (1)			13.7				—				(47.4	)			1.4
Change in contingent considerations		—				(0.8	)			—				8.9
Equity (earnings) loss			(18.6	)			(10.0	)			(54.1	)			(15.9	)
Risk management activities		(10.4	)			(7.1	)			(125.9	)			0.1
Distributions from unconsolidated affiliates and preferred partner interests, net			28.2				14.0				81.6				33.4
Severance and related benefits (2)		6.5				—				6.5				—
Change in contingent considerations			—				—				—				8.8
Noncontrolling interests adjustments (3)		(13.1	)			(9.6	)			(202.6	)			(16.7	)
Risk management activities			(88.3	)			100.7				(214.2	)			100.8
TRP Adjusted EBITDA	$	338.0			$	293.8			$	752.6			$	594.8
Severance and related benefits (2)			—				—				6.5				—
Noncontrolling interests adjustments (3)			(9.2	)			(8.9	)			(211.7	)			(25.6	)
TRP Adjusted EBITDA		$	404.9			$	337.8			$	1,157.7			$	932.6

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

(2) Represents one-time severance and related benefit ~~expenses~~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).

Consolidated Results of Operations

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

	Three Months Ended June 30,												Six Months Ended June 30,
	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,~~280~~840.68		$	1,~~684~~594.2		$	~~(403~~246.6	)		~~(24~~15	%)	$	34,~~060~~900.28		$	35,~~660~~254.78		$	(~~600~~354.50	)		(167	%)	%)
Fees from midstream services		~~242~~274.93			~~311~~308.13			(6834.20	)		(2211	%)		~~512~~786.27			~~634~~942.04			(~~121~~155.87	)		(1917	%)	%)
Total revenues		12,~~523~~115.51			1,~~995~~902.35			~~(471~~212.86	)		~~(24~~11	%)		35,~~572~~687.45			46,~~294~~197.72			(~~722~~509.37	)		(178	%)	%)
Product purchases		~~860~~1,303.62			1,~~361~~328.61			(~~501~~24.09	)		(372	%)		23,~~043~~346.68			34,~~087~~415.67			(1,~~044~~068.09	)		(3424	%)	%)
Gross margin (1)		~~662~~811.9			~~633~~574.74			29237.25			541	%		12,~~528~~340.87			1,~~207~~781.15			~~321~~559.72			2731	%	%
Operating expenses		~~183~~181.49			~~210~~200.2			(2618.83	)		(139	%)		~~383~~565.31			~~400~~600.57			(1735.26	)		(46	%)	%)
Operating margin (1)		~~479~~630.50			~~423~~374.52			56255.08			1368	%		1,~~145~~775.56			~~806~~1,180.68			~~338~~594.98			4250	%	%
Depreciation and amortization expense		~~204~~203.57			~~237~~244.23			(3240.76	)		(1417	%)		~~443~~647.63			~~474~~718.69			(3171.06	)		(710	%)	%)
General and administrative expense		5856.63			6965.36			(109.73	)		(1514	%)		~~115~~171.57			~~146~~212.73			(3140.26	)		(2119	%)	%)
Impairment of long-lived assets		—			—			—			—			2,442.8			—			2,442.8			—
Other operating (income) expense		072.42			(018.24	)		053.68		NM	292	%		173.68			321.37			(152.71	)		~~(52~~240	%	%)
Income (loss) from operations		~~216~~297.08			~~117~~45.29			98251.89		NM	84	%		(1,~~858~~560.0	)		~~182~~227.09			(21,~~040~~787.09	)	NM
Interest expense, net		(94.39	)		(6984.52	)		(2410.87	)		3613	%		(~~188~~283.10	)		(~~144~~229.92	)		(4353.28	)		3023	%	%
Equity earnings (loss)		1418.96			310.20			118.76		NM	86	%		3554.51			515.9			2938.62		NM	240	%
Gain (loss) from financing activities		21(13.87	)		—			21(13.87	)		—			6147.14			(1.4	)		6248.58		NM
Change in contingent considerations		—			0.8			(0.8	)		(100	%)		—			(8.9	)		8.9			100		%
Gain (loss) from sale of equity-method investment		—			65.8			(65.8	)		(100	%)		—			65.8			(65.8	)		(100	%)
Other, net		0.8			—			0.8			—			0.8			—			0.8			—
Change in contingent considerations		—			—			—			—			—			(8.8	)		8.8			100	%
Net income (loss)		159.2			51.7			107.5			208	%		(1,948.7	)		32.7			(1,981.4	)	NM
Other, net		1.3			—			1.3			—			2.0			—			2.0			—
Less: Net income (loss) attributable to noncontrolling interests		93.3			56.3			37.0			66	%		8.0			67.7			(59.7	)		(88		%)
Net income (loss)		209.1			37.5			171.6		NM				(1,739.5	)		70.2			(1,809.7	)	NM
Net income (loss) attributable to Targa Resources Partners LP	$	65.9		$	(4.6	)	$	70.5		NM			$	(1,956.7	)	$	(35.0	)	$	(1,921.7	)	NM
Less: Net income (loss) attributable to noncontrolling interests		100.1			76.6			23.5			31	%		108.1			144.3			(36.2	)		(25	%)
Financial data:
Net income (loss) attributable to Targa Resources Partners LP	$	109.0		$	(39.1	)	$	148.1		NM			$	(1,847.6	)	$	(74.1	)	$	(1,773.5	)	NM
Adjusted EBITDA (1)	$	338.0		$	293.8		$	44.2			15	%	$	752.6		$	594.8		$	157.8			27		%
Financial data:
Growth capital expenditures (2)		142.8			821.4			(678.6	)		(83	%)		420.1			1,691.5			(1,271.4	)		(75		%)
Adjusted EBITDA (1)	$	404.9		$	337.8		$	67.1			20	%	$	1,157.7		$	932.6		$	225.1			24	%
Maintenance capital expenditures (3)		26.8			35.5			(8.7	)		(25	%)		53.7			71.1			(17.4	)		(24		%)

(1)	Gross margin, operating margin, and Adjusted EBITDA 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.”

