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.

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

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

As of ~~November 5, 2018,~~May 3, 2019, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.

Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” “TRP” or ~~“the Partnership”~~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:

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, 2018~~March 31, 2019 (“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:

						September 30, 2018			December 31, 2017								March 31, 2019			December 31, 2018
						(Unaudited)											(Unaudited)
						(In millions)											(In millions)
ASSETS	ASSETS											ASSETS
Current assets:	Current assets:											Current assets:
Cash and cash equivalents	Cash and cash equivalents					$	187.5		$	124.7		Cash and cash equivalents					$	111.7		$	203.3
Trade receivables, net of allowances of $0.1 and $0.1 million at September 30, 2018 and December 31, 2017							1,036.0			825.7
Trade receivables, net of allowances of $0.2 and $0.1 million at March 31, 2019 and December 31, 2018												Trade receivables, net of allowances of $0.2 and $0.1 million at March 31, 2019 and December 31, 2018						751.7			864.4
Inventories	Inventories						177.9			204.5		Inventories						197.9			164.7
Assets from risk management activities	Assets from risk management activities						59.6			37.9		Assets from risk management activities						75.9			115.3
Other current assets	Other current assets						66.4			55.8		Other current assets						24.9			32.2
Held for sale assets (see Note 4)							165.7			—
Total current assets	Total current assets						1,693.1			1,248.6		Total current assets						1,162.1			1,379.9
Property, plant and equipment	Property, plant and equipment						16,214.6			14,198.6		Property, plant and equipment						18,182.3			17,213.8
Accumulated depreciation							(4,133.8	)		(3,768.7	)
Accumulated depreciation and amortization												Accumulated depreciation and amortization						(4,479.2	)		(4,285.5	)
Property, plant and equipment, net	Property, plant and equipment, net						12,080.8			10,429.9		Property, plant and equipment, net						13,703.1			12,928.3
Intangible assets, net	Intangible assets, net						2,029.6			2,165.8		Intangible assets, net						1,940.2			1,983.2
Goodwill, net	Goodwill, net						256.6			256.6		Goodwill, net						46.6			46.6
Long-term assets from risk management activities	Long-term assets from risk management activities						8.4			23.2		Long-term assets from risk management activities						23.1			34.1
Investments in unconsolidated affiliates	Investments in unconsolidated affiliates						441.5			221.6		Investments in unconsolidated affiliates						605.9			490.5
Other long-term assets	Other long-term assets						16.5			13.3		Other long-term assets						50.0			27.5
Total assets	Total assets					$	16,526.5		$	14,359.0		Total assets					$	17,531.0		$	16,890.1

LIABILITIES AND OWNERS' EQUITY	LIABILITIES AND OWNERS' EQUITY											LIABILITIES AND OWNERS' EQUITY
Current liabilities:	Current liabilities:											Current liabilities:
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities					$	1,984.1		$	1,106.6		Accounts payable and accrued liabilities					$	1,619.4		$	1,636.9
Accounts payable to Targa Resources Corp.	Accounts payable to Targa Resources Corp.						136.5			76.9		Accounts payable to Targa Resources Corp.						171.2			187.4
Liabilities from risk management activities	Liabilities from risk management activities						176.3			79.7		Liabilities from risk management activities						43.3			33.6
Current debt obligations	Current debt obligations						290.0			350.0		Current debt obligations						318.1			1,027.9
Held for sale liabilities (see Note 4)							1.7			—
Total current liabilities	Total current liabilities						2,588.6			1,613.2		Total current liabilities						2,152.0			2,885.8
Long-term debt	Long-term debt						5,243.9			4,268.0		Long-term debt						6,683.5			5,197.4
Long-term liabilities from risk management activities	Long-term liabilities from risk management activities						67.5			19.6		Long-term liabilities from risk management activities						9.4			3.1
Deferred income taxes, net	Deferred income taxes, net						24.0			24.0		Deferred income taxes, net						23.9			23.9
Other long-term liabilities	Other long-term liabilities						245.2			576.0		Other long-term liabilities						258.3			233.8
Contingencies (see Note 15)
Contingencies (see Note 16)												Contingencies (see Note 16)
Owners' equity:	Owners' equity:											Owners' equity:
Series A preferred limited partners	Series A preferred limited partners	Issued		Outstanding			120.6			120.6		Series A preferred limited partners	Issued		Outstanding			120.6			120.6
September 30, 2018			5,000,000		5,000,000
December 31, 2017			5,000,000		5,000,000
March 31, 2019												March 31, 2019		5,000,000		5,000,000
December 31, 2018												December 31, 2018		5,000,000		5,000,000
Common limited partners	Common limited partners	Issued		Outstanding			6,525.5			6,500.3		Common limited partners	Issued		Outstanding			5,961.0			6,227.2
September 30, 2018			275,168,410		275,168,410
December 31, 2017			275,168,410		275,168,410
March 31, 2019												March 31, 2019		275,168,410		275,168,410
December 31, 2018												December 31, 2018		275,168,410		275,168,410
General partner	General partner	Issued		Outstanding			808.7			808.2		General partner	Issued		Outstanding			797.1			802.6
September 30, 2018			5,629,136		5,629,136
December 31, 2017			5,629,136		5,629,136
March 31, 2019												March 31, 2019		5,629,136		5,629,136
December 31, 2018												December 31, 2018		5,629,136		5,629,136
Accumulated other comprehensive income (loss)	Accumulated other comprehensive income (loss)						(165.7	)		(46.0	)	Accumulated other comprehensive income (loss)						64.8			124.9
							7,289.1			7,383.1								6,943.5			7,275.3
Noncontrolling interests in subsidiaries							1,068.2			475.1
Noncontrolling interests												Noncontrolling interests						1,460.4			1,270.8
Total owners' equity	Total owners' equity						8,357.3			7,858.2		Total owners' equity						8,403.9			8,546.1
Total liabilities and owners' equity	Total liabilities and owners' equity					$	16,526.5		$	14,359.0		Total liabilities and owners' equity					$	17,531.0		$	16,890.1

See notes to consolidated financial statements.	See notes to consolidated financial statements.											See notes to consolidated financial statements.

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2018			2017			2018			2017			2019			2018
	(Unaudited)												(Unaudited)
	(In millions)												(In millions)
Revenues:
Sales of commodities (see Note 3)	$	2,654.1		$	1,871.5		$	6,981.4		$	5,353.1
Fees from midstream services (see Note 3)		332.3			260.3			904.9			759.0
Sales of commodities													$	1,976.5		$	2,173.7
Fees from midstream services														322.9			281.9
Total revenues		2,986.4			2,131.8			7,886.3			6,112.1			2,299.4			2,455.6
Costs and expenses:
Product purchases (see Note 3)		2,383.5			1,663.1			6,229.7			4,737.8
Product purchases														1,726.0			1,941.0
Operating expenses		194.9			155.5			538.7			462.6			190.2			173.2
Depreciation and amortization expense		206.3			208.3			607.1			602.8			237.4			198.1
General and administrative expense		59.3			46.6			165.0			139.4			77.7			52.6
Impairment of property, plant and equipment		—			378.0			—			378.0
Other operating (income) expense		61.8			0.6			15.7			17.2			3.4			0.3
Income (loss) from operations		80.6			(320.3	)		330.1			(225.7	)		64.7			90.4
Other income (expense):
Interest expense, net		(75.7	)		(51.9	)		(113.3	)		(169.5	)
Interest income (expense), net														(75.4	)		20.2
Equity earnings (loss)		3.0			0.2			6.4			(16.6	)		2.8			1.5
Gain (loss) from financing activities		—			—			(1.3	)		(10.7	)		(1.4	)		—
Change in contingent considerations		(16.6	)		126.8			(12.1	)		125.6			(9.7	)		(56.1	)
Other, net		—			0.2			—			(2.7	)
Income (loss) before income taxes		(8.7	)		(245.0	)		209.8			(299.6	)		(19.0	)		56.0
Income tax (expense) benefit		—			—			—			4.2			—			—
Net income (loss)		(8.7	)		(245.0	)		209.8			(295.4	)		(19.0	)		56.0
Less: Net income (loss) attributable to noncontrolling interests		9.7			9.7			32.0			25.9			11.4			13.2
Net income (loss) attributable to Targa Resources Partners LP	$	(18.4	)	$	(254.7	)	$	177.8		$	(321.3	)	$	(30.4	)	$	42.8

Net income attributable to preferred limited partners	$	2.8		$	2.8		$	8.4		$	8.4		$	2.8		$	2.8
Net income (loss) attributable to general partner		(0.4	)		(5.2	)		3.4			(6.6	)		(0.7	)		0.8
Net income (loss) attributable to common limited partners		(20.8	)		(252.3	)		166.0			(323.1	)		(32.5	)		39.2
Net income (loss) attributable to Targa Resources Partners LP	$	(18.4	)	$	(254.7	)	$	177.8		$	(321.3	)	$	(30.4	)	$	42.8

	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
	2018			2017			2018			2017				2019				2018
	(Unaudited)																(Unaudited)
	(In millions)													(In millions)
Net income (loss)	$	(8.7	)	$	(245.0	)	$	209.8		$	(295.4	)	Net income (loss)	$	(19.0	)		$	56.0
Other comprehensive income (loss):													Other comprehensive income (loss):
Commodity hedging contracts:													Commodity hedging contracts:
Change in fair value		(139.6	)		(106.8	)		(178.0	)		(10.5	)	Change in fair value		(38.8	)			64.6
Settlements reclassified to revenues		23.9			2.1			58.3			2.2		Settlements reclassified to revenues		(21.3	)			26.7
Other comprehensive income (loss)		(115.7	)		(104.7	)		(119.7	)		(8.3	)	Other comprehensive income (loss)		(60.1	)			91.3
Comprehensive income (loss)		(124.4	)		(349.7	)		90.1			(303.7	)	Comprehensive income (loss)		(79.1	)			147.3
Less: Comprehensive income (loss) attributable to noncontrolling interests		9.7			9.7			32.0			25.9		Less: Comprehensive income (loss) attributable to noncontrolling interests		11.4				13.2
Comprehensive income (loss) attributable to Targa Resources Partners LP	$	(134.1	)	$	(359.4	)	$	58.1		$	(329.6	)	Comprehensive income (loss) attributable to Targa Resources Partners LP	$	(90.5	)		$	134.1

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, 2017

5,000

$
120.6

275,168

$
6,500.3

5,629

$
808.2

$
(46.0
)

$
475.1

$
7,858.2

Contributions from Targa
   Resources Corp.

—

—

—

529.2

—

10.8

—

—

540.0

Acquisition of related party (see Note 14)

—

—

—

—

—

—

—

1.1

1.1

Distributions to noncontrolling
   interests

—

—

—

—

—

—

—

(51.5
)

(51.5
)
Contributions from noncontrolling
   interests

—

—

—

—

—

—

—

611.6

611.6

Purchase of noncontrolling
   interests in subsidiary

—

—

—

—

—

—

—

(0.1
)

(0.1
)
Other comprehensive income
  (loss)

—

—

—

—

—

—

(119.7
)

—

(119.7
)
Net income (loss)

—

8.4

—

166.0

—

3.4

—

32.0

209.8

Distributions

—

(8.4
)

—

(670.0
)

—

(13.7
)

—

—

(692.1
)
Balance, September 30, 2018

5,000

$
120.6

275,168

$
6,525.5

5,629

$
808.7

$
(165.7
)

$
1,068.2

$
8,357.3

																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
Distributions to noncontrolling interests		—		—			—		—			—		—			—			(18.6	)		(18.6	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			196.8			196.8
Other comprehensive income (loss)		—		—			—		—			—		—			(60.1	)		—			(60.1	)
Net income (loss)		—	2.8				—		(32.5	)		—		(0.7	)		—			11.4			(19.0	)
Distributions		—		(2.8	)		—		(233.7	)		—		(4.8	)		—			—			(241.3	)
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

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, 2016

5,000

$
120.6

275,168

$
5,939.9

5,629

$
796.7

$
(61.8
)

$
355.2

$
7,150.6

Contributions from Targa
   Resources Corp.

—

—

—

1,587.5

—

32.5

—

—

1,620.0

Purchase of noncontrolling
   interests in subsidiary

—

—

—

—

—

—

—

(12.5
)

(12.5
)
Distributions to
   noncontrolling interests

—

—

—

—

—

—

—

(33.4
)

(33.4
)
Contributions from
   noncontrolling interests

—

—

—

—

—

—

—

93.8

93.8

Other comprehensive
   income (loss)

—

—

—

—

—

—

(8.3
)

—

(8.3
)
Net income (loss)

—

8.4

—

(323.1
)

—

(6.6
)

—

25.9

(295.4
)
Distributions

—

(8.4
)

—

(612.2
)

—

(12.5
)

—

—

(633.1
)
Balance, September 30, 2017

5,000

$
120.6

275,168

$
6,592.1

5,629

$
810.1

$
(70.1
)

$
429.0

$
7,881.7

																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, 2017		5,000	$	120.6			275,168	$	6,500.3			5,629	$	808.2		$	(46.0	)	$	475.1		$	7,858.2
Contributions from Targa Resources Corp.		—		—			—		58.8			—		1.2			—			—			60.0
Purchase of noncontrolling interests in subsidiary		—		—			—		—			—		—			—			1.2			1.2
Distributions to noncontrolling interests		—		—			—		—			—		—			—			(16.5	)		(16.5	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			280.1			280.1
Other comprehensive income (loss)		—		—			—		—			—		—			91.3			—			91.3
Net income (loss)		—		2.8			—		39.2			—		0.8			—			13.2			56.0
Distributions		—		(2.8	)		—		(221.2	)		—		(4.5	)		—			—			(228.5	)
Balance, March 31, 2018	��	5,000	$	120.6			275,168	$	6,377.1			5,629	$	805.7		$	45.3		$	753.1		$	8,101.8

			Nine Months Ended September 30,
			2018			2017				Three Months Ended March 31,
										2019			2018
		(Unaudited)							(Unaudited)
		(In millions)							(In millions)
Cash flows from operating activities	Cash flows from operating activities
Net income (loss)	Net income (loss)		$	209.8		$	(295.4	)		$	(19.0	)	$	56.0
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense	Amortization in interest expense			6.8			7.1				2.4			2.3
Depreciation and amortization expense	Depreciation and amortization expense			607.1			602.8				237.4			198.1
Impairment of property, plant and equipment				—			378.0
Accretion of asset retirement obligations	Accretion of asset retirement obligations			2.8			3.0				1.0			0.9
Increase (decrease) in redemption value of mandatorily redeemable preferred interests	Increase (decrease) in redemption value of mandatorily redeemable preferred interests			(66.3	)		8.5				—			(72.5	)
Equity (earnings) loss of unconsolidated affiliates	Equity (earnings) loss of unconsolidated affiliates			(6.4	)		16.6				(2.8	)		(1.5	)
Distributions of earnings received from unconsolidated affiliates	Distributions of earnings received from unconsolidated affiliates			16.0			8.4				4.8			4.2
Risk management activities	Risk management activities			9.6			7.3				7.2			10.9
(Gain) loss on sale or disposition of assets	(Gain) loss on sale or disposition of assets			14.3			16.6				3.2			(0.1	)
(Gain) loss from financing activities	(Gain) loss from financing activities			1.3			10.7				1.4			—
Change in contingent considerations included in Other expense (income)				12.1			(125.6	)
Change in contingent considerations											9.7			56.1
Changes in operating assets and liabilities, net of business acquisitions:	Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets	Receivables and other assets			(221.7	)		(91.5	)			83.9			114.2
Inventories	Inventories			(16.6	)		(136.4	)			(60.6	)		110.2
Accounts payable and other liabilities	Accounts payable and other liabilities			374.7			53.1				39.0			(124.6	)
Net cash provided by operating activities	Net cash provided by operating activities			943.5			463.2				307.6			354.2
Cash flows from investing activities	Cash flows from investing activities
Outlays for property, plant and equipment	Outlays for property, plant and equipment			(2,033.6	)		(866.6	)			(942.9	)		(595.9	)
Outlays for business acquisition, net of cash acquired				—			(570.8	)
Proceeds from sale of assets	Proceeds from sale of assets			71.5			—				0.5			—
Investments in unconsolidated affiliates	Investments in unconsolidated affiliates			(223.7	)		(7.5	)			(117.4	)		(88.0	)
Return of capital from unconsolidated affiliates	Return of capital from unconsolidated affiliates			2.2			2.2				—			1.5
Other, net	Other, net			(9.2	)		(14.8	)			(9.0	)		5.1
Net cash used in investing activities	Net cash used in investing activities			(2,192.8	)		(1,457.5	)			(1,068.8	)		(677.3	)
Cash flows from financing activities	Cash flows from financing activities
Debt obligations:	Debt obligations:
Proceeds from borrowings under credit facility	Proceeds from borrowings under credit facility			950.0			1,496.0				750.0			600.0
Repayments of credit facility	Repayments of credit facility			(970.0	)		(1,216.0	)			(780.0	)		(240.0	)
Proceeds from borrowings under accounts receivable securitization facility	Proceeds from borrowings under accounts receivable securitization facility			440.0			281.6				378.0			—
Repayments of accounts receivable securitization facility	Repayments of accounts receivable securitization facility			(500.0	)		(278.5	)			(350.4	)		(50.0	)
Proceeds from issuance of senior notes	Proceeds from issuance of senior notes			1,000.0			—				1,500.0
Redemption of senior notes	Redemption of senior notes			—			(287.6	)			(749.4	)		—
Principal payments of finance leases											(2.7	)		—
Costs incurred in connection with financing arrangements	Costs incurred in connection with financing arrangements			(15.8	)		(0.1	)			(12.8	)		—
Purchase of noncontrolling interests in subsidiary				(0.1	)		(12.5	)
Contributions from general partner	Contributions from general partner			10.8			32.5				—			1.2
Contributions from TRC	Contributions from TRC			529.2			1,587.5				—			58.8
Contributions from noncontrolling interests	Contributions from noncontrolling interests			611.6			93.8				196.8			280.1
Distributions to noncontrolling interests	Distributions to noncontrolling interests			(51.5	)		(33.4	)			(18.6	)		(16.5	)
Distributions to unitholders	Distributions to unitholders			(692.1	)		(633.1	)			(241.3	)		(228.5	)
Net cash provided by (used in) financing activities				1,312.1			1,030.2
Net cash provided by financing activities											669.6			405.1
Net change in cash and cash equivalents	Net change in cash and cash equivalents			62.8			35.9				(91.6	)		82.0
Cash and cash equivalents, beginning of period	Cash and cash equivalents, beginning of period			124.7			68.0				203.3			124.7
Cash and cash equivalents, end of period	Cash and cash equivalents, end of period		$	187.5		$	103.9			$	111.7		$	206.7

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.

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 PRA.”

See Note 19 – 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.

~~We have prepared these~~The accompanying unaudited consolidated financial statements have been prepared in accordance ~~with GAAP for interim financial information and~~ with the instructions to Form 10-Q and ~~Article 10 of Regulation S-X. Accordingly, they~~ do not include all ~~of the~~ information and ~~footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all~~ disclosures required by ~~GAAP for annual periods. These unaudited consolidated financial statements and other~~GAAP. Therefore, this information ~~included in this Quarterly Report~~ should be read in conjunction with our consolidated financial statements and notes ~~thereto included~~contained in our Annual Report.

