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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 October 31, 2017, 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”) 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, 2017 (“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:~~

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 May 1, 2018, there were 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units outstanding.

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 March 31, 2018 (“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, 2017			December 31, 2016								March 31, 2018			December 31, 2017
						(Unaudited)											(Unaudited)
						(In millions)											(In millions)
ASSETS	ASSETS											ASSETS
Current assets:	Current assets:											Current assets:
Cash and cash equivalents	Cash and cash equivalents					$	103.9		$	68.0		Cash and cash equivalents					$	206.7		$	124.7
Trade receivables, net of allowances of $0.1 and $0.9 million at September 30, 2017 and December 31, 2016							709.2			673.2
Trade receivables, net of allowances of $0.1 and $0.1 million at March 31, 2018 and December 31, 2017												Trade receivables, net of allowances of $0.1 and $0.1 million at March 31, 2018 and December 31, 2017						744.8			825.7
Inventories	Inventories						267.4			137.7		Inventories						96.7			204.5
Assets from risk management activities	Assets from risk management activities						18.7			16.8		Assets from risk management activities						63.2			37.9
Other current assets	Other current assets						80.5			31.5		Other current assets						31.3			55.8
Total current assets	Total current assets						1,179.7			927.2		Total current assets						1,142.7			1,248.6
Property, plant and equipment	Property, plant and equipment						13,685.2			12,511.9		Property, plant and equipment						14,762.0			14,198.6
Accumulated depreciation	Accumulated depreciation						(3,616.4	)		(2,821.0	)	Accumulated depreciation						(3,920.4	)		(3,768.7	)
Property, plant and equipment, net	Property, plant and equipment, net						10,068.8			9,690.9		Property, plant and equipment, net						10,841.6			10,429.9
Intangible assets, net	Intangible assets, net						2,214.8			1,654.0		Intangible assets, net						2,120.1			2,165.8
Goodwill, net	Goodwill, net						256.6			210.0		Goodwill, net						256.6			256.6
Long-term assets from risk management activities	Long-term assets from risk management activities						13.7			5.1		Long-term assets from risk management activities						41.4			23.2
Investments in unconsolidated affiliates	Investments in unconsolidated affiliates						222.1			240.8		Investments in unconsolidated affiliates						313.4			221.6
Other long-term assets	Other long-term assets						16.5			16.9		Other long-term assets						11.9			13.3
Total assets	Total assets					$	13,972.2		$	12,744.9		Total assets					$	14,727.7		$	14,359.0

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					$	949.2		$	773.9		Accounts payable and accrued liabilities					$	968.3		$	1,106.6
Accounts payable to Targa Resources Corp.	Accounts payable to Targa Resources Corp.						71.7			61.0		Accounts payable to Targa Resources Corp.						64.6			76.9
Liabilities from risk management activities	Liabilities from risk management activities						80.9			49.1		Liabilities from risk management activities						53.6			79.7
Current debt obligations	Current debt obligations						528.4			275.0		Current debt obligations						300.0			350.0
Total current liabilities	Total current liabilities						1,630.2			1,159.0		Total current liabilities						1,386.5			1,613.2
Long-term debt	Long-term debt						3,933.6			4,177.0		Long-term debt						4,629.2			4,268.0
Long-term liabilities from risk management activities	Long-term liabilities from risk management activities						14.9			26.1		Long-term liabilities from risk management activities						18.1			19.6
Deferred income taxes, net	Deferred income taxes, net						26.9			26.9		Deferred income taxes, net						24.0			24.0
Other long-term liabilities	Other long-term liabilities						484.9			205.3		Other long-term liabilities						568.1			576.0

Contingencies (see Note 16)

Contingencies (see Note 15)												Contingencies (see Note 15)
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, 2017			5,000,000		5,000,000
December 31, 2016			5,000,000		5,000,000
March 31, 2018												March 31, 2018		5,000,000		5,000,000
December 31, 2017												December 31, 2017		5,000,000		5,000,000
Common limited partners	Common limited partners	Issued		Outstanding			6,592.1			5,939.9		Common limited partners	Issued		Outstanding			6,377.1			6,500.3
September 30, 2017			275,168,410		275,168,410
December 31, 2016			275,168,410		275,168,410
March 31, 2018												March 31, 2018		275,168,410		275,168,410
December 31, 2017												December 31, 2017		275,168,410		275,168,410
General partner	General partner	Issued		Outstanding			810.1			796.7		General partner	Issued		Outstanding			805.7			808.2
September 30, 2017			5,629,136		5,629,136
December 31, 2016			5,629,136		5,629,136
March 31, 2018												March 31, 2018		5,629,136		5,629,136
December 31, 2017												December 31, 2017		5,629,136		5,629,136
Accumulated other comprehensive income (loss)	Accumulated other comprehensive income (loss)						(70.1	)		(61.8	)	Accumulated other comprehensive income (loss)						45.3			(46.0	)
							7,452.7			6,795.4								7,348.7			7,383.1
Noncontrolling interests in subsidiaries	Noncontrolling interests in subsidiaries						429.0			355.2		Noncontrolling interests in subsidiaries						753.1			475.1
Total owners' equity	Total owners' equity						7,881.7			7,150.6		Total owners' equity						8,101.8			7,858.2
Total liabilities and owners' equity	Total liabilities and owners' equity					$	13,972.2		$	12,744.9	��	Total liabilities and owners' equity					$	14,727.7		$	14,359.0

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,
	2017			2016			2017			2016			2018			2017
	(Unaudited)												(Unaudited)
	(In millions)												(In millions)
Revenues:
Sales of commodities	$	1,871.5		$	1,398.7		$	5,353.1		$	3,882.9
Fees from midstream services		260.3			253.6			759.0			795.5
Sales of commodities (see Note 3)													$	2,173.7		$	1,858.1
Fees from midstream services (see Note 3)														281.9			254.5
Total revenues		2,131.8			1,652.3			6,112.1			4,678.4			2,455.6			2,112.6
Costs and expenses:
Product purchases		1,663.1			1,222.7			4,737.8			3,378.9
Product purchases (see Note 3)														1,941.0			1,654.2
Operating expenses		155.5			143.0			462.6			413.9			173.2			151.9
Depreciation and amortization expense		208.3			184.0			602.8			563.6			198.1			191.1
General and administrative expense		46.6			44.0			139.4			132.3			52.6			45.5
Impairment of property, plant and equipment		378.0			—			378.0			—
Impairment of goodwill		—			—			—			24.0
Other operating (income) expense		0.6			4.9			17.2			6.1			0.3			16.2
Income (loss) from operations		(320.3	)		53.7			(225.7	)		159.6			90.4			53.7
Other income (expense):
Interest expense, net		(51.9	)		(57.9	)		(169.5	)		(171.2	)
Interest income (expense), net														20.2			(58.6	)
Equity earnings (loss)		0.2			(2.2	)		(16.6	)		(11.4	)		1.5			(12.6	)
Gain (loss) from financing activities		—			—			(10.7	)		21.4			—			—
Change in contingent considerations		126.8			0.3			125.6			0.3			(56.1	)		(3.3	)
Other, net		0.2			1.0			(2.7	)		0.8			—			(5.2	)
Income (loss) before income taxes		(245.0	)		(5.1	)		(299.6	)		(0.5	)		56.0			(26.0	)
Income tax (expense) benefit		—			(1.0	)		4.2			—			—			4.7
Net income (loss)		(245.0	)		(6.1	)		(295.4	)		(0.5	)		56.0			(21.3	)
Less: Net income attributable to noncontrolling interests		9.7			4.7			25.9			13.5
Less: Net income (loss) attributable to noncontrolling interests														13.2			6.0
Net income (loss) attributable to Targa Resources Partners LP	$	(254.7	)	$	(10.8	)	$	(321.3	)	$	(14.0	)	$	42.8		$	(27.3	)

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		(5.2	)		29.0			(6.6	)		68.2			0.8			(0.6	)
Net income (loss) attributable to common limited partners		(252.3	)		(42.6	)		(323.1	)		(90.6	)		39.2			(29.5	)
Net income (loss) attributable to Targa Resources Partners LP	$	(254.7	)	$	(10.8	)	$	(321.3	)	$	(14.0	)	$	42.8		$	(27.3	)

		Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
		2017			2016			2017			2016			2018		2017
		(Unaudited)						(Unaudited)						(Unaudited)
		(In millions)						(In millions)						(In millions)
Net income (loss)	Net income (loss)	$	(245.0	)	$	(6.1	)	$	(295.4	)	$	(0.5	)	$	56.0	$	(21.3	)
Other comprehensive income (loss):	Other comprehensive income (loss):
Commodity hedging contracts:	Commodity hedging contracts:
Change in fair value	Change in fair value		(106.8	)		12.9			(10.5	)		(40.5	)		64.6		66.2
Settlements reclassified to net income			2.1			(8.1	)		2.2			(50.6	)
Settlements reclassified to revenues															26.7		6.1
Other comprehensive income (loss)	Other comprehensive income (loss)		(104.7	)		4.8			(8.3	)		(91.1	)		91.3		72.3
Comprehensive income (loss)	Comprehensive income (loss)		(349.7	)		(1.3	)		(303.7	)		(91.6	)		147.3		51.0
Less: Comprehensive income attributable to noncontrolling interests			9.7			4.7			25.9			13.5
Less: Comprehensive income (loss) attributable to noncontrolling interests															13.2		6.0
Comprehensive income (loss) attributable to Targa Resources Partners LP	Comprehensive income (loss) attributable to Targa Resources Partners LP	$	(359.4	)	$	(6.0	)	$	(329.6	)	$	(105.1	)	$	134.1	$	45.0

																Accumulated																												Accumulated
	Limited					Limited					General					Other			Treasury				Non-						Limited					Limited					General					Other			Treasury				Non-
	Partner					Partner					Partner					Comprehensive			Units				controlling						Partner					Partner					Partner					Comprehensive			Units				controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Units		Amount		Interests			Total			Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)			Units		Amount		Interests			Total
	(Unaudited)																												(Unaudited)
	(In millions, except units in thousands)																												(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
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.		—		—			—		1,587.5			—		32.5			—			—		—		—			1,620.0			—		—			—		58.8			—		1.2			—			—		—		—			60.0
Purchase of noncontrolling interests in subsidiary		—		—			—		—			—		—			—			—		—		(12.5	)		(12.5	)
Acquisition of related party (see Note 14)																														—		—			—		—			—		—			—			—		—		1.2			1.2
Distributions to noncontrolling interests		—		—			—		—			—		—			—			—		—		(33.4	)		(33.4	)		—		—			—		—			—		—			—			—		—		(16.5	)		(16.5	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			—		—		93.8			93.8			—		—			—		—			—		—			—			—		—		280.1			280.1
Other comprehensive income (loss)		—		—			—		—			—		—			(8.3	)		—		—		—			(8.3	)		—		—			—		—			—		—			91.3			—		—		—			91.3
Net income (loss)		—	8.4				—		(323.1	)		—		(6.6	)		—			—		—		25.9			(295.4	)		—	2.8				—		39.2			—		0.8			—			—		—		13.2			56.0
Distributions		—		(8.4	)		—		(612.2	)		—		(12.5	)		—			—		—		—			(633.1	)		—		(2.8	)		—		(221.2	)		—		(4.5	)		—			—		—		—			(228.5	)
Balance, September 30, 2017		5,000	$	120.6			275,168	$	6,592.1			5,629	$	810.1		$	(70.1	)		—	$	—	$	429.0		$	7,881.7
Balance, March 31, 2018																														5,000	$	120.6			275,168	$	6,377.1			5,629	$	805.7		$	45.3			—	$	—	$	753.1		$	8,101.8

Accumulated

Limited

Limited

General

Other

Treasury

Non-

Partner

Partner

Partner

Comprehensive

Units

controlling

Preferred

Amount

Common

Amount

Units

Amount

Income (Loss)

Units

Amount

Interests

Total

(Unaudited)

(In millions, except units in thousands)

Balance, December 31, 2015

5,000

$
120.6

184,871

$
4,550.4

3,773

$
1,735.3

$
86.8

212

$
(10.3
)

$
420.1

$
6,902.9

Compensation on equity grants

—

—

—

2.2

—

—

—

—

—

—

2.2

Distribution equivalent rights

—

—

—

(0.2
)

—

—

—

—

—

—

(0.2
)
Issuance of common units under
   compensation program

—

—

30

—

—

—

—

—

—

—

—

Units tendered for tax
   withholding obligations

—

—

(1
)

—

—

—

—

1

(0.1
)

—

(0.1
)
Cancellation of treasury units

—

—

—

(10.2
)

—

(0.2
)

—

(213
)

10.4

—

—

Contributions from Targa
   Resources Corp.

—

—

58,621

1,167.2

1,197

23.8

—

—

—

—

1,191.0

Distributions to
   noncontrolling interests

—

—

—

—

—

—

—

—

—

(16.8
)

(16.8
)
Contributions from
   noncontrolling interests

—

—

—

—

—

—

—

—

—

32.7

32.7

Other comprehensive
   income (loss)

—

—

—

—

—

—

(91.1
)

—

—

—

(91.1
)
Net income (loss)

—

8.4

—

(90.6
)

—

68.2

—

—

—

13.5

(0.5
)
Distributions

—

(8.4
)

—

(440.2
)

—

(94.0
)

—

—

—

—

(542.6
)
Balance, September 30, 2016

5,000

$
120.6

243,521

$
5,178.6

4,970

$
1,733.1

$
(4.3
)

—

$
—

$
449.5

$
7,477.5


																Accumulated
	Limited					Limited					General					Other			Treasury					Non-
	Partner					Partner					Partner					Comprehensive				Units				controlling
	Preferred		Amount			Common		Amount			Units		Amount			Income (Loss)				Units		Amount		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.		—		—			—		641.9			—		13.1			—				—		—		—			655.0
Distributions to noncontrolling interests		—		—			—		—			—		—			—				—		—		(9.7	)		(9.7	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—				—		—		8.9			8.9
Other comprehensive income (loss)		—		—			—		—			—		—			72.3				—		—		—			72.3
Net income (loss)		—		2.8			—		(29.5	)		—		(0.6	)		—				—		—		6.0			(21.3	)
Distributions		—		(2.8	)		—		(191.4	)		—		(3.9	)		—				—		—		—			(198.1	)
Balance, March 31, 2017		5,000	$	120.6			275,168	$	6,360.9			5,629	$	805.3		$	10.5				—	$	—	$	360.4		$	7,657.7

			Nine Months Ended September 30,								Three Months Ended March 31,
			2017			2016					2018			2017