(2) Growth capital expenditures, net of contributions from noncontrolling interest, were $404.2 million and $1,440.5 million for the six months ended June 30, 2020 and 2019. Net contributions to investments in unconsolidated affiliates were $0.3 million and $57.3 million for the six months ended June 30, 2020 and 2019.

(3) Maintenance capital expenditures, net of contributions from noncontrolling interests, were $51.4 million and $67.2 million for the six months ended June 30, 2020 and 2019.

NM	Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.

Three Months Ended ~~June~~September 30, 2020 Compared to Three Months Ended ~~June~~September 30, 2019

The ~~decrease~~increase in commodity sales reflects ~~lower~~higher NGL, ~~condensate,~~ and ~~petroleum~~natural ~~products~~gas prices ($~~476~~133.25 million), ~~and~~higher ~~lower~~NGL, ~~crude~~condensate ~~marketing,~~and petroleum products, ~~and natural gas~~ volumes ($~~150~~100.37 million), ~~partially~~and ~~offset~~the byfavorable ~~higher~~impact ~~NGL~~of ~~and~~hedges ~~condensate volumes~~ ($~~137~~171.90 million), ~~higher~~partially offset by lower crude marketing and natural gas ~~prices~~volumes ($59128.59 million) and ~~the~~lower ~~favorable~~condensate ~~impact~~and ofpetroleum ~~hedges~~product prices ($2629.16 million).

The decrease in fees from midstream services is primarily due to new ~~transportation~~commercial arrangements for ~~Badlands~~ 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 ~~decreased~~lower ~~NGL~~crude marketing volumes associated with the sale of the Delaware crude system, ~~condensate~~which was effective December 1, 2019, and ~~petroleum~~lower ~~products~~natural ~~prices~~gas volumes, partially offset by ~~increases~~higher inNGL ~~volumes~~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.

31Depreciation 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.

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 gathering 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.33

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

~~Interest~~Other operating (income) expense, ~~net~~in 2020 consisted primarily of a loss associated with the reduction in the carrying value of our assets in Channelview, ~~increased~~Texas ~~due~~in toconnection ~~higher~~with ~~average~~the ~~borrowings~~October 2020 Sale and ~~lower~~write-down ~~capitalized~~of ~~interest~~certain ~~resulting~~assets ~~from~~to ~~lower~~their ~~growth~~recoverable ~~capital~~amounts. ~~investments~~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 ~~three~~third ~~months~~quarter ~~ended~~of ~~June 30,~~ 2020, we ~~repurchased~~redeemed ~~a portion of our outstanding senior notes on~~ the ~~open market, paying $117.7 million plus accrued interest to repurchase $140.~~6¾% ~~million~~Senior ofNotes ~~the~~due ~~notes~~2024, resulting in a $2113.87 million net ~~gain~~loss from financing activities.

~~Net~~During ~~income~~the ~~attributable~~third toquarter ~~noncontrolling~~of ~~interests~~2019, ~~was~~we ~~higher~~closed inon ~~2020~~the ~~primarily~~sale ~~due~~of toan ~~income~~equity-method ~~allocated~~investment tothat ~~noncontrolling~~resulted ~~interest holders~~ in ~~Targa~~the ~~Badlands~~recognition ~~LLC~~of ~~(“Targa~~a ~~Badlands”),~~gain ~~Targa~~of ~~GCX~~$65.8 ~~Pipeline LLC (“GCX DevCo JV”), and the Grand Prix Joint Venture~~million.

~~Six~~Net ~~Months~~income ~~Ended~~attributable ~~June~~to ~~30,~~noncontrolling interests was higher in 2020 ~~Compared~~primarily due to ~~Six~~income ~~Months~~allocated ~~Ended~~to ~~June~~noncontrolling 30interest holders in the Grand Prix Joint Venture, ~~2019~~Targa GCX Pipeline LLC (“GCX DevCo JV”) and the Centrahoma Joint Venture.