The ~~unaudited consolidated financial statements for the three and nine months ended September 30, 2018 include~~information furnished herein reflects all adjustments that ~~we believe~~ are, in the opinion of management, necessary for a fair statement of the results ~~for~~of the interim ~~periods.~~periods reported. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation.

~~Our financial~~ Operating results for the three ~~and nine~~ months ended ~~September 30, 2018~~March 31, 2019, are not necessarily indicative of the results that may be expected for the ~~full year.~~

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 three months ended March 31, 2019.

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842). The amendments in this update ~~require, among other items, that lessees recognize~~supersede the ~~following for all~~ leases ~~(with~~guidance in Topic 840. We adopted Topic 842 on January 1, 2019 by applying the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We are currently monitoring recent exposure drafts and clarifications issued by the FASB.

~~In January 2018, the FASB issued ASU 2018-01,~~ ~~Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842.~~ ~~The amendments in this update permit an entity to elect an~~ optional transition ~~practical expedient to not evaluate land easements that existed or expired before the entity’s adoption of Topic 842 and that were not previously accounted for as leases under Topic 840.~~

~~In July 2018, the FASB issued ASU 2018-10,~~ ~~Codification Improvements to Topic 842, Leases. The amendments~~method in this update affect narrow aspects of the guidance issued in ASU 2016-02 and is intended to alleviate unintended consequences from applying the new standard. The amendments do not make substantive changes to the core provisions or principles of the new standard and will be considered during our implementation process.

~~In July 2018, the FASB also issued ASU 2018-11,~~ ~~Leases (Topic 842): Targeted Improvements. The amendments in this update provide entities with an optional transition method,~~ASU-2018-11, which permits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. ~~In addition,~~The adoption of Topic 842 did not result in a cumulative effect adjustment to retained earnings on January 1, 2019. As part of the ~~amendments in this update also provide lessors with~~adoption of Topic 842, we recognized a net right-of-use asset of $64.2 million (net of $0.4 million of lease incentives/deferred rent) and lease liability of $64.6 million. Other practical ~~expedient (provided certain conditions are met),~~expedients we elected include:

We recognize the lessee, our leasing activity primarily consists of railcars, office space, tractors, vehicles, land, and terminals. Though the evaluation process is still in progress, we currently anticipate that the new lease guidance will result in changes to the way we recognize, present and disclose our operating leases in our consolidated financial statements, including the recognition of a lease liability and an offsetting right-of-use asset in our consolidated balance sheetfollowing for ~~our operating~~all leases (with the exception of short-term leases). at the commencement date:

We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered short-term leases, which are excluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the commencement date based on ~~Financial Instruments~~the present value of future lease payments over the lease term. The right-of-use asset also includes any lease prepayments and excludes lease incentives. As most of the Company’s leases do not provide an implicit interest rate, we use our incremental borrowing rate as the discount rate to compute the present value of our lease liability. The discount rate applied is determined based on information available on the date of adoption for all leases existing as of that date, and on the date of lease commencement for all subsequent leases.

Our lease arrangements may include variable lease payments based on an index or market rate or may be based on performance. For variable lease payments based on an index or market rate, we estimate and apply a rate based on information available at the ~~FASB issued ASU 2016-13,~~ ~~Financial Instruments-Credit Losses (Topic 326): Measurement~~commencement date. Variable lease payments based on performance are excluded from the calculation of ~~Credit Losses on Financial Instruments.~~ ~~The amendments~~the right-of-use asset and lease liability, and are recognized in ~~this update change~~our Consolidated Statements of Operations when the contingency underlying such variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options are included in the measurement of ~~credit losses~~our right-of-use asset and liability, provided we determine that we are reasonably certain to exercise the option.

See Note 11 – Leases for most financial assets and certain other instruments that are not measured at fair value through net income. The amendments affect investments in loans, investments in debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that ~~have~~ the contractual right to receive cash. The amendments also replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2019, with early adoption permitted. We expect to early adopt the amendments on January 1, 2019 and do not expect a material impact on our consolidated financial statements.additional details.

Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract

In August 2018, the FASB issued ASU 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract. The amendments in this update require customers in a cloud computing arrangement that is a service contract to assess related implementation costs for capitalization using the same approach as implementation costs associated with internal-use software. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2019, with early adoption permitted. ~~We are currently evaluating the effect of~~Entities may apply the amendments using a retrospective or prospective transition method. The amendments will be effective for Targa in the first quarter of 2020. We currently plan to apply the prospective transition method and do not expect a material impact on our ~~consolidated financial statements and related disclosures.~~

~~In May 2014, the FASB issued ASU 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606)~~. The amendments in this update supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The amendments also create a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The core principal of Topic 606 is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to, in exchange for those goods or services. We adopted Topic 606 on January 1, 2018 by applying the modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption of Topic 606 did not result in a material cumulative effect adjustment to retained earnings on January 1, 2018. However, the adoption did have an impact on the classification between “Fees from midstream services” and “Product purchases,” as well as the reporting of gross vs. net revenues, as discussed below:

~~The following tables summarize the effects of adoption on our consolidated financial statements:~~

~~See Note 16 – Revenue for information regarding our performance obligations and Note 19 – Segment Information for further disaggregation of our revenues.~~Consolidated Financial Statements.

~~In August 2017, FASB issued ASU 2017-12,~~ ~~Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities~~. The amendments in this update are intended to better align risk management activities and financial reporting for hedging relationships. The amendments cover multiple aspects of hedge accounting including: (1) change the way in which ineffectiveness is accounted; (2) allow for new hedge strategies; and (3) change hedge disclosures. Under the new guidance, companies will have the option to perform a qualitative quarterly effectiveness assessment once the initial quantitative test has been performed. In addition, any ineffectiveness that exists is required to be recorded in other comprehensive income instead of in earnings as was required under prior guidance. Several new hedging strategies qualify for hedge accounting treatment, most of these strategies involving the hedging of contractually specified components. Lastly, disclosure requirements have been updated to: (1) require that hedge income be presented on the same line item as the related hedged item; (2) require hedge program objectives to be disclosed; and (3) eliminate the requirement to separately disclose ineffectiveness. These amendments are effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted. We early adopted the amendments on January 1, 2018, with the changes to ineffectiveness resulting in no effect on retained earnings, as we had no accumulated ineffectiveness at December 31, 2017. See updated disclosures as a result of these amendments in Note 12 – Derivative Instruments and Hedging Activities and Note 19 – Segment Information.

~~In August 2016, the FASB issued ASU 2016-15,~~ ~~Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)~~. The amendments in this update clarify how entities should classify certain cash receipts and cash payments in the statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the update clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. The amendments were effective for us on January 1, 2018 and were adopted on a retrospective basis, with no material effect on our consolidated financial statements. In addition, we elected to continue to apply our historical cumulative earnings approach to classify distributions received from equity method investees.

In ~~February~~ ~~2017, FASB issued ASU 2017-05,~~ ~~Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20). The amendments in this update clarify the scope of Subtopic 610-20 and add guidance for partial sales of nonfinancial assets. Subtopic 610-20 was issued in May 2014 as part of ASU 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606),~~ and provides guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with noncustomers. Specifically, the amendments clarify that the guidance applies to all nonfinancial assets and in substance nonfinancial assets unless other specific guidance applies and defines "in substance nonfinancial asset" as an asset or group of assets for which substantially all of the fair value consists of nonfinancial assets and the group or subsidiary is not a business. These amendments also impact the accounting for partial sales of nonfinancial assets, whereby an entity that transfers its controlling interest in a nonfinancial asset but retains a noncontrolling ownership interest, will measure the retained interest at fair value resulting in the full gain/loss recognition upon sale. These amendments were effective for us on January 1, 2018 and were adopted by applying the modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption did not result in a cumulative effect adjustment to retained earnings on January 1, 2018.

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. Besides those noted below, there were no other significant updates or revisions to our policies during the nine months ended September 30, 2018.

We have multiple types of contracts with commercial counterparties and many of these may result in cash inflows to Targa due to the structure of settlement provisions with embedded fees. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606. Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases.

Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues.Subsequent Event

We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis.

Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price.

Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract.

The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation.

Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue.

Certain provisions of our service contracts (i.e., tiered price structures) require further assessment to determine if the allocation exception for variable consideration is met. If the allocation exception is not met, we estimate the total consideration that we expect to be entitled to for the applicable term of the contract, based on projections of future activity. In such instance, revenue is recognized using an output method of progress based on the volume of commodities serviced during the reporting period. Our estimate of total consideration is reassessed each reporting period until contract completion.

For contracts with minimum volume commitments, we generally expect the customer to meet the commitment. However, such contracts are reassessed throughout the term of the commitment, and if we no longer expect the customer to meet the commitment, the allocation exception for variable consideration would not be met. That is, from that point onwards, an allocation based on the applicable fee applied to the volumes serviced does not depict the amount of consideration which we expect to be entitled to, in exchange for the service. In such instance, revenue will be recognized up to the minimum volume commitment in proportion to the days of service elapsed and the remaining duration of the commitment.

Contract assets are presented separately from amounts presented as a receivable when or as a performance obligation(s) is satisfied and prior to having a right to payment that is unconditional at the end of the reporting period. We classify our contract assets as receivables because we generally have an unconditional right to payment for the commodities sold or services performed at the end of reporting period.

In ~~May 2017,~~February 2019, we announced ~~plans to construct~~an extension of Grand Prix ~~a new common carrier~~from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with the Williams Companies, Inc. (“Williams”) Bluestem Pipeline and link the Conway, Kansas, and Mont Belvieu, Texas, NGL ~~pipeline.~~markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix ~~will transport volumes from the Permian Basin~~ and fractionate at our ~~North Texas system to our fractionation and storage complex in the NGL market hub at~~ Mont Belvieu ~~Texas. Grand Prix will be supported by~~facilities. Williams also had an initial option to purchase a 20% equity interest in one of our ~~volumes~~recently announced 110 MBbl/d fractionation trains (Train 7 or Train 8) in Mont Belvieu. Williams exercised its option to acquire a 20% equity interest in Train 7 and ~~other third-party customer volume commitments, and is expected to be fully in service~~subsequently executed a joint venture agreement with us in the second quarter of 2019. Certain fractionation-related infrastructure for Train 7, including storage caverns and brine handling, will be funded and owned 100% by Targa.

On April 3, 2019, we ~~sold~~closed on the sale of a ~~25%~~45% interest in Targa Badlands LLC, the entity that holds substantially all of our ~~consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”),~~ ~~which owns the portion of Grand Prix extending from the Permian Basin to Mont Belvieu, Texas,~~assets in North Dakota, to funds managed by GSO Capital Partners and Blackstone ~~Energy Partners ("Blackstone"~~Tactical Opportunities (collectively, “Blackstone”).for $1.6 billion in cash. We ~~are~~used the net cash proceeds to repay debt and for general corporate purposes, including funding our growth capital program. We continue to be the operator of Targa Badlands LLC and ~~construction manager~~hold majority governance rights. Future growth capital of ~~Grand Prix.~~Targa Badlands LLC is expected to be funded on a pro rata ownership basis. Targa Badlands LLC will pay a minimum quarterly distribution (“MQD”) to Blackstone and Targa, with Blackstone having a priority right on such MQDs. Additionally, Blackstone’s capital contributions would have a liquidation preference upon a sale of Targa Badlands LLC. We ~~account for Grand Prix~~will continue to present Targa Badlands LLC on a consolidated basis in our consolidated financial statements.

Concurrent with the sale of the 25% interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC (“EagleClaw”), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin.

In March 2018, we announced an extension of Grand Prix from North Texas into southern Oklahoma. The pipeline expansion is supported by long-term commitments for both transportation and fractionation services from our existing and future processing plants in the Arkoma area in our SouthOK system and from third-party commitments, including a long-term commitment for transportation and fractionation with Valiant Midstream, LLC. The ~~extension of Grand Prix into southern Oklahoma is not part of the Grand Prix Joint Venture and its expected cost of approximately $350 million will be funded exclusively by Targa.~~

The capacity of the 24-inch pipeline segment from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d. The pipeline segment from the Permian Basin will be connected to a 30-inch diameter pipeline segment in North Texas, where Permian, North Texas and Oklahoma volumes will be connected to Mont Belvieu, and will have capacity of approximately 450 MBbl/d, expandable to 950 MBbl/d. The capacity from southern Oklahoma to North Texas will vary based on telescoping pipe size.

~~Grand Prix economics related to volumes flowing on the pipeline from the Permian Basin to Mont Belvieu are included in the Blackstone and~~ ~~Grand Prix Development LLC (“Grand Prix DevCo JV”) joint venture arrangements, while the economics related to volumes flowing from North Texas and southern Oklahoma to Mont Belvieu accrue solely to Targa’s benefit.~~

~~The total cost for~~ ~~Grand Prix, including the extension into southern Oklahoma, is expected to be approximately $1.7 billion.~~

~~In July 2017, we entered into the Cayenne Pipeline, LLC joint venture (“Cayenne~~ ~~Joint Venture”)~~ with American Midstream LLC to convert an existing 62-mile gas pipeline to an NGL pipeline connecting the VESCO plant in Venice, Louisiana to the Enterprise Products Operating LLC (“Enterprise”) pipeline at Toca, Louisiana, for delivery to Enterprise’s Norco Fractionator. We acquired a 50% interest in the Cayenne ~~Joint Venture for $5.0 million. The project commenced operations in December 2017. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the Cayenne Joint Venture.~~

In ~~December 2017,~~ ~~we entered into definitive joint venture agreements with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP (“DCP”) with respect to the joint development of~~ ~~Gulf Coast Express Pipeline~~ ~~(“GCX”),~~ ~~a natural gas pipeline from the Waha hub to Agua Dulce in South Texas. The pipeline~~ ~~will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. We and DCP each own a 25% interest, and KMTP owns a~~ 50% interest in GCX. In addition, Apache Corporation (which will also be a shipper on GCX) has an option to purchase up to a 15% equity stake from KMTP. KMTP will serve as the operator and constructor of GCX, and we will commit significant volumes to the pipeline. In ~~addition, Pioneer Natural Resources Company, a joint~~ ~~owner~~ ~~in our WestTX Permian Basin system has committed volumes to the project. GCX is designed to transport up to~~ 1.~~98 Bcf/d of natural gas and the total cost of the project is expected to be approximately $1.75 billion. GCX is expected to be in service in the fourth quarter of 2019, pending regulatory approvals. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the GCX Joint Venture.~~

In January 2018, we formed a 50/50 joint venture with Hess Midstream Partners LP to construct a new 200 MMcf/d natural gas processing plant (“LM4 Plant”) at the Partnership’s existing Little Missouri facility (“Little Missouri 4”). The LM4 Plant is anticipated to be completed in the second quarter of 2019. The Partnership is managing the construction of, and will operate, the LM4 Plant. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the Little Missouri 4 Joint Venture.

In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix, GCX and an approximately 100 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). Stonepeak owns a 95% interest in the Grand Prix DevCo JV, which owns a 20% interest in the Grand Prix Joint Venture (which does not include the extension into southern Oklahoma). Stonepeak owns an 80% interest in both Targa GCX Pipeline LLC (“GCX DevCo JV”), which owns our 25% interest in GCX, and Targa Train 6 LLC (“Train 6 DevCo JV”), which owns a 100% interest in certain assets associated with Train 6. The Train 6 DevCo JV does not include certain fractionation-related infrastructure such as brine and storage, which will be funded and owned 100% by us. We hold the remaining interests in the DevCo JVs as well as control the management, construction and operation of Grand Prix and Train 6.

For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, we have the option to acquire all or part of Stonepeak’s interests in the DevCo JVs. Targa may acquire up to 50% of Stonepeak’s invested capital in multiple increments with a minimum of $100 million, and Stonepeak’s remaining 50% interest in a single final purchase. The purchase price payable for such partial or full interests is based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs. Targa will control the management of the DevCo JVs unless and until Targa declines to exercise its option to acquire Stonepeak's interests. ~~Train 6 is expected to begin operations in the first quarter of 2019. Grand Prix~~ ~~is expected to be fully in service in the second quarter of 2019~~. GCX ~~is expected to be in service in the fourth quarter of 2019, pending regulatory approvals.~~

We hold a controlling interest in each of the DevCo JVs, as we have the majority voting interest and the supermajority voting provisions of the joint venture agreements do not represent substantive participating rights and are protective in nature to Stonepeak. As a result, we have consolidated each of the DevCo JVs in our financial statements~~. We continue to account for Grand Prix and Train 6 on a consolidated basis in our consolidated financial statements, and continue to account for GCX as~~ ~~an equity method investment as disclosed in Note 7 – Investments in Unconsolidated Affiliates.~~

In April 2018, we joined WhiteWater Midstream, LLC (“WhiteWater Midstream”), WPX Energy, Inc., and Markwest Energy Partners, L.P., as joint venture partners in WhiteWater Midstream’s Delaware Basin Agua Blanca pipeline (“Agua Blanca Joint Venture”). The Agua Blanca pipeline is an approximately 160 mile natural gas residue pipeline with an initial capacity of 1.4 Bcf/d. The pipeline, which commenced operations in April 2018, runs from Orla, Texas to the Waha hub, servicing portions of Culberson, Loving, Pecos, Reeves and Ward counties with multiple direct downstream connections including to the Trans-Pecos Header. We acquired a 10% interest in the Agua Blanca ~~Joint Venture~~ ~~for $3.5 million. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the Agua Blanca Joint Venture.~~

In May 2018, Sanchez Midstream Partners LP and we merged our respective 50% interests in the Carnero Gathering and Carnero Processing Joint Ventures, which own the high-pressure Carnero gathering line and Raptor natural gas processing plant, to form an expanded 50/50 joint venture in South Texas (the “Carnero Joint Venture”). In connection with the joint venture merger transactions, the Carnero Joint Venture acquired our 200 MMcf/d Silver Oak II natural gas processing plant located in Bee County Texas, which increased the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d. Additional enhancements to the prior joint ventures include dedication of over 315,000 additional gross acres in the Western Eagle Ford, operated by Sanchez Energy Corporation, under a new long-term firm gas gathering and processing agreement. Including the approximately 105,000 Catarina acreage, the joint venture now has over 420,000 gross acres dedicated long term. We operate the gas gathering and processing facilities in the joint venture. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.

In August 2018, we announced that we were involved in the development of the Whistler Pipeline (“Whistler”), consisting of a pipeline designed to transport natural gas from the Waha area of the Permian Basin to Agua Dulce in South Texas~~, with an additional segment continuing from Agua Dulce to Wharton County, TX. We are continuing to work on securing commitments on Whistler and the project remains subject to final investment decisions and regulatory approvals.~~

On March 1, 2017, we completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”).

We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the “initial purchase price”). Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments. The first earn-out payment due in May 2018 expired with no required payment. The second potential earn-out payment would occur in May 2019 and will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.

~~Pro Forma Impact of Permian Acquisition on Consolidated Statements of Operations~~

The following summarized unaudited pro forma Consolidated Statements of Operations information for the three and nine months ended September 30, 2017 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future.