		(Unaudited)								(Unaudited)
		(In millions)								(In millions)
Cash flows from operating activities	Cash flows from operating activities								Cash flows from operating activities
Net income (loss)	Net income (loss)		$	(295.4	)	$	(0.5	)	Net income (loss)		$	56.0		$	(21.3	)
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:								Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense	Amortization in interest expense			7.1			9.8		Amortization in interest expense			2.3			2.4
Compensation on equity grants				—			2.2
Depreciation and amortization expense	Depreciation and amortization expense			602.8			563.6		Depreciation and amortization expense			198.1			191.1
Impairment of property, plant and equipment				378.0			—
Impairment of goodwill				—			24.0
Accretion of asset retirement obligations	Accretion of asset retirement obligations			3.0			3.5		Accretion of asset retirement obligations			0.9			1.3
Increase (decrease) in redemption value of mandatorily redeemable preferred interests	Increase (decrease) in redemption value of mandatorily redeemable preferred interests			8.5			(18.8	)	Increase (decrease) in redemption value of mandatorily redeemable preferred interests			(72.5	)		2.5
Deferred income tax expense (benefit)									Deferred income tax expense (benefit)			—			(0.5	)
Equity (earnings) loss of unconsolidated affiliates	Equity (earnings) loss of unconsolidated affiliates			16.6			11.4		Equity (earnings) loss of unconsolidated affiliates			(1.5	)		12.6
Distributions of earnings received from unconsolidated affiliates	Distributions of earnings received from unconsolidated affiliates			8.4			1.8		Distributions of earnings received from unconsolidated affiliates			4.2			2.7
Risk management activities	Risk management activities			13.9			11.7		Risk management activities			30.1			8.5
(Gain) loss on sale or disposition of assets	(Gain) loss on sale or disposition of assets			16.6			5.7		(Gain) loss on sale or disposition of assets			(0.1	)		16.1
(Gain) loss from financing activities				10.7			(21.4	)
Change in contingent considerations included in Other expense (income)	Change in contingent considerations included in Other expense (income)			(125.6	)		(0.3	)	Change in contingent considerations included in Other expense (income)			56.1			3.3
Changes in operating assets and liabilities, net of business acquisitions:	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			(91.5	)		(28.3	)	Receivables and other assets			95.0			140.6
Inventories	Inventories			(136.4	)		(27.8	)	Inventories			110.2			53.7
Accounts payable and other liabilities	Accounts payable and other liabilities			46.5			32.1		Accounts payable and other liabilities			(124.6	)		(99.8	)
Net cash provided by operating activities	Net cash provided by operating activities			463.2			568.7		Net cash provided by operating activities			354.2			313.2
Cash flows from investing activities	Cash flows from investing activities								Cash flows from investing activities
Outlays for property, plant and equipment	Outlays for property, plant and equipment			(866.6	)		(425.0	)	Outlays for property, plant and equipment			(595.9	)		(144.2	)
Outlays for business acquisition, net of cash acquired	Outlays for business acquisition, net of cash acquired			(570.8	)		—		Outlays for business acquisition, net of cash acquired			—			(480.8	)
Investments in unconsolidated affiliates	Investments in unconsolidated affiliates			(7.5	)		(4.6	)	Investments in unconsolidated affiliates			(88.0	)		(0.5	)
Return of capital from unconsolidated affiliates	Return of capital from unconsolidated affiliates			2.2			3.4		Return of capital from unconsolidated affiliates			1.5			—
Other, net	Other, net			(14.8	)		4.2		Other, net			5.1			—
Net cash used in investing activities	Net cash used in investing activities			(1,457.5	)		(422.0	)	Net cash used in investing activities			(677.3	)		(625.5	)
Cash flows from financing activities	Cash flows from financing activities								Cash flows from financing activities
Debt obligations:	Debt obligations:								Debt obligations:
Proceeds from borrowings under credit facility	Proceeds from borrowings under credit facility			1,496.0			1,110.0		Proceeds from borrowings under credit facility			600.0			480.0
Repayments of credit facility	Repayments of credit facility			(1,216.0	)		(1,390.0	)	Repayments of credit facility			(240.0	)		(630.0	)
Proceeds from borrowings under accounts receivable securitization facility	Proceeds from borrowings under accounts receivable securitization facility			281.6			121.4		Proceeds from borrowings under accounts receivable securitization facility			—			75.0
Repayments of accounts receivable securitization facility	Repayments of accounts receivable securitization facility			(278.5	)		(115.7	)	Repayments of accounts receivable securitization facility			(50.0	)		(65.0	)
Open market purchases of senior notes				—			(534.3	)
Redemption of senior notes				(287.6	)		—
Costs incurred in connection with financing arrangements	Costs incurred in connection with financing arrangements			(0.1	)		(7.5	)	Costs incurred in connection with financing arrangements			—			(0.1	)
Repurchase of common units under compensation plans				—			(0.1	)
Purchase of noncontrolling interests in subsidiary				(12.5	)		—
Contributions from general partner	Contributions from general partner			32.5			23.8		Contributions from general partner			1.2			13.1
Contributions from TRC	Contributions from TRC			1,587.5			1,167.2		Contributions from TRC			58.8			641.9
Contributions from noncontrolling interests	Contributions from noncontrolling interests			93.8			32.7		Contributions from noncontrolling interests			280.1			8.9
Distributions to noncontrolling interests	Distributions to noncontrolling interests			(33.4	)		(16.8	)	Distributions to noncontrolling interests			(16.5	)		(9.7	)
Distributions to unitholders	Distributions to unitholders			(633.1	)		(542.6	)	Distributions to unitholders			(228.5	)		(198.1	)
Payments of distribution equivalent rights				—			(0.3	)
Net cash provided by (used in) financing activities				1,030.2			(152.2	)
Net cash provided by financing activities									Net cash provided by financing activities			405.1			316.0
Net change in cash and cash equivalents	Net change in cash and cash equivalents			35.9			(5.5	)	Net change in cash and cash equivalents			82.0			3.7
Cash and cash equivalents, beginning of period	Cash and cash equivalents, beginning of period			68.0			135.4		Cash and cash equivalents, beginning of period			124.7			68.0
Cash and cash equivalents, end of period	Cash and cash equivalents, end of period		$	103.9		$	129.9		Cash and cash equivalents, end of period		$	206.7		$	71.7

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.

On February 17, 2016, TRC completed the previously announced transactions contemplated pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement,” and such transactions, the “TRC/TRP Merger”),Our common units are wholly owned by ~~and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”),~~ TRC and ~~Spartan Merger Sub LLC,~~no longer publicly traded as a ~~subsidiary~~result of ~~TRC (“Merger Sub”), pursuant to which TRC acquired indirectly all~~TRC’s acquisition of our outstanding common units that ~~TRC~~it and its subsidiaries did not already ~~own. Upon the terms and conditions set forth~~own in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.2016.

At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares.

Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. 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.”

On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), which became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the incentive distribution rights (“IDRs”) held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special General Partner Interest (the “Special GP Interest” as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable.

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 unaudited consolidated financial statements 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 information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report.

The unaudited consolidated financial statements for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2018 include all adjustments that we believe are necessary for a fair statement of the results for interim periods. 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 results for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2018 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. There were no significant updates or revisions to our policies during the nine months ended September 30, 2017, except as noted below.

~~Revenue from Contracts with Customers~~Recently issued accounting pronouncements not yet adopted

In ~~May 2014,~~February 2016, the Financial Accounting Standards Board ~~("FASB"~~(“FASB”) issued Accounting ~~Standard~~Standards Update (“ASU”) ~~No. 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements in Topic 605,~~ ~~Revenue Recognition, and most industry-specific guidance. The update also creates 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 new revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standard requires a five step process of (1) identifying the contracts with customers, (2) identifying the performance obligations in the contracts, (3) determining the transaction price, (4) allocating the transaction price to the performance obligations, and (5) recognizing revenue when, or as, the performance obligations are satisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

~~With the~~ ~~issuance~~ ~~in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,~~ the revenue recognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retrospectively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the standard is adopted.

~~In March 2016, the FASB issued ASU 2016-08,~~ ~~Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations~~. The amendments in this update improve the operability and understandability of the implementation guidance on principal versus agent considerations, including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer. These amendments are effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted.

In ~~April~~ ~~2016, the FASB issued ASU 2016-10,~~ ~~Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing~~. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.

~~In May 2016, the FASB issued ASU 2016-12,~~ ~~Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients~~. These amendments address certain implementation issues related to assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition, and also provide additional practical expedients.

~~In December~~ ~~2016, the FASB issued ASU 2016-20,~~ ~~Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers~~. The amendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement for remaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provide clarified guidance regarding impairment testing of capitalized contract costs.

We have disaggregated contracts within our two segments and are in the process of completing our review of contracts and transaction types with counterparties in order to evaluate how the new standard would impact our current revenue recognition and disclosure policies upon adoption.

Based on our progress to date, we have preliminarily concluded that the contracts within our Gathering and Processing segment where we purchase and obtain control of the entire natural gas stream are contracts with suppliers rather than customers and therefore, not included in the scope of Topic 606. However, these supplier contracts are subject to updated guidance in ASC 705, ~~Cost of Sales and Services~~, whereby any embedded fees within such contracts, which historically have been reported as “Fees from midstream services,” will be reported instead as a reduction of “Product purchases” upon adoption of Topic 606. In addition, we have concluded that in most cases, we are acting as the principal in the sale of hydrocarbons to end customers. We are continuing to assess certain Gathering and Processing contracts whereby we obtain control over some, but not all, of the natural gas and natural gas liquids stream, including arrangements where the producer takes or may elect to take a portion of the merchantable gas and/or natural gas liquids in kind. ~~Specifically, when such arrangements contain both a service revenue element and a supply element, we are in the process of determining how each element should be measured.~~

At this time, we are not anticipating a significant change in revenue recognition for the contracts within our Logistics and Marketing segment, although the potential effects of contributions in aid of construction (which may also affect certain Gathering and Processing contracts where we are acting as an agent for the producer), tiered pricing, and excess fuel are currently being evaluated. We are also anticipating additional disclosures for fixed consideration allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the current reporting period, separate presentation of revenue from contracts with customers and non-customer revenue (i.e. the effects of derivative activity and lease revenue) as well as unbilled receivables and deferred revenue.

The new revenue recognition standard is effective for us on January 1, 2018, and currently we plan to adopt using the modified retrospective method and will recognize a cumulative effect adjustment, if any, in the first quarter of 2018. However, we will continue to evaluate our planned adoption method based on our views regarding stakeholder needs and a final determination on remaining accounting matters still under evaluation. We have also established a cross-functional team to assist with the implementation through documentation of process changes, identification of implementation risks, update and development of mitigating controls, determination of data requirements, and identification of changes in system mapping and configuration.

In ~~February~~ ~~2016, the FASB issued ASU~~ 2016-02, Leases (Topic 842). The amendments in this update require, among other ~~things,~~items, that lessees recognize the following for all leases (with 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 March 2018, the FASB approved an additional transition method that, if elected, would allow entities to apply the new leases standard to all new leases entered into after January 1, 2019 and all existing lease contracts as of January 1, 2019 through a cumulative adjustment to retained earnings.

We expect to adopt Topic 842 on January 1, 2019, and expect to elect the ~~amendments~~land easement practical expedient as well as the optional additional transition method. We are currently in the ~~first quarter~~process of ~~2019~~gathering a complete population of our lease arrangements, and are ~~currently~~ evaluating the ~~impacts~~impact of the ~~amendments to~~new standard on our consolidated financial ~~statements and accounting practices for leases.~~statements.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. ~~These~~The amendments in this update change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The amendments ~~in this update~~ 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 ~~this guidance~~the amendments on January 1, 2019 and ~~are continuing to evaluate the~~do not expect a material impact on our ~~measurement~~consolidated financial statements.

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 ~~credit losses.~~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 table summarizes the effects of adoption on our 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.

~~Cash Flow Classification~~Targeted Improvements to Accounting for Hedge Activities

In August ~~2016, the~~2017, FASB issued ASU ~~2016-15,~~2017-12, ~~Statement of Cash Flows~~Derivatives and Hedging (Topic ~~230)~~815): ~~Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). These amendments clarify how entities should classify certain cash receipts and cash payments in the statement of cash flows related~~Targeted Improvements 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. These amendments are effectiveAccounting for ~~fiscal years, and interim periods within those years, beginning after December 15, 2017, with~~

~~early adoption permitted. We plan to adopt the applicable amendments in the first quarter of 2018 and expect a minimal effect on our consolidated financial statements.~~

In ~~October~~ ~~2016, the FASB issued ASU 2016-16,~~ ~~Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory~~Hedge Activities. The amendments in this update are intended to ~~improve the accounting~~better align risk management activities and financial reporting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party or otherwise recovered, which is an exception to the principle of comprehensive recognition of current and deferred income taxes in GAAP. This update eliminates the exception by requiring entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. We early adopted the applicable amendments in first quarter of 2017 on a modified retrospective basis. The adoption resulted in no effect as TRP is not subject to income taxes.

In ~~January~~ ~~2017, the FASB issued ASU 2017-01,~~ ~~Business Combinations (Topic 805): Clarifying the Definition of a Business~~.hedging relationships. The amendments ~~clarify~~cover multiple aspects of hedge accounting including: (1) change the ~~definition of a business to assist entities with evaluating whether transactions should be accounted~~way in which ineffectiveness is accounted; (2) allow for ~~as acquisitions (or disposals) of assets or businesses by providing an initial required screen to determine when an integrated set of assets~~new hedge strategies; and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, then the amendments (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments also provide a framework to assist entities in evaluating whether both an input and a substantive process are present. These amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods, with early application permitted for transactions that have not been previously reported. We will apply this guidance to all transactions completed subsequent to our adoption of these amendments.

~~In January 2017, FASB issued ASU 2017-04,~~ ~~Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment~~, which eliminates Step 2 from the goodwill impairment test. Step 2 required entities to compute the implied fair value of goodwill if it was determined that the carrying amount of a reporting unit exceeded its fair value.(3) change hedge disclosures. Under the amendments in this update, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount and should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value. The goodwill impairment recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity still hasnew guidance, companies will have the option to perform a qualitative quarterly effectiveness assessment once the ~~qualitative assessment~~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 ~~a reporting unit to determine if~~hedge accounting treatment, most of these strategies involving the quantitative impairment test is necessary. These amendments are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We expect to apply these amendments for our annual goodwill impairment test ashedging of ~~November 30, 2017.~~ ~~Had we applied this new guidance for our November 2016 impairment test date, the full balance of our goodwill would~~contractually specified components. Lastly, disclosure requirements have been ~~impaired. We expect~~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 ~~apply these amendments for our annual goodwill impairment test as of November 30, which may result in impairment of goodwill for 2017.~~

~~In February 2017, FASB issued ASU 2017-05,~~ ~~Other Income—Gains~~be disclosed; and ~~Losses from~~(3) eliminate the ~~Derecognition of Nonfinancial Assets (Subtopic 610-20), which clarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Specifically, the amendments clarify that the guidance applies~~requirement to all nonfinancial assets and in substance nonfinancial assets unless other specific guidance applies and defines "in substance financial 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. separately disclose ineffectiveness. These amendments are effective for fiscal years beginning after December 15, 2018, and interim periods within those years, ~~beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of such amendments on our consolidated financial statements.~~

In ~~May~~ ~~2017, FASB issued ASU 2017-09,~~ ~~Compensation—Stock Compensation (Topic 718): Scope of Modification Accounting~~, which clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. Under the new guidance, an entity will apply modification accounting only if the fair value, vesting conditions or the classification of the award changes as a result of the change in terms or conditions of a share-based payment award. In addition, the new guidance clarifies that regardless of whether an entity is required to apply modification accounting, the existing disclosure requirements and other aspects of GAAP associated with modifications continue to apply. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We early adopted the ~~applicable~~ amendments ~~in the second quarter of 2017 and will apply the new guidance prospectively to any awards modified~~ on ~~or after the adoption date.~~

~~In July 2017, FASB issued ASU 2017-11,~~ Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception. The amendments in this update are intended to simplify the accounting for certain equity-linked financial instruments and embedded features with down round features that result in the strike price being reduced on the basis of the pricing of future equity offerings. Under the new guidance, a down round feature will no longer need to be considered when determining whether certain financial instruments or embedded features should be classified as liabilities or equity instruments. That is, a down round feature will no longer preclude equity classification when assessing whether an instrument or embedded feature is indexed to an entity's own stock. In addition, the amendments clarify existing disclosure requirements for equity-classified instruments. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15,January 1, 2018, with ~~early adoption permitted. We early adopted~~ the ~~applicable amendments~~changes to ineffectiveness resulting in ~~the second quarter of 2017 on a retrospective basis noting~~ no effect on ~~our consolidated financial statements.~~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 2017, FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities~~, which~~. The amendments in this update are intended to better align risk management activities and financial reporting for hedging relationships. The ~~new guidance covers~~amendments cover multiple aspects of hedge ~~accounting:~~accounting including: (1) ~~changes~~change the way in which ineffectiveness is ~~accounted,~~accounted; (2) ~~allows~~allow for new hedge ~~strategies,~~strategies; and (3) ~~changes~~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 iswas required under ~~current~~prior guidance. Several new hedging strategies ~~will be allowed to be given~~qualify for hedge accounting treatment, most of ~~which involve~~these strategies involving the hedging of contractually specified components. Lastly, disclosure requirements ~~will be~~have been updated toto: (1) require that hedge income be presented on the same line item as the related hedged ~~item,~~item; (2) require hedge program objectives to be ~~disclosed,~~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 apply the cumulative earnings approach to classify distributions received from equity method investees which is consistent with our historical practice.