~~The~~Nine ~~decrease~~Months inEnded ~~commodity~~September ~~sales reflects lower NGL~~30, ~~natural~~2020 ~~gas,~~Compared ~~condensate,~~to ~~and~~Nine ~~petroleum~~Months ~~products~~Ended ~~prices~~September ~~($1~~30,~~243.0~~ million) and lower crude marketing volumes ($131.2 million), partially offset by higher NGL, natural gas, condensate, and petroleum products volumes ($596.5 million) and the favorable impact of hedges ($174.1 million).2019

The decrease in ~~fees~~commodity ~~from~~sales ~~midstream~~reflects ~~services~~lower isNGL, ~~primarily~~condensate, ~~due~~natural togas ~~new~~and ~~transportation~~petroleum ~~arrangements~~product ~~for~~prices ~~Badlands~~($1,112.5 ~~volumes~~million) ~~during~~and ~~the~~lower ~~six~~crude ~~months~~marketing ~~ended~~volumes ~~June~~($254.7 30million), ~~2020,~~partially ~~which~~offset ~~resulted~~by inhigher aNGL, ~~change~~condensate, ~~from~~natural ~~net~~gas ~~presentation~~and aspetroleum ~~fees~~product ~~from~~volumes ~~midstream~~($664.3 ~~services~~million), tothe ~~gross~~favorable ~~presentation~~impact asof ~~sales~~hedges of($345.1 ~~commodities~~million) and ~~product~~higher ~~purchases,~~crude ~~partially~~marketing ~~offset~~prices by($3.8 ~~increased export volumes~~million).

The decrease in ~~product~~fees ~~purchases~~from ~~reflects~~midstream ~~decreased~~services ~~NGL,~~is ~~natural~~primarily ~~gas~~due to new commercial arrangements for volumes effective in January 2020, ~~petroleum~~which ~~products~~resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and ~~condensate~~product ~~prices~~purchases, and lower gas processing volumes, partially offset by ~~increases~~increased inexport and terminaling and storage volumes.

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.

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 ~~gathering~~ 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 ~~reduced~~lower compensation and benefits and ~~lower~~ 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 ~~first~~nine ~~quarter~~months ofended 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 higher average borrowings and lower capitalized interest resulting from lower growth capital investments.~~34

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, partially offset by lower earnings from GCF.

32During the nine months ended September 30, 2020, we 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 ~~six~~third ~~months~~quarter ~~ended~~of ~~June 30~~2019, ~~2020,~~we ~~the~~closed ~~Partnership repurchased a portion of its outstanding senior notes~~ on the ~~open~~sale ~~market,~~of ~~paying~~an ~~$239.8~~equity-method ~~million~~investment ~~plus~~that ~~accrued~~resulted ~~interest~~in tothe ~~repurchase~~recognition ~~$303.3 million~~ of ~~the~~a ~~notes,~~gain ~~resulting~~of ~~in a~~ $6165.18 million ~~net gain from financing activities~~.

Net income attributable to noncontrolling interests was lower in 2020 primarily due to the allocation of impairment losses ~~allocated~~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”), ~~GCX~~the DevCo ~~JV,~~Joint Ventures and the Grand Prix Joint Venture ~~and Train 6~~.

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:
June 30, 2020	$	237.2	$	231.5	$	10.8		$	479.5
September 30, 2020	$	261.0	$	280.4	$	88.6		$	630.0
June 30, 2019		232.1		184.4		7.0			423.5
September 30, 2019		246.5		228.9		(101.2	)		374.2
Six Months Ended:
Nine Months Ended:
June 30, 2020	$	492.8	$	525.5	$	127.2		$	1,145.5
September 30, 2020	$	753.7	$	806.0	$	215.9		$	1,775.6
June 30, 2019		470.3		336.3		—			806.6
September 30, 2019		716.8		565.0		(101.1	)		1,180.7