The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to the unaudited results of the acquired businesses for the periods indicated:

A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its fair value. We agreed to pay up to an additional $935.0 million in aggregate potential earn-out payments in May 2018 and May 2019. The acquisition date fair value of the potential earn-out payments of $416.3 million was originally recorded within Other long-term liabilities on our Consolidated Balance Sheets. Changes in the fair value of the liability (that were not accounted for as revisions of the acquisition date fair value) have been included in Other income (expense).

During the three months ended September 30, 2018 and 2017, we recognized $16.6 million expense and $126.6 million income, respectively, in Other income (expense) related to the change in fair value of the contingent consideration. The increase in fair value of the contingent consideration during the three months ended September 30, 2018 was ~~primarily attributable to a shorter discount period. The underlying forecasted volumes reflect the most recently observed production trends.~~ ~~During the nine months ended~~ ~~September 30, 2018 and 2017, we recognized $12.0 million expense and $125.5 million income in Other income (expense) related to the change in fair value of the contingent consideration~~.

The portion of the earn-out due in 2018 expired with no required payment. As of September 30, 2018, the fair value of the second potential earn-out payment of $329.0 million has been recorded as a component of Accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. See Note 13 – Fair Value Measurements for additional discussion of the fair value methodology.

During the third quarter of 2018, we executed agreements to sell our Downstream refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD, to a third party for approximately $160 million. The sale closed in the fourth quarter of 2018 and we intend to use the proceeds to repay debt and to fund a portion of our growth capital program. In relation to the sale, we classified our Tacoma and Baltimore refined products and crude oil storage and terminaling facilities assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $57.5 million included within Other operating income (expense) in our Consolidated Statements of Operations for the three and nine months ended September 30, 2018. The sale of these businesses does not qualify for reporting as discontinued operations as it did not represent a strategic shift that would have a major effect on our operations and financial results.

~~The adjusted carrying amounts of the assets and liabilities held for sale as of September 30, 2018 are as follows:~~

	September 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Commodities	$	163.3	$	191.6	$	176.4	$	151.1
Materials and supplies		14.6		12.9		21.5		13.6
	$	177.9	$	204.5	$	197.9	$	164.7

	September 30, 2018			December 31, 2017			Estimated Useful Lives (In Years)	March 31, 2019			December 31, 2018			Estimated Useful Lives (In Years)
Gathering systems	$	7,395.2		$	7,037.2		5 to 20	$	8,417.2		$	7,547.9		5 to 20
Processing and fractionation facilities		3,842.4			3,563.0		5 to 25		4,287.4			4,001.0		5 to 25
Terminaling and storage facilities		1,068.1			1,244.1		5 to 25		1,173.0			1,138.7		5 to 25
Transportation assets		456.1			343.6		10 to 25		1,016.8			445.1		10 to 25
Other property, plant and equipment		313.6			303.5		3 to 25		398.6			334.3		3 to 25
Land		146.8			125.7		—		149.2			144.3		—
Construction in progress		2,992.4			1,581.5		—		2,699.2			3,602.5		—
Finance lease right-of-use assets									40.9			—
Property, plant and equipment		16,214.6			14,198.6				18,182.3			17,213.8
Accumulated depreciation		(4,133.8	)		(3,768.7	)
Accumulated depreciation and amortization									(4,479.2	)		(4,285.5	)
Property, plant and equipment, net	$	12,080.8		$	10,429.9			$	13,703.1		$	12,928.3

Intangible assets	$	2,736.6		$	2,736.6		10 to 20	$	2,736.6		$	2,736.6		10 to 20
Accumulated amortization		(707.0	)		(570.8	)			(796.4	)		(753.4	)
Intangible assets, net	$	2,029.6		$	2,165.8			$	1,940.2		$	1,983.2

~~Impairment~~During the preparation of ~~North Texas Gathering~~the Company's consolidated financial statements for the three months ended March 31, 2019, 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 ~~Processing Assets~~accordingly, has not adjusted the historical financial statements. The Company has recorded the cumulative impact of the adjustment in the three months ended March 31, 2019. This adjustment resulted in a one-time $12.5 million overstatement of depreciation expense during the three months ended March 31, 2019.

~~We recorded a non-cash pre-tax impairment charge of $378.0~~During the three months ended March 31, 2019 and 2018, depreciation expense was $194.4 million ~~in the third quarter of 2017 for the partial impairment of gas processing facilities~~ and gathering systems associated with our North Texas operations in our Gathering and Processing segment. The impairment was a result of our assessment that forecasted undiscounted future net cash flows from operations, while positive, would not be sufficient to recover the existing total net book value of the underlying assets. Given the price environment at the time, we projected a continuing decline in natural gas production across the Barnett Shale in North Texas due in part to producers pursuing more attractive opportunities in other basins. We measured the impairment of property, plant and equipment using discounted estimated future cash flow analysis (“DCF”) including a terminal value (a Level 3 fair value measurement). The future cash flows were based on our estimates of future revenues, income from operations and other factors, such as timing of capital expenditures. We took into account current and expected industry and market conditions, including commodity prices and volumetric forecasts. The discount rate used in our DCF analysis was based on a weighted average cost of capital determined from relevant market comparisons. These carrying value adjustments are included in Impairment of property, plant and equipment in our Consolidated Statements of Operations.$152.4 million.

Intangible assets consist of customer contracts and customer relationships acquired in the Permian Acquisition and the acquisition of the Flag City Plant assets in SouthTX in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlands acquisition in 2012.prior business combinations. The fair ~~values~~value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate.

Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers. We are amortizing these assets over lives ranging from 10 to 20 years using a method that closely reflects the cash flow pattern underlying their ~~intangible asset~~ valuation, or the straight-line method, if a reliably determinable pattern of amortization could not be identified.

The estimated annual amortization expense for intangible assets is approximately ~~$182.6 million,~~ $171.6 million, $159.4 million, $149.5 million, $141.2 million and ~~$141.2~~$136.0 million for each of the years ~~2018~~2019 through ~~2022.~~2023.

~~During the second quarter of~~ ~~2018, we sold our inland marine barge business to a third party for $69.3 million.~~ As a result of the sale, we recognized a gain of $48.1 million in our Consolidated Statements of Operations for the nine months ended September 30, 2018 as part of Other operating (income) expense. We continue to own and operate two ocean-going barges.

The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting.

The T2 Joint Ventures ~~Acquisitions~~were formed to provide services for the benefit of their joint interest owners and ~~Divestitures for discussion~~have capacity lease agreements with their joint interest owners, which cover costs of operations (excluding depreciation and amortization). On April 1, 2019, we assumed the operatorship of the ~~formation of our GCX~~T2 Joint ~~Venture and Little Missouri 4 Joint Venture, and our acquisition of interests in the Cayenne Joint Venture and the Agua Blanca Joint Venture.~~Ventures.

The following table shows the activity related to our investments in unconsolidated affiliates:

	Balance at December 31, 2017		Equity Earnings (Loss)			Cash Distributions (1)			Acquisition		Contributions (2)		Balance at September 30, 2018		Balance at December 31, 2018		Equity Earnings (Loss)			Cash Distributions			Contributions		Balance at March 31, 2019
GCF	$	45.8	$	14.2		$	(16.3	)	$	—	$	—	$	43.7	$	40.3	$	4.3		$	(2.2	)	$	—	$	42.4
T2 LaSalle ~~(3)~~(1)		54.1		(3.8	)		—			—		0.1		50.4		49.3		(1.5	)		—			—		47.8
T2 Eagle Ford ~~(3)~~(1)		109.2		(7.6	)		—			—		—		101.6		99.0		(2.4	)		—			—		96.6
T2 EF Cogen		3.9		(1.3	)		—			—		—		2.6
Cayenne		8.6		4.6			(1.9	)		—		5.5		16.8		16.6		1.9			(2.6	)		—		15.9
GCX		—		0.1			—			—		154.8		154.9
GCX (2)																211.6		0.6			—			110.4		322.6
Little Missouri 4		—		—			(8.0	)		—		75.3		67.3		67.3		—			—			7.0		74.3
Agua Blanca		—		0.2			—			3.5		0.5		4.2		6.4		(0.1	)		—			—		6.3
Total	$	221.6	$	6.4		$	(26.2	)	$	3.5	$	236.2	$	441.5	$	490.5	$	2.8		$	(4.8	)	$	117.4	$	605.9

	September 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Commodities	$	975.5	$	711.9	$	779.3	$	721.9
Other goods and services		499.8		286.9		379.4		474.5
Interest		83.3		54.1		91.0		79.4
Permian Acquisition contingent consideration, estimated current portion		329.0		6.8
Permian Acquisition contingent consideration						317.9		308.2
Income and other taxes		88.6		26.3		40.4		45.4
Other		7.9		20.6		11.4		7.5
	$	1,984.1	$	1,106.6	$	1,619.4	$	1,636.9

Accounts payable and accrued liabilities includes ~~$53.8~~$28.9 million and ~~$49.7~~$52.2 million of liabilities to creditors to whom we have issued checks that remained outstanding as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017.~~2018.

As a result of a 2017 acquisition of certain gas gathering and processing and crude gathering assets in the Permian Basin (the “Permian Acquisition”), we have included the related contingent consideration in accounts payable and accrued liabilities as of March 31, 2019, and December 31, 2018. The ~~current portion of the~~ Permian Acquisition contingent consideration represents the ~~estimated~~second earn-out payment, which will be paid in May 2019, and is derived on a multiple of realized gross margin during the earn-out period from contracts that existed on March 1, 2017, in accordance with the terms of the purchase and sale agreements. The first potential earn-out payment would have occurred in May 2018 and expired with no required payment.

Changes in the value of the contingent consideration liability have been included in Other income (expense). For the period from December 31, 2018 to March 31, 2019, the value of the contingent consideration increased by $9.7 million, primarily attributable to the elimination of discounting and an increase in actual gross margin through the end of the earn-out period. During the three months ended March 31, 2018, we recognized $56.0 million of expense in Other income (expense) related to the change in fair value of the ~~earn-out payments due within twelve months~~contingent consideration.

See Note 14 – Fair Value Measurements for additional discussion of the ~~respective balance sheet dates.~~fair value methodology.

	September 30, 2018			December 31, 2017			March 31, 2019			December 31, 2018
Current:
Accounts receivable securitization facility, due December 2018 (1)	$	290.0		$	350.0
Accounts receivable securitization facility, due December 2019 (1)							$	307.6		$	280.0
Senior unsecured notes, 4⅛% fixed rate, due November 2019								—			749.4
								307.6			1,029.4
Debt issuance costs, net of amortization								—			(1.5	)
Finance lease liabilities								10.5			—
Current debt obligations								318.1			1,027.9

Long-term:
Senior secured revolving credit facility, variable rate, due June 2023 (2)		—			20.0			670.0			700.0
Senior unsecured notes:
4⅛% fixed rate, due November 2019		749.4			749.4
5¼% fixed rate, due May 2023		559.6			559.6			559.6			559.6
4¼% fixed rate, due November 2023		583.9			583.9			583.9			583.9
6¾% fixed rate, due March 2024		580.1			580.1			580.1			580.1
5⅛% fixed rate, due February 2025		500.0			500.0			500.0			500.0
5⅞% fixed rate, due April 2026		1,000.0			—			1,000.0			1,000.0
5⅜% fixed rate, due February 2027		500.0			500.0			500.0			500.0
6½% fixed rate, due July 2027								750.0			—
5% fixed rate, due January 2028		750.0			750.0			750.0			750.0
TPL notes, 4¾% fixed rate, due November 2021		6.5			6.5
TPL notes, 5⅞% fixed rate, due August 2023		48.1			48.1
6⅞% fixed rate, due January 2029								750.0			—
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		0.3			0.4			0.3			0.3
		5,277.9			4,298.0			6,698.5			5,228.5
Debt issuance costs, net of amortization		(34.0	)		(30.0	)		(42.7	)		(31.1	)
Finance lease liabilities								27.7			—
Long-term debt		5,243.9			4,268.0			6,683.5			5,197.4
Total debt obligations	$	5,533.9		$	4,618.0		$	7,001.6		$	6,225.3
Irrevocable standby letters of credit outstanding	$	76.6		$	27.2
Irrevocable standby letters of credit outstanding (2)							$	69.8		$	79.5

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the ~~nine~~three months ended ~~September 30, 2018:~~March 31, 2019:

As of ~~September 30, 2018,~~March 31, 2019, we were in compliance with the covenants contained in our various debt agreements.

In ~~April 2018,~~January 2019, we issued ~~$1.0 billion aggregate principal amount~~$750.0 million of 5⅞~~% senior notes due April 2026 (the “5~~⅞6½% Senior Notes due ~~2026”). We used the~~July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of ~~$991.9 million after costs~~$1,487.3 million. The net proceeds from ~~this offering~~the offerings were used to ~~repay~~redeem in full our outstanding 4⅛% Senior Notes due 2019 with the remainder used for general partnership purposes, which included repaying borrowings under our credit ~~facilities and for general partnership purposes. The 5~~facilities.

In February 2019, we redeemed in full our outstanding 4⅞⅛% Senior Notes due ~~2026 are unsecured senior obligations that have substantially~~2019 at par value plus accrued interest through the ~~same terms and covenants as our other senior notes.~~

~~In June 2018, we entered into an agreement~~redemption date. The redemption resulted in a non-cash loss to amend and restate the TRP Revolver, which extended the maturity date from October 2020 to June 2023, increased available commitments from $1.6 billion to $2.2 billion and lowered the applicable margin range and commitment fee range used in the calculationwrite-off $1.4 million of ~~interest. Our ability to request additional commitments of $500.0 million remained unchanged.~~

The TRP Revolver bears interest, at our option, either at the base rate or the Eurodollar rate. The base rate is equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin (a) before the collateral release date, ranging from 0.25% to 1.25% dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA and (b) upon and after the collateral release date, ranging from 0.125% to 0.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The Eurodollar rate is equal to LIBOR rate plus an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings.

We are required to pay a commitment fee equal to an applicable rate ranging from (a) before the collateral release date, 0.25% to 0.375% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA) and (b) upon and after the collateral release date, 0.125% to 0.35% (dependent on our non-credit-enhanced senior unsecured long-term debt ratings) times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The TRP Revolver’s covenants remained substantially the same.

~~During the nine months ended September 30, 2018, we incurred a loss of $1.3 million to partially write-off~~unamortized debt issuance costs, ~~associated with~~which is included in Gain (loss) from financing activities in the ~~TRP Revolver amendment as a result~~Consolidated Statements of a change in syndicate members. The remaining debt issuance costs, along with debt issuance costs incurred with this amendment, will be amortized on a straight-line basis over the TRP Revolver’s new term.

	September 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Asset retirement obligations	$	53.4	$	50.3	$	63.4	$	55.0
Mandatorily redeemable preferred interests		10.3		76.2
Deferred revenue		176.4		136.2		174.6		175.5
Permian Acquisition contingent consideration, noncurrent portion		—		310.2
Operating lease liabilities						17.3		—
Other liabilities		5.1		3.1		3.0		3.3
Total long-term liabilities	$	245.2	$	576.0	$	258.3	$	233.8

Our asset retirement obligations (“ARO”) primarily relate to certain gas gathering pipelines, processing facilities and ~~processing facilities.~~

Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037.

For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. As redemption cannot occur before 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of redemption value as of September 30, 2018.transportation assets.

In February 2018, the parties amended the agreements governing each joint venture to: (i) increase the priority return for capital contributions made on or after January 1, 2017; and (ii) add a non-consent feature effective with respect to certain capital projects undertaken on or after January 1, 2017. During the nine months ended September 30, 2018, the change in the estimated redemption value of the mandatorily redeemable preferred interests is primarily attributable to the amendments.

We have certain long-term contractual arrangements ~~under~~for which we have received consideration ~~but which require future performance by Targa. These arrangements result in~~that we are not yet able to recognize as revenue. The resulting deferred revenue ~~which~~ will be recognized ~~over the periods that performance will be provided.~~once all conditions for revenue recognition have been met.

Deferred revenue includes ~~consideration~~$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. On December 27, 2015, Targa Terminals LLC and Noble Americas Corp., then a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (the “Splitter Agreement”) under which we will build and operate a crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (the “Channelview Splitter”) and provide approximately 730,000 Bbl of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 Bbl/d of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter project is expected to be substantially completed inIn December 2018, ~~and has an estimated total cost of approximately $150 million.~~ ~~In January 2018,~~ Vitol ~~US Holding Co. acquired Noble Americas Corp.As of September 30, 2018,~~elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments ~~due under~~are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement ~~totaling $129.0 million, have been received.~~

deferred revenue is currently dependent upon resolution of the dispute 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.

Balance at December 31, 2017	$	136.2
Balance at December 31, 2018				$	175.5
Additions		43.1			—
Revenue recognized		(2.9	)		(0.9	)
Balance at September 30, 2018	$	176.4
Balance at March 31, 2019				$	174.6

~~Upon closing~~We have non-cancellable operating leases primarily associated with our office facilities, rail assets, land, and storage and terminal assets. We have finance leases primarily associated with our tractors and vehicles. Our leases have remaining lease terms of 1 to 6 years, some of which include options to extend the Permian Acquisition, a contingent consideration liability arising from potential earn-out provisions was recognized at its preliminary fair value. See Note 4 – Newly-Formed Joint Ventures, Acquisitionslease term for up to 10 years.

The balances of right-of-use assets and ~~Divestitures. The first potential earn-out payment would have occurred in May 2018 while the second potential earn-out payment would occur in May 2019. The acquisition date fair value~~liabilities of ~~the contingent consideration of $416.3 million was recorded within Other long-term liabilities~~finance leases and operating leases, and their locations on our Consolidated Balance ~~Sheets.~~ ~~For~~Sheets are as follows:

Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements of Operations, depending on the ~~period from the acquisition date to December 31, 2017, the fair value~~nature of the ~~contingent consideration decreased by $99.3 million, bringing the total Permian Acquisition contingent consideration~~leases. Finance lease costs are included in Depreciation and amortization expense and Interest income (expense) in our Consolidated Statements of Operations. The components of lease expense were as follows:

Other supplemental information related to ~~$317.0 million at December 31, 2017, of which $6.8 million was a current liability.~~our leases are as follows:

The weighted-average remaining lease terms for operating leases and finance leases are 4 years and 3 years, respectively. The weighted-average discount rates for operating leases and finance leases are 3.9% and 3.9%, respectively.

The ~~portion~~following table presents the maturities of ~~the earn-out due in 2018 expired with no required payment. For the period from~~our lease liabilities under non-cancellable leases as of March 31, 2019:

The following table presents future minimum payments under non-cancellable leases as of December 31, ~~2017 to September 30, 2018, the fair value of~~ ~~the contingent consideration increased~~ by $12.0 million. As of September 30, 2018, the fair value of the second potential earn-out payment of $329.0 million has been recorded as a component of accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. See Note 13 – Fair Value Measurements for additional discussion of the fair value methodology.2018:

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

The following table details the distributions declared ~~and/or~~and paid by us for the ~~nine~~three months ended ~~September 30, 2018:~~March 31, 2019:

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 the ~~nine~~three months ended ~~September 30, 2018,~~March 31, 2019, TRC ~~made total capital~~did not make contributions to ~~us of $540.0 million.~~us.

Our Preferred Units rank senior to our common units with respect to 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 $8.4~~ million of distributions to the holders of ~~preferred units~~Preferred Units (“Preferred Unitholders”) for the three ~~and nine~~ months ended ~~September 30, 2018.~~March 31, 2019.