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments in this update clarify the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing an initial required screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, then the amendments (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments also provide a framework to assist entities in evaluating whether both an input and a substantive process are present. The amendments were effective for us on January 1, 2018 and were adopted on a prospective basis.

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.

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

In February 2018, FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220). The amendments in this update allow a reclassification of stranded tax effects in accumulated other comprehensive income as a result of the Tax Cuts and Jobs Act to retained earnings. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We ~~plan~~early adopted the amendments on January 1, 2018, however, as we are not subject to ~~adopt~~federal income taxes, there was no impact on our consolidated financial statements.

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 three months ended March 31, 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.

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 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, which is a series of distinct days of the applicable ~~amendments~~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 to the customer of the days of service transferred to date, relative to the remaining days of service promised under the contract. The transaction price of such 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 the Company is 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, the Company measures 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, the Company defines 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 the Company is 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, the Company estimates the total consideration, which 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. The Company’s 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.

In May 2017, we announced plans to construct Grand Prix, a new common carrier NGL pipeline. Grand Prix will transport volumes from the Permian Basin and 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 our volumes and other third party customer commitments, and is expected to be in service in the second quarter of 2019. The capacity of the pipeline from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d.

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. We account for Grand Prix 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.

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, 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 initially own a 25% interest, and KMTP initially 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 the receipt of necessary 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 at the end of the fourth quarter of 2018. The Partnership will manage construction of, and 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 Grand Prix Development LLC (“Grand Prix DevCo JV”), which owns a 20% interest in the Grand Prix Joint Venture (not including 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 ~~2018~~2019. Grand Prix is expected to be in service in the second quarter of 2019. GCX is expected to be in service in the fourth quarter of 2019, pending the receipt of necessary regulatory approvals.

We hold a controlling interest in each of the DevCo JVs, as we have the majority voting interest and ~~expect an immaterial effect~~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 ~~our~~a consolidated basis in our consolidated financial ~~statements.~~statements, and continue to account for GCX as an equity method investment as disclosed in Note 7 – Investments in Unconsolidated Affiliates.

On March 1, 2017, ~~Targa~~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 that would occur in May 2018 and May 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017.

~~New Delaware’s gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties in Texas.~~ 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 New Delaware assets include 70 MMcf/d of processing capacity, and we are in the process of installing a 60 MMcf/d plant, known as the Oahu Plant, in the Delaware Basin with expectations of commencing operations in the fourth quarter of 2017. Currently, there is 40 MBbl/d of crude gathering capacity on the New Delaware system. Since March 1, 2017, financial and statistical data of New Delaware have been included in Sand Hills operations.

New Midland’s gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties in Texas. 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. Since March 1, 2017, financial and statistical data of New Midland have been included in SAOU operations.

New Delaware’s gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and the New Midland’s gas gathering and processing assets were connected to our existing WestTX system in October 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and will afford enhanced flexibility in serving our producer customers.

On January 26, 2017, Targa completed a public offering of 9,200,000 shares of its common stock (including the shares sold pursuant to the underwriters’ overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. Targa used the net proceeds from this public offering to fund the cash portion of the ~~Permian Acquisition purchase price~~earn-out due ~~upon closing and for general corporate purposes.~~in 2018 expired with no required payment.

The acquired businesses contributed revenues of $75.2 million and a net loss of $21.5 million to us for the period from March 1, 2017 to September 30, 2017, and are reported in our Gathering and Processing segment. As of September 30, 2017, we had incurred $5.6 million of acquisition-related costs. These expenses are included in Other expense in our Consolidated Statements of Operations for the nine months ended September 30, 2017.

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

The following summarized unaudited pro forma Consolidated ~~Statement~~Statements of Operations information for the ~~nine~~three months ended ~~September 30,~~March 31, 2017 ~~and September 30, 2016~~ 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.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			March 31, 2017
	Pro Forma			Pro Forma			Pro Forma			Pro Forma			Pro Forma
Revenues	$	2,131.8		$	1,663.0		$	6,126.2		$	4,697.3		$	2,126.7
Net income (loss)		(244.7	)		(18.3	)		(297.0	)		(44.7	)		(23.4	)

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:

~~The following table summarizes the consideration transferred to acquire New Delaware and New Midland:~~

We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair value of the assets acquired and liabilities assumed at the acquisition date is shown below:

Under the acquisition method of accounting, the assets acquired and liabilities assumed are recognized at their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. ~~Such excess of purchase price over the fair value of net assets acquired was approximately $46.6 million, which was recorded as goodwill. The goodwill is attributable to expected~~ ~~operational and capital synergies.~~ ~~The goodwill is amortizable for tax purposes.~~

~~The fair value of assets acquired included trade receivables of $6.7 million, substantially all of which has been subsequently collected.~~

The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 17 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.

During the three months ended June 30, 2017, we recorded measurement period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs, including forecasts of future volumes, capital expenditures and operating expenses. The measurement period adjustments were based upon information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of the amounts recognized at that date. We recognized these measurement period adjustments in the three months ended June 30, 2017, with the effect in the Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at March 1, 2017. During the three months ended June 30, 2017, the acquisition date fair value of contingent consideration liability decreased by $45.3 million, intangible assets increased by $66.7 million, and other assets, net, increased by $0.4 million, which resulted in a decrease in goodwill of $112.4 million. These adjustments resulted in an increase in depreciation and amortization expense of $0.4 million recorded for the three months ended June 30, 2017.

~~During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional measurement period adjustments.~~

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 ~~that would occur~~ in May 2018 and May 2019. The acquisition date fair value of the potential earn-out payments of $416.3 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets. Changes in the fair value of ~~this~~the liability (that were not accounted for as revisions of the acquisition date fair value) are included in earnings. During the three ~~and nine~~ months ended ~~September 30,~~March 31, 2018 and 2017, we recognized ~~$126.6~~$56.0 million and ~~$125.5~~$3.2 million as Other income related to the change in fair value of the contingent ~~consideration. See~~consideration.

~~Note 11 – Other Long-term Liabilities and Note 14 – Fair Value Measurements for additional discussion~~

The portion of the ~~change~~earn-out due in ~~fair value and the fair value methodology.~~

~~On May 9, 2017, we purchased all~~ See Note 10 – Other Long-term Liabilities and Note 13 – Fair Value Measurements for additional discussion of the equity interests in Flag City Processing Partners, LLC ("FCCP") from Boardwalk Midstream, LLC (“Boardwalk”) and all of the equity interests in FCPP Pipeline, LLC from Boardwalk Field Services, LLC (“BFS”) for a base purchase price of $60.0 million subject to customary closing adjustments. The final adjustment to the base purchase price paid to Boardwalk was an additional $3.6 million. As part of the acquisition (the “Flag City Acquisition”), we acquired a natural gas processing plant with 150 MMcf/d of operating capacity (the “Flag City Plant”) located in Jackson County, Texas; 24 miles of gas gathering pipeline systems and related rights-of-ways located in Bee and Karnes counties in Texas; 102.1 acres of land surrounding the Flag City Plant; and a limited number of gas supply contracts.

The gas processing activities under the Flag City Plant contracts have been transferred to our Silver Oak Plants. We have shut down the Flag City Plant and are moving the plant and its component parts to other Targa locations.

We accounted for this purchase as an asset acquisition and have capitalized less than $0.1 million of acquisition related costs as a component of the cost of assets acquired, which resulted in an allocation of $52.3 million of property, plant and equipment, $7.7 million of intangible assets for customer contracts and $3.6 million of current assets and liabilities, net.

Effective as of June 1, 2017, we repurchased from SN Catarina, LLC (a subsidiary of Sanchez Energy Corp.) their 10% interest in our consolidated Silver Oak II Gas processing facility and other related assets located in Bee County, Texas for a purchase price of $12.5 million. The change in our ownership interest was accounted for as an equity transaction representing the acquisition of a noncontrolling interest and no gain or loss was recognized in our Consolidated Statements of Operations as a result.

Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice Gas Plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. ~~Additionally, the VGS asset retirement obligations (“ARO”) were assumed by the buyer.~~ VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice Gas Plant through our ownership in VESCO. Targa Midstream Services LLC continued to operate the Venice gathering system for four months after closing pursuant to a Transition Services Agreement with VGS.

As a result of the April 4, 2017 sale, we recognized a loss of $16.1 million in our Consolidated Statements of Operations for the three months ended March 31, 2017 as part of Other operating (income) expense to impair our basis in the VGS net assets to its fair ~~value.~~

In May 2017, we announced plans to construct a new common carrier NGL pipeline. The NGL pipeline (“Grand Prix”) will transport volumes from the Permian Basin and 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 our volumes and other third party customer commitments, and is expected to be in service in the second quarter of 2019. The capacity of the pipeline from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d.

~~In September 2017, we sold to funds managed by Blackstone Energy Partners ("Blackstone") a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”).We are the operator and construction manager of Grand Prix. Our share of~~ ~~total growth capital expenditures for Grand Prix is expected to be approximately $975 million, with approximately $275 million of spending in 2017.~~

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 for transportation and fractionation whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin.

	September 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
Commodities	$	255.6	$	126.9	$	79.6	$	191.6
Materials and supplies		11.8		10.8		17.1		12.9
	$	267.4	$	137.7	$	96.7	$	204.5

	September 30, 2017			December 31, 2016			Estimated Useful Lives (In Years)	March 31, 2018			December 31, 2017			Estimated Useful Lives (In Years)
Gathering systems	$	6,900.8		$	6,626.9		5 to 20	$	7,154.4		$	7,037.2		5 to 20
Processing and fractionation facilities		3,571.3			3,383.6		5 to 25		3,678.3			3,563.0		5 to 25
Terminaling and storage facilities		1,238.0			1,205.0		5 to 25		1,252.3			1,244.1		5 to 25
Transportation assets		343.2			451.4		10 to 25		343.6			343.6		10 to 25
Other property, plant and equipment		284.7			274.0		3 to 25		312.1			303.5		3 to 25
Land		123.8			121.2		—		144.3			125.7		—
Construction in progress		1,223.4			449.8		—		1,877.0			1,581.5		—
Property, plant and equipment		13,685.2			12,511.9				14,762.0			14,198.6
Accumulated depreciation		(3,616.4	)		(2,821.0	)			(3,920.4	)		(3,768.7	)
Property, plant and equipment, net	$	10,068.8		$	9,690.9			$	10,841.6		$	10,429.9

Intangible assets	$	2,736.6		$	2,036.6		10 to 20	$	2,736.6		$	2,736.6		10 to 20
Accumulated amortization		(521.8	)		(382.6	)			(616.5	)		(570.8	)
Intangible assets, net	$	2,214.8		$	1,654.0			$	2,120.1		$	2,165.8

We recorded a non-cash pre-tax impairment charge of $378.0 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 is a result of our current assessment that forecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. Given the current price environment, Targa is projecting 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 are based on our estimates of future revenues, income from operations and other factors, such as timing of capital expenditures. We take into account current and expected industry and market conditions, including commodity prices and volumetric forecasts. The discount rate used in our DCF analysis is 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 expense in our Consolidated Statements of Operations.

~~Intangible assets consist~~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 ~~customer contracts~~Gulf Coast Express Pipeline (“GCX”), a natural gas pipeline from the Waha hub to Agua Dulce, 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 ~~customer relationships acquired~~DCP each initially own a 25% interest, and KMTP initially 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 the receipt of necessary regulatory approvals. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the GCX Joint Venture.

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 in service in the second quarter of 2019. GCX is expected to be in service in the fourth quarter of 2019, pending the receipt of necessary 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.

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 ~~Flag City Acquisitions~~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, ~~the mergers with Atlas Energy L.P.~~ and ~~Atlas Pipeline Partners L.P.~~paid an additional $90.0 million in ~~2015~~cash on May 30, 2017 (collectively, the ~~“Atlas mergers”~~“initial purchase price”). Subject to certain performance-linked measures and ~~our Badlands acquisition~~other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in ~~2012.~~potential earn-out payments that would occur in May 2018 and May 2019. The ~~fair values~~potential earn-out payments will be based upon a multiple of ~~these acquired intangible assets were determined at the date of acquisition based~~realized gross margin from contracts that existed 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 capacityMarch 1, 2017. The portion of the ~~gathering~~earn-out due in 2018 expired with no required payment.

~~system, pricing volatility and the discount rate.~~ Pro Forma Impact of Permian Acquisition on Consolidated Statements of Operations~~Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers.~~

The ~~intangible assets acquired in~~following summarized unaudited pro forma Consolidated Statements of Operations information for the three months ended March 31, 2017 assumes that the Permian Acquisition ~~were recorded at a~~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.

A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its fair value. We ~~are amortizing these intangible assets over a 10-year life using~~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 ~~straight-line method.~~

~~The intangible assets acquired~~potential earn-out payments of $416.3 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets. Changes in the ~~Atlas mergers~~fair value of the liability (that were not accounted for as revisions of the acquisition date fair value) are ~~being amortized over a 20-year life using~~included in earnings. During the ~~straight-line method,~~three months ended March 31, 2018 and 2017, we recognized $56.0 million and $3.2 million as ~~a reliably determinable pattern of amortization could not be identified. Amortization expense attributable to our intangible assets~~Other income related to the ~~Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation over a 20-year life.~~

~~The estimated annual amortization expense for intangible assets is approximately $188.4 million, $182.6 million, $171.6 million, $159.4 million and $149.5 million for each~~change in fair value of the ~~years 2017 through 2021.~~contingent consideration.

The ~~changes~~portion of the earn-out due in 2018 expired with no required payment. As of March 31, 2018, the fair value of the second potential earn-out payment of $373.0 million has been recorded within Other long-term liabilities on our ~~intangible assets are as follows:~~Consolidated Balance Sheets. See Note 10 – Other Long-term Liabilities and Note 13 – Fair Value Measurements for additional discussion of the fair value methodology.

As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. During the first quarter of 2016, we finalized our 2015 impairment assessment and recorded additional impairment expense of $24.0 million in our Consolidated Statement of Operations. The impairment of goodwill was primarily due to the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas.

~~Changes in the net book value of our goodwill are as follows:~~5 — Inventories

~~Our investments in unconsolidated affiliates consist of the following:~~6 — Property, Plant and Equipment and Intangible Assets

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 were formed to provide services for the benefit of its joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with its joint interest owners, which cover costs of operations (excluding depreciation and amortization).