3335

Gathering and Processing Segment

	Three Months Ended June 30,									Six Months Ended June 30,
	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	$	~~338~~362.39	$	~~363~~366.87	$	(253.58	)	(71	%)	$	~~708~~1,071.74	$	~~725.~~1,092.0	$	(1620.46	)	(2	%)
Operating expenses		101.19		~~131~~120.72		(3018.63	)	(2315	%)		~~215~~317.97		~~254~~375.82		(3857.95	)	(15	%)
Operating margin	$	~~237~~261.20	$	~~232~~246.15	$	514.15		26	%	$	~~492~~753.87	$	~~470~~716.38	$	2236.59		5	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)		1,~~698~~811.95		1,~~425~~513.39		~~273~~297.6		1920	%		1,~~677~~722.01		1,~~374~~421.23		~~302~~300.8		2221	%
Permian Delaware		~~651~~758.61		~~545~~629.14		~~106~~128.57		20	%		~~689~~712.34		~~513~~552.02		~~176~~160.32		3429	%
Total Permian		2,~~350~~569.56		12,~~970~~143.43		~~380~~426.13					2,~~366~~434.35		1,~~887~~973.25		~~479~~461.10
SouthTX (5)		~~265~~233.16		~~313~~328.86		(4895.70	)	(1629	%)		~~275~~261.75		~~338~~335.73		(6373.08	)	(1922	%)
North Texas		197.8		~~224~~228.02		(2630.24	)	(1213	%)		~~210~~206.63		227.26		(1621.63	)	(79	%)
SouthOK (6)		~~439~~386.89		~~607~~590.78		(~~167~~203.9	)	(2835	%)		~~501~~463.93		~~613~~606.81		(~~111~~142.98	)	(1824	%)
WestOK		~~251~~233.26		~~338~~329.2		(8795.06	)	(2629	%)		~~271~~258.47		~~338~~335.2		(6676.85	)	(2023	%)
Total Central		1,~~153~~051.9		1,~~483~~476.78		(~~329~~424.89	)				1,~~259~~189.68		1,~~517~~504.92		(~~258~~314.34	)
Badlands (7),(8)		~~111~~137.60		92120.38		1916.32		2113	%		~~135~~136.61		94103.64		4132.07		4332	%
Total Field		3,~~616~~758.05		3,~~546~~740.49		6917.6					3,~~761~~760.54		3,~~499~~581.71		~~261~~179.83
Coastal		~~713~~522.08		~~804~~764.9		(91242.91	)	(1132	%)		~~748~~672.89		~~787~~779.59		(38107.70	)	(514	%)
Total		4,~~329~~281.03		4,~~351~~505.38		(22224.35	)	(15	%)		4,~~510~~433.3		4,~~287~~361.20		~~223~~72.13		52	%
NGL production, MBbl/d (3)
Permian Midland (4)		~~245~~253.0		~~198~~216.05		4736.05		2417	%		~~245~~247.06		~~191~~199.38		5347.78		2824	%
Permian Delaware		89105.63		7182.43		1823.20		2528	%		9397.01		6571.94		2725.17		4136	%
Total Permian		~~334~~358.63		~~269~~298.48		6559.25					~~338~~344.07		~~257~~271.2		8073.85
SouthTX (5)		2829.82		41.75		(12.93	)	(3130	%)		28.57		4544.20		(1615.73	)	(3735	%)
North Texas		23.57		2627.63		(3.16	)	(1213	%)		24.95		26.79		(12.84	)	(79	%)
SouthOK (6)		5145.39		6869.35		(1723.06	)	(2534	%)		5954.06		6365.34		(410.38	)	(717	%)
WestOK		2119.03		2319.82		(20.81	)	~~(12~~1	%)		2221.12		2422.04		(1.92	)	(85	%)
Total Central		~~124~~118.61		~~160~~157.45		(3539.84	)				~~134~~129.50		~~159~~158.27		(2429.7	)
Badlands (8)		1317.90		1114.30		23.60		2321	%		16.03		1112.32		4.71		4234	%
Total Field		~~473~~493.14		~~441~~470.13		3223.01					~~488~~490.50		~~427~~442.71		6047.89
Coastal		4332.25		4745.34		(412.19	)	(928	%)		4641.05		47.80		(15.85	)	(412	%)
Total		~~516~~525.39		~~488~~515.47		2710.92		62	%		~~534~~531.5		~~475~~489.51		5942.04		129	%
Crude oil gathered, Badlands, MBbl/d		157.9		167.3		(9.4	)	(6	%)		167.5		168.4		(0.9	)	(1	%)
Crude oil, Badlands, MBbl/d		146.4		164.3		(17.9	)	(11	%)		160.4		167.0		(6.6	)	(4	%)
Crude oil gathered, Permian, MBbl/d (9)		40.2		86.3		(46.1	)	(53	%)		45.6		81.4		(35.8	)	(44	%)
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,~~048~~032.93		2,~~049~~056.76		(024.83	)	(01	%)		2,~~103~~079.03		12,~~988~~011.12		~~114~~68.91		63	%
NGL sales, MBbl/d (3),(10)		~~395~~389.05		~~389~~398.30		5(8.75	)	1(2	%)		~~414~~406.30		~~374~~382.54		3923.86		116	%
Condensate sales, MBbl/d		1613.16		1311.20		2.96		2224	%		1716.31		12.82		43.59		3532	%
Average realized prices - inclusive of hedges (11):
Natural gas, $/MMBtu		1.0334		01.9013		0.1321		1419	%		01.9810		1.4031		(0.4221	)	(3016	%)
NGL, $/gal		0.1929		0.3428		(0.1501	)	~~(44~~4	%)		0.2124		0.3935		(0.1811	)	(4631	%)
Condensate, $/Bbl		2843.1349		4950.8223		(216.6974	)	(4413	%)		3638.6156		4849.49		(1110.8893	)	(2422	%)

(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 ~~gathered~~ volume and includes the Targa~~-gathered~~ 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 gathered volumes reflect the sale of the Delaware crude gathering system, which was effective December 1, 2019.~~36

(109) ~~Natural~~Permian ~~gas~~crude ~~and~~oil ~~NGL sales statistics include Badlands starting January 1, 2020. New transportation arrangements for Badlands~~ volumes ~~resulted~~reflect inthe asale ~~change from net presentation as “Fees from midstream services” to gross presentation as “Sales~~ of ~~commodities”~~the ~~and~~Delaware ~~“Product~~crude ~~purchases”.~~system, ~~This~~which ~~change~~was ineffective ~~presentation~~December ~~did~~1, ~~not result in an impact to our operating or gross margin~~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 June 30, 2020						Three Months Ended June 30, 2019
	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)		17.35	$	0.5320	$	93.25		1618.18	$	1.9707		$	3120.81
NGL (MMgal)		~~100~~126.24		0.2208		2110.75		72110.70		0.1217			818.95
Crude oil (MBbl)		0.5		2916.8575		148.10		0.4		(41.9876	)		(10.87	)
					$	4522.0						$	3837.9
	Six Months Ended June 30, 2020						Six Months Ended June 30, 2019
	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)		3350.16	$	0.7355	$	2427.17		2847.20	$	1.4329		$	4060.46
NGL (MMgal)		~~195~~322.71		0.2015		3949.27		~~142~~252.1		0.0711			927.49
Crude oil (MBbl)		01.94		2119.2472		1927.7		01.71		(2.5828	)		(12.86	)
					$	83105.01						$	4885.09