In ~~October 2018,~~April 2019, 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 ~~November~~May 15, ~~2018.~~2019.

Note 1213 — ~~Derivative Instruments~~Derivative Instruments and Hedging Activities

The primary purpose of our commodity risk management activities is 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, ~~and~~ (ii) future commodity purchases and sales in our Logistics and Marketing segment and (iii) natural gas transportation basis risk in our Logistics and Marketing segment. ~~These~~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. We have~~prices and are designated ~~these derivative contracts~~ as cash flow hedges for accounting purposes.

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

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

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

At ~~September 30, 2018,~~March 31, 2019, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2018		2019		2020		2021		2022		2023		Instrument	Unit	2019		2020		2021		2022		2023
Natural Gas	Swaps	MMBtu/d		210,109		158,246		31,630		11,821		-		-	Swaps	MMBtu/d		175,364		79,930		52,055		-		-
Natural Gas	Basis Swaps	MMBtu/d		158,478		109,281		70,417		56,658		40,000		20,000	Basis Swaps	MMBtu/d		111,100		189,119		166,658		150,000		95,000
NGL	Swaps	Bbl/d		19,820		16,269		11,607		2,434		-		-	Swaps	Bbl/d		17,903		13,267		3,676		-		-
NGL	Futures	Bbl/d		33,620		2,890		3,115		-		-		-	Futures	Bbl/d		9,735		4,645		-		-		-
NGL	Options	Bbl/d		1,310		410		-		-		-		-	Options	Bbl/d		410		-		-		-		-
Condensate	Swaps	Bbl/d		4,990		3,413		1,170		388		-		-	Swaps	Bbl/d		4,266		2,390		1,404		-		-
Condensate	Options	Bbl/d		590		590		-		-		-		-	Options	Bbl/d		590		-		-		-		-

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 ~~values~~value of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:

		Fair Value as of September 30, 2018				Fair Value as of December 31, 2017					Fair Value as of March 31, 2019				Fair Value as of December 31, 2018
	Balance Sheet	Derivative		Derivative		Derivative		Derivative		Balance Sheet	Derivative		Derivative		Derivative		Derivative
	Location	Assets		Liabilities		Assets		Liabilities		Location	Assets		Liabilities		Assets		Liabilities
Derivatives designated as hedging instruments
Commodity contracts	Current	$	57.5	$	164.1	$	37.9	$	78.6	Current	$	72.5	$	25.2	$	112.5	$	18.9
	Long-term		6.9		65.2		23.2		18.7	Long-term		20.4		3.1		31.6		1.5
Total derivatives designated as hedging instruments		$	64.4	$	229.3	$	61.1	$	97.3		$	92.9	$	28.3	$	144.1	$	20.4
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	2.1	$	12.2	$	—	$	1.1	Current	$	3.4	$	18.1	$	2.8	$	14.7
	Long-term		1.5		2.3		—		0.9	Long-term		2.7		6.3		2.5		1.6
Total derivatives not designated as hedging instruments		$	3.6	$	14.5	$	—	$	2.0		$	6.1	$	24.4	$	5.3	$	16.3
Total current position		$	59.6	$	176.3	$	37.9	$	79.7		$	75.9	$	43.3	$	115.3	$	33.6
Total long-term position			8.4		67.5		23.2		19.6			23.1		9.4		34.1		3.1
Total derivatives		$	68.0	$	243.8	$	61.1	$	99.3		$	99.0	$	52.7	$	149.4	$	36.7

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

		Gross Presentation							Pro Forma Net Presentation						Gross Presentation								Pro Forma Net Presentation
September 30, 2018		Asset		Liability			Collateral		Asset		Liability
March 31, 2019														March 31, 2019	Asset		Liability			Collateral			Asset		Liability
Current Position	Current Position													Current Position
	Counterparties with offsetting positions or collateral	$	59.6	$	(163.6	)	$	39.0	$	11.3	$	(76.3	)	Counterparties with offsetting positions or collateral	$	69.0	$	(42.0	)	$	(7.3	)	$	43.5	$	(23.8	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		6.9		-			-			6.9		-
	Counterparties without offsetting positions - liabilities		-		(12.7	)		-		-		(12.7	)	Counterparties without offsetting positions - liabilities		-		(1.3	)		-			-		(1.3	)
			59.6		(176.3	)		39.0		11.3		(89.0	)			75.9		(43.3	)		(7.3	)		50.4		(25.1	)
Long Term Position	Long Term Position													Long Term Position
	Counterparties with offsetting positions or collateral		8.4		(42.2	)		-		-		(33.8	)	Counterparties with offsetting positions or collateral		19.0		(9.1	)		-			13.5		(3.6	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		4.1		-			-			4.1		-
	Counterparties without offsetting positions - liabilities		-		(25.3	)		-		-		(25.3	)	Counterparties without offsetting positions - liabilities		-		(0.3	)		-			-		(0.3	)
			8.4		(67.5	)		-		-		(59.1	)			23.1		(9.4	)		-			17.6		(3.9	)
Total Derivatives	Total Derivatives													Total Derivatives
	Counterparties with offsetting positions or collateral		68.0		(205.8	)		39.0		11.3		(110.1	)	Counterparties with offsetting positions or collateral		88.0		(51.1	)		(7.3	)		57.0		(27.4	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		11.0		-			-			11.0		-
	Counterparties without offsetting positions - liabilities		-		(38.0	)		-		-		(38.0	)	Counterparties without offsetting positions - liabilities		-		(1.6	)		-			-		(1.6	)
		$	68.0	$	(243.8	)	$	39.0	$	11.3	$	(148.1	)		$	99.0	$	(52.7	)	$	(7.3	)	$	68.0	$	(29.0	)

		Gross Presentation							Pro Forma Net Presentation						Gross Presentation								Pro Forma Net Presentation
December 31, 2017		Asset		Liability			Collateral		Asset		Liability
December 31, 2018														December 31, 2018	Asset		Liability			Collateral			Asset		Liability
Current Position	Current Position													Current Position
	Counterparties with offsetting positions or collateral	$	37.9	$	(74.7	)	$	22.9	$	13.8	$	(27.7	)	Counterparties with offsetting positions or collateral	$	100.0	$	(33.6	)	$	(14.2	)	$	70.0	$	(17.8	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		15.3		-			-			15.3		-
	Counterparties without offsetting positions - liabilities		-		(5.0	)		-		-		(5.0	)	Counterparties without offsetting positions - liabilities		-		-			-			-		-
			37.9		(79.7	)		22.9		13.8		(32.7	)			115.3		(33.6	)		(14.2	)		85.3		(17.8	)
Long Term Position	Long Term Position													Long Term Position
	Counterparties with offsetting positions or collateral		23.2		(17.3	)		-		14.8		(8.9	)	Counterparties with offsetting positions or collateral		8.9		(3.1	)		-			5.9		(0.1	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		25.2		-			-			25.2		-
	Counterparties without offsetting positions - liabilities		-		(2.3	)		-		-		(2.3	)	Counterparties without offsetting positions - liabilities		-		-			-			-		-
			23.2		(19.6	)		-		14.8		(11.2	)			34.1		(3.1	)		-			31.1		(0.1	)
Total Derivatives	Total Derivatives													Total Derivatives
	Counterparties with offsetting positions or collateral		61.1		(92.0	)		22.9		28.6		(36.6	)	Counterparties with offsetting positions or collateral		108.9		(36.7	)		(14.2	)		75.9		(17.9	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		40.5		-			-			40.5		-
	Counterparties without offsetting positions - liabilities		-		(7.3	)		-		-		(7.3	)	Counterparties without offsetting positions - liabilities		-		-			-			-		-
		$	61.1	$	(99.3	)	$	22.9	$	28.6	$	(43.9	)		$	149.4	$	(36.7	)	$	(14.2	)	$	116.4	$	(17.9	)

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 a broker that clears the hedges through an exchange. We maintain a margin deposit with the broker 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 other current assets on our Consolidated Balance Sheets and is not offset against the fair ~~values~~value of our derivative instruments.

The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net ~~liability~~asset of ~~$175.8~~$46.3 million as of ~~September 30, 2018.~~March 31, 2019. 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~~comprehensive income (“OCI”) and amounts reclassified from OCI to revenue ~~and expense~~ for the periods indicated:

	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)												Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Derivatives in Cash Flow	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
Hedging Relationships	2018			2017			2018			2017			2019			2018
Commodity contracts	$	(139.6	)	$	(106.8	)	$	(178.0	)	$	(10.5	)	$	(38.8	)	$	64.6

	Gain (Loss) Reclassified from OCI into Income (Effective Portion)												Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
Location of Gain (Loss)	2018			2017			2018			2017			2019		2018
Revenues	$	(23.9	)	$	(2.1	)	$	(58.3	)	$	(2.2	)	$	21.3	$	(26.7	)

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.

	Location of Gain	Gain (Loss) Recognized in Income on Derivatives												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,						Recognized in Income on	Three Months Ended March 31,
as Hedging Instruments	Derivatives	2018			2017			2018			2017			Derivatives	2019			2018
Commodity contracts	Revenue	$	(1.1	)	$	(1.5	)	$	(14.1	)	$	(2.9	)	Revenue	$	(9.5	)	$	(10.8	)

Based on valuations as of ~~September 30, 2018,~~March 31, 2019, we expect to reclassify commodity hedge-related deferred ~~losses~~gains of ~~$164.9~~$64.6 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2021, with ~~$106.6~~$47.3 million of ~~losses~~gains to be reclassified over the next twelve months.

See Note 1314 – Fair Value Measurements and Note 19 – Segment Information for additional disclosures related to derivative instruments and hedging activities.

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.

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

The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at ~~September 30, 2018,~~March 31, 2019, a net ~~liability~~asset position of ~~$175.8~~$46.3 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 ~~$281.7~~$40.1 million, ignoring an adjustment for counterparty credit risk. 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 ~~liability~~asset of ~~$69.9~~$129.2 million, ignoring an adjustment for counterparty credit risk.

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:

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

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:

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

			September 30, 2018																March 31, 2019
						Fair Value																Fair Value
			Carrying Value			Total			Level 1			Level 2			Level 3				Carrying Value			Total			Level 1			Level 2			Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:																Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)	Assets from commodity derivative contracts (1)		$	67.7		$	67.7		$	—		$	67.7		$	—	Assets from commodity derivative contracts (1)		$	97.2		$	97.2		$	—		$	93.3		$	3.9
Liabilities from commodity derivative contracts (1)	Liabilities from commodity derivative contracts (1)			243.5			243.5			—			231.0			12.5	Liabilities from commodity derivative contracts (1)			50.9			50.9			—			50.5			0.4
Permian Acquisition contingent consideration (2)				329.0			329.0			—			—			329.0
TPL contingent consideration (3)				2.5			2.5			—			—			2.5
TPL contingent consideration (2)																				2.4			2.4			—			—			2.4
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:																Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents	Cash and cash equivalents			187.5			187.5			—			—			—	Cash and cash equivalents			111.7			111.7			—			—			—
TRP Revolver	TRP Revolver			—			—			—			—			—	TRP Revolver			670.0			670.0			—			670.0			—
Senior unsecured notes	Senior unsecured notes			5,277.9			5,322.8			—			5,322.8			—	Senior unsecured notes			6,028.5			6,268.9			—			6,268.9			—
Accounts receivable securitization facility	Accounts receivable securitization facility			290.0			290.0			—			290.0			—	Accounts receivable securitization facility			307.6			307.6			—			307.6			—

		December 31, 2017																December 31, 2018
					Fair Value																Fair Value
			Carrying Value		Total			Level 1			Level 2			Level 3					Carrying Value		Total			Level 1			Level 2			Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:																Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value:
Assets from commodity derivative contracts (1)	Assets from commodity derivative contracts (1)		$	60.3		$	60.3		$	—		$	58.8		$	1.5	Assets from commodity derivative contracts (1)		$	144.4		$	144.4		$	—		$	137.5		$	6.9
Liabilities from commodity derivative contracts (1)	Liabilities from commodity derivative contracts (1)			98.5			98.5			—			93.3			5.2	Liabilities from commodity derivative contracts (1)			31.7			31.7			—			31.3			0.4
Permian Acquisition contingent consideration (2)				317.0			317.0			—			—			317.0
TPL contingent consideration (3)				2.4			2.4			—			—			2.4
Permian Acquisition contingent consideration (3)																				308.2			308.2			—			—			308.2
TPL contingent consideration (2)																	TPL contingent consideration (2)			2.4			2.4			—			—			2.4
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:	Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:																Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents	Cash and cash equivalents			124.7			124.7			—			—			—	Cash and cash equivalents			203.3			203.3			—			—			—
TRP Revolver	TRP Revolver			20.0			20.0			—			20.0			—	TRP Revolver			700.0			700.0			—			700.0			—
Senior unsecured notes	Senior unsecured notes			4,278.0			4,362.4			—			4,362.4			—	Senior unsecured notes			5,277.9			5,088.9			—			5,088.9			—
Accounts receivable securitization facility	Accounts receivable securitization facility			350.0			350.0			—			350.0			—	Accounts receivable securitization facility			280.0			280.0			—			280.0			—

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 ~~or market prices~~ 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.

As of ~~September 30, 2018,~~March 31, 2019, we had 1613 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are (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 is immaterial.

The fair value of the Permian Acquisition contingent consideration as of December 31, 2018, was determined using a Monte Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. ~~A significant decrease~~The Permian Acquisition contingent consideration earn-out period ended on February 28, 2019. The first earn-out payment due in ~~expected~~May 2018 expired with no required payment. The second earn-out payment will be paid in May 2019 and is derived on a multiple of realized gross margin during the earn-out period ~~or significant increase~~from contracts that existed on March 1, 2017, in accordance with the ~~discount rate or volatility would result in a lower~~terms of the purchase and sale agreements. As such, the carrying value of the Permian Acquisition contingent consideration as of March 31, 2019, approximates fair value, ~~estimate.~~ as with our other accounts payables. See Note 8 – Accounts Payable and Accrued Liabilities for additional discussion of the Permian Acquisition contingent consideration.

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 for both models are not observable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. Changes in the fair value of these liabilities are included in Other income (expense) in our Consolidated Statements of Operations.

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

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 (1) costs attributable to Targa’s status as a separate reporting company and (2) until March 2018, costs of Targa providing management and support services to certain unaffiliated spun-off entities. 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. Management believes these transactions are executed on terms that are fair and ~~reasonable.~~reasonable:

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2018		2017		2018		2017		2019		2018
Targa billings of payroll and related costs included in operating expenses	$	61.3	$	54.0	$	177.7	$	148.6	$	54.1	$	59.5
Targa allocation of general and administrative expense		54.6		43.2		149.3		126.6		67.8		47.3
Cash distributions to Targa based on general partner and limited partner ownership		231.2		222.6		683.7		624.7		238.5		225.7
Cash contributions from Targa related to limited partner ownership (1)		450.7		14.7		529.2		1,587.5		—		58.8
Cash contributions from Targa to maintain its 2% general partner ownership		9.2		0.3		10.8		32.5		—		1.2

In December 2010, immediately prior to Targa’s initial public offering, Sajet Resources LLC (“Sajet”) was spun-off from Targa. Certain directors and executive officers of Targa are also directors and executive officers of Sajet. The primary assets of Sajet are real property. Sajet also holds (i) an ownership interest in Floridian Natural Gas Storage Company, LLC through a December 2016 merger with Tesla Resources LLC, (ii) an ownership interest in Allied CNG Ventures LLC and (iii) certain technology rights. Former holders of Targa’s pre-IPO common equity, including certain of Targa’s current and former executives, managers and directors collectively own an 18% interest in Sajet. We provide general and administrative services to Sajet and are reimbursed for these amounts. Services provided to Sajet totaled less than $0.1 million in January and February of 2018.

In March 2018, we acquired the 82% interest in Sajet that was held by Warburg Pincus sponsored funds for $5.0 million in cash (the “Warburg Funds Transaction”) and extinguished Sajet’s third-party debt in exchange for a promissory note from Sajet of $9.9 million. Minority shareholders had the right to join the transaction and sell up to 100% of their membership interests in Sajet to us at substantially the same terms and price as the Warburg Funds Transaction (the “Tag-Along Rights”). Minority shareholders who currently hold, or formerly held, executive positions at Targa, and minority shareholders who are board members of Targa, agreed not to exercise their Tag-Along Rights resulting from the Warburg Funds Transaction. Certain minority shareholders chose to sell interests totaling 1.6% for approximately $0.1 million in April 2018.

~~Since March 2018, Sajet has been accounted for on a consolidated basis in our consolidated financial statements.~~

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 in ~~2018,~~2019, including but not limited to the 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 ~~Health,~~ Environmental ~~Health Section,~~Quality, which assert penalties 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.

On February 26, 2019, the U.S. Environmental Protection Agency Region 8 and Targa Badlands LLC entered into a Final Order and Consent Agreement in connection with Targa Badlands LLC’s alleged violation of Subpart ZZZZ of the National Emission Standards for Hazardous Air Pollutants at its Junction Compressor Station in McKenzie County, North Dakota. The Consent Agreement imposed a $220,000 civil penalty and requires certain compliance improvements.

The following table includes the estimated minimum revenue expected to be recognized in the future related to 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.

In accordance with the optional exemptions that we elected to apply, 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 ~~to which~~that we have the right to invoice for services performed is also excluded from the table above, with the exception of any fixed consideration attributable to such contracts. 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 and~~policy; the estimated remaining duration of such contracts primarily ranges from 1 to 1620 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 additional information on our revenue recognition policy and the adoption of ASU No. 2014-09, see Note 3~~ ~~– Significant Accounting Policies.~~ For disclosures related to disaggregated revenue, see Note 19– Segment Information.