~~In July 2017, we entered into the 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 is expected to be completed by November 2017.~~

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

~~(2) Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford.~~

Our equity loss for the nine months ended September 30, 2017 includes the effect of an impairment in the carrying value of our investment in T2 EF Cogen. As a result of the decrease in current and expected future utilization of the underlying cogeneration assets, we have determined that factors indicate that a decrease in the value of our investment occurred that was other than temporary. As a result of this evaluation, we recorded an impairment loss of approximately $12.0 million in the first quarter of 2017, which represented our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as our impairment of the unamortized excess fair value resulting from the Atlas mergers.

~~The carrying values of the T2~~ ~~Joint Venture~~s include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of September 30, 2017, $26.8 million of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20-year useful lives of the underlying assets.

In ~~October~~December 2017, we ~~announced that we had executed a letter of intent along~~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 proposed~~ Gulf Coast Express Pipeline ~~Project~~ (“~~GCX Project”~~GCX”), ~~which would~~ a natural gas pipeline from the Waha hub to Agua Dulce, Texas. The pipeline will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. ~~Under the terms of the letter of intent, we would~~We and DCP each initially own a 25% interest, and KMTP initially owns a 50% interest in ~~the GCX Project.~~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 ~~would~~will serve as the operator and constructor of ~~the~~ GCX, ~~Project,~~ and we ~~would~~will commit significant volumes to ~~it, including certain volumes provided by~~the pipeline. In addition, Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin ~~system. The participation~~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 the receipt of necessary regulatory approvals. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the GCX Joint Venture.

In February 2018, we formed three ~~parties involved~~development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix, GCX ~~Project~~and an approximately 100 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). Stonepeak owns a 95% interest in Grand Prix Development LLC (“Grand Prix DevCo JV”), which owns a 20% interest in the Grand Prix Joint Venture (not including 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 ~~subject~~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 ~~negotiation~~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 in service in the second quarter of 2019. GCX is expected to be in service in the fourth quarter of 2019, pending the receipt of necessary regulatory approvals.

We hold a controlling interest in each of the DevCo JVs, as we have the majority voting interest and ~~execution~~the supermajority voting provisions of ~~definitive agreements.~~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.

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”).

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 months ended March 31, 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.

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 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) are included in earnings. During the three months ended March 31, 2018 and 2017, we recognized $56.0 million and $3.2 million as Other income 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 March 31, 2018, the fair value of the second potential earn-out payment of $373.0 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. See Note 10 – Other Long-term Liabilities and Note 13 – Fair Value Measurements for additional discussion of the fair value methodology.

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. The fair values 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 and $141.2 million for each of the years 2018 through 2022.

On May 1, 2018, we executed an agreement to sell our inland marine barge business to Kirby Corp. for approximately $69.3 million. Subject to customary regulatory approvals and other closing conditions, the transaction is expected to close during the second quarter of 2018. Subsequent to the closing of the sale, we will continue to own and operate two ocean-going barges.

The T2 Joint Ventures were formed to provide services for the benefit of their joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with their joint interest owners, which cover costs of operations (excluding depreciation and amortization).

The carrying values of the T2 Joint Ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of March 31, 2018, $25.8 million of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20-year useful lives of the underlying assets.

See Note 4 – Newly-Formed Joint Ventures and Acquisitions for discussion of the formation of our Cayenne Joint Venture, GCX Joint Venture and Little Missouri 4 Joint Venture.

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

	September 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
Commodities	$	600.9	$	574.5	$	593.0	$	711.9
Other goods and services		220.5		113.4		254.7		286.9
Interest		48.7		52.2		63.4		54.1
Permian Acquisition contingent consideration, estimated current portion		5.9		—		—		6.8
Income and other taxes		57.3		19.1		28.3		26.3
Other		15.9		14.7		28.9		20.6
	$	949.2	$	773.9	$	968.3	$	1,106.6

Accounts payable and accrued liabilities includes ~~$29.2~~$56.6 million and ~~$30.2~~$49.7 million of liabilities to creditors to whom we have issued checks that remained outstanding as of ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016.~~2017. The estimated current portion of the Permian Acquisition contingent consideration represents the fair value ~~as of September 30, 2017~~ of the first potential earn-out payment that would ~~be payable~~have been due in May 2018. The estimated remaining portion that would be payable in May 2019 ~~and~~ is recorded within Other long-term liabilities on our Consolidated Balance Sheets.

	September 30, 2017			December 31, 2016
							March 31, 2018			December 31, 2017
Current:
Accounts receivable securitization facility, due December 2017	$	278.1		$	275.0
Senior unsecured notes, 5% fixed rate, due January 2018 (1)		250.5			—
		528.6			275.0
Debt issuance costs, net of amortization		(0.2	)		—
Current debt obligations		528.4			275.0
Accounts receivable securitization facility, due December 2018							$	300.0		$	350.0

Long-term:
Senior secured revolving credit facility, variable rate, due October 2020 (2)		430.0			150.0
Senior secured revolving credit facility, variable rate, due October 2020 (1)								380.0			20.0
Senior unsecured notes:
5% fixed rate, due January 2018 (1)		—			250.5
4⅛% fixed rate, due November 2019		749.4			749.4			749.4			749.4
6⅜% fixed rate, due August 2022		—			278.7
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
5⅜% fixed rate, due February 2027		500.0			500.0			500.0			500.0
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
5% fixed rate, due January 2028								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
Unamortized premium		0.4			0.5			0.4			0.4
		3,958.0			4,207.3			4,658.0			4,298.0
Debt issuance costs, net of amortization		(24.4	)		(30.3	)		(28.8	)		(30.0	)
Long-term debt		3,933.6			4,177.0			4,629.2			4,268.0
Total debt obligations	$	4,462.0		$	4,452.0		$	4,929.2		$	4,618.0
Irrevocable standby letters of credit outstanding	$	22.4		$	13.2		$	25.9		$	27.2

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, 2017:~~March 31, 2018:

As of ~~September 30, 2017,~~March 31, 2018, we were in compliance with the covenants contained in our various debt agreements.

On February 23, 2017, we amended the accounts receivable securitization facility (“Securitization Facility”) to increase the facility size from $275.0 million to $350.0 million. As of September 30, 2017, there was $278.1 million outstanding under the Securitization Facility.

In ~~June 2017,~~April 2018, we ~~redeemed our outstanding 6⅜~~issued $1.0 billion aggregate principal amount of 5⅞% senior notes due April 2026 (the “5⅞% Senior Notes due August 2022 (“6⅜% Senior Notes”), totaling $278.7 million in aggregate principal amount, at a price of 103.188% plus accrued interest through the redemption date. The redemption resulted in a $10.7 million loss, which is reflected as Loss from financing activities in the Consolidated Statements of Operations, consisting of premiums paid of $8.9 million and a non-cash loss to write-off $1.8 million of unamortized debt issuance costs.

~~In October 2017, we issued $750.0 million aggregate principal amount of 5% senior notes due January 2028 (the “5% Senior Notes due 2028”~~2026”). We used the net proceeds of ~~$744.4~~$992.3 million after costs from this offering to ~~redeem our 5% Senior Notes due 2018, reduce~~repay borrowings under our credit facilities and for general partnership purposes.

~~In October 2017, we redeemed our outstanding~~ ~~5% Senior Notes due 2018 at par value~~ plus accrued interest through the redemption date. The redemption resulted in a non-cash Loss from financing activities to write-off $0.2 million of unamortized debt issuance costs in the fourth quarter of 2017.

	September 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
Asset retirement obligations	$	49.4	$	64.1	$	52.5	$	50.3
Mandatorily redeemable preferred interests		80.0		68.5		4.2		76.2
Deferred revenue		67.5		69.8		135.2		136.2
Permian Acquisition contingent consideration, noncurrent portion		284.9		—		373.0		310.2
Other liabilities		3.1		2.9		3.2		3.1
Total long-term liabilities	$	484.9	$	205.3	$	568.1	$	576.0

Our ARO primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows:

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. ~~Because~~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, 2017.~~March 31, 2018.

The following table shows the changes attributable to mandatorily redeemable preferred interests:

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 three months ended March 31, 2018, the $72.5 million 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 which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided.

Deferred revenue includes consideration received 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 ~~(“Splitter~~(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 ~~(“Channelview~~(the “Channelview Splitter”) and provide approximately 730,000 ~~barrels~~Bbl of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 ~~barrels per day~~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 completed byin the ~~first half~~second quarter of 2018, and has an estimated total cost of approximately ~~$140.0~~$140 million. The first annual advance payment due under the Splitter Agreement

was received in October 2016 and has been recorded as deferred revenue, as the Splitter Agreement requires future performance by Targa. The Splitter Agreement provides that subsequent annual payments of $43.0 million (subject to an annual inflation factor) are to be paid to Targa through 2022. In October 2017, we received $43.0 million representing the second annual payment under the Splitter Agreement, which ~~will be~~has been recorded as deferred revenue. The deferred revenue receipts will be recognized over the contractual period that future performance will be provided, currently anticipated to commence with start-up in 2018 and continuing through 2025. In January 2018, Vitol US Holding Co. acquired Noble Americas Corp.

Deferred revenue also includes nonmonetary consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processing agreement. We measured the estimated fair value of the gathering assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. ~~Because~~As the gas contract amendment will require future performance by Targa, we have recorded the consideration received as deferred revenue. In December 2017, we received monetary consideration to further amend the terms of the gas gathering and processing agreement. The deferred revenue related to ~~this amendment~~these amendments is being recognized on a straight-line basis through the end of the agreement’s term in ~~2030.~~2035.

Deferred revenue also includes consideration received for other construction activities of facilities connected to our systems. The deferred revenue related to these other construction activities will be recognized over the periods that future performance will be provided, which extend through 2023.

	September 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
Splitter agreement	$	43.0	$	43.0	$	86.0	$	86.0
Gas contract amendment		18.6		19.7		44.1		44.7
Other deferred revenue		5.9		7.1		5.1		5.5
Total deferred revenue	$	67.5	$	69.8	$	135.2	$	136.2

Balance at December 31, 2016	$	69.8
Balance at December 31, 2017				$	136.2
Additions		—			—
Revenue recognized		(2.3	)		(1.0	)
Balance at September 30, 2017	$	67.5
Balance at March 31, 2018				$	135.2

Upon closing of the Permian Acquisition, a contingent consideration liability arising from potential earn-out provisions was recognized at its preliminary fair value. The potential earn-out payments will be based upon a multiple of gross margin realized during the first two annual periods after the acquisition date from contracts that existed on March 1, 2017. The first potential earn-out payment would occur in May 2018 and the second potential earn-out payment would occur in May 2019. The ~~preliminary~~ acquisition date fair value of the contingent consideration of ~~$461.6~~$416.3 million was recorded within Other long-term liabilities on our Consolidated Balance ~~Sheets as of March 31, 2017.~~Sheets. Subsequent changes in the fair value of the contingent consideration ~~that were not accounted for as revisions (measurement period adjustments) to the acquisition date fair value~~ have been included in Other income (expense).

During the three months ended June 30, 2017, we recognized certain adjustments that were accounted for as revisions to the acquisition date fair value and decreased the acquisition date fair value of the contingent consideration by $45.3 million to $416.3

million. During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional revisions to the acquisition date fair value. See Note 4 – Acquisitions and Divestments for additional discussion.

For the period from the acquisition date to ~~September 30,~~December 31, 2017, the fair value of this liability decreased by ~~$125.5~~$99.3 million, bringing the total Permian Acquisition contingent consideration to ~~$290.8~~$317.0 million at ~~September 30,~~December 31, 2017.

The ~~decrease in fair value~~portion of the ~~contingent consideration was primarily related to reductions~~earn-out due in actual and forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since the acquisition date. Such changes in estimated fair value of the contingent consideration are attributable to events and circumstances that occurred after the acquisition date, and as such have been recognized in Other income (expense).

2018 expired with no required payment. As of September 30, 2017, the fair value of the first potential earn-out payment of $5.9 million has been recorded as a component of Accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. As of September 30, 2017,March 31, 2018, the fair value of the second potential earn-out payment of ~~$284.9~~$373.0 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. The increase in fair value of the contingent consideration during the three months ended March 31, 2018 was primarily related to an increase in underlying forecasted volumes for the remainder of the earn-out period and a shorter term over which such projections are discounted. See Note 1413 – Fair Value Measurements for additional discussion of the fair value methodology.

~~As a result of the TRC/TRP Merger,~~ TRC is entitled to receive all Partnership distributions ~~from available cash on the Partnership’s common units~~ after payment of preferred ~~units~~ distributions each quarter. ~~We have discretion under~~ ~~the Third A&R Partnership Agreement~~ ~~as to whether to distribute all available cash for any period.~~ ~~See Note 1 – Organization and Operations.~~

The following details the distributions declared and/or paid by us for the ~~nine~~three months ended ~~September 30, 2017:~~March 31, 2018:

~~Subsequent to December 1, 2016, the effective date of the Third A&R Partnership Agreement, no units will be issued for~~All capital contributions ~~to us, but all capital contributions will~~ 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 ~~general partner. For the nine~~three months ended ~~September 30, 2017,~~March 31, 2018, TRC made total capital contributions to us of ~~$1,620.0~~$60.0 million.

~~In October 2015, we completed an offering of 5,000,000~~Our Preferred Units ~~at a price of $25.00 per unit. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.”~~

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 equalrank senior to ~~all accumulated and unpaid distributions thereon~~our common units with respect 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. Holders of Preferred Units have no voting rights except for certain exceptions set forth in our Partnership Agreement.

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 Unitholders”) ~~during~~for the three ~~and nine~~ months ended ~~September 30, 2017.~~March 31, 2018. The Preferred Units are reported as noncontrolling interests in our financial statements.

In ~~October 2017,~~April 2018, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred ~~Unit. This distribution~~Unit, resulting in approximately $0.9 million in distributions which will be paid on ~~November~~May 15, ~~2017.~~2018.

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 hedged the commodity prices 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 by entering into derivative instruments. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have 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.

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 and $5.8 million and $20.9 million for the three and nine months ended September 30, 2016, related to these novated contracts. From the acquisition date through September 30, 2017, we have received derivative settlements of $100.9 million. ~~The remainder of the novated contracts will settle by the end of 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.~~

The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Additionally, we recorded ineffectiveness losses of less than $0.1 million and $0.1 million for the three and nine months ended September 30, 2017 and less than $0.1 million and $0.3 million for the three and nine months ended September 30, 2016, related to otherwise qualifying TPL derivatives, which are primarily natural gas swaps.