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

Three Months Ended ~~June~~September 30, 2020 Compared to Three Months Ended ~~June~~September 30, 2019

~~The~~Gathering ~~decrease~~and inProcessing segment gross margin ~~was primarily due to lower volumes in the Central region~~contributions, attributable to ~~temporary~~higher ~~shut-ins~~system ~~and~~volumes ~~reduced producer activity,~~ and ~~lower~~fee-based ~~realized~~margin ~~NGL~~in ~~and~~the ~~condensate~~Permian ~~prices~~region, ~~partially~~were offset by ~~higher~~lower volumes ~~and~~in ~~fee-based~~the ~~margin~~Central inregion ~~the~~and ~~Permian~~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 ~~plant~~and inGateway ~~the~~plants ~~second~~in ~~quarter of~~ 2020. ~~These~~Lower ~~increases~~volumes ~~were~~in ~~partially~~the ~~offset~~Central byregion ~~the~~were ~~impact~~attributable ofto temporary shut-ins and reduced producer activity. In the Badlands, natural gas ~~gathered~~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, ~~partially~~volumes ~~offset~~were bylower due to continued low producer activity and the ~~impact~~effects of multiple Gulf Coast hurricanes in the third quarter of 2020, which necessitated temporary ~~shut-ins~~shutdowns ~~and~~of ~~reduced~~certain ~~producer~~facilities ~~activity~~in Louisiana. Total crude oil ~~gathered~~ volumes decreased in the Badlands due to ~~temporary shut-ins and~~ reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude ~~gathering~~ system in the fourth quarter of 2019.

~~Despite~~Operating ~~the addition of new processing facilities in the Permian, operating~~ expenses were lower due to cost reduction measures that resulted in adecreases ~~decrease~~ in ~~expenses~~compensation ~~from~~and benefits, contract labor, and chemicals, ~~taxes~~despite the addition of the Peregrine and ~~supplies~~Gateway processing facilities in the Permian.

35Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

~~Six~~Gathering ~~Months~~and ~~Ended~~Processing ~~June~~segment 30gross 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. ~~Compared~~Lower volumes in the Central region were attributable to ~~Six~~temporary ~~Months~~shut-ins ~~Ended~~and ~~June~~reduced 30producer 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.

~~The~~Operating ~~decrease~~expenses inwere ~~gross~~lower ~~margin was primarily~~ due to ~~lower~~cost ~~volumes~~reduction inmeasures ~~the~~that ~~Central~~resulted ~~region~~in ~~attributable~~decreases toin ~~temporary~~contract ~~shut-ins and reduced producer activity~~labor, ~~and~~chemicals ~~lower realized commodity prices, partially offset by higher volumes~~ and ~~fee-based~~compression ~~margin~~rentals ~~in the Permian~~ and ~~Badlands.~~lower Inad ~~the~~valorem ~~Permian~~taxes, ~~inlet~~despite ~~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 ~~plant in the second quarter of 2020. These increases were partially offset by the impact of temporary shut-ins~~ and ~~reduced~~Gateway ~~producer activity. In the Badlands, natural gas gathered volumes and NGL production increased due to production from new wells and the incremental~~ processing ~~capacity~~facilities ~~available with the commencement of operations at the Little Missouri 4 Plant~~ in the ~~third quarter of 2019, partially offset by the impact of temporary shut-ins and reduced producer activity. Total crude oil gathered volumes were flat in the Badlands, while the decrease in the~~ Permian ~~was primarily due to the sale of the Delaware crude gathering system in the fourth quarter of 2019~~.

Despite the addition of new processing facilities in the Permian, operating expenses were lower due to cost reduction measures that resulted in a decrease in expenses from contract labor, taxes and chemicals, partially offset by increased compensation and related benefits.37

Logistics and Transportation Segment

		Three Months Ended June 30,								Six Months Ended June 30,
		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		$	~~314~~362.70	$	~~262~~310.54	$	5251.26	2017	%	$	~~695~~1,057.0	$	~~482~~792.04	$	~~213~~264.06		4433	%
Operating expenses (1)			8381.26		7881.15		50.1	70	%		~~169~~251.50		~~145~~227.74		23.86		1610	%
Operating margin		$	~~231~~280.54	$	~~184~~228.49	$	4751.15	2622	%	$	~~525~~806.50	$	~~336~~565.30	$	~~189~~241.20		5643	%
Operating statistics MBbl/d (2):
Fractionation volumes (3)			~~579~~589.35		~~512~~508.58		6680.87	1316	%		~~602~~598.30		~~484~~492.78		~~117~~105.62		2421	%
Export volumes (4)			~~253~~308.85		~~231~~239.52		2269.3	1029	%		~~261~~277.32		~~222~~228.41		3849.91		1722	%
Pipeline throughput (5)			~~256~~300.19		—131.8		~~256~~169.1	—128	%		~~258~~273.90		—44.4		~~258~~228.96	NM	—
NGL sales			~~692~~724.61		~~605~~672.21		8752.40	148	%		~~720~~721.46		~~594~~620.89		~~125~~100.67		2116	%

(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.

~~Three~~NM ~~Months~~Due ~~Ended~~to ~~June~~a 30low denominator, ~~2020~~the ~~Compared~~noted topercentage ~~Three~~change ~~Months~~is ~~Ended~~disproportionately ~~June~~high 30and as a result, ~~2019~~considered not meaningful.