		Nine Months Ended September 30,							Three Months Ended March 31,
		2018				2017			2019			2018
Cash:
Interest paid, net of capitalized interest (1)	$		140.5		$		154.5		$	61.2		$	39.4
Income taxes paid, net of refunds			0.2				(4.9	)		0.3			0.2
Non-cash investing activities:
Deadstock commodity inventory transferred to property, plant and equipment	$		39.4		$		8.3		$	17.5		$	1.7
Impact of capital expenditure accruals on property, plant and equipment			283.9				118.3			(38.4	)		(22.3	)
Transfers from materials and supplies inventory to property, plant and equipment			8.9				2.8			1.1			0.4
Contribution of property, plant and equipment to investments in unconsolidated affiliates			16.0				1.0			—			16.0
Change in ARO liability and property, plant and equipment due to revised cash flow estimate			1.2				3.1
Non-cash balance sheet movements related to assets held for sale (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures):
Trade receivables	$		8.8		$		—
Inventories			5.5				—
Property, plant and equipment, net			151.4				—
Accounts payable and accrued liabilities			(1.7	)			—
Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures):
Contingent consideration recorded at the acquisition date	$		—		$		416.3
Change in ARO liability and property, plant and equipment										7.4			2.1
Non-cash balance sheet movements related to acquisition of related party:
Intercompany payable									$	—		$	1.4
Noncontrolling interest			1.1				—			—			1.2
Lease liabilities arising from recognition of right-of-use assets:
Operating lease									$	0.4		$	—
Finance lease										1.5			—

We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (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 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 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 ~~exposure to~~ the SCOOP and ~~STACK plays)~~STACK) and South Central Kansas; the Williston Basin in North ~~Dakota~~Dakota; and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing 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 storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Marketing segment includes the Grand Prix pipeline, which is currently under ~~construction.~~construction with certain segments of the pipeline currently in operation. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipeline projects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

	Three Months Ended September 30, 2018												Three Months Ended March 31, 2019
	Gathering and Processing		Logistics and Marketing		Other			Corporate and Eliminations			Total		Gathering and Processing		Logistics and Marketing		Other		Corporate and Eliminations			Total
Revenues
Sales of commodities	$	296.7	$	2,378.2	$	(20.8	)	$	—		$	2,654.1	$	247.6	$	1,726.8	$	2.1	$	—		$	1,976.5
Fees from midstream services		199.3		133.0		—			—			332.3		199.9		123.0		—		—			322.9
		496.0		2,511.2		(20.8	)		—			2,986.4		447.5		1,849.8		2.1		—			2,299.4
Intersegment revenues
Sales of commodities		1,069.7		15.5		—			(1,085.2	)		—		822.8		38.4		—		(861.2	)		—
Fees from midstream services		1.5		8.5		—			(10.0	)		—		1.9		5.5		—		(7.4	)		—
		1,071.2		24.0		—			(1,095.2	)		—		824.7		43.9		—		(868.6	)		—
Revenues	$	1,567.2	$	2,535.2	$	(20.8	)	$	(1,095.2	)	$	2,986.4	$	1,272.2	$	1,893.7	$	2.1	$	(868.6	)	$	2,299.4
Operating margin	$	255.3	$	173.5	$	(20.8	)	$	—		$	408.0	$	229.0	$	152.1	$	2.1	$	—		$	383.2
Other financial information:
Total assets (1)	$	11,331.5	$	5,019.0	$	64.2		$	111.8		$	16,526.5	$	11,713.9	$	5,644.9	$	87.9	$	84.3		$	17,531.0
Goodwill	$	256.6	$	—	$	—		$	—		$	256.6	$	46.6	$	—	$	—	$	—		$	46.6
Capital expenditures	$	453.0	$	560.7	$	—		$	4.0		$	1,017.7	$	417.8	$	470.9	$	—	$	16.9		$	905.6

	Nine Months Ended September 30, 2017											Three Months Ended March 31, 2018
	Gathering and Processing		Logistics and Marketing		Other		Corporate and Eliminations			Total		Gathering and Processing		Logistics and Marketing		Other			Corporate and Eliminations			Total
Revenues
Sales of commodities	$	544.4	$	4,804.8	$	3.9	$	—		$	5,353.1	$	265.2	$	1,926.3	$	(17.8	)	$	—		$	2,173.7
Fees from midstream services		399.3		359.7		—		—			759.0		161.3		120.6		—			—			281.9
		943.7		5,164.5		3.9		—			6,112.1		426.5		2,046.9		(17.8	)		—			2,455.6
Intersegment revenues
Sales of commodities		2,209.2		237.8		—		(2,447.0	)		—		866.5		55.7		—			(922.2	)		—
Fees from midstream services		5.1		21.1		—		(26.2	)		—		1.9		6.9		—			(8.8	)		—
		2,214.3		258.9		—		(2,473.2	)		—		868.4		62.6		—			(931.0	)		—
Revenues	$	3,158.0	$	5,423.4	$	3.9	$	(2,473.2	)	$	6,112.1	$	1,294.9	$	2,109.5	$	(17.8	)	$	(931.0	)	$	2,455.6
Operating margin	$	549.3	$	358.5	$	3.9	$	—		$	911.7	$	220.8	$	138.4	$	(17.8	)	$	—		$	341.4
Other financial information:
Total assets (1)	$	10,644.3	$	3,240.9	$	30.8	$	56.2		$	13,972.2	$	10,908.5	$	3,595.1	$	103.0		$	121.1		$	14,727.7
Goodwill	$	256.6	$	—	$	—	$	—		$	256.6	$	256.6	$	—	$	—		$	—		$	256.6
Capital expenditures	$	730.7	$	241.8	$	—	$	15.2		$	987.7	$	273.2	$	251.0	$	—		$	33.8		$	558.0
Business acquisition	$	987.1	$	—	$	—	$	—		$	987.1

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

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2018			2017			2018			2017			2019			2018
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas	$	451.9		$	505.4		$	1,338.5		$	1,485.2		$	411.3		$	470.1
NGL		2,063.2			1,276.2			5,254.4			3,628.5			1,408.1			1,607.3
Condensate		95.7			44.9			286.1			135.8
Condensate and crude oil														137.7			86.9
Petroleum products		68.2			48.6			176.0			108.5			7.6			48.2
		2,679.0			1,875.1			7,055.0			5,358.0			1,964.7			2,212.5
Non-customer revenue:
Derivative activities - Hedge		(23.8	)		(2.1	)		(59.6	)		(2.0	)		21.3			(28.0	)
Derivative activities - Non-hedge (1)		(1.1	)		(1.5	)		(14.0	)		(2.9	)		(9.5	)		(10.8	)
		(24.9	)		(3.6	)		(73.6	)		(4.9	)		11.8			(38.8	)
Total sales of commodities		2,654.1			1,871.5			6,981.4			5,353.1			1,976.5			2,173.7

Fees from midstream services:
Revenue recognized from contracts with customers:
Fractionating and treating		31.1			29.8			90.3			92.8
Storage, terminaling, transportation and export		86.9			75.0			260.8			247.8
NGL transportation and services														36.2			41.1
Storage, terminaling and export														79.6			78.2
Gathering and processing		196.5			138.0			522.3			368.5			194.5			152.1
Other		17.8			17.5			31.5			49.9			12.6			10.5

Total fees from midstream services		332.3			260.3			904.9			759.0			322.9			281.9

Total revenues	$	2,986.4		$	2,131.8		$	7,886.3		$	6,112.1		$	2,299.4		$	2,455.6

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

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2018			2017			2018			2017			2019			2018
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Gathering and Processing operating margin	$	255.3		$	198.3		$	718.4		$	549.3		$	229.0		$	220.8
Logistics and Marketing operating margin		173.5			115.9			441.7			358.5			152.1			138.4
Other operating margin		(20.8	)		(1.0	)		(42.2	)		3.9			2.1			(17.8	)
Depreciation and amortization expenses		(206.3	)		(208.3	)		(607.1	)		(602.8	)
General and administrative expenses		(59.3	)		(46.6	)		(165.0	)		(139.4	)
Impairment of property, plant and equipment		—			(378.0	)		—			(378.0	)
Interest expense, net		(75.7	)		(51.9	)		(113.3	)		(169.5	)
Depreciation and amortization expense														(237.4	)		(198.1	)
General and administrative expense														(77.7	)		(52.6	)
Interest income (expense), net														(75.4	)		20.2
Change in contingent considerations		(16.6	)		126.8			(12.1	)		125.6			(9.7	)		(56.1	)
Other, net		(58.8	)		(0.2	)		(10.6	)		(47.2	)		(2.0	)		1.2
Income (loss) before income taxes	$	(8.7	)	$	(245.0	)	$	209.8		$	(299.6	)	$	(19.0	)	$	56.0

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, ~~2017~~2018 (“Annual Report”), as well as the unaudited consolidated financial statements and notes hereto included in this Quarterly Report on Form 10-Q.

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 PRA.”

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.

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

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 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 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 ~~exposure to~~ the SCOOP and ~~STACK plays)~~STACK) and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.

Our Logistics and Marketing 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 storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Marketing segment also includes the Grand Prix pipeline (“Grand Prix”), as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), which isare both currently under ~~construction.~~construction and expected to fully begin operations in 2019. Grand Prix, once fully completed, will integrate 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 pipeline projects, are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipeline projects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.

In February 2018, in response to increasing production and to meet the infrastructure needs of producers, ~~we have announced the construction of additional processing plants that further expand the gathering and processing footprint of our Permian Midland systems:~~

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. We are ~~constructing~~completing construction of approximately 220 miles of 12- to 24-inch ~~high pressure~~high-pressure rich gas gathering pipelines across the Delaware ~~Basin,~~Basin. We are also constructing a new 250 MMcf/d cryogenic natural gas processing plant (the “Falcon Plant”) in the Delaware Basin that is expected to begin operations in the fourth quarter of ~~2019, and~~ 2019. We have also commenced construction of a second 250 MMcf/d cryogenic natural gas processing plant ~~in Culberson County~~ (the “Peregrine Plant”) in the Delaware Basin that is expected to begin operations in the second quarter of 2020.

We will 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. Total growth capital expenditures related to the plants and ~~high pressure~~high-pressure pipeline system are expected to be approximately $500 million.

In May 2017, we announced plans to build a new plant and further expand the gathering footprint of our Permian Delaware systems. This project includes a new 250 MMcf/d cryogenic processing plant, known as the Wildcat Plant, which began operations in the second quarter of 2018.

We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the "initial purchase price"). Subject to certain performance-based measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments in May 2018 and May 2019. The potential earn-out payments are based upon a multiple of realized gross margin from contracts that existed on March 1, 2017. The 2018 portion of the earn-out expired with no payment required.

New Delaware's gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. The initial New Delaware assets included 70 MMcf/d of processing capacity. In addition, the Oahu Plant, a 60 MMcf/d plant in the Delaware Basin, which was completed in March 2018 and placed into service in April 2018, was added to the New Delaware system. Currently, there is 40 MBbl/d of crude gathering capacity on the New Delaware system.

New Midland's gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the New Midland system.

New Delaware's gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and New Midland's gas gathering and processing assets were connected to our WestTX system in the fourth quarter of 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and is expected to afford enhanced flexibility in serving producers.

In January 2018, we announced the formation of a 50/50 joint venture with Hess Midstream Partners LP tounder which Targa will construct and operate a new 200 MMcf/d natural gas processing plant (“~~LM4 Plant”~~Little Missouri 4”) at Targa’s existing Little Missouri facility. ~~The LM4 Plant~~Little Missouri 4 is anticipated to be completed early in the ~~second~~third quarter of 2019. ~~Targa is managing the construction of, and will operate, the LM4 Plant.~~

In December 2017, ownership of the Flag City Plant assets located in Jackson County, Texas, was transferred to Centrahoma Processing, LLC, a joint venture that we operate (“Centrahoma” or the “Centrahoma Joint Venture”), and in which we have a 60% ownership interest; the remaining 40% ownership interest is held by MPLX, LP (“MPLX”). The former Flag City Plant assets have been relocated to, and installed in, Hughes County, Oklahoma, as a new 150 MMcf/d cryogenic natural gas processing plant (the “Hickory Hills Plant”). The Hickory Hills Plant will process natural gas production from the Arkoma Woodford Basin and is expected to begin operations in the fourth quarter of 2018. In October 2018, Targa contributed the 120 MMcf/d cryogenic Tupelo Plant in Coal County, Oklahoma to Centrahoma. ~~In conjunction with Targa’s contribution of both the Hickory Hills and Tupelo plant assets, MPLX made cash contributions to Centrahoma in order to maintain its 40% ownership interest.~~

In August 2018, we announced that we were involved in the development of the Whistler Pipeline (“Whistler”), consisting of a pipeline designed to transport natural gas from the Waha area of the Permian Basin to Agua Dulce in South Texas, ~~with an additional segment continuing from Agua Dulce to Wharton County, TX. We are continuing to work on securing commitments on Whistler and the project remains subject to final investment decisions and regulatory approvals.~~

In May 2017, we announced initial plans to construct a new common carrier NGL ~~pipeline. The NGL~~ pipeline in Texas and New Mexico, which is owned by Grand Prix Pipeline LLC (“Grand ~~Prix”~~Prix Joint Venture”), a consolidated subsidiary of which Targa owns a 56% interest. Since then, we announced an extension to Southern Oklahoma in March 2018 and an extension to Central Oklahoma in February 2019. Each announced extension is 100% owned by Targa.

Grand Prix will transport ~~volumes~~NGLs from the Permian Basin, ~~and~~ North Texas, Southern Oklahoma, and Central Oklahoma to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. ~~Grand Prix will be supported by our volumes and other third-party customer volume commitments, and~~The pipeline is ~~expected to be fully in service in the second quarter~~comprised of ~~2019.~~

In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the "Grand Prix Joint Venture"), which owns the portion of Grand Prix extending from the Permian Basin to Mont Belvieu, Texas, to funds managed by Blackstone Energy Partners (“Blackstone”). We are the operator and construction manager of Grand Prix.

Concurrent with the sale of the minority interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC ("EagleClaw"), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw's natural gas volumes produced or processed in the Delaware Basin.four primary segments:

The ~~capacity~~three segments noted above are expected to be fully in service in the third quarter of 2019.

Grand Prix ~~economics related to~~ volumes flowing on the pipeline from the Permian Basin to Mont Belvieu are included in the ~~Blackstone and~~ Grand Prix ~~DevCo joint venture arrangements,~~Joint Venture, while the ~~economics related to~~ volumes flowing from North Texas and ~~southern~~ Oklahoma to Mont Belvieu accrue solely to Targa’s benefit.

Total growth capital spending on Grand Prix, including the ~~extension~~extensions into ~~southern~~ Oklahoma, is ~~now~~ estimated to be approximately ~~$1.7~~$1.9 billion, with our portion of growth capital spending estimated to be approximately ~~$1.1~~$1.3 billion. ~~We expect that our portion of growth capital spending in 2018 will be approximately $900 million.~~

In February 2018, we announced plans to construct a new 100 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 6”), which began operations in early May 2019. The total cost of the fractionation train and related infrastructure is expected to be approximately $350 million. Targa Train 6 LLC, a joint venture between Targa and Stonepeak Infrastructure Partners (“Stonepeak”), owns 100% interest in certain assets associated with Train 6. Certain fractionation-related infrastructure for Train 6, such as storage caverns and brine handling, will be funded and owned 100% by Targa.

In November 2018, we announced plans to construct two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7 and Train 8”), which are expected to begin operations in the first quarter of 2020 and ~~second~~third quarter of 2020, respectively. The total cost of these fractionation trains and related infrastructure is expected to be approximately $825 million. In connection with the Central Oklahoma Extension, Williams exercised its option to acquire a 20% equity interest in Train 7 and executed a joint venture agreement with us. Certain fractionation-related infrastructure for Train 7, including storage caverns and brine handling, will be funded and owned 100% by Targa.

In February ~~2018,~~2019, we announced plans to ~~construct a new 100 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 6”), which is expected~~further expand our LPG export capabilities of propane and butanes at our Galena Park Marine Terminal by increasing refrigeration capacity and associated load rates. Our current effective export capacity of 7 MMBbl per month will increase to ~~begin operations early in~~approximately 11 to 15 MMBbl per month, depending upon the ~~second quarter~~mix of ~~2019.~~propane and butane demand, vessel size and availability of supply, among other factors. The total cost of the ~~fractionation train~~expansion and related infrastructure is expected to be approximately ~~$350 million.~~$120 million and is expected to be completed in the third quarter of 2020.

In December 2017, we entered into definitive joint venture agreements with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP (“DCP”) with respect to the joint development of the Gulf Coast Express Pipeline (“GCX Pipeline”)~~(“GCX”)~~, a natural gas pipeline from the Waha hub, including direct connections to the tailgate of many of our Midland Basin processing facilities, to Agua Dulce in South Texas. The pipeline will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. WeTarga GCX Pipeline LLC, a joint venture between us and Stonepeak, and DCP each own a 25% interest, ~~and~~ KMTP owns a ~~50%~~35% interest, and Altus Midstream Company owns the remaining 15% interest in ~~GCX. Shipper Apache Corporation has an option to purchase up to a 15% equity stake from KMTP.~~GCX. KMTP ~~will serve~~serves as the construction manager and operator of ~~GCX.~~GCX Pipeline. We have committed significant volumes to ~~GCX.~~GCX Pipeline. In addition, Pioneer Natural Resources Company, a joint owner in ~~our~~our WestTX Permian Basin ~~system,~~assets, has committed volumes to the project. GCX Pipeline is designed to transport up to 1.98 Bcf/d of natural gas and the total cost of the project is estimated to be approximately $1.75 billion. GCX Pipeline is expected to be in service in the fourth quarter of ~~2019, pending regulatory approva~~ls.

In February 2018, we also announced the formation of three development joint ventures (the “DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”). Stonepeak owns an 80% interest in both the GCX DevCo JV, which owns our 25% interest in GCX, and the Train 6 DevCo JV, which owns a 100% interest in certain assets associated with Train 6. Stonepeak owns a 95% interest in the Grand Prix DevCo JV, which owns a 20% interest in the Grand Prix Joint Venture. We hold the remaining interest of each DevCo JV, as well as control the management, construction and operation of Grand Prix and the fractionation train. The Train 6 DevCo JV will fund the fractionation train while we will fund 100% of the required brine, storage and other infrastructure that will support the fractionation train’s operations.

Stonepeak committed a maximum of approximately $960 million of capital to the DevCo JVs, including an initial contribution of approximately $190 million that was distributed to the Partnership to reimburse it for a portion of capital spent to date.2019.

For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, Targa has the option to acquire all or part of Stonepeak’s interests in the DevCo JVs. Targa may acquire up to 50% of Stonepeak’s invested capital in multiple increments with a minimum of $100 million, ~~and Stonepeak’s remaining 50% interest in a single final purchase.~~ The purchase price payable for such partial or full interests would be based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs.

On December 27, 2015, we and Noble Americas Corp., then an affiliate of Noble Group Ltd., entered into a long-term, fee-based agreement (the “Splitter Agreement”) under which we will build and operate a 35,000 Bbl/d crude oil and condensate splitterThe Channelview Splitter, located at our Channelview Terminal on the Houston Ship Channel, ~~(the “Channelview Splitter”).~~is currently operating but still being tested by engineering and operations and has an estimated total cost of approximately $160 million. The Channelview Splitter will have the capability to split approximately 35,000 Bbl/d of crude oil and condensate into its various components, including naphtha, ~~kerosene,~~distillate, gas oil, kerosene/jet fuel and liquefied petroleum gas and will provide segregated storage for the crude and condensate and each of their components. We are working on commercialization of the Channelview Splitter.

~~The Channelview Splitter is expected~~April 2019, we closed on the sale of a 45% interest in Targa Badlands LLC, the entity that holds substantially all of our assets in North Dakota, to ~~be substantially completed~~funds managed by GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “Blackstone”) for $1.6 billion in ~~December 2018, and has an estimated total cost of approximately $150 million. The first three annual payments due under~~cash. We used the ~~Splitter Agreement, totaling $129.0 million, have been received and are reflected in deferred revenue as a component of other long-term liabilities on our Consolidated Balance Sheet.~~

~~During the second quarter of 2018, we sold our inland marine barge business to a third party for $69.3 million. We continue to own and operate two ocean-going barges.~~

During the third quarter of 2018, we executed agreements to sell our refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD, to a third party for approximately $160 million. The sale closed in the fourth quarter of 2018 and we intend to use thenet cash proceeds to repay debt and ~~to fund a portion of~~for general corporate purposes, including funding our growth capital program.