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, 2017,~~March 31, 2018, the notional volumes of our commodity derivative contracts were:

Commodity	Instrument	Unit	2017		2018		2019		2020		Instrument	Unit	2018		2019		2020
Natural Gas	Swaps	MMBtu/d		160,347		151,100		116,136		-
Natural Gas	Basis Swaps	MMBtu/d		92,200		15,726		12,500		10,445	Swaps	MMBtu/d		170,739		131,506		-
Natural Gas	Futures	MMBtu/d		-		1,103		-		-	Basis Swaps	MMBtu/d		138,009		78,062		10,417
Natural Gas	Options	MMBtu/d		22,900		9,486		-		-	Options	MMBtu/d		5,096		-		-
NGL	Swaps	Bbl/d		23,432		12,858		7,399		-	Swaps	Bbl/d		22,779		13,449		4,567
NGL	Futures	Bbl/d		38,880		6,589		329		-	Futures	Bbl/d		8,923		1,383		-
NGL	Options	Bbl/d		3,094		2,986		410		-	Options	Bbl/d		1,310		410		-
Condensate	Swaps	Bbl/d		3,150		2,420		1,293		-	Swaps	Bbl/d		4,990		2,653		-
Condensate	Options	Bbl/d		1,380		691		590		-	Options	Bbl/d		590		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 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, 2017				Fair Value as of December 31, 2016					Fair Value as of March 31, 2018				Fair Value as of December 31, 2017
	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	$	18.4	$	79.9	$	16.7	$	48.6	Current	$	61.1	$	43.3	$	37.9	$	78.6
	Long-term		13.7		14.4		5.1		26.1	Long-term		40.5		13.2		23.2		18.7
Total derivatives designated as hedging instruments		$	32.1	$	94.3	$	21.8	$	74.7		$	101.6	$	56.5	$	61.1	$	97.3
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	0.3	$	1.0	$	0.1	$	0.5	Current	$	2.1	$	10.3	$	—	$	1.1
	Long-term		-		0.5		-		-	Long-term		0.9		4.9		—		0.9
Total derivatives not designated as hedging instruments		$	0.3	$	1.5	$	0.1	$	0.5		$	3.0	$	15.2	$	—	$	2.0
Total current position		$	18.7	$	80.9	$	16.8	$	49.1		$	63.2	$	53.6	$	37.9	$	79.7
Total long-term position			13.7		14.9		5.1		26.1			41.4		18.1		23.2		19.6
Total derivatives		$	32.4	$	95.8	$	21.9	$	75.2		$	104.6	$	71.7	$	61.1	$	99.3

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, 2017		Asset		Liability			Collateral		Asset		Liability
March 31, 2018														March 31, 2018	Asset		Liability			Collateral		Asset		Liability
Current Position	Current Position													Current Position
	Counterparties with offsetting positions or collateral	$	18.7	$	(79.5	)	$	44.6	$	3.6	$	(19.8	)	Counterparties with offsetting positions or collateral	$	63.2	$	(51.2	)	$	5.8	$	39.6	$	(21.8	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(1.4	)		-		-		(1.4	)	Counterparties without offsetting positions - liabilities		-		(2.4	)		-		-		(2.4	)
			18.7		(80.9	)		44.6		3.6		(21.2	)			63.2		(53.6	)		5.8		39.6		(24.2	)
Long Term Position	Long Term Position													Long Term Position
	Counterparties with offsetting positions or collateral		13.5		(14.2	)		-		6.5		(7.2	)	Counterparties with offsetting positions or collateral		41.4		(16.9	)		-		32.7		(8.2	)
	Counterparties without offsetting positions - assets		0.2		-			-		0.2		-		Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(0.7	)		-		-		(0.7	)	Counterparties without offsetting positions - liabilities		-		(1.2	)		-		-		(1.2	)
			13.7		(14.9	)		-		6.7		(7.9	)			41.4		(18.1	)		-		32.7		(9.4	)
Total Derivatives	Total Derivatives													Total Derivatives
	Counterparties with offsetting positions or collateral		32.2		(93.7	)		44.6		10.1		(27.0	)	Counterparties with offsetting positions or collateral		104.6		(68.1	)		5.8		72.3		(30.0	)
	Counterparties without offsetting positions - assets		0.2		-			-		0.2		-		Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(2.1	)		-		-		(2.1	)	Counterparties without offsetting positions - liabilities		-		(3.6	)		-		-		(3.6	)
		$	32.4	$	(95.8	)	$	44.6	$	10.3	$	(29.1	)		$	104.6	$	(71.7	)	$	5.8	$	72.3	$	(33.6	)

		Gross Presentation							Pro forma net presentation						Gross Presentation							Pro forma net presentation
December 31, 2016		Asset		Liability			Collateral		Asset		Liability
December 31, 2017														December 31, 2017	Asset		Liability			Collateral		Asset		Liability
Current Position	Current Position													Current Position
	Counterparties with offsetting positions or collateral	$	16.8	$	(46.1	)	$	7.0	$	5.7	$	(28.0	)	Counterparties with offsetting positions or collateral	$	37.9	$	(74.7	)	$	22.9	$	13.8	$	(27.7	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(3.0	)		-		-		(3.0	)	Counterparties without offsetting positions - liabilities		-		(5.0	)		-		-		(5.0	)
			16.8		(49.1	)		7.0		5.7		(31.0	)			37.9		(79.7	)		22.9		13.8		(32.7	)
Long Term Position	Long Term Position													Long Term Position
	Counterparties with offsetting positions or collateral		5.1		(18.7	)		-		-		(13.6	)	Counterparties with offsetting positions or collateral		23.2		(17.3	)		-		14.8		(8.9	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(7.4	)		-		-		(7.4	)	Counterparties without offsetting positions - liabilities		-		(2.3	)		-		-		(2.3	)
			5.1		(26.1	)		-		-		(21.0	)			23.2		(19.6	)		-		14.8		(11.2	)
Total Derivatives	Total Derivatives													Total Derivatives
	Counterparties with offsetting positions or collateral		21.9		(64.8	)		7.0		5.7		(41.6	)	Counterparties with offsetting positions or collateral		61.1		(92.0	)		22.9		28.6		(36.6	)
	Counterparties without offsetting positions - assets		-		-			-		-		-		Counterparties without offsetting positions - assets		-		-			-		-		-
	Counterparties without offsetting positions - liabilities		-		(10.4	)		-		-		(10.4	)	Counterparties without offsetting positions - liabilities		-		(7.3	)		-		-		(7.3	)
		$	21.9	$	(75.2	)	$	7.0	$	5.7	$	(52.0	)		$	61.1	$	(99.3	)	$	22.9	$	28.6	$	(43.9	)

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 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 ~~$63.4~~$32.9 million as of ~~September 30, 2017.~~March 31, 2018. 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 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	2017			2016		2017			2016			2018		2017
Commodity contracts	$	(106.8	)	$	12.9	$	(10.5	)	$	(40.5	)	$	64.6	$	66.2

	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)	2017			2016		2017			2016		2018			2017
Revenues	$	(2.1	)	$	8.1	$	(2.2	)	$	50.6	$	(26.7	)	$	(6.1	)

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	2017			2016			2017			2016		Derivatives	2018			2017
Commodity contracts	Revenue	$	(1.5	)	$	(0.3	)	$	(2.9	)	$	1.3	Revenue	$	(10.8	)	$	(0.8	)

Based on valuations as of ~~September 30, 2017,~~March 31, 2018, we expect to reclassify commodity hedge-related deferred ~~losses~~gains of ~~$64.1~~$45.2 million included in accumulated other comprehensive income into earnings before income taxes through the end of ~~2019,~~2020, with ~~$63.0~~$17.9 million of ~~losses~~gains to be reclassified over the next twelve months.

See Note 1413 – 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, 2017,~~March 31, 2018, a net ~~liability~~asset position of ~~$63.4~~$32.9 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 ~~$149.9~~$42.9 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 asset of ~~$22.2~~$108.8 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.

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, 2017																March 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)		$	32.0		$	32.0		$	—		$	29.0		$	3.0	Assets from commodity derivative contracts (1)		$	104.3		$	104.3		$	—		$	103.9		$	0.4
Liabilities from commodity derivative contracts (1)	Liabilities from commodity derivative contracts (1)			95.4			95.4			—			86.5			8.9	Liabilities from commodity derivative contracts (1)			71.4			71.4			—			67.7			3.7
Permian Acquisition contingent consideration (2)				290.8			290.8			—			—			290.8				373.0			373.0			—			—			373.0
TPL contingent consideration (3)	TPL contingent consideration (3)			2.5			2.5			—			—			2.5	TPL contingent consideration (3)			2.5			2.5			—			—			2.5
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			103.9			103.9			—			—			—	Cash and cash equivalents			206.7			206.7			—			—			—
TRP Revolver	TRP Revolver			430.0			430.0			—			430.0			—	TRP Revolver			380.0			380.0			—			380.0			—
Senior unsecured notes	Senior unsecured notes			3,778.5			3,881.2			—			3,881.2			—	Senior unsecured notes			4,278.0			4,257.0			—			4,257.0			—
Accounts receivable securitization facility	Accounts receivable securitization facility			278.1			278.1			—			278.1			—	Accounts receivable securitization facility			300.0			300.0			—			300.0			—

		December 31, 2016																December 31, 2017
					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)		$	21.0		$	21.0		$	—		$	19.6		$	1.4	Assets from commodity derivative contracts (1)		$	60.3		$	60.3		$	—		$	58.8		$	1.5
Liabilities from commodity derivative contracts (1)	Liabilities from commodity derivative contracts (1)			74.2			74.2			—			69.3			4.9	Liabilities from commodity derivative contracts (1)			98.5			98.5			—			93.3			5.2
Permian Acquisition contingent consideration (2)				—			—			—			—			—				317.0			317.0			—			—			317.0
TPL contingent consideration (3)	TPL contingent consideration (3)			2.6			2.6			—			—			2.6	TPL contingent consideration (3)			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			68.0			68.0			—			—			—	Cash and cash equivalents			124.7			124.7			—			—			—
TRP Revolver	TRP Revolver			150.0			150.0			—			150.0			—	TRP Revolver			20.0			20.0			—			20.0			—
Senior unsecured notes	Senior unsecured notes			4,057.3			4,101.6			—			4,101.6			—	Senior unsecured notes			4,278.0			4,362.4			—			4,362.4			—
Accounts receivable securitization facility	Accounts receivable securitization facility			275.0			275.0			—			275.0			—	Accounts receivable securitization facility			350.0			350.0			—			350.0			—

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 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, 2017,~~March 31, 2018, we had 3112 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 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 in expected gross margin during the earn-out period, or significant increase in the discount rate or volatility would result in a lower fair value estimate. 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 ~~the~~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) 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.

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2017		2016		2018		2017
Targa billings of payroll and related costs included in operating expense	$	54.0	$	42.6	$	148.6	$	125.0
Targa billings of payroll and related costs included in operating expenses									$	59.5	$	47.0
Targa allocation of general and administrative expense		43.2		40.1		126.6		117.7		47.3		42.0
Cash distributions to Targa based on IDR, general partner and limited partner ownership (1)		222.6		178.9		624.7		395.1
Cash distributions to Targa based on general partner and limited partner ownership										225.7		195.3
Cash contributions from Targa related to limited partner ownership ~~(2)~~(1)		14.7		210.7		1,587.5		1,167.2		58.8		641.9
Cash contributions from Targa to maintain its 2% general partner ownership		0.3		4.3		32.5		23.8		1.2		13.1

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 our 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.

As of March 2018, Sajet is 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.

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 fractionation, export, terminaling and storage agreements.

In accordance with the optional exemptions that we elected to apply, the amounts presented in the table 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 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 the estimated remaining duration of such contracts ranges from 1 to 25 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 in our Consolidated Financial Statements.

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2017		2016		2018			2017
Loss on sale or disposal of assets (1)	$	0.3	$	4.7	$	16.6	$	5.7
(Gain) loss on sale or disposal of assets (1)									$	(0.1	)	$	16.1
Miscellaneous business tax		0.3		0.2		0.6		0.4		0.3			0.1
Other										0.1			—
	$	0.6	$	4.9	$	17.2	$	6.1	$	0.3		$	16.2

		Nine Months Ended September 30,								Three Months Ended March 31,
		2017				2016				2018				2017
Cash:
Interest paid, net of capitalized interest (1)	$		154.5		$		197.1		$		39.4		$		53.5
Income taxes paid, net of refunds			(4.9	)			1.2				0.2				(0.1	)
Non-cash investing activities:
Deadstock commodity inventory transferred to property, plant and equipment	$		8.3		$		16.9		$		1.7		$		8.3
Impact of capital expenditure accruals on property, plant and equipment			118.3				(0.5	)			(22.3	)			30.0
Transfers from materials and supplies inventory to property, plant and equipment			2.8				1.9				0.4				0.4
Contribution of property, plant and equipment to investments in unconsolidated affiliates			1.0				—				16.0				1.0
Change in ARO liability and property, plant and equipment due to revised cash flow estimate			3.1				(9.2	)			2.1				1.7
Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Acquisitions and Divestitures):
Non-cash financing activities:
Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures and Acquisitions):
Contingent consideration recorded at the acquisition date	$		416.3		$		—		$		—		$		461.6
Non-cash financing activities:
Cancellation of treasury units	$		—		$		(10.4	)
Accrued distributions on unvested equity awards under share compensation arrangements			—				0.2
Purchase consideration payable recorded for the Permian Acquisition											—				90.0
Non-cash balance sheet movements related to acquisition of related party:
Intercompany payable											1.4				—
Noncontrolling interest											1.2				—

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; 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) 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 ~~all~~ the activities and assets necessary to convert mixed NGLs into NGL products and ~~provides certain value added~~also includes other assets and value-added services such as storing, fractionating, terminaling, ~~distributing~~transporting and marketing of NGLs ~~the storage~~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 including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs.~~businesses. The Logistics and Marketing segment ~~also~~ includes ~~our~~ Grand Prix, ~~project.~~

~~Logistics and Marketing operations~~which is currently under construction. 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 ~~located~~ in Mont Belvieu and Galena Park, Texas, and ~~Channelview, Texas;~~in Lake Charles, ~~Louisiana and Tacoma, Washington.~~Louisiana.

Other contains the results ~~(including any hedge ineffectiveness)~~ of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating ~~margin.~~margin and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column.

	Three 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	$	200.3	$	1,672.2	$	(1.0	)	$	—		$	1,871.5	$	265.2	$	1,926.3	$	(17.8	)	$	—		$	2,173.7
Fees from midstream services		148.5		111.8		—			—			260.3		161.3		120.6		—			—			281.9
		348.8		1,784.0		(1.0	)		—			2,131.8		426.5		2,046.9		(17.8	)		—			2,455.6
Intersegment revenues
Sales of commodities		783.7		80.6		—			(864.3	)		—		866.5		55.7		—			(922.2	)		—
Fees from midstream services		1.7		7.0		—			(8.7	)		—		1.9		6.9		—			(8.8	)		—
		785.4		87.6		—			(873.0	)		—		868.4		62.6		—			(931.0	)		—
Revenues	$	1,134.2	$	1,871.6	$	(1.0	)	$	(873.0	)	$	2,131.8	$	1,294.9	$	2,109.5	$	(17.8	)	$	(931.0	)	$	2,455.6
Operating margin	$	198.3	$	115.9	$	(1.0	)	$	—		*		$	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	$	295.9	$	71.0	$	—		$	11.8		$	378.7	$	273.2	$	251.0	$	—		$	33.8		$	558.0

	Three Months Ended September 30, 2016											Three Months Ended March 31, 2017
	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	$	172.2	$	1,215.3	$	11.2	$	—		$	1,398.7	$	166.7	$	1,692.4	$	(1.0	)	$	—		$	1,858.1
Fees from midstream services		120.6		133.0		—		—			253.6		118.2		136.3		—			—			254.5
		292.8		1,348.3		11.2		—			1,652.3		284.9		1,828.7		(1.0	)		—			2,112.6
Intersegment revenues
Sales of commodities		574.8		76.3		—		(651.1	)		—		713.0		75.4		—			(788.4	)		—
Fees from midstream services		1.9		6.6		—		(8.5	)		—		1.9		7.0		—			(8.9	)		—
		576.7		82.9		—		(659.6	)		—		714.9		82.4		—			(797.3	)		—
Revenues	$	869.5	$	1,431.2	$	11.2	$	(659.6	)	$	1,652.3	$	999.8	$	1,911.1	$	(1.0	)	$	(797.3	)	$	2,112.6
Operating margin	$	149.4	$	126.0	$	11.2	$	—			*	$	177.4	$	130.1	$	(1.0	)	$	—		$	306.5
Other financial information:
Total assets (1)	$	10,047.3	$	2,737.5	$	47.2	$	76.2		$	12,908.2	$	10,780.4	$	2,687.2	$	44.8		$	57.4		$	13,569.8
Goodwill	$	393.0	$	—	$	—	$	—		$	393.0	$	369.0	$	—	$	—		$	—		$	369.0
Capital expenditures	$	97.1	$	36.2	$	—	$	1.3		$	134.6	$	139.2	$	34.6	$	—		$	0.8		$	174.6

* Total operating margin is not presented in this table as it represents a non-GAAP measure.