~~The~~Three ~~increase~~Months inEnded ~~Logistics~~September ~~and Transportation segment gross margin was primarily due to higher NGL transportation and fractionation margin and higher LPG export margin~~30, ~~partially~~2020 ~~offset~~Compared ~~by lower marketing margin. NGL transportation and fractionation margin increased due~~ to ~~volumes~~Three ~~delivered~~Months onEnded ~~Grand~~September ~~Prix~~30, ~~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 operations of Train 6 for a portion of the second quarter of 2019. LPG export margin increased primarily due to higher volumes, driven in part by phased expansions of our LPG export capabilities. Marketing margin decreased due to less optimization margin realized in our marketing businesses.

~~Operating~~The ~~expenses~~increase ~~were~~in ~~higher~~Logistics and Transportation segment gross margin was primarily due to ~~the~~higher ~~addition~~NGL oftransportation ~~incremental~~and fractionation ~~capacity,~~margin and higher ~~taxes~~LPG ~~primarily~~export ~~attributable~~margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to ~~Train~~higher 7volumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher ~~compensation~~fractionation volumes as a result of the commencement of operations of Train 7 in the first quarter of 2020 and ~~benefits,~~Train ~~partially~~8 ~~offset~~late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by ~~lower~~expansion ~~fuel~~of ~~and~~our ~~power~~LPG ~~costs~~export ~~and~~capabilities. Marketing ~~cost~~margin ~~reduction~~decreased ~~measures~~primarily due to less optimization margin realized in our marketing businesses.

36Operating 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.

~~Six~~Nine Months Ended ~~June~~September 30, 2020 Compared to ~~Six~~Nine Months Ended ~~June~~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 ~~operations of~~ Train 68 ~~for~~late ain ~~portion of~~ the ~~second~~third quarter of ~~2019~~2020. LPG export margin increased ~~primarily~~ due to higher volumes driven ~~in part~~ by ~~phased~~expansion ~~expansions~~ of our LPG export capabilities~~, partially offset by lower fees~~. Marketing margin decreased ~~primarily~~ due to less optimization margin realized in our marketing businesses.

Operating expenses were higher primarily due to the ~~addition~~inclusion of ~~incremental~~our share of operating expenses associated with GCF, increased costs attributable to our fractionation ~~capacity~~and LPG export expansions, higher taxes primarily attributable to Grand Prix and to ~~Train~~additional 7incremental fractionation capacity, and higher ~~compensation~~maintenance ~~and~~primarily ~~benefits~~attributable ~~and~~to ~~higher~~Grand ~~maintenance~~Prix, partially offset by lower fuel and power costs ~~and cost reduction measures~~.

Other

	Three Months Ended June 30,							Six Months Ended June 30,
	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	$	1088.86	$	7(101.02	)	$	3189.8	$	~~127~~215.29	$	—(101.1	)	$	~~127~~317.20
Operating margin	$	1088.86	$	7(101.02	)	$	3189.8	$	~~127~~215.29	$	—(101.1	)	$	~~127~~317.20

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.”

Liquidity and Capital Resources

As of ~~June~~September 30, 2020, we had $~~173~~248.60 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~~facility (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 ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing or repaying our indebtedness, and meeting our collateral requirements, 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.”

Our main sources of liquidity and capital resources are internally generated cash flows from operations, contributions from TRC that are funded through TRC’s access to debt and equity markets, borrowings under the TRP Revolver and the Securitization Facility, and access to debt 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 facility, cash investments, hedging abilities, customer performance risks and counterparty performance risks.

Short-term Liquidity

Our short-term liquidity as of ~~August~~November 32, 2020 was:

		August 3, 2020
		November 2, 2020
		(In millions)
Cash on hand		$	~~189~~252.63
Total availability under the TRP Revolver			2,200.0
Total availability under the Securitization Facility			250.0
			2,639.6
			2,702.3
Less:	Outstanding borrowings under the TRP Revolver		(~~580~~600.0	)
	Outstanding borrowings under the Securitization Facility		(250.0	)
	Outstanding letters of credit under the TRP Revolver		(5637.85	)
	Total liquidity	$	1,~~752~~814.8

Other potential capital resources associated with our existing arrangements include:

•

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 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 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 ~~June~~September 30, 2020 increased $~~105~~249.47 million compared to December 31, 2019. The increase was primarily attributable to higher inventory balances, lower ~~product~~current ~~purchase~~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 ~~and volumes~~.

Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow, contributions from TRC, borrowings available under the TRP Revolver and the Securitization Facility and proceeds from debt 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 cash distributions to Targa 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 ~~June~~September 30, 2020, total contributions from Stonepeak to the DevCo JVs were $~~906~~911.54 million. As of ~~June~~September 30, 2020, total contributions from funds managed by Blackstone Energy Partners (“Blackstone”) to the Grand Prix Joint Venture were $~~338~~341.63 million. These contributions from Stonepeak and Blackstone are included in noncontrolling interests.

38From 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 $7,217.2 million and $7,005.2 million, respectively.