~~During~~ We continue to be the ~~fourth quarter~~operator of ~~2018, we~~ ~~announced that we are evaluating the potential~~Targa Badlands LLC and hold majority governance rights. Future growth capital of Targa Badlands LLC is expected to be funded on a pro rata ownership basis. Targa Badlands LLC will pay a minimum quarterly distribution (“MQD”) to Blackstone and Targa, with Blackstone having a priority right on such MQDs. Additionally, Blackstone’s capital contributions would have a liquidation preference upon a sale of ~~a minority interest in our~~Targa Badlands ~~assets in North Dakota to a select small group of counterparties.~~LLC.

In ~~April 2018,~~January 2019, we issued ~~$1.0 billion aggregate principal amount~~$750.0 million of 5⅞~~% senior notes due 2026 (the “5~~⅞6½% Senior Notes due ~~2026”). We used the~~July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of ~~$991.9 million after costs~~$1,487.3 million. The net proceeds from ~~this offering~~the offerings were used to redeem in full our ~~repay~~4⅛% Senior Notes due 2019, at par value plus accrued interest through the redemption date, with the remainder used for general partnership purposes, which included repaying borrowings under our credit ~~facilities and for general partnership purposes.~~

On October 29, 2018, Standard & Poor’s Corporation (“S&P”) raised our corporate credit rating and our issue-level rating on senior unsecured notes to 'BB' from 'BB-', and raised the outlook to positive from stable.

In June 2018, we entered into an agreement to amend and restate the TRP Revolver, which extended the maturity date from October 2020 to June 2023, increased available commitments from $1.6 billion to $2.2 billion and lowered the applicable margin range and commitment fee range used in the calculation of interest. Our ability to request additional commitments of $500.0 million remained unchanged.

actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The TRP Revolver’s covenants remained substantially the same.facilities.

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.

The profitability of our business ~~segments~~ 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, 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, expansion of our downstream facilities, 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 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.

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 ~~in the future through our~~ Grand Prix, ~~pipeline,~~ 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. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

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 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.

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.

The gross margin impacts of our equity volumes hedge settlements are reported in Other.

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:

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net ~~income.~~income (loss) attributable to TRP. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

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. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and ~~pay dividends~~make distributions to holders of our ~~investors.~~equity interests.

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

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

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

	Three Months Ended September 30,							Nine Months Ended September 30,						Three Months Ended March 31,
	2018				2017				2018		2017			2019			2018
	(In millions)													(In millions)
Reconciliation of Net Income (loss) to TRP Operating Margin and Gross Margin:
Reconciliation of Net Income (Loss) attributable to TRP to Operating Margin and Gross Margin
Net income (loss)		$	(8.7	)	$	(245.0	)		$	209.8	$	(295.4	)	$	(19.0	)	$	56.0
Depreciation and amortization expense			206.3			208.3				607.1		602.8			237.4			198.1
General and administrative expense			59.3			46.6				165.0		139.4			77.7			52.6
Impairment of property, plant and equipment			—			378.0				—		378.0
Interest expense, net			75.7			51.9				113.3		169.5
Income tax expense (benefit)			—			—				—		(4.2	)
Interest (income) expense, net															75.4			(20.2	)
(Gain) loss on sale or disposition of assets			61.1			0.3				14.3		16.6			3.2			(0.1	)
(Gain) loss from financing activities			—			—				1.3		10.7			1.4			—
Change in contingent considerations															9.7			56.1
Other, net			14.3			(126.9	)			7.1		(105.7	)		(2.6	)		(1.1	)
Operating margin			408.0			313.2				1,117.9		911.7			383.2			341.4
Operating expenses			194.9			155.5				538.7		462.6			190.2			173.2
Gross margin		$	602.9		$	468.7			$	1,656.6	$	1,374.3		$	573.4		$	514.6

	Three Months Ended September 30,								Nine Months Ended September 30,								Three Months Ended March 31,
	2018				2017				2018				2017				2019			2018
	(In millions)																(In millions)
Reconciliation of Net Income (Loss) attributable to TRP to Adjusted EBITDA
Net income (loss) attributable to TRP		$	(18.4	)		$	(254.7	)		$	177.8			$	(321.3	)	$	(30.4	)	$	42.8
Interest expense, net (1)			75.7				51.9				113.3				169.5
Income tax expense (benefit)			—				—				—				(4.2	)
Interest (income) expense, net (1)																		75.4			(20.2	)
Depreciation and amortization expense			206.3				208.3				607.1				602.8			237.4			198.1
Impairment of property, plant and equipment			—				378.0				—				378.0
(Gain) loss on sale or disposition of assets			61.1				0.3				14.3				16.6			3.2			(0.1	)
(Gain) loss from financing activities			—				—				1.3				10.7
(Earnings) loss from unconsolidated affiliates			(3.0	)			(0.2	)			(6.4	)			16.6
(Gain) loss from financing activities (2)																		1.4			—
Equity (earnings) loss																		(2.8	)		(1.5	)
Distributions from unconsolidated affiliates and preferred partner interests, net			7.5				4.6				21.4				15.0			6.8			6.9
Change in contingent considerations			16.6				(126.8	)			12.1				(125.6	)		9.7			56.1
Transaction costs related to business acquisitions			—				0.4				—				5.6
Splitter Agreement (2)			10.8				10.8				32.3				32.3
Risk management activities (3)			(0.8	)			2.0				8.3				7.2
Splitter Agreement (3)																		—			10.8
Risk management activities																		7.2			9.7
Noncontrolling interests adjustments (4)			(7.7	)			(5.0	)			(19.7	)			(13.6	)		(7.1	)		(5.1	)
TRP Adjusted EBITDA		$	348.1			$	269.6			$	961.8			$	789.6		$	300.8		$	297.5

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

		Three Months Ended September 30,												Nine Months Ended September 30,												Three Months Ended March 31,
		2018			2017			2018 vs. 2017						2018			2017			2018 vs. 2017						2019			2018			2019 vs. 2018
	(In millions, except operating statistics and price amounts)																								(In millions)
Revenues:
Sales of commodities		$	2,654.1		$	1,871.5		$	782.6			42	%	$	6,981.4		$	5,353.1		$	1,628.3		30	%		$	1,976.5		$	2,173.7		$	(197.2	)		(9	%)
Fees from midstream services			332.3			260.3			72.0			28	%		904.9			759.0			145.9		19	%			322.9			281.9			41.0			15	%
Total revenues			2,986.4			2,131.8			854.6			40	%		7,886.3			6,112.1			1,774.2		29	%			2,299.4			2,455.6			(156.2	)		(6	%)
Product purchases			2,383.5			1,663.1			720.4			43	%		6,229.7			4,737.8			1,491.9		31	%			1,726.0			1,941.0			(215.0	)		(11	%)
Gross margin (1)			602.9			468.7			134.2			29	%		1,656.6			1,374.3			282.3		21	%			573.4			514.6			58.8			11	%
Operating expenses			194.9			155.5			39.4			25	%		538.7			462.6			76.1		16	%			190.2			173.2			17.0			10	%
Operating margin (1)			408.0			313.2			94.8			30	%		1,117.9			911.7			206.2		23	%			383.2			341.4			41.8			12	%
Depreciation and amortization expense			206.3			208.3			(2.0	)		(1	%)		607.1			602.8			4.3		1	%			237.4			198.1			39.3			20	%
General and administrative expense			59.3			46.6			12.7			27	%		165.0			139.4			25.6		18	%			77.7			52.6			25.1			48	%
Impairment of property, plant and equipment			—			378.0			(378.0	)		(100	%)		—			378.0			(378.0	)	(100	%)
Other operating (income) expense			61.8			0.6			61.2		NM				15.7			17.2			(1.5	)	(9	%)			3.4			0.3			3.1		NM
Income (loss) from operations			80.6			(320.3	)		400.9			125	%		330.1			(225.7	)		555.8		246	%			64.7			90.4			(25.7	)		(28	%)
Interest expense, net			(75.7	)		(51.9	)		(23.8	)		(46	%)		(113.3	)		(169.5	)		56.2		33	%
Interest income (expense), net																											(75.4	)		20.2			(95.6	)	NM
Equity earnings (loss)			3.0			0.2			2.8		NM				6.4			(16.6	)		23.0		139	%			2.8			1.5			1.3			87	%
Gain (loss) from financing activities			—			—			—			—			(1.3	)		(10.7	)		9.4		88	%			(1.4	)		—			(1.4	)		—
Change in contingent considerations			(16.6	)		126.8			(143.4	)		(113	%)		(12.1	)		125.6			(137.7	)	(110	%)			(9.7	)		(56.1	)		46.4			83	%
Other income (expense), net			—			0.2			(0.2	)		(100	%)		—			(2.7	)		2.7		100	%
Income tax (expense) benefit			—			—			—			—			—			4.2			(4.2	)	(100	%)
Net income (loss)			(8.7	)		(245.0	)		236.3			96	%		209.8			(295.4	)		505.2		171	%			(19.0	)		56.0			(75.0	)		(134	%)
Less: Net income (loss) attributable to noncontrolling interests			9.7			9.7			—			—			32.0			25.9			6.1		24	%			11.4			13.2			(1.8	)		(14	%)
Net income (loss) attributable to Targa Resources Partners LP		$	(18.4	)	$	(254.7	)	$	236.3			93	%	$	177.8		$	(321.3	)	$	499.1		155	%		$	(30.4	)	$	42.8		$	(73.2	)		(171	%)
Financial data:
Adjusted EBITDA (1)		$	348.1		$	269.6		$	78.5			29	%	$	961.8		$	789.6		$	172.2		22	%		$	300.8		$	297.5		$	3.3			1	%
Capital expenditures (2)			1,017.7			378.7			639.0			169	%		2,310.4			987.7			1,322.7		134	%
Business acquisition (3)			—			—			—			—			—			987.1			(987.1	)	(100	%)
Growth capital expenditures (2)																											870.0			535.6			334.4			62	%
Maintenance capital expenditures (3)																											35.6			22.4			13.2			59	%

Three Months Ended ~~September 30, 2018~~March 31, 2019 Compared to Three Months Ended ~~September 30, 2017~~March 31, 2018

The ~~increase~~decrease in commodity sales reflects ~~increased~~lower NGL, natural gas ~~condensate and petroleum volumes ($538.4 million) and higher NGL~~ and condensate prices ($~~475.5~~437.8 million) and lower petroleum volumes due to the sale of certain petroleum logistics storage and terminaling facilities in the fourth quarter of 2018 ($40.5 million), partially offset by ~~lower natural gas prices~~higher NGL and crude marketing volumes ($~~127.5~~228.4 million) and the impact of hedges ($~~21.4~~50.5 million). ~~Fee-based and other revenues increased~~The increase in fee-based revenue was primarily due to higher gas processing and crude gathering fees.

The ~~increase~~decrease in product purchases reflects ~~increased volumes and higher~~decreased NGL, natural gas and condensate ~~prices.~~

~~The prospective adoption of the revenue recognition accounting standard as set forth~~prices, partially offset by increases in Topic 606 in 2018 resulted in lower commodity sales ($84.6 million) and lower fee revenue ($5.8 million) with a corresponding net reduction in product purchases, resulting in no impact on operating margin or gross margin.volumes.

The higher operating margin and gross margin in ~~2018~~2019 reflect increased segment margin results for Gathering and Processing and Logistics and Marketing. ~~Additionally, our operating margin for the three months ended September 30, 2017 was reduced by approximately $10 million due to temporary operational issues related to the impact of Hurricane Harvey.~~ ~~Operating expenses increased compared to 2017~~ ~~primarily due to system expansions and higher activity levels~~. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense ~~was flat as~~increased primarily due to higher depreciation related to ~~our~~major growth ~~investments was~~projects placed in service, including the Permian Basin Segment of Grand Prix, and additional processing plants and associated infrastructure in the Permian Basin. The increase is partially offset by lower depreciation for our ~~North Texas system~~downstream facilities, resulting from the sale of certain petroleum logistics storage and ~~lower scheduled amortization of Badlands intangibles. Lower North Texas system depreciation reflects the impact of a partial impairment of property, plant and equipment recorded~~terminaling facilities in the ~~third~~fourth quarter of ~~2017.~~2018.

General and administrative expense increased primarily due to higher compensation and benefits, including increased staffing levels, system costs and ~~higher~~ outside professional services.

Interest expense, net, increased due to a reduction of non-cash interest income related to the ~~impact of~~mandatorily redeemable interests, and higher average borrowings, ~~and lower interest income on the mandatorily redeemable preferred interest valuations,~~ partially offset by higher capitalized interest related to our major growth investments. During 2018, we recognized non-cash interest income resulting from a decrease in the estimated redemption value of the mandatorily redeemable interests, primarily attributable to the February 2018 amendments to such arrangements.

~~Equity earnings increased~~During 2019, we recorded expense of $9.7 million resulting from an increase in ~~2018,~~the value of the Permian Acquisition contingent consideration liability. The increase in 2019 was primarily ~~reflecting increased earnings at Gulf Coast Fractionators LP (“GCF”)~~attributable to the elimination of discounting and an increase in actual gross margin through the ~~commencement~~end of ~~operations of Cayenne.~~

the earn-out period. During 2018, we recorded expense of ~~$16.6~~$56.1 million resulting primarily from anthe increase in fair value as of ~~September 30,~~March 31, 2018 of the Permian Acquisition contingent consideration liability. The fair value change was primarily related to an increase in ~~2018~~ ~~was primarily attributable to~~underlying forecasted volumes for the remainder of the earn-out period and a shorter ~~discount period.~~ During 2017, we recorded income of $126.8 million resulting from a decrease in the fair value of the contingent consideration liability from June 30, 2017 to September 30, 2017. The fair value decrease in 2017 reflected reductions in actual and forecasted volumes and gross margin resulting from changes in producers’ drilling activity in the region.term over which such projections are discounted.

~~Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017~~

The increase in commodity sales reflects increased NGL, natural gas, petroleum and condensate volumes ($1,241.7 million) and higher NGL and condensate prices ($1,097.5 million), partially offset by lower natural gas prices ($389.2 million) and the impact of hedges ($68.7 million). Fee-based and other revenues increased primarily due to higher gas processing and crude gathering fees.

~~The increase in product purchases reflects increased volumes and higher NGL and condensate prices.~~

The prospective adoption of the revenue recognition accounting standard as set forth in Topic 606 in 2018 resulted in lower commodity sales ($250.6 million) and lower fee revenue ($18.6 million) with a corresponding net reduction in product purchases, resulting in no impact on operating margin or gross margin.

The higher operating margin and gross margin in 2018 reflect increased segment margin results for Gathering and Processing and Logistics and Marketing. Additionally, our operating margin for the nine months ended September 30, 2017 was reduced by approximately $10 million due to temporary operational issues related to the impact of Hurricane Harvey. ~~Operating expenses increased compared to 2017~~ primarily due to system expansions, higher activity levels and the inclusion of the Permian Acquisition for nine months in 2018 as compared with seven months in 2017. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis.

Depreciation and amortization expense was flat as higher depreciation related to our growth investments was offset by lower depreciation for our North Texas system, lower scheduled amortization of Badlands intangibles and lower depreciation on our inland marine barge business sold in the second quarter of 2018. In 2017, we recorded a partial impairment of property, plant and equipment in our North Texas system.

~~General and administrative expense increased primarily due to higher compensation and benefits and higher outside professional services.~~

~~Other operating (income) expense in 2018 was comprised primarily of the estimated loss on~~ ~~our refined products and crude oil storage and terminaling facilities in Tacoma, Washington, and Baltimore, Maryland, that were held for sale as of September 30, 2018, partially offset by~~ ~~the gain on sale of our inland marine barge business. In 2017, other operating (income) expense included the loss on sale of our 100% ownership interest in the Venice Gathering System~~.

Lower interest expense, net, in 2018 was primarily due to higher non-cash interest income related to a decrease in the mandatorily redeemable preferred interests liability and higher capitalized interest related to our major growth investments. These factors more than offset the impact of higher average outstanding borrowings during 2018. The mandatorily redeemable preferred interests liability is revalued quarterly at the estimated redemption value as of the reporting date~~, and the decrease in 2018 of its estimated redemption value is primarily attributable to the February 2018 amendments to the agreements governing the WestTX and WestOK joint ventures.~~

Equity earnings increased in 2018, which reflects decreased losses of the T2 Joint Ventures, which in 2017 included a $12.0 million loss provision due to the impairment of our investment in the T2 EF Cogen joint venture, increased earnings at GCF and the commencement of operations at Cayenne.

~~In 2018,~~ ~~we recorded a loss from financing activities of $1.3 million~~ ~~associated with amendments to our revolving credit facilities, which resulted in a write-off of debt issuance costs. In 2017, we recorded a loss from financing activities of $10.7 million on~~ ~~the redemption of the outstanding 6~~⅜~~% Senior Notes.~~

During 2018, we recorded expense of $12.1 million resulting from the change in the fair value of contingent considerations, substantially all of which was due to the increase in fair value as of September 30, 2018 of the Permian Acquisition contingent consideration liability described above. During 2017, we recorded income of $125.6 million resulting from a decrease in the fair value of the Permian Acquisition contingent consideration liability from the acquisition date to September 30, 2017.