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

	Three Months Ended September 30,					Nine Months Ended September 30,				Three Months Ended March 31,
	2017			2016		2017		2016		2018			2017
Sales of commodities:
Revenue recognized from contracts with customers:
Natural gas	$	504.1		$	465.6	$	1,480.9	$	1,102.0	$	470.1		$	481.7
NGL		1,274.9			866.7		3,623.9		2,575.8		1,607.3			1,319.7
Condensate		44.9			35.0		135.9		96.2		86.9			43.6
Petroleum products		48.6			20.2		108.5		52.0		48.2			19.8
Derivative activities		(1.0	)		11.2		3.9		56.9
											2,212.5			1,864.8
Non-customer revenue:
Derivative activities - Hedge											(28.0	)		(5.9	)
Derivative activities - Non-hedge (1)											(10.8	)		(0.8	)
											(38.8	)		(6.7	)
Total sales of commodities											2,173.7			1,858.1
		1,871.5			1,398.7		5,353.1		3,882.9
Fees from midstream services:
Revenue recognized from contracts with customers:
Fractionating and treating		29.8			33.2		92.8		94.8		31.1			31.0
Storage, terminaling, transportation and export		75.0			89.7		247.8		316.3		88.7			99.7
Gathering and processing		138.0			110.9		368.5		329.9		152.1			107.7
Other		17.5			19.8		49.9		54.5		10.0			16.1
		260.3			253.6		759.0		795.5
Total fees from midstream services											281.9			254.5

Total revenues	$	2,131.8		$	1,652.3	$	6,112.1	$	4,678.4	$	2,455.6		$	2,112.6

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,
	2017			2016			2017			2016			2018			2017
Reconciliation of reportable segment operating margin to income (loss) before income taxes:
Gathering and Processing operating margin	$	198.3		$	149.4		$	549.3		$	404.1		$	220.8		$	177.4
Logistics and Marketing operating margin		115.9			126.0			358.5			424.6			138.4			130.1
Other operating margin		(1.0	)		11.2			3.9			56.9			(17.8	)		(1.0	)
Depreciation and amortization expenses		(208.3	)		(184.0	)		(602.8	)		(563.6	)		(198.1	)		(191.1	)
General and administrative expenses		(46.6	)		(44.0	)		(139.4	)		(132.3	)		(52.6	)		(45.5	)
Impairment of property, plant and equipment		(378.0	)		—			(378.0	)		—
Impairment of goodwill		—			—			—			(24.0	)
Interest expense, net		(51.9	)		(57.9	)		(169.5	)		(171.2	)
Interest income (expense), net														20.2			(58.6	)
Other, net		126.6			(5.8	)		78.4			5.0			(54.9	)		(37.3	)
Income (loss) before income taxes	$	(245.0	)	$	(5.1	)	$	(299.6	)	$	(0.5	)	$	56.0		$	(26.0	)

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, ~~2016~~2017 (“Annual Report”), as well as the unaudited consolidated financial statements and Notes hereto included in this Quarterly Report on Form 10-Q.

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. 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 an impact to our operating or gross margin. 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. For more information, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.

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.

On February 17, 2016, TRC completed the previously announced transactions contemplated by the Merger Agreement, by and among us, our general partner, TRC and Merger Sub pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP, with TRP continuing as the surviving entity and as a subsidiary of TRC. Following the closing of the TRC/TRP Merger on February 17, 2016, TRC owns all our outstanding common units.

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 Logistics and Marketing segment includes ~~all~~ the activities and assets necessary to convert mixed NGLs into NGL products and ~~provides certain value added~~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 ~~our~~ Grand Prix, ~~project.~~

~~Logistics and Marketing operations~~which is currently under construction. 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 ~~located~~ in Mont Belvieu and Galena Park, Texas, and ~~Channelview, Texas;~~in Lake Charles, ~~Louisiana and Tacoma, Washington.~~Louisiana.

Other contains the results ~~(including any hedge ineffectiveness)~~ of ~~our~~ commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating ~~margin.~~margin and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges.

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 system:

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. We will construct approximately 220 miles of 12- to 24-inch high pressure rich gas gathering pipelines across the Delaware Basin, 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 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 pipeline system are approximately $500 million, with approximately $200 million expected to be spent in 2018.

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

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"). ~~Contributions from TRC were used to fund the cash portion of the Permian Acquisition purchase price.~~ Subject to certain ~~performance-linked~~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 that would occur in May 2018 and May 2019. The potential earn-out payments will be 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 New Delaware assets include 70 MMcf/d of processing ~~capacity and we are in~~capacity. In addition, the ~~process of installing~~Oahu Plant, a 60 MMcf/d plant ~~known as the Oahu Plant,~~ in the Delaware Basin, ~~with expectations of commencing operations~~which was completed in March 2018 and placed into service in April 2018, was added to the ~~fourth quarter of 2017.~~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 ~~the~~ New Midland's gas gathering and processing assets were connected to our ~~existing~~ WestTX system in ~~October~~the fourth quarter of 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and ~~will~~is expected to afford enhanced flexibility in serving ~~our producer customers.~~producers.

In ~~November 2016,~~January 2018, we announced ~~plans~~the formation of a 50/50 joint venture with Hess Midstream Partners LP to restart the idled 45 MMcf/d Benedum cryogenic processing plant and to add 20 MMcf/d of capacity at our Midkiff Plant in our WestTX system. The Benedum Plant was idled in September 2014 after the start-up of the 200 MMcf/d Edward Plant, and was brought back online in the first quarter of 2017. The addition of 20 MMcf/d of capacity at our Midkiff Plant was completed in the second quarter of 2017 and increased overall plant capacity of the Midkiff/Consolidator Plant complex in Reagan County, Texas from 210 MMcf/d to 230 MMcf/d. Also in November 2016, we announced plans to build the 200 MMcf/d Joyce Plant, which is expected to be completed in the first quarter of 2018. We expect total net growth capital expenditures for the Joyce Plant to be approximately $80 million.

~~In May 2017, we announced plans to build a new plant and expand the gathering footprint of our Permian Midland system in the Midland Basin. This project includes~~construct a new 200 MMcf/d ~~cryogenic~~natural gas processing plant ~~known as~~(“LM4 Plant”) at Targa’s existing Little Missouri facility. The LM4 Plant is anticipated to be completed at the ~~Johnson Plant, which is expected to begin operations in~~end of the ~~third~~fourth quarter of 2018. ~~We expect total net growth capital expenditures for~~Targa will manage construction of, and operate, the ~~Johnson Plant to be approximately $100 million.~~LM4 Plant.

In December 2017, ownership of the Flag City Plant assets located in ~~May 2017,~~Jackson County, Texas, was transferred to Centrahoma Processing, LLC, a joint venture that we ~~announced plans~~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. In conjunction with Targa’s contribution of the plant assets, MPLX, LP made a cash contribution to ~~build~~Centrahoma in order to maintain its 40% ownership interest. The former Flag City Plant assets are being relocated to, and installed in, Hughes County, Oklahoma, in 2018 as a new ~~plant and expand the gathering footprint of our Permian Delaware system in the Delaware Basin. This project includes a new 250~~150 MMcf/d cryogenic natural gas processing plant ~~known as~~(the “Hickory Hills Plant”). The Hickory Hills Plant will process natural gas production from the ~~Wildcat Plant, which~~Arkoma Woodford Basin and is expected to begin operations in the second ~~quarter~~half of 2018. ~~We expect total net growth capital expenditures for~~Targa will also contribute the ~~Wildcat~~120 MMcf/d cryogenic Tupelo Plant in Coal County, Oklahoma to ~~be approximately $130 million.~~

~~In October 2015, we announced that we had entered into~~Centrahoma upon the Carnero Joint Ventures with Sanchez Energy Corporation (“Sanchez”) to construct the 200 MMcf/d Raptor Plant and approximately 45 miles of associated pipelines. In July 2016, Sanchez sold its interest in the gathering joint venture to Sanchez Midstream Partners, L.P. (“SNMP”), formerly known as

Sanchez Production Partners, L.P., and in November 2016, sold its interest in the processing joint venture to SNMP. Through the Carnero Joint Ventures, we indirectly own a 50% interest in the plant and the approximately 45 miles of high pressure gathering pipelines that will connect SNMP's Catarina gathering system to the plant. We hold the capacity on the high pressure gathering pipelines, and pay the gathering joint venture fees for transportation.

~~The Raptor Plant began operations in the second quarter of 2017, and is capable of processing 200 MMcf/d. In February 2017, we announced the addition of compression to increase the processing capacity~~in-service date of the Raptor Plant to 260 MMcf/d, which we expect to be completed in the fourth quarter of 2017. The Raptor Plant accommodates growing production from Sanchez’s premier Eagle Ford Shale acreage position in Dimmit, La Salle and Webb Counties, Texas and from other third party producers. The plant and high pressure gathering pipelines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We manage operations of the high pressure gathering lines and the plant. Prior to the plant being placed in service, we benefited from Sanchez natural gas volumes that were processed at our Silver Oak facilities in Bee County, Texas.

In May 2017, we acquired a 150 MMcf/d natural gas processing plant (the “Flag City Plant”) and associated assets from subsidiaries of Boardwalk Pipeline Partners, L.P. (“Boardwalk”) for $60.0 million, subject to customary closing adjustments. The gas processing activities under the Flag City Plant contracts have been transferred to our Silver Oak facilities. We shut down the Flag City Plant and are moving the plant and its component parts to other Targa locations.

~~During 2017, we expect to invest approximately $150 million to~~ expand our crude gathering and natural gas processing business in the Williston Basin, North Dakota. The expansion includes the addition of pipelines, LACT units, compression and other infrastructure to support continued growth in producer activity.

Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice Gas Plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company ~~engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash.~~ ~~Additionally, the VGS asset retirement obligations were assumed by the buyer.~~ VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gas Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice Gas Plant through our ownership in VESCO. Targa Midstream Services LLC operated the Venice gathering system for four months after closing pursuant to a Transition Services Agreement with VGS.Hickory Hills Plant.

In May 2017, we announced plans to construct a new common carrier NGL pipeline. The NGL pipeline (“Grand Prix”) will transport volumes from the Permian Basin and ~~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 our volumes and other ~~third party~~third-party customer commitments, and is expected to be fully in service in the second quarter of 2019. The capacity of the pipeline from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d.

In September 2017, we sold ~~to funds managed by Blackstone Energy Partners ("Blackstone")~~ a ~~25 percent~~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. ~~Our share of total growth capital expenditures for Grand Prix is expected to be approximately $975 million, with approximately $275 million of spending in 2017.~~

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 ~~for transportation and fractionation~~ ~~services~~ 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 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. Once completed, the capacity of Grand Prix from North Texas, where Permian and Oklahoma volumes will be connected to a 30-inch diameter segment of the pipeline to Mont Belvieu, will be approximately 450 MBbl/d, expandable to 950 MBbl/d. The capacity from southern Oklahoma to North Texas will vary based on telescoping pipe size. The extension of Grand Prix into southern Oklahoma is not part of the Grand Prix Joint Venture. The vast majority of the pipe for Grand Prix has already been purchased.

Total growth capital spending on Grand Prix, including the extension into southern Oklahoma, is now estimated to be approximately $1.7 billion, with our portion of growth capital spending estimated to be approximately $1.1 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, which is expected to begin operations in the first quarter of 2019. The total cost of the fractionation train and related infrastructure is expected to be approximately $350 million.

In ~~October~~December 2017, we ~~announced that we executed a letter of intent along~~entered into definitive joint venture agreements with Kinder Morgan Texas Pipeline LLC ~~a subsidiary of Kinder Morgan, Inc.~~ (“~~Kinder Morgan”~~KMTP”) and DCP Midstream Partners, LP (“DCP”) with respect to the joint development of the ~~proposed~~ Gulf Coast Express Pipeline ~~Project ("GCX Project"~~(“GCX”), ~~which would~~a natural gas pipeline from the Waha hub to Agua Dulce, Texas. The pipeline will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. ~~Under the terms of the letter of intent, we would~~We and DCP each initially own a ~~25 percent~~25% interest, and KMTP initially owns a 50% interest in ~~the~~ GCX ~~Project.~~ . Shipper Apache Corporation has an option to purchase up to a 15% equity stake from KMTP. KMTP ~~would~~will serve as the construction manager and operator ~~and constructor~~ of ~~the GCX Project, and we would commit~~GCX. We have committed significant volumes to ~~it, including certain volumes provided by~~GCX. In addition, Pioneer Natural Resources Company, ~~(“Pioneer”),~~ a joint owner in our WestTX Permian Basin system,~~. The participation~~ 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 ~~three parties involved with the~~project is estimated to be approximately $1.75 billion. GCX ~~Project is subject to negotiation and execution of definitive agreements.~~

~~The GCX Project~~ is expected to ~~have capacity~~be in service in the fourth quarter of ~~approximately 1.92 billion cubic feet per day,~~2019.

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 ~~would include~~the Train 6 DevCo JV, which owns a ~~lateral into~~100% interest in certain assets associated with a 100 MBbl/d fractionation train in Mont Belvieu, Texas. Stonepeak owns a 95% interest in the ~~Midland Basin, consisting~~Grand Prix DevCo JV, which owns a 20% interest in the Grand Prix Joint Venture. We hold the remaining interest of ~~approximately 50 miles of 36-inch pipeline and associated compression to serve gas processing facilities owned by us,~~each DevCo JV, as well as ~~those owned jointly by us~~control the management, construction and ~~Pioneer in our WestTX system.~~operation of Grand Prix and the fractionation train. The ~~expected in-service date~~Train 6 DevCo JV will fund the fractionation train while we will fund 100% of the ~~pipeline continues~~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.

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 splitter at our Channelview Terminal on the Houston Ship Channel (the “Channelview Splitter”). 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. In January 2018, Vitol US Holding Co. acquired Noble Americas Corp.

The Channelview Splitter is expected to be ~~scheduled~~completed in the second quarter of 2018, and has an estimated total cost of approximately $140 million. The first and second annual payments due under the Splitter Agreement were received in 2016 and 2017 and are reflected in deferred revenue as a component of other long-term liabilities on our Consolidated Balance Sheet.

We have engaged an independent investment banking advisory firm to evaluate the potential divestiture of our Downstream Petroleum Logistics business, which includes terminals in Baltimore, MD; Tacoma, WA; and our Channelview Splitter and terminal in Channelview, TX. The potential divestiture is predicated on third party valuations adequately capturing our forward growth expectations for the assets.