~~From~~The ~~time~~majority toof ~~time,~~our wedebt ~~issue~~is ~~long-term~~fixed ~~debt~~rate ~~securities~~borrowings; however, ~~which~~ we ~~refer~~have tosome asexposure ~~senior notes. Our senior notes issued~~ to ~~date,~~the ~~generally~~risk ~~have~~of ~~similar~~changes ~~terms~~in ~~other than~~ interest rates, ~~maturity~~primarily ~~dates~~as ~~and~~a ~~redemption~~result ~~premiums.~~of Asthe ofvariable ~~June~~rate ~~30,~~borrowings ~~2020,~~under ~~and~~the ~~December 31, 2019,~~TRP Revolver and the ~~aggregate~~Securitization ~~principal~~Facility. ~~amount~~We ~~outstanding~~may ofenter ~~our~~into ~~senior~~interest ~~notes~~rate ~~and~~hedges ~~other~~with ~~various~~the ~~long-term~~intent ~~debt~~to ~~obligations,~~mitigate ~~including~~the ~~unamortized~~impact of ~~premiums,~~changes ~~debt~~in ~~issuance~~interest ~~costs~~rates ~~and~~on ~~non-current~~cash ~~liabilities~~flows. As of September 30, ~~finance leases~~2020, ~~was~~we ~~$7,144.6~~did ~~million~~not ~~and~~have ~~$7,005.2~~any ~~million,~~interest ~~respectively~~rate hedges.

~~The~~In ~~majority~~2019, ofwe ~~our~~closed ~~debt~~on isthe ~~fixed~~sale ~~rate~~of ~~borrowings;~~a ~~however,~~45% weinterest ~~have~~in ~~some~~Targa ~~exposure~~Badlands to ~~the~~GSO ~~risk~~Capital ofPartners ~~changes~~and inBlackstone ~~interest~~Tactical ~~rates~~Opportunities (collectively, ~~primarily~~“GSO”) asfor a$1.6 ~~result~~billion in cash. Growth capital of Targa Badlands after the ~~variable~~sale ~~rate~~is ~~borrowings~~funded ~~under~~on ~~the~~a ~~TRP~~pro ~~Revolver~~rata ownership basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to GSO and ~~the~~Targa, ~~Securitization~~with ~~Facility~~GSO having a priority right on such MQDs. WeAdditionally, ~~may~~GSO’s ~~enter~~capital ~~into~~contributions ~~interest~~would ~~rate~~have ~~hedges~~a ~~with~~liquidation preference upon a sale of Targa Badlands. Targa Badlands is a discrete entity and the ~~intent~~assets and credit of Targa Badlands are not available to ~~mitigate~~satisfy the ~~impact of~~debts ~~changes~~and inother ~~interest~~obligations ~~rates~~of onTarga ~~cash~~or ~~flows~~its other subsidiaries. As of ~~June~~ September 30, 2020, wethe ~~did~~contributions ~~not~~from ~~have~~GSO ~~any~~were ~~interest rate hedges~~$74.0 million.

InOn ~~2019~~November 2, 2020, we ~~closed~~redeemed on the ~~sale of a 45% interest in Targa Badlands to GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “GSO”) for~~ $1559.6 ~~billion~~million inremaining ~~cash.~~balance ~~Growth capital~~ of ~~Targa~~our ~~Badlands~~5 ~~after~~¼% ~~the~~Senior ~~sale~~Notes isdue ~~funded on a pro rata ownership basis~~2023. 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 June 30, 2020, the contributions from GSO were $74.0 million.

~~During~~In the ~~six~~third ~~months~~quarter ~~ended~~of ~~June 30,~~ 2020, we ~~repurchased~~issued ~~a portion of the outstanding senior notes on the open market, paying~~ $~~239~~1.80 ~~million~~billion ~~plus~~of ~~accrued~~4⅞% ~~interest~~Senior toNotes ~~repurchase~~due ~~$303.3 million of the notes~~2031, resulting in ~~a $61.1 million~~ net ~~gain,~~proceeds ~~which included the write-off~~ of $2991.40 million ~~in related debt issuance costs~~. WeA ~~may~~portion ~~retire or purchase various series~~ of ~~our~~the ~~outstanding~~net ~~debt~~proceeds ~~through~~from ~~cash~~the ~~purchases~~issuance ~~and/or~~were ~~exchanges~~used ~~for~~to ~~other~~fund ~~debt,~~the inTender ~~open~~Offer ~~market~~and ~~purchases,~~redemption ~~privately~~payments ~~negotiated~~for ~~transactions~~our or6¾% ~~otherwise. Such repurchases or exchanges~~Notes, ifwith ~~any,~~the ~~will~~remainder ~~depend~~used onfor ~~prevailing~~repayment ~~market~~of ~~conditions,~~borrowings ~~our~~under ~~liquidity~~the ~~requirements,~~TRP ~~contractual restrictions and other factors~~Revolver. ~~The amounts involved may be material.~~

Additionally, during the first half of 2020, we repurchased a portion of the 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 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 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.”

Distributions on our 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 our general partner. Distributions on our 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 our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. If we do not (or a third party with our prior written consent does not) exercise this option, then the Preferred Unitholders have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our Partnership Agreement.

Compliance with Debt Covenants

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

Cash Flow

Cash Flows from Operating Activities

Six Months Ended June 30,
Nine Months Ended September 30,
2020		2019		2020 vs. 2019
(In millions)
$	~~706~~1,054.69	$	~~545~~897.04	$	~~161~~157.65

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 ~~gas~~ processing, ~~crude~~ gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs, ~~and~~ 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.