~~We recorded an income tax benefit in 2017 primarily due to a Texas Margin Tax refund.~~

~~Net income attributable to noncontrolling interests was higher in 2018 due to increased earnings at our Carnero joint venture and Cedar Bayou Fractionators.~~

																				Three Months Ended March 31,
	Three Months Ended September 30,									Nine Months Ended September 30,										2019		2018		2019 vs. 2018
	2018		2017		2018 vs. 2017					2018		2017			2018 vs. 2017					(In millions, except operating statistics and price amounts)
Gross margin	$	373.7	$	289.7	$	84.0		29	%	$	1,046.3	$	817.1	$		229.2		28	%	$	351.9	$	325.6	$	26.3		8	%
Operating expenses		118.4		91.4		27.0		30	%		327.9		267.8			60.1		22	%		122.9		104.8		18.1		17	%
Operating margin	$	255.3	$	198.3	$	57.0		29	%	$	718.4	$	549.3	$		169.1		31	%	$	229.0	$	220.8	$	8.2		4	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Permian Midland (4)		1,161.7		932.1		229.6		25	%		1,100.8		864.9			235.9		27	%		1,334.4		1,014.1		320.3		32	%
Permian Delaware (4)		470.5		403.9		66.6		16	%		432.5		373.6			58.9		16	%
Permian Delaware																					480.4		409.2		71.2		17	%
Total Permian		1,632.2		1,336.0		296.2					1,533.3		1,238.5			294.8					1,814.8		1,423.3		391.5

SouthTX		364.1		330.1		34.0		10	%		397.8		242.1			155.7		64	%
SouthTX (5)																					363.9		416.3		(52.4	)	(13	%)
North Texas		247.6		261.8		(14.2	)	(5	%)		243.0		273.7			(30.7	)	(11	%)		230.5		235.1		(4.6	)	(2	%)
SouthOK		568.2		515.2		53.0		10	%		549.4		478.5			70.9		15	%
SouthOK (6)																					620.0		529.9		90.1		17	%
WestOK		353.9		367.1		(13.2	)	(4	%)		350.8		382.5			(31.7	)	(8	%)		338.1		350.1		(12.0	)	(3	%)
Total Central		1,533.8		1,474.2		59.6					1,541.0		1,376.8	��		164.2					1,552.5		1,531.4		21.1

Badlands (5)		90.5		60.9		29.6		49	%		83.3		53.1			30.2		57	%
Badlands (7)																					96.9		73.3		23.6		32	%
Total Field		3,256.5		2,871.1		385.4					3,157.6		2,668.4			489.2					3,464.2		3,028.0		436.2

Coastal		783.3		750.5		32.8		4	%		724.5		750.1			(25.6	)	(3	%)		769.9		724.3		45.6		6	%

Total		4,039.8		3,621.6		418.2		12	%		3,882.1		3,418.5			463.6		14	%		4,234.1		3,752.3		481.8		13	%
NGL production, MBbl/d (3)
Permian Midland (4)		152.2		122.8		29.4		24	%		148.0		111.8			36.2		32	%		184.3		140.2		44.1		31	%
Permian Delaware (4)		58.9		46.3		12.6		27	%		51.6		42.4			9.2		22	%
Permian Delaware																					60.5		45.7		14.8		32	%
Total Permian		211.1		169.1		42.0					199.6		154.2			45.4					244.8		185.9		58.9

SouthTX		49.0		35.4		13.6		38	%		52.5		25.2			27.3		108	%
SouthTX (5)																					48.8		54.1		(5.3	)	(10	%)
North Texas		29.6		29.3		0.3		1	%		28.1		30.8			(2.7	)	(9	%)		26.8		25.9		0.9		3	%
SouthOK		61.2		42.7		18.5		43	%		53.8		40.7			13.1		32	%
SouthOK (6)																					58.3		48.9		9.4		19	%
WestOK		20.7		20.7		-		-			19.9		22.3			(2.4	)	(11	%)		24.1		19.4		4.7		24	%
Total Central		160.5		128.1		32.4					154.3		119.0			35.3					158.0		148.3		9.7

Badlands		10.5		9.0		1.5		17	%		10.5		7.4			3.1		42	%		11.4		10.2		1.2		12	%
Total Field		382.1		306.2		75.9					364.4		280.6			83.8					414.2		344.4		69.8

Coastal		47.3		40.0		7.3		18	%		42.8		38.2			4.6		12	%		48.4		42.6		5.8		14	%

Total		429.4		346.2		83.2		24	%		407.2		318.8			88.4		28	%		462.6		387.0		75.6		20	%
Crude oil gathered, Badlands, MBbl/d		161.7		108.7		53.0		49	%		139.9		111.6			28.3		25	%		169.5		117.7		51.8		44	%
Crude oil gathered, Permian, MBbl/d (4)		75.1		35.7		39.4		110	%		63.8		24.6			39.2		159	%
Crude oil gathered, Permian, MBbl/d																					67.4		49.4		18.0		36	%
Natural gas sales, BBtu/d (3)		1,817.6		1,738.5		79.1		5	%		1,821.1		1,647.8			173.3		11	%		1,925.9		1,767.3		158.6		9	%
NGL sales, MBbl/d		329.6		244.4		85.2		35	%		311.3		240.4			70.9		29	%		359.5		300.4		59.1		20	%
Condensate sales, MBbl/d		12.6		11.4		1.2		11	%		12.8		11.4			1.4		12	%		12.5		16.2		(3.7	)	(23	%)
Average realized prices (6):
Average realized prices (8):
Natural gas, $/MMBtu		1.93		2.58		(0.66	)	(26	%)		2.03		2.71			(0.68	)	(25	%)		1.89		2.37		(0.48	)	(20	%)
NGL, $/gal		0.75		0.56		0.19		34	%		0.67		0.51			0.16		31	%		0.45		0.59		(0.14	)	(24	%)
Condensate, $/Bbl		58.31		42.69		15.62		37	%		58.49		43.42			15.07		35	%		47.09		59.66		(12.57	)	(21	%)

~~Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017~~

The increase in gross margin was primarily due to higher Permian, Central and Badlands volumes and higher NGL and condensate prices, partially offset by lower natural gas prices. The increase in Field Gathering and Processing inlet volumes included both areas in the Permian region, SouthTX, SouthOK and Badlands, partially offset by decreases at WestOK and North Texas. NGL sales and natural gas sales increased primarily due to higher Field Gathering and Processing inlet volumes and increased NGL production, including additional ethane recoveries. Prior year NGL sales were unfavorably impacted by temporary operational issues related to Hurricane Harvey in the third quarter of 2017. Coastal Gathering and Processing gross margin increased due to higher inlet volumes, richer gas, increased recoveries and higher NGL prices. In the Badlands, total crude oil gathered volumes and natural gas gathered volumes increased primarily due to production from new wells and system expansions. Total crude oil gathered volumes increased in the Permian region due to production from new wells.

~~Operating expenses in the Permian region increased primarily as a result of higher compensation, contract labor, and other costs associated with plant expansions.~~

~~Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017~~

The increase in gross margin was primarily due to higher Permian volumes including those associated with the Permian Acquisition in March 2017, higher Central and Badlands volumes and higher NGL and condensate prices, partially offset by lower natural gas prices. The overall increase in Field Gathering and Processing inlet volumes included both areas of the Permian region, SouthTX, SouthOK and Badlands, partially offset by decreases at WestOK and North Texas. NGL sales and natural gas sales increased primarily due to higher Field Gathering and Processing inlet volumes and increased NGL production, including additional ethane recoveries. Prior year NGL sales were unfavorably impacted by temporary operational issues related to Hurricane Harvey in the third quarter of 2017. Coastal Gathering and Processing gross margin increased due to richer gas, increased recoveries and higher NGL prices. In the Badlands, total crude oil gathered volumes and natural gas gathered volumes increased primarily due to production from new wells and system expansions. Total crude oil gathered volumes increased in the Permian region due to the Permian Acquisition and production from new wells and system expansions.

Operating expenses in the Permian region increased primarily as a result of higher compensation, contract labor, and other costs associated with plant expansions as well as the inclusion of the March 2017 Permian Acquisition for the full period of 2018.

~~The table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field portion of the Gathering and Processing segment:~~

The increase in gross margin was primarily due to higher Badlands and Permian volumes, partially offset by lower commodity prices and lower SouthTX volumes. The effect of commodity prices excludes the impact of hedging activities presented in Other. NGL production, NGL sales and natural gas sales increased primarily due to higher Field Gathering and Processing inlet volumes and increased NGL recoveries including reduced ethane rejection. Total crude oil gathered volumes increased in the Permian region due to production from new wells. In the Badlands, total crude oil gathered volumes and natural gas gathered volumes increased primarily due to production from new wells and system expansions.

The increase in operating expenses was primarily driven by gas plant and system expansions in the Permian region. Operating expenses in other regions were relatively flat.

		Three Months Ended September 30,									Nine Months Ended September 30,										Three Months Ended March 31,
		2018		2017		2018 vs. 2017					2018		2017		2018 vs. 2017						2019		2018		2019 vs. 2018
	(In millions)																			(In millions, except operating statistics and price amounts)
Gross margin		$	249.4	$	180.0	$	69.4		39	%	$	653.1	$	553.3	$	99.8		18	%		$	219.5	$	206.9	$	12.6		6	%
Operating expenses			75.9		64.1		11.8		18	%		211.4		194.8		16.6		9	%			67.4		68.5		(1.1	)	(2	%)
Operating margin		$	173.5	$	115.9	$	57.6		50	%	$	441.7	$	358.5	$	83.2		23	%		$	152.1	$	138.4	$	13.7		10	%
Operating statistics MBbl/d (1):
Fractionation volumes ~~(3)~~(2)			454.5		329.3		125.2		38	%		419.0		324.3		94.7		29	%			456.6		389.7		66.9		17	%
LSNG treating volumes (2)			36.3		27.2		9.1		33	%		33.4		31.6		1.9		6	%
Benzene treating volumes (2)			—		16.1		(16.1	)	(100	%)		4.4		20.5		(16.2	)	(79	%)
Export volumes (4)			208.2		154.5		53.6		35	%		200.2		175.5		24.6		14	%
Export volumes (3)																						213.1		201.9		11.2		6	%
NGL sales			555.7		463.4		92.3		20	%		526.7		468.1		58.6		13	%			586.2		514.8		71.4		14	%
Average realized prices:
NGL realized price, $/gal		$	0.88	$	0.67	$	0.21		31	%	$	0.80	$	0.64	$	0.16		25	%		$	0.60	$	0.76	$	(0.16	)	(21	%)

Three Months Ended ~~September 30, 2018~~March 31, 2019 Compared to Three Months Ended ~~September 30, 2017~~March 31, 2018

Logistics and Marketing gross margin increased due to higher LPG export margin, higher fractionation margin, partially offset by lower terminaling and storage throughput, and lower commercial transportation margin. LPG export margin increased primarily due to higher ~~fractionation margin~~volumes despite restrictions and ~~higher LPG export margin.~~temporary closures of the Houston Ship Channel during the quarter. Fractionation margin increased due to higher supply volume, ~~and higher fees,~~ partially offset by lower system product gains. Fractionation margin was partially impacted by the variable effects of fuel and power that are largely reflected in operating expenses (see footnote (2) above). ~~LPG export margin increased primarily~~Terminaling and storage throughput decreased due to ~~higher volumes. Prior year fractionation supply volume~~the sale of certain petroleum logistics storage and ~~LPG export volumes were unfavorably impacted by temporary operational issues related~~terminaling facilities in the fourth quarter of 2018. Commercial transportation margin decreased due to ~~Hurricane Harvey. Other contributors to gross margin included higher treating margin, higher marketing gains and higher terminal and storage throughput.~~the sale of the Company’s inland marine barge business in the second quarter of 2018.

Operating expenses ~~increased~~decreased due to ~~higher fuel~~lower taxes and ~~power costs that are largely passed through, higher compensation and benefits and higher ad valorem taxes.~~

~~Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017~~

Logistics and Marketing gross margin increased primarily due to higher fractionation margin. Fractionation margin increased due to higher supply volume. Fractionation margin was partially impacted by the variable effects of fuel and power that are largely reflected in operating expenses (see footnote (2) above). Prior year fractionation supply volume was unfavorably impacted by temporary operational issues related to Hurricane Harvey. Other contributors to gross margin included higher marketing gains, higher terminal and storage throughput and higher domestic marketing margin.

~~Operating expenses increased due to higher compensation and benefits, higher fuel and power costs that are largely passed through and higher ad valorem taxes, partially offset by lower~~ maintenance.

	Three Months Ended September 30,									Nine Months Ended September 30,								Three Months Ended March 31,
	2018			2017			2018 vs. 2017			2018			2017		2018 vs. 2017			2019		2018			2019 vs. 2018
	(In millions)																	(In millions)
Gross margin	$	(20.8	)	$	(1.0	)	$	(19.8	)	$	(42.2	)	$	3.9	$	(46.1	)	$	2.1	$	(17.8	)	$	19.9
Operating margin	$	(20.8	)	$	(1.0	)	$	(19.8	)	$	(42.2	)	$	3.9	$	(46.1	)	$	2.1	$	(17.8	)	$	19.9

Other contains the results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and mark-to-market gain/losses related to derivative contracts that were not designated as cash flow hedges. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow. We have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes in our Gathering and Processing operations that result from percent of proceeds/liquids processing arrangements. Because we are essentially forward-selling a portion of our future plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices.

The following table provides a breakdown of the change in Other operating margin:

	Three Months Ended September 30, 2018								Three Months Ended September 30, 2017								Three Months Ended March 31, 2019								Three Months Ended March 31, 2018
	(In millions, except volumetric data and price amounts)																(In millions, except volumetric data and price amounts)
	Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)			Gain (Loss)
Natural gas (BBtu)		15.7	$	0.82		$	12.9			17.3	$	0.23		$	4.0			12.1	$	0.72		$	8.7			17.4	$	0.33		$	5.8
NGL (MMgal)		99.0		(0.27	)		(26.4	)		74.8		(0.09	)		(6.7	)		69.4		0.01			0.5			87.2		(0.11	)		(9.4	)
Crude oil (MBbl)		0.5		(15.81	)		(8.1	)		0.4		6.29			2.3			0.3		(0.04	)		—			0.4		(10.30	)		(4.6	)
Non-hedge accounting (2)							0.8								(0.6	)							(7.1	)							(9.6	)
Ineffectiveness (3)							—								—
						$	(20.8	)						$	(1.0	)						$	2.1							$	(17.8	)

	Nine Months Ended September 30, 2018								Nine Months Ended September 30, 2017
	(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)		48.6	$	0.74		$	35.8			43.3	$	0.15		$	6.6
NGL (MMgal)		286.3		(0.17	)		(49.7	)		177.5		(0.04	)		(7.7	)
Crude oil (MBbl)		1.5		(13.10	)		(20.0	)		0.9		6.29			5.8
Non-hedge accounting (2)							(8.3	)							(0.9	)
Ineffectiveness (3)							—								0.1
						$	(42.2	)						$	3.9

As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $1.4 million and $6.3 million for the three and nine months ended September 30, 2017. ~~The final settlement was received in December 2017.~~ ~~These settlements were reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.~~

As of ~~September 30, 2018,~~March 31, 2019, we had ~~$187.5~~$111.7 million of “Cash and cash equivalents,” on our Consolidated Balance Sheets. We believe our cash position, remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”), and our cash flows from operating activities 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 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, weather and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

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 ~~may~~ supplement these sources of liquidity with joint venture arrangements and proceeds from ~~potential~~ 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.

		November 5, 2018				May 3, 2019
		(In millions)				(In millions)
Cash on hand	Cash on hand	$	319.0		Cash on hand	$	297.9
Total availability under the TRP Revolver	Total availability under the TRP Revolver		2,200.0		Total availability under the TRP Revolver		2,200.0
Total availability under the Securitization Facility	Total availability under the Securitization Facility		350.0		Total availability under the Securitization Facility		334.9
			2,869.0				2,832.8

Less:	Outstanding borrowings under the TRP Revolver		(180.0	)	Outstanding borrowings under the TRP Revolver		—
	Outstanding borrowings under the Securitization Facility		(350.0	)	Outstanding borrowings under the Securitization Facility		(300.0	)
	Outstanding letters of credit under the TRP Revolver		(78.4	)	Outstanding letters of credit under the TRP Revolver		(66.0	)
	Total liquidity	$	2,260.6		Total liquidity	$	2,466.8

Other potential capital resources associated with our existing arrangements include:

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 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 NGL 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 projects; (iv) changes in the fair value of the current portion of derivative contracts; ~~(iv)~~(v) monthly swings in borrowings under the Securitization Facility; and ~~(v)~~(vi) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth projects.

Working capital as of ~~September 30, 2018~~March 31, 2019 ~~decreased $530.9~~increased $516.0 million compared to December 31, ~~2017.~~2018. ~~Our~~ working capital, exclusive of current debt obligations, and reclassifications from other long term liabilities and held for sale assets, decreased $413.3 million from December 31, 2017 to September 30, 2018. The ~~major items contributing to this decrease in working capital were increases in accounts payable and accruals especially those related to our Grand Prix and Train 6 projects, a reduction in inventories~~increase was primarily attributable to ~~a decrease in volumes in storage,~~the February redemption of our 4⅛% Senior Notes due 2019, partially offset by ~~an increase in prices,~~a lower cash balance and a decrease in our net risk management asset position due to changes in forward prices of commodities, partially offset by higher cash balances. Working capital as of September 30, 2018 was also impacted by a $329.0 million decrease primarily due to the reclassification of the May 2019 estimated contingent consideration payment from noncurrent liabilities, a $151.4 million increase due to the reclassification of held for sale assets relating to the Targa Sound and Baltimore terminals from long-term assets, and a $60.0 million increase due to lower borrowings under our Securitization Facility.commodities.

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 ~~potential~~ 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.

In February 2018, we formed three development joint ventures (“DevCo ~~JVs~~JVs”) with investment vehicles affiliated with Stonepeak, which committed a maximum of approximately $960 million of capital to the DevCo JVs. ~~For the nine months ended September 30, 2018,~~

As of March 31, 2019, total contributions from Stonepeak to the DevCo JVs were ~~$448.8 million, which~~$701.3 million. As of March 31, 2019, total contributions from Blackstone to the Grand Prix Joint Venture were $265.0 million. These contributions from Stonepeak and Blackstone are included in noncontrolling interests.

From time to time, we issue long-term debt securities, which we refer to as senior notes. Our senior notes issued to date, generally have similar terms other than interest rates, maturity dates and redemption premiums. ~~All~~As of March 31, 2019 and December 31, 2018, the aggregate principal amount outstanding of our ~~fixed rate~~ senior notes ~~provide that the notes may be redeemed at any time at a price equal to 100% plus accrued interest to the redemption date,~~ and ~~in some cases, a make-whole premium.~~other various long-term debt obligations, including unamortized premiums, debt issuance costs and non-current liabilities of finance leases, was $6,683.5 million and $5,197.4 million, respectively.

The majority of our ~~long-term~~ debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRP Revolver and the Securitization Facility. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of ~~September 30, 2018,~~March 31, 2019, we did not have any interest rate hedges.

In ~~April 2018,~~January 2019, we issued ~~$1.0 billion aggregate principal amount~~$750.0 million of ~~the 5~~⅞6½% Senior Notes due ~~2026.~~July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of $1,487.3 million. The net proceeds from the offerings were used to redeem in full our outstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date and the remainder was used for general partnership purposes, which included repaying borrowings under our credit facilities.

In April 2019, we closed on the sale of a 45% interest in Targa Badlands LLC, the entity that holds substantially all of our assets in North Dakota, to funds managed by Blackstone for $1.6 billion in cash. We used the net cash proceeds ~~of $991.9 million after costs from this offering~~ to repay ~~borrowings under its credit facilities~~debt and for general ~~partnership purposes.~~

~~In June 2018, we entered into~~corporate purposes, including funding our growth capital program. We continue to be the operator of Targa Badlands LLC and hold majority governance rights. Future growth capital of Targa Badlands LLC is expected to be funded on a pro rata ownership basis. Targa Badlands LLC will pay an ~~agreement~~MQD to ~~amend~~Blackstone and restate the TRP Revolver which extended the maturity date from October 2020 to June 2023 and increased available commitments from $1.6 billion to $2.2 billion. Our ability to request additional commitmentsTarga, with Blackstone having a priority right on such MQDs. Additionally, Blackstone’s capital contributions would have a liquidation preference upon a sale of $500.0 million remained unchanged. The TRP Revolver continues to bear interest costs that are dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA and the covenants remained substantially the same.Targa Badlands LLC.

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 9 - 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.

As of ~~September 30, 2018,~~March 31, 2019, we were in compliance with the covenants contained in our various debt agreements.

Nine Months Ended September 30,
2018		2017		2018 vs. 2017
Three Months Ended March 31,						Three Months Ended March 31,
2019						2019	2018		2019 vs. 2018
(In millions)	(In millions)					(In millions)
$	943.5	$	463.2	$	480.3	307.6	$	354.2	$	(46.6	)

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 ~~purchases~~purchase of NGLs and natural gas, (iii) changes in payables and accruals related to major growth projects; and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts.