On May 1, 2018, we executed an agreement to sell our inland marine barge business to Kirby Corp. for approximately $69.3 million. Subject to customary regulatory approvals and other closing conditions, the transaction is expected to close during the second ~~half~~quarter of ~~2019, pending~~2018. Subsequent to the ~~timely completion~~closing of ~~definitive agreements with shippers~~the sale, we will continue to own and ~~a final investment decision by the three parties.~~operate two ocean-going barges

~~On February 23, 2017,~~In April 2018, we ~~amended our account receivable securitization facility (“Securitization Facility”) to increase the facility size to $350.0 million from $275.0 million.~~

~~On June 26, 2017, we redeemed our 6⅜~~issued $1.0 billion aggregate principal amount of 5⅞% senior notes due 2026 (the “5⅞% Senior Notes due August 2022 (“6⅜% Senior Notes”). The redemption price was 103.188% of the principal amount. The $278.7 million principal amount outstanding was redeemed on June 26, 2017 for a total redemption payment of $287.6 million, excluding accrued interest.

~~On October 17, 2017, we issued $750.0 million aggregate principal amount of 5% senior notes due January 2028 (the “5% Senior Notes due 2028”~~2026”). We used the net proceeds of ~~$744.4~~$992.3 million after costs from this offering to ~~redeem our 5% Senior Notes due 2018, reduce~~ repay borrowings under our credit facilities and for general partnership purposes.

On October 30, 2017, we redeemed our outstanding 5% Senior Notes due 2018 at par value plus accrued interest through the redemption date. The redemption resulted in a non-cash loss from financing activities to write-off $0.2 million of unamortized debt issuance costs in the fourth quarter of 2017.

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 ~~revenues.~~ contracts. Our ~~growth strategy, based on~~growing fee-related capital expenditures for pipelines, expansion of ~~existing~~our downstream facilities, as well as third-party acquisitions of businesses and assets, ~~has increased~~will continue to increase the ~~percentage~~number of our ~~revenues~~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 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~~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, typically connected by third-party transportation, to our Downstream Business fractionation 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, ~~generally~~ remain relatively stable and independent of the volumes through our systems, but 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.

Gathering and Processing segment gross margin consists primarily of revenues from the sale of natural gas, condensate, crude oil and NGLs and ~~fee revenues~~fees related to natural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases.

The gross margin impacts of ~~cash flow~~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. 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;~~before interest, income taxes; depreciation and amortization; impairments of goodwill and property, plant and equipment; gains or losses on debt repurchases, redemptions, amendments, exchanges and early debt extinguishments and asset disposals; risk management activities related to derivative instruments, including the cash impact of hedges acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015; non-cash compensation on equity grants; transaction costs related to business acquisitions; ~~the Splitter Agreement adjustment; earnings/losses from unconsolidated affiliates net of distributions, distributions from preferred interests, change in contingent consideration and the noncontrolling interest portion of~~taxes, depreciation and amortization, ~~expense.~~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 ~~make distributions~~pay dividends to our investors.

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,
	2017				2016				2017			2016			2018				2017
	(In millions)														(In millions)
Reconciliation of Net Income (loss) to TRP Operating Margin and Gross Margin:
Net income (loss)		$	(245.0	)	$	(6.1	)		$	(295.4	)	$	(0.5	)		$	56.0		$	(21.3	)
Depreciation and amortization expense			208.3			184.0				602.8			563.6				198.1			191.1
General and administrative expense			46.6			44.0				139.4			132.3				52.6			45.5
Impairment of property, plant and equipment			378.0			—				378.0			��
Impairment of goodwill			—			—				—			24.0
Interest expense, net			51.9			57.9				169.5			171.2
Interest (income) expense, net																	(20.2	)		58.6
Income tax expense (benefit)			—			1.0				(4.2	)		—				—			(4.7	)
(Gain) loss on sale or disposition of assets			0.3			4.7				16.6			5.7				(0.1	)		16.1
(Gain) loss from financing activities			—			—				10.7			(21.4	)
Other, net			(126.9	)		1.1				(105.7	)		10.7				55.0			21.2
Operating margin			313.2			286.6				911.7			885.6				341.4			306.5
Operating expenses			155.5			143.0				462.6			413.9				173.2			151.9
Gross margin		$	468.7		$	429.6			$	1,374.3		$	1,299.5			$	514.6		$	458.4

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2018			2017
	(In millions)												(In millions)
Reconciliation of Net Income (Loss) attributable to TRP to Adjusted EBITDA
Net income (loss) attributable to TRP	$	(254.7	)	$	(10.8	)	$	(321.3	)	$	(14.0	)	$	42.8		$	(27.3	)
Interest expense, net		51.9			57.9			169.5			171.2
Interest (income) expense, net (1)														(20.2	)		58.6
Income tax expense (benefit)		—			1.0			(4.2	)		—			—			(4.7	)
Depreciation and amortization expense		208.3			184.0			602.8			563.6			198.1			191.1
Impairment of property, plant and equipment		378.0			—			378.0			—
Impairment of goodwill		—			—			—			24.0
(Gain) loss on sale or disposition of assets		0.3			4.7			16.6			5.7			(0.1	)		16.1
(Gain) loss from financing activities		—			—			10.7			(21.4	)
(Earnings) loss from unconsolidated affiliates		(0.2	)		2.2			16.6			11.4			(1.5	)		12.6
Distributions from unconsolidated affiliates and preferred partner interests, net		4.6			3.8			15.0			12.6			6.9			4.2
Change in contingent consideration included in Other expense		(126.8	)		(0.3	)		(125.6	)		(0.3	)		56.1			3.3
Compensation on TRP equity grants		—			—			—			2.2
Transaction costs related to business acquisitions		0.4			—			5.6			—			—			5.1
Splitter Agreement (1)		10.8			—			32.3			—
Risk management activities		2.0			6.2			7.2			18.7
Noncontrolling interests adjustments (2)		(5.0	)		(8.4	)		(13.6	)		(20.5	)
Splitter Agreement (2)														10.8			10.8
Risk management activities (3)														9.7			3.6
Noncontrolling interests adjustments (4)														(5.1	)		(4.3	)
TRP Adjusted EBITDA	$	269.6		$	240.3		$	789.6		$	753.2		$	297.5		$	269.1

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,
		2017			2016			2017 vs. 2016						2017			2016			2017 vs. 2016							2018			2017			2018 vs. 2017
	(In millions, except operating statistics and price amounts)																									(In millions, except operating statistics and price amounts)
Revenues:
Sales of commodities		$	1,871.5		$	1,398.7		$	472.8			34	%	$	5,353.1		$	3,882.9		$	1,470.2			38	%		$	2,173.7		$	1,858.1		$	315.6			17	%
Fees from midstream services			260.3			253.6			6.7			3	%		759.0			795.5			(36.5	)		(5	%)			281.9			254.5			27.4			11	%
Total revenues			2,131.8			1,652.3			479.5			29	%		6,112.1			4,678.4			1,433.7			31	%			2,455.6			2,112.6			343.0			16	%
Product purchases			1,663.1			1,222.7			440.4			36	%		4,737.8			3,378.9			1,358.9			40	%			1,941.0			1,654.2			286.8			17	%
Gross margin (1)			468.7			429.6			39.1			9	%		1,374.3			1,299.5			74.8			6	%			514.6			458.4			56.2			12	%
Operating expenses			155.5			143.0			12.5			9	%		462.6			413.9			48.7			12	%			173.2			151.9			21.3			14	%
Operating margin (1)			313.2			286.6			26.6			9	%		911.7			885.6			26.1			3	%			341.4			306.5			34.9			11	%
Depreciation and amortization expense			208.3			184.0			24.3			13	%		602.8			563.6			39.2			7	%			198.1			191.1			7.0			4	%
General and administrative expense			46.6			44.0			2.6			6	%		139.4			132.3			7.1			5	%			52.6			45.5			7.1			16	%
Impairment of property, plant and equipment			378.0			—			378.0			—			378.0			—			378.0			—
Impairment of goodwill			—			—			—			—			—			24.0			(24.0	)		(100	%)
Other operating (income) expense			0.6			4.9			(4.3	)		(88	%)		17.2			6.1			11.1			182	%			0.3			16.2			(15.9	)		(98	%)
Income from operations			(320.3	)		53.7			(374.0	)	NM				(225.7	)		159.6			(385.3	)		(241	%)
Interest expense, net			(51.9	)		(57.9	)		6.0			10	%		(169.5	)		(171.2	)		1.7			1	%
Income (loss) from operations																												90.4			53.7			36.7			69	%
Interest income (expense), net																												20.2			(58.6	)		78.8			134	%
Equity earnings (loss)			0.2			(2.2	)		2.4			109	%		(16.6	)		(11.4	)		(5.2	)		46	%			1.5			(12.6	)		14.1			112	%
Gain (loss) from financing activities			—			—			—			—			(10.7	)		21.4			(32.1	)		(150	%)
Change in contingent considerations			126.8			0.3			126.5		NM				125.6			0.3			125.3		NM					(56.1	)		(3.3	)		(52.8	)	NM
Other income (expense), net			0.2			1.0			(0.8	)		(80	%)		(2.7	)		0.8			(3.5	)	NM					—			(5.2	)		5.2			100	%
Income tax (expense) benefit			—			(1.0	)		1.0			100	%		4.2			—			4.2			—				—			4.7			(4.7	)		(100	%)
Net income (loss)			(245.0	)		(6.1	)		(238.9	)	NM				(295.4	)		(0.5	)		(294.9	)	NM					56.0			(21.3	)		77.3			NM
Less: Net income attributable to noncontrolling interests			9.7			4.7			5.0			106	%		25.9			13.5			12.4			92	%
Less: Net income (loss) attributable to noncontrolling interests																												13.2			6.0			7.2			120	%
Net income (loss) attributable to Targa Resources Partners LP		$	(254.7	)	$	(10.8	)	$	(243.9	)	NM			$	(321.3	)	$	(14.0	)	$	(307.3	)	NM				$	42.8		$	(27.3	)	$	70.1			256	%
Financial and operating data:
Financial data:
Adjusted EBITDA (1)		$	269.6		$	240.3		$	29.3			12	%	$	789.6		$	753.2		$	36.4			5	%		$	297.5		$	269.1		$	28.4			11	%
Capital expenditures			378.7			134.6			244.1			181	%		987.7			426.5			561.2			132	%			558.0			174.6			383.4			220	%
Business acquisition (2)			—			—			—			—			987.1			—			987.1			—				—			1,032.4			(1,032.4	)		(100	%)
Operating statistics: (3)
Crude oil gathered, Badlands, MBbl/d			108.7			103.9			4.8			5	%		111.6			105.7			5.9			6	%			117.7			113.5			4.2			4	%
Crude oil gathered, Permian, MBbl/d (4)			35.7			—			35.7			—			24.6			—			24.6			—				49.4			9.2			40.2		NM
Plant natural gas inlet, MMcf/d (5)(6)			3,621.4			3,356.6			264.8			8	%		3,418.5			3,422.3			(3.8	)		—				3,752.3			3,223.8			528.5			16	%
Gross NGL production, MBbl/d			346.2			310.4			35.8			12	%		318.9			305.4			13.5			4	%			386.9			288.7			98.2			34	%
Export volumes, MBbl/d (7)			154.5			156.7			(2.2	)		(1	%)		175.5			173.0			2.5			1	%			201.9			217.5			(15.6	)		(7	%)
Natural gas sales, BBtu/d (6)(8)			2,054.1			1,993.0			61.1			3	%		1,942.5			1,975.4			(32.9	)		(2	%)			2,107.1			1,813.3			293.8			16	%
NGL sales, MBbl/d (8)			497.6			497.3			0.3			—			501.6			520.6			(19.0	)		(4	%)			574.9			533.6			41.3			8	%
Condensate sales, MBbl/d			11.4			10.0			1.4			14	%		11.5			10.3			1.2			12	%			16.2			10.7			5.5			51	%

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

Three Months Ended ~~September 30, 2017~~March 31, 2018 Compared to Three Months Ended ~~September 30, 2016~~March 31, 2017

The increase in commodity sales was primarily due to increased commodity volumes ($244.8 million) and higher ~~commodity~~NGL and condensate prices ($~~443.3 million) and increased volumes ($40.0~~206.6 million), partially offset by lower natural gas and petroleum product prices ($103.7 million) and the impact of ~~hedge settlements~~hedges ($~~10.5~~32.0 million). Fee-based and other revenues increased primarily due to higher gas processing and crude gathering fees.

The increase in product purchases was primarily due to ~~the impact of~~increased volumes and higher ~~commodity prices~~NGL and ~~increased volumes.~~

In the third quarter of 2017, we experienced limited impacts to our operations as a result of Hurricane Harvey. We incurred: (i) flooding at our Mont Belvieu facilities that resulted in temporary constraints on the receipt of NGLs and the temporary removal of fractionators from service at CBF, resulting in increased levels of mixed NGLs in storage and (ii) the shut-in of our Galena Park Marine Terminal for approximately one week due to the closure of the Houston Ship Channel. Our operating margin for the three months ended September 30, 2017, was reduced by approximately $10 million as a result of Hurricane Harvey, comprised of the impact on the Mont Belvieu and Galena Park Marine Terminal facilities along with lost operating margin associated with temporary production disruptions for a limited number of our producer and downstream customers. We expect to recover approximately $7 million of the reduced operating margin during the fourth quarter of 2017 when the additional stored volumes of mixed NGLs are fractionated and sold. No property insurance claims are expected as a result of the storm as damage to our facilities was minimal. Business interruption insurance claims related to the storm are expected to be minimal.condensate prices.

The higher operating margin and gross margin in ~~2017~~2018 reflects increased segment margin results for Gathering and Processing ~~partially offset by decreased~~and Logistics and ~~Marketing segment margins.~~ Marketing. Operating expenses increased compared to ~~2016~~2017 primarily due to ~~the impact of the Permian Acquisition,~~ plant and system expansions in the

Permian region, the inclusion of the Permian Acquisition for a full quarter in 2018 as compared with one month in 2017 and the ~~June 2017~~ commencement ofin operations of the Raptor Plant at SouthTX in ~~the Gathering and Processing segment, and higher labor, repairs and maintenance expense in the Logistics and Marketing segment.~~ June 2017.See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis. The increase in operating expenses was primarily driven by plant and system expansions in the Permian region, the inclusion of the Permian Acquisition for a full quarter in 2018 as compared with one month in 2017 and the commencement in operations of the Raptor Plant at SouthTX in June 2017.

Depreciation and amortization expense increased primarily due to the impact of the Permian Acquisition for a full quarter in 2018 and other growth investments.

General and administrative expense increased primarily due to higher compensation and ~~benefits, partially offset by lower professional services.~~benefits.

~~The impairment of property, plant and equipment~~Other operating (income) expense in 2017 ~~reflects~~ ~~an impairment as of September 30, 2017 of gas processing facilities and gathering systems associated with our North Texas operations~~includes the loss due to the reduction in the ~~Gathering and Processing segment. The impairment is a result~~carrying value of our ~~current assessment that forecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover~~100% ownership interest in the ~~existing total net book value of the underlying assets. Given the current price environment, Targa is projecting a continuing decline~~Venice Gathering System, which we sold in ~~natural gas production across the Barnett Shale in North Texas due in part to producers pursuing more attractive opportunities in other basins.~~April 2017.

~~Net~~The change in interest ~~expense decreased~~income (expense), net was primarily due to ~~the impact of lower average outstanding borrowings during 2017, partially offset by~~ higher non-cash interest ~~expense~~income related to the mandatorily redeemable preferred interests that is revalued quarterly at the estimated redemption value as of the reporting date, as well as higher capitalized interest. These factors more than offset the impact of higher average outstanding borrowings during 2018. The decrease in the estimated redemption value of the mandatorily redeemable preferred interests 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 the commencement of operations at Cayenne, increased equity earnings at GCF, and decreased equity losses from 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.

During ~~2017,~~2018, we recorded ~~other income~~expense of ~~$126.8~~$56.1 million resulting from the change in the fair value of contingent considerations, substantially all of which was due to the ~~reduction~~increase in fair value as of ~~September 30, 2017~~March 31, 2018 of the Permian Acquisition contingent consideration liability, which is based on a multiple of gross margin realized during the first two annual periods after the acquisition date. The ~~decrease~~increase in fair value was primarily related to reductions in actual and forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since the acquisition date. Such changes in estimated fair value of the contingent consideration during the three months ended March 31, 2018 was primarily related to an increase in underlying forecasted volumes for the remainder of the earn-out period and a shorter term over which such projections are ~~attributable to events and circumstances that occurred after the acquisition date, and as such are recognized in earnings.~~discounted. The fair value of the contingent consideration represents our current view of the future payment amounts, and may decrease or increase until the settlement dates, resulting in the recognition of additional other income (expense). During 2017, we recorded other expense of $3.2 million resulting from an increase in the fair value of the Permian Acquisition contingent consideration liability from the acquisition date to March 31, 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 ~~2017~~2018 due to increased earnings at our consolidated joint ventures as compared with ~~2016.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~

The increase in commodity sales was primarily due to higher commodity prices ($1,600.9 million) and increased petroleum products and condensate volumes ($44.0 million), partially offset by decreased NGL and natural gas sales volumes ($126.0 million) and the impact of hedge settlements ($48.7 million). Fee-based and other revenues decreased primarily due to lower export fees, partially offset by increases in gas processing and crude gathering fees.

~~The increase in product purchases was primarily due to the impact of higher commodity prices, partially offset by decreased volumes.~~

In the third quarter of 2017, we experienced limited impacts to our operations as a result of Hurricane Harvey. Our operating margin for the nine months ended September 30, 2017, was reduced by approximately $10 million as a result of Hurricane Harvey, comprised

of the impact on the Mont Belvieu and Galena Park Marine Terminal facilities along with lost operating margin associated with temporary production disruptions for a limited number of our producer and chemical customers. We expect to recover approximately $7 million of the reduced operating margin during the fourth quarter of 2017 when the additional stored volumes of mixed NGLs are fractionated and sold.

~~The higher operating margin and gross margin in 2017 reflects increased segment margin results for Gathering and Processing, partially offset by decreased Logistics and Marketing segment margins.~~ Operating expenses increased compared to 2016 due to the impact of the Permian Acquisition, plant and system expansions in the Permian region and the June 2017 commencement of operations of the Raptor Plant at SouthTX in the Gathering and Processing segment, and higher fuel and power that is largely passed through in the Logistics and Marketing segment. ~~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 increased primarily due to the impact of~~ the March 2017 Permian Acquisition and the impact of other growth investments, including CBF Train 5 that went into service in the second quarter of 2016 and the Raptor Plant at SouthTX that went into service in the second quarter of 2017.

~~General and administrative expense increased primarily due to higher compensation and benefits, partially offset by lower professional services.~~

~~The impairment of property, plant and equipment in 2017 reflects~~ ~~an impairment of gas processing facilities and gathering systems associated with our North Texas operations in the Gathering and Processing segment (described above).~~

In the first quarter of 2016, we recognized a $24.0 million adjustment to a provisional impairment of goodwill recorded in the fourth quarter of 2015 related to goodwill acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively the “Atlas mergers’).

~~Other operating expense in 2017 is primarily due to the reduction in the carrying value of our ownership interest in the Venice Gathering System in connection with the April 2017 sale.~~ ~~Other operating expense in 2016 is primarily due to the loss on decommissioning two storage wells at our Hattiesburg facility and an acid gas injection well at our Versado facility.~~

Net interest expense in 2017 decreased as compared with 2016 primarily due to lower average outstanding borrowings during 2017, partially offset by higher non-cash interest expense related to the mandatorily redeemable preferred interests that is revalued quarterly at the estimated redemption value as of the reporting date.

Higher equity losses in 2017 reflects a $12.0 million loss provision due to the impairment of our investment in the T2 EF Cogen joint venture, partially offset by increased equity earnings at Gulf Coast Fractionators.

~~During 2017, we recorded a loss from financing activities of $10.7 million on the redemption of the outstanding~~ ~~6⅜% Senior~~ ~~Notes, whereas in 2016 we recorded a gain of $21.4 million on open market debt repurchases.~~

During 2017, we recorded other income of $125.6 million resulting from the change in the fair value of contingent considerations, substantially all of which was due to the reduction in fair value as of September 30, 2017 of the Permian Acquisition contingent consideration liability.

~~The increase in income tax benefit was primarily due to a Texas Margin Tax refund in the first quarter of~~ 2017.

Net income attributable to noncontrolling interests was higher in 2017 due to our October 2016 acquisition of the 37% interest of Versado that we did not already own. Further, earnings at our joint ventures increased as compared with 2016.

	Three Months Ended September 30,									Nine Months Ended September 30,											Three Months Ended March 31,
	2017		2016		2017 vs. 2016					2017		2016				2017 vs. 2016					2018		2017		2018 vs. 2017
Gross margin	$	289.7	$	231.7	$	58.0		25	%	$	817.1	$	648.0		$		169.1		26	%	$	325.6	$	263.0	$	62.6			24	%
Operating expenses		91.4		82.3		9.1		11	%		267.8		243.9				23.9		10	%		104.8		85.6		19.2			22	%
Operating margin	$	198.3	$	149.4	$	48.9		33	%	$	549.3	$	404.1		$		145.2		36	%	$	220.8	$	177.4	$	43.4			24	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
SAOU (4)		324.6		262.5		62.1		24	%		304.1		255.1				49.0		19	%
WestTX		607.5		506.0		101.5		20	%		560.8		480.8				80.0		17	%
Total Permian Midland		932.1		768.5		163.6					864.9		735.9				129.0
Sand Hills (4)		193.0		140.9		52.1		37	%		171.6		142.6				29.0		20	%
Versado		210.9		180.6		30.3		17	%		202.0		176.5				25.5		14	%
Total Permian Delaware		403.9		321.5		82.4					373.6		319.1				54.5
Permian Midland (4)																						1,014.1		793.6		220.5			28	%
Permian Delaware (4)																						409.2		338.0		71.2			21	%
Total Permian		1,336.0		1,090.0		246.0					1,238.5		1,055.0				183.5					1,423.3		1,131.6		291.7

SouthTX		330.1		218.0		112.1		51	%		242.1		219.7				22.4		10	%		416.3		171.8		244.5			142	%
North Texas		261.8		315.2		(53.4	)	(17	%)		273.7		323.4				(49.7	)	(15	%)		235.1		282.5		(47.4	)		(17	%)
SouthOK		515.2		469.8		45.4		10	%		478.5		466.1				12.4		3	%		529.9		440.4		89.5			20	%
WestOK		367.1		434.4		(67.3	)	(15	%)		382.5		455.6				(73.1	)	(16	%)		350.1		393.1		(43.0	)		(11	%)
Total Central		1,474.2		1,437.4		36.8					1,376.8		1,464.8				(88.0	)				1,531.4		1,287.8		243.6

Badlands (5)		60.9		53.8		7.1		13	%		53.1		52.9				0.2		—			73.3		46.0		27.3			59	%
Total Field		2,871.1		2,581.2		289.9					2,668.4		2,572.7				95.7					3,028.0		2,465.4		562.6

Coastal		750.5		775.5		(25.0	)	(3	%)		750.1		849.7				(99.6	)	(12	%)		724.3		758.2		(33.9	)		(4	%)

Total		3,621.6		3,356.7		264.9		8	%		3,418.5		3,422.4				(3.9	)	—			3,752.3		3,223.6		528.7			16	%
Gross NGL production, MBbl/d (3)
SAOU (4)		38.7		32.8		5.9		18	%		36.6		31.4				5.2		17	%
WestTX		84.1		67.6		16.5		24	%		75.2		60.7				14.5		24	%
Total Permian Midland		122.8		100.4		22.4					111.8		92.1				19.7
Sand Hills (4)		21.0		15.2		5.8		38	%		18.6		15.0				3.6		24	%
Versado		25.3		21.8		3.5		16	%		23.8		21.3				2.5		12	%
Total Permian Delaware		46.3		37.0		9.3					42.4		36.3				6.1
Permian Midland (4)																						140.2		99.7		40.5			41	%
Permian Delaware (4)																						45.7		37.9		7.8			21	%
Total Permian		169.1		137.4		31.7					154.2		128.4				25.8					185.9		137.6		48.3

SouthTX		35.4		20.9		14.5		69	%		25.2		25.1				0.1		—			54.1		16.6		37.5			226	%
North Texas		29.3		36.2		(6.9	)	(19	%)		30.8		36.3				(5.5	)	(15	%)		25.9		32.0		(6.1	)		(19	%)
SouthOK		42.7		42.4		0.3		1	%		40.7		39.3				1.4		4	%		48.9		40.9		8.0			20	%
WestOK		20.7		27.2		(6.5	)	(24	%)		22.3		27.9				(5.6	)	(20	%)		19.4		22.8		(3.4	)		(15	%)
Total Central		128.1		126.7		1.4					119.0		128.6				(9.6	)				148.3		112.3		36.0
														��
Badlands		9.0		7.8		1.2		15	%		7.4		7.5				(0.1	)	(1	%)		10.2		5.5		4.7			85	%
Total Field		306.2		271.9		34.3					280.6		264.5				16.1					344.4		255.4		89.0

Coastal		40.0		38.6		1.4		4	%		38.2		41.0				(2.8	)	(7	%)		42.6		33.3		9.3			28	%

Total		346.2		310.5		35.7		11	%		318.8		305.5				13.3		4	%		387.0		288.7		98.3			34	%
Crude oil gathered, Badlands, MBbl/d		108.7		103.9		4.8		5	%		111.6		105.7				5.9		6	%		117.7		113.5		4.2			4	%
Crude oil gathered, Permian, MBbl/d (4)		35.7		—		35.7		—			24.6		—				24.6		—			49.4		9.2		40.2		NM
Natural gas sales, BBtu/d (3)		1,738.5		1,617.6		120.9		7	%		1,647.8		1,636.8				11.0		1	%		1,767.3		1,547.4		219.9			14	%
NGL sales, MBbl/d		244.4		248.4		(4.0	)	(2	%)		240.4		241.3				(0.9	)	-			300.4		227.6		72.8			32	%
Condensate sales, MBbl/d		11.4		9.7		1.7		18	%		11.4		10.0				1.4		14	%		16.2		10.7		5.5			51	%
Average realized prices (6):
Natural gas, $/MMBtu		2.58		2.49		0.09		4	%		2.71		1.96				0.75		38	%		2.37		2.89		(0.52	)		(18	%)
NGL, $/gal		0.56		0.36		0.20		56	%		0.51		0.33				0.18		55	%		0.59		0.50		0.09			18	%
Condensate, $/Bbl		42.69		38.29		4.40		11	%		43.42		34.18				9.24		27	%		59.66		44.98		14.68			33	%

Three Months Ended ~~September 30, 2017~~March 31, 2018 Compared to Three Months Ended ~~September 30, 2016~~March 31, 2017

The increase in gross margin was primarily due to higher ~~commodity prices and higher~~ Permian volumes including those associated with the Permian ~~Acquisition. Field~~Acquisition in March 2017, higher Central and Badlands region volumes and higher NGL prices. The overall increase in Gathering and Processing

inlet ~~volume increases~~volumes included all areas in the Permian region, ~~as well as~~ SouthTX, ~~Badlands~~SouthOK, and ~~SouthOK,~~Badlands, partially offset by decreases at WestOK, North Texas and ~~North Texas.~~Coastal. The ~~inlet volume decrease for~~ Coastal Gathering and Processing ~~which generates~~assets generate significantly lower unit margins ~~partially offset~~than the Field Gathering and Processing ~~inlet volume increase.~~assets. NGL production, NGL sales and natural gas sales increased primarily due to ~~increased Field~~higher Gathering and Processing inlet ~~volumes. The decrease in~~volumes and increased NGL ~~sales was~~recoveries primarily due to ~~the deferral to the fourth quarter of 2017 of NGL sales impacted by the temporary operational issues related to Hurricane Harvey.~~reduced ethane rejection. Total crude oil gathered volumes increased in the Permian region due to the Permian ~~Acquisition. Total~~Acquisition and higher production from new wells and system expansions. In Badlands, total crude oil gathered volumes and natural gas gathered volumes increased primarily due to higher production from new wells and system expansions.

The increase in operating expenses was primarily driven by ~~the inclusion of the Permian Acquisition,~~ plant and system expansions in the Permian region, the inclusion of the Permian Acquisition in March 2017 and the ~~June 2017~~ commencement in operations of the Raptor Plant at ~~SouthTX.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~

~~The increase~~SouthTX in gross margin was primarily due to higher commodity prices and higher Permian volumes including those associated with the Permian Acquisition. Field Gathering and Processing inlet volume increases included all areas in the Permian region, as well as SouthTX and SouthOK, partially offset by decreases at WestOK and North Texas. The inlet volume decrease for Coastal Gathering and Processing, which generates significantly lower unit margins, more than offset the Field Gathering and Processing inlet volume increase. Despite overall lower inlet volumes, NGL production increased primarily due to increased plant recoveries including additional ethane recovery. Third quarter NGL sales were reduced due to the deferral to the fourth quarter of 2017 of NGL sales impacted by the temporary operational issues related to Hurricane Harvey. Natural gas sales increased primarily due to increased Field Gathering and Processing inlet volumes. Total crude oil gathered volumes increased in the Permian region due to the Permian Acquisition. Total Badlands crude oil gathered increased due to system expansions. Badlands natural gas volumes were relatively flat primarily due to the impact of the severe winter weather in the first quarter ofJune 2017.

The increase in operating expenses was primarily driven by the inclusion of the Permian Acquisition, plant and system expansions in the Permian region and the June 2017 commencement in operations of the Raptor Plant at SouthTX.

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:

	Three Months Ended September 30, 2017									Three Months Ended March 31, 2018
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)	Gross Volume (3)		Ownership %			Net Volume (3)		Actual Reported		Gross Volume (3)		Ownership %			Net Volume (3)		Actual Reported
SAOU (4)		324.6		100	%		324.6		324.6
WestTX (5) (6)		834.5		73	%		607.5		607.5
Total Permian Midland		1,159.1					932.1		932.1
Sand Hills (4)		193.0		100	%		193.0		193.0
Versado (7)		210.9		100	%		210.9		210.9
Total Permian Delaware		403.9					403.9		403.9
Permian Midland											1,257.8	Varies (4)				1,014.1		1,014.1
Permian Delaware											409.2		100	%		409.2		409.2
Total Permian		1,563.0					1,336.0		1,336.0		1,667.0					1,423.3		1,423.3

SouthTX		330.1	Varies (8) (9)				260.0		330.1		416.3	Varies (5)				294.3		416.3
North Texas		261.8		100	%		261.8		261.8		235.1		100	%		235.1		235.1
SouthOK		515.2	Varies (10)				412.1		515.2		529.9	Varies (6)				429.0		529.9
WestOK		367.1		100	%		367.1		367.1		350.1		100	%		350.1		350.1
Total Central		1,474.2					1,301.0		1,474.2		1,531.4					1,308.5		1,531.4

Badlands (11)		60.9		100	%		60.9		60.9
Badlands (7)											73.3		100	%		73.3		73.3
Total Field		3,098.1					2,697.9		2,871.1		3,271.7					2,805.1		3,028.0

Gross NGL production, MBbl/d (2)
SAOU (4)		38.7		100	%		38.7		38.7
WestTX (5) (6)		115.5		73	%		84.1		84.1
Total Permian