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

Six Months Ended June 30,
Nine Months Ended September 30,
2020			2019			2020 vs. 2019
(In millions)
$	(~~472~~654.10	)	$	(12,~~961~~619.97	)	$	1,~~489~~965.87

Cash used in investing activities decreased in 2020 compared to 2019, primarily due to lower outlays for property, plant and equipment of $1,134.6 million, resulting from the completion of construction of Grand Prix, Train 6, and additional processing plants and associated infrastructure in the Permian Basin in 2019. The change is also attributable to proceeds of $134.1 million received from the sale of our Delaware crude gathering system and a $193.4 million decrease in our contributions to unconsolidated affiliates primarily due to the completion of GCX Pipeline in 2019.41

Cash used in investing activities decreased in 2020 compared to 2019, primarily due to lower outlays for property, plant and equipment of $1,630.7 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

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2020			2019
Source of Financing Activities, net	(In millions)
	(In millions)
Distributions	$	(295.0	)	$	(679.1	)
Source of Financing Activities, net
Contributions from (distributions to) noncontrolling interests		(180.5	)		367.6
Distributions	$	(346.8	)	$	(921.5	)
Debt, including financing costs		73.5			239.0
Contributions from (distributions to) noncontrolling interests		(277.3	)		419.8
Contributions from TRC and General Partner		50.0			190.0
Debt, including financing costs		130.1			823.7
Contributions from TRC and General Partner		50.0			200.0
Sale of ownership interests in subsidiaries		—			1,619.7
Payment of contingent consideration		—			(317.1	)
Other		—			(10.7	)
Net cash provided by financing activities	$	(~~352~~444.0	)	$	1,~~409~~813.49

In 2020, net cash used in financing activities is primarily due to distributions to TRC, and net distributions to noncontrolling interests, partially offset by a net increase of debt outstanding and contributions from TRC and General Partner. 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 ~~net~~the ~~borrowings~~issuance ~~under~~of ~~our~~the ~~credit~~4⅞% ~~facility~~Senior Notes due 2031 that resulted in cash proceeds of $991.0 million, partially offset by ~~repurchases~~repurchasing of 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 ~~contributions~~increase ~~from~~of ~~noncontrolling~~debt ~~interests~~outstanding and a net ~~increase~~contributions offrom ~~debt~~noncontrolling ~~outstanding~~interests. The result was partially offset by payments of 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.

Distributions

TRC is entitled to receive all available Partnership distributions after payments of preferred distributions each quarter.

The following table details the distributions declared and/or paid by us during the ~~six~~nine months ended ~~June~~ September 30, 2020:

Three Months Ended	Date Paid or To Be Paid		Total Distributions			Distributions to Targa Resources Corp.
June 30, 2020	August 13, 2020	$		51.7	$		48.9
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

Preferred Units

Distributions on our Preferred Units are declared and paid monthly. As of ~~June~~ September 30, 2020, we have 5,000,000 Preferred Units outstanding. For the three and ~~six~~nine months ended ~~June~~September 30, 2020, $2.8 million and $58.64 million of distributions were paid. We have accrued distributions to Series A Preferred Unitholders of $0.9 million for ~~June~~September, which were paid subsequently on ~~July~~October 15, 2020.

In ~~July~~October 2020, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit. This distribution will be paid on ~~August~~November 1716, 2020.

Capital Expenditures

~~Our~~The ~~capital~~following ~~expenditures~~table ~~are~~details ~~classified~~cash asoutlays ~~growth~~for capital ~~expenditures,~~projects ~~business~~for ~~acquisitions, and maintenance capital expenditures. Growth capital expenditures improve~~ the ~~service~~nine ~~capability~~months ofended ~~the~~September ~~existing assets~~30, ~~extend~~2020 ~~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.2019:

The following table details cash outlays for capital projects for the six months ended June 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			150.6
Cash outlays for capital projects	$	803.1		$	2,433.8

	Six Months Ended June 30,
	2020			2019
	(In millions)
Capital expenditures:
Growth (1)	$	420.1		$	1,691.5
Maintenance (2)		53.7			71.1
Gross capital expenditures		473.8			1,762.6
Transfers from materials and supplies inventory to property, plant and equipment		(1.8	)		(16.4	)
Change in capital project payables and accruals, net		143.9			4.3
Cash outlays for capital projects	$	615.9		$	1,750.5

(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.

(12) ~~Growth~~Maintenance capital expenditures, net of contributions from noncontrolling interests, were $~~404~~66.21 million and $~~1,440~~95.5 million for the ~~six~~nine months ended ~~June~~September 30, 2020 and 2019. ~~Net contributions to investments in unconsolidated affiliates were $0.3 million and $57.3 million for the six months ended June 30, 2020 and 2019.~~

~~(2)~~We ~~Maintenance~~currently estimate that in 2020 we will invest approximately $700 million in growth capital expenditures, net of ~~contributions from~~ noncontrolling interests, ~~were~~and ~~$51.4~~net ~~million~~contributions ~~and~~to ~~$67.2~~investments ~~million~~in unconsolidated affiliates for ~~the~~announced ~~six~~projects. ~~months~~We ~~ended~~expect ~~June~~that 302020 maintenance capital expenditures, ~~2020~~net ~~and~~of ~~2019~~noncontrolling interests, will be approximately $110 million.

WeTotal ~~currently~~growth ~~estimate~~capital

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