Net cash provided by operations ~~increased from 2017~~decreased in 2019 compared to 2018, primarily due to the ~~impact of higher commodity prices and volumes, higher capitalized interest, increases in distributions from unconsolidated affiliates and lower acquisition costs, offset by increases~~increase in payments for operating ~~expenses. The increase~~and general and administrative expenses resulting from system expansions and higher compensation and benefits, and increases in interest payments due to higher average borrowings, partially offset by the impact of lower commodity prices and ~~volumes resulted in higher cash collections from customers, partially offset by higher product purchases and an increase in cash payments~~increased margin withdrawals related to our derivative contracts. ~~Higher capitalized interest~~Lower commodity prices resulted in lower ~~interest payments included in operating~~product purchases, partially offset by lower cash ~~flow. Increases in earnings~~collections from ~~unconsolidated affiliates contributed to higher distributions. Increases in payments for operating expenses were mainly due to system expansions and higher activity levels.~~

Nine Months Ended September 30,
2018			2017			2018 vs. 2017
Three Months Ended March 31,									Three Months Ended March 31,
2019									2019		2018			2019 vs. 2018
(In millions)	(In millions)								(In millions)
$	(2,192.8	)	$	(1,457.5	)	$	(735.3	)	(1,068.8	)	$	(677.3	)	$	(391.5	)

Cash used in investing activities increased in ~~2018~~2019 compared to ~~2017,~~2018, primarily due to ~~increased~~higher outlays for property, plant and equipment ~~and contributions to unconsolidated affiliates, partially offset by lower outlays for business acquisitions and higher proceeds from the sale~~ of ~~assets.~~

~~Our capital expenditures for property, plant and equipment increased $1,167.0~~$347.4 million, ~~in 2018 primarily~~mainly related to the construction of Train 7 and Train 8, and additional processing plants and associated infrastructure in the Permian Basin. The change is also attributable to a ~~large number of capital projects, and~~$29.4 million increase in our contributions to unconsolidated affiliates ~~increased $216.2 million primarily~~essentially due to ~~the~~higher construction activities of GCX ~~and LM4.~~

~~We have made no cash payment for business acquisitions in 2018, whereas in 2017 we paid $570.8 million for the initial cash portion~~Pipeline, partially offset by lower construction activities of ~~the Permian Acquisition. In 2018, we received proceeds of $69.3 million from the sale of our inland marine barge business.~~Little Missouri 4.

	Nine Months Ended September 30,						Three Months Ended March 31,
	2018			2017			2019			2018
Source of Financing Activities, net	(In millions)						(In millions)
Debt, including financing costs	$	904.2		$	(4.6	)	$	732.7		$	310.0
Contributions from noncontrolling interests		611.6			93.8			196.8			280.1
Contributions from TRC and General Partner		540.0			1,620.0			—			60.0
Distributions		(692.1	)		(633.1	)		(241.3	)		(228.5	)
Other		(51.6	)		(45.9	)		(18.6	)		(16.5	)
Net cash provided by (used in) financing activities	$	1,312.1		$	1,030.2		$	669.6		$	405.1

In ~~2018,~~2019, we realized a net source of cash from financing activities primarily due to a net increase of debt outstanding, ~~and~~ contributions from noncontrolling interests, ~~and TRC,~~ partially offset by payments of ~~distributions to TRC.~~dividends and distributions. The issuance of 5⅞6½% Senior Notes due ~~2026,~~2027 and 6⅞% Senior Notes due January 2029, partially offset by ~~repayments~~the redemption of ~~outstanding borrowings under TRP Revolver~~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 ~~projects.~~projects

In ~~2017,~~2018, we realized a net source of cash from financing activities primarily due to borrowings under the TRP Revolver and contributions from ~~TRC,~~noncontrolling interests, partially offset by the payments of distributions to ~~TRC, repayments of the TRP Revolver and redemption of our~~ ~~6⅜%~~ ~~Senior Notes. In September 2017, we sold a 25% interest in the Grand Prix Joint Venture and receive a total of $75.0 million in~~TRC. The contributions from ~~Blackstone.~~noncontrolling interests were primarily from Stonepeak and Blackstone to fund growth projects.

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~~and paid by us during the ~~nine~~three months ended ~~September 30, 2018.~~March 31, 2019:

Distributions on our Preferred Units are declared and paid monthly. As of ~~September 30, 2018,~~March 31, 2019, we have 5,000,000 Preferred Units outstanding. For the ~~nine~~three months ended ~~September 30, 2018, $8.4~~March 31, 2019, $2.8 million of distributions were paid. We have accrued distributions to Series A Preferred Unitholders of $0.9 million for ~~September,~~March, which were paid subsequently on ~~October~~April 15, ~~2018.~~2019.

In ~~October 2018,~~April 2019, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit. This distribution will be paid on ~~November~~May 15, ~~2018.~~2019.

Our capital ~~requirements relate to capital~~ expenditures ~~which~~ are classified as growth capital expenditures, business acquisitions, and maintenance expenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets. 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.

The following table details cash outlays for capital projects for the three months ended March 31, 2019 and 2018:

We currently estimate that in ~~2018~~2019 we will invest ~~at least $2,400~~approximately $2,300 million in net growth capital expenditures (exclusive of outlays for business acquisitions) and net contributions to investments in unconsolidated affiliates for announced projects. Given our objective of growth through expansions of existing assets, other internal growth projects, and acquisitions, we anticipate that over time that we will invest significant amounts of capital to grow and acquire assets. Future growth capital expenditures may vary significantly based on investment opportunities. We expect that ~~2018~~2019 net maintenance capital expenditures will be approximately ~~$110~~$130 million.

Total growth capital expenditures increased for the ~~nine~~three months ended ~~September 30, 2018~~March 31, 2019 as compared to the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2018, primarily due to spending related to ~~Grand Prix,~~construction of Train 7 and Train 8, and additional processing plants and associated infrastructure in the Permian ~~Basin, SouthOK and Badlands, and construction of Train 6 and other growth projects.~~Basin. Total maintenance capital expenditures increased for ~~2018~~the three months ended March 31, 2019 as compared to ~~2017,~~the three months ended March 31, 2018, primarily due to our increased asset base and additional infrastructure.

As of ~~September 30, 2018,~~March 31, 2019, there were ~~$54.7~~$56.5 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement.

Item 3. Quantitative and ~~Qualitative~~Qualitative Disclosures About Market Risk.

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

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

Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, ~~equity volumes,~~ NGL ~~equity volumes~~ and condensate equity volumes ~~and~~, future commodity purchases and sales, and transportation basis risk through ~~2021.~~2023. Market conditions may also impact our ability to enter into future commodity derivative contracts.

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

The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of ~~September 30, 2018,~~March 31, 2019, we have hedged the commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from our percent-of-proceeds processing arrangements, ~~and~~ (ii) future commodity purchases and sales in our Logistics and Marketing segment and (iii) natural gas transportation basis risk in our Logistics and Marketing segment by entering into derivative instruments. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.

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

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

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

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

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

The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of ~~September 30, 2018~~March 31, 2019:

	Fair Value			Result of 10% Price Decrease			Result of 10% Price Increase			Fair Value			Result of 10% Price Decrease		Result of 10% Price Increase
Natural gas	$	47.5		$	65.5		$	29.4		$	27.7		$	57.3	$	(1.8	)
NGLs		(185.5	)		(115.0	)		(256.0	)		23.2			59.4		(12.9	)
Crude oil		(37.8	)		(20.4	)		(55.1	)		(4.6	)		12.5		(25.4	)
Total	$	(175.8	)	$	(69.9	)	$	(281.7	)	$	46.3		$	129.2	$	(40.1	)

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

Our operating revenues increased (decreased) by ~~$(24.9)~~$11.8 million and $~~(3.6)~~(38.8) million during the three months ended ~~September 30,~~March 31, 2019 and 2018, ~~and 2017, and $(73.6) million and $(4.9) million during the nine months ended September 30, 2018 and 2017,~~ as a result of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in other comprehensive income until the underlying hedged transactions settle. We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues.

Our risk management position has moved from a net ~~liability~~asset position of ~~$38.2~~$112.7 million at December 31, ~~2017~~2018 to a net ~~liability~~asset position of ~~$175.8~~$46.3 million at ~~September 30, 2018.~~March 31, 2019. The fixed prices we currently expect to receive on derivative contracts are ~~below~~above the aggregate forward prices for commodities related to those contracts, creating this net ~~liability~~asset position.

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and the Securitization Facility. As of ~~September 30, 2018,~~March 31, 2019, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with the intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRP Revolver and the Securitization Facility will also increase. As of ~~September 30, 2018,~~March 31, 2019, we had ~~$290.0~~$977.6 million in outstanding variable rate borrowings under the TRP Revolver and the Securitization Facility. A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact our annual interest expense by ~~$2.9 million.~~$9.8 million based on our March 31, 2019 debt balances.

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts have limited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We have master netting provisions in the International Swap Dealers Association agreements with our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by ~~$68.0~~$52.7 million as of ~~September 30, 2018. Our potential loss~~March 31, 2019. The range of losses attributable to anour individual ~~counterparty is $4.9 million~~counterparties as of ~~September 30, 2018.~~March 31, 2019 would be between less than $0.1 million and $21.6 million, depending on the counterparty in default.

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

We have an active credit management process, which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectible accounts resulted in a 1% reduction of our third-party accounts receivable as of ~~September 30, 2018,~~March 31, 2019, our operating income would decrease by ~~$10.4~~$7.5 million in the year of the assessment.

During the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately ~~17%~~12% and ~~16%~~14% of our consolidated revenues. ~~No customer comprised greater than 10% of our consolidated revenues in the three and nine months ended September 30, 2017.~~

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered in this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of ~~September 30, 2018,~~March 31, 2019, the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

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

The information required for this item is provided in Note 1516 – Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.

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

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

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)


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

TABLE OF CONTENTS PART I—FINANCIAL INFORMATION

Item 1. Financial Statements		4

Consolidated Balance Sheets as of ~~September 30, 2018~~March 31, 2019 and December 31, ~~2017~~2018		4

Consolidated Statements of Operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~		5

Consolidated Statements of Comprehensive Income (Loss) for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~		6

Consolidated Statements of Changes in Owners' Equity for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~		7

Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2019 and 2018 ~~and 2017~~		8

Notes to Consolidated Financial Statements		9

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		3627

Item 3. Quantitative and Qualitative Disclosures About Market Risk		5843

Item 4. Controls and Procedures		6045

PART II—OTHER INFORMATION

Item 1. Legal Proceedings		6146

Item 1A. Risk Factors		6146

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		6146

Item 3. Defaults Upon Senior Securities		6146

Item 4. Mine Safety Disclosures		6146

Item 5. Other Information		6146

Item 6. Exhibits		6247

SIGNATURES

Signatures		6449


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
~~GPM~~	~~Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gas~~
~~LACT~~	~~Lease Automatic Custody Transfer~~
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

Three Months Ended	Date Paid Or to Be Paid		Total Distributions			Distributions to Targa Resources Corp.
September 30, 2018	November 13, 2018	$		237.6	$		234.8
June 30, 2018	August 13, 2018			234.0			231.2
March 31, 2018	May 11, 2018			229.7			226.9
December 31, 2017	February 12, 2018			228.5			225.7

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

	Three Months Ended September 30, 2018
	Pre-Adoption			Effect of Adoption			Post-Adoption
Revenues:
Sales of commodities	$	2,738.7		$	(84.6	)	$	2,654.1
Fees from midstream services		338.1			(5.8	)		332.3
Total revenues		3,076.8			(90.4	)		2,986.4
Costs and expenses:
Product purchases		2,473.9			(90.4	)		2,383.5
Income from operations		80.6			—			80.6
Income (loss) before income taxes		(8.7	)		—			(8.7	)
Net income (loss)	$	(8.7	)	$	—		$	(8.7	)

	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017
	Pro Forma			Pro Forma
Revenues	$	2,131.8		$	6,126.2
Net income (loss)		(244.7	)		(297.0	)

Balance at December 31, 2017	$	2,165.8
Amortization		(136.2	)
Balance at September 30, 2018	$	2,029.6

	Balance Sheet Location	March 31, 2019
Right-of-use assets
Operating leases, gross	Other long-term assets	$	25.2
Finance leases, gross	Property, plant and equipment		40.9

Lease liabilities
Current:
Operating leases	Accounts payable and accrued liabilities	$	6.6
Finance leases	Current debt obligations		10.5
Non-current:
Operating leases	Other long-term liabilities		17.3
Finance leases	Long-term debt		27.7

		Three Months Ended March 31, 2019
Lease cost
Operating lease cost	$	1.9
Short-term lease cost		7.6
Variable lease cost		1.3
Finance lease cost
Amortization of right-of-use assets		3.1
Interest expense		0.4
Total lease cost	$	14.3

	Three Months Ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows for operating leases	$	1.9
Operating cash flows for finance leases		0.4
Financing cash flows for finance leases		2.7

	Operating Leases			Finance Leases
Future Minimum Lease Payments Beginning After March 31,
2019	$	7.4		$	11.8
2020		5.6			11.0
2021		5.3			9.2
2022		4.2			8.2
2023		2.4			1.0
Thereafter		1.0			—
Total undiscounted cash flows		25.9			41.2
Less imputed interest		(2.0	)		(3.0	)
Total lease liabilities	$	23.9		$	38.2

	Leases
2019	$	20.5
2020		17.7
2021		14.9
2022		12.6
2023		6.0
Thereafter		1.7
Total payments	$	73.4

		Commodity
		Derivative Contracts			Contingent
		Asset/(Liability)			Liability
Balance, December 31, 2017		$	(3.8	)	$	(319.4	)
	Change in fair value of TPL contingent consideration		-			(0.1	)
	Change in fair value of Permian Acquisition contingent consideration (1)		-			(12.0	)
	New Level 3 derivative instruments		(1.0	)		-
	Settlements included in Revenue		2.6			-
	Unrealized gain/(loss) included in OCI		(10.3	)		-
Balance, September 30, 2018		$	(12.5	)	$	(331.5	)

		2018				2019				2020 and after
Fixed consideration to be recognized as of September 30, 2018		$	116.5			$	500.1			$	2,790.7

		2019				2020				2021 and after
Fixed consideration to be recognized as of March 31, 2019		$	394.3			$	463.0			$	3,327.5

		Gathering and Processing		Logistics and Marketing		Other			Corporate and Eliminations		Consolidated Operating Margin
	(In millions)
Three Months Ended:
September 30, 2018		$	255.3	$	173.5	$	(20.8	)	$	—	$	408.0
September 30, 2017			198.3		115.9		(1.0	)		—		313.2

Nine Months Ended:
September 30, 2018		$	718.4	$	441.7	$	(42.2	)	$	—	$	1,117.9
September 30, 2017			549.3		358.5		3.9			—		911.7

	Three Months Ended September 30, 2018
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)	Gross Volume (3)		Ownership %			Net Volume (3)		Actual Reported
Permian Midland		1,466.9	Varies (4)				1,161.7		1,161.7
Permian Delaware		470.5		100	%		470.5		470.5
Total Permian		1,937.4					1,632.2		1,632.2

SouthTX		364.1	Varies (5)				272.1		364.1
North Texas		247.6		100	%		247.6		247.6
SouthOK		568.2	Varies (6)				454.6		568.2
WestOK		353.9		100	%		353.9		353.9
Total Central		1,533.8					1,328.2		1,533.8

Badlands (7)		90.5		100	%		90.5		90.5
Total Field		3,561.7					3,050.9		3,256.5

NGL production, MBbl/d (2)
Permian Midland		193.3	Varies (4)				152.2		152.2
Permian Delaware		58.9		100	%		58.9		58.9
Total Permian		252.2					211.1		211.1

SouthTX		49.0	Varies (5)				35.5		49.0
North Texas		29.6		100	%		29.6		29.6
SouthOK		61.2	Varies (6)				48.3		61.2
WestOK		20.7		100	%		20.7		20.7
Total Central		160.5					134.1		160.5

Badlands		10.5		100	%		10.5		10.5
Total Field		423.2					355.7		382.1

Number		Description

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

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

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

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

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

4.1	Specimen Unit Certificate for the Series A Preferred Units (attached as Exhibit B to the Second Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP and incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 15, 2015 (File No. 001-33303)).


4.2	~~Supplemental~~ Indenture dated ~~July 24, 2018 to Indenture dated October 25, 2012,~~as of January 17, 2019 among the ~~Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation,~~Issuers, the ~~other Subsidiary~~ Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit ~~4.4~~4.1 to Targa Resources Partners LP’s ~~Quarterly~~Current Report on Form ~~10-Q~~8-K filed ~~August 9, 2018~~January 23, 2019 (File No. 001-33303)).

4.3	~~Supplemental Indenture~~Registration Rights Agreement dated ~~July 24, 2018 to Indenture dated May 14, 2013,~~as of January 17, 2019 among the ~~Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation,~~Issuers, the ~~other Subsidiary~~ Guarantors and ~~U.S. Bank National Association~~Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit ~~4.5~~4.2 to Targa Resources Partners LP’s ~~Quarterly~~Current Report on Form ~~10-Q~~8-K filed ~~August 9, 2018~~January 23, 2019 (File No. 001-33303)).

4.4	~~Supplemental Indenture~~Registration Rights Agreement dated ~~July 24, 2018 to Indenture dated October 28, 2014,~~as of January 17, 2019 among the ~~Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation,~~Issuers, the ~~other Subsidiary~~ Guarantors and ~~U.S. Bank National Association~~Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit ~~4.6~~4.3 to Targa Resources Partners LP’s ~~Quarterly~~Current Report on Form ~~10-Q~~8-K filed ~~August 9, 2018~~January 23, 2019 (File No. 001-33303)).

~~4.5~~10.1	~~Supplemental Indenture~~Purchase Agreement dated ~~July 24, 2018 to Indenture dated September 14, 2015,~~as of January 10, 2019, among the ~~Guaranteeing Subsidiary,~~ Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers.

10.2+	Targa Resources ~~Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association~~Corp. 2019 Annual Incentive Compensation Plan (incorporated by reference to Exhibit ~~4.7~~10.1 to Targa Resources Partners LP’s ~~Quarterly~~Current Report on Form ~~10-Q~~8-K filed ~~August 9, 2018~~January 22, 2019 (File No. 001-33303)).

~~4.6~~10.3+	~~Supplemental Indenture dated July 24, 2018 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary,~~Indemnification Agreement by and between Targa Resources ~~Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors~~Corp. and ~~U.S. Bank National Association~~Julie Boushka, dated February 22, 2017 (incorporated by reference to Exhibit ~~4.8~~10.1 to Targa Resources Partners LP’s ~~Quarterly~~Current Report on Form ~~10-Q~~8-K filed ~~August 9, 2018~~March 5, 2019 (File No. 001-33303)).

~~Number~~		~~Description~~

~~4.7~~	Supplemental Indenture dated July 24, 2018 to Indenture dated October 17, 2017, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-33303)).

~~4.8~~	Supplemental Indenture dated July 24, 2018 to Indenture dated April 12, 2018, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-33303)).

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

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

Number		Description

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

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

101.INS*	XBRL Instance Document

101.SCH*	XBRL Taxonomy Extension Schema Document

101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*	XBRL Taxonomy Extension Label Linkbase Document

101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

	Targa Resources Partners LP

	By:	Targa Resources GP LLC,
		its general partner

Date: ~~November~~May 8, ~~2018~~2019	By:	/s/ Jennifer R. Kneale
		Jennifer R. Kneale
		Chief Financial Officer
		(Principal Financial Officer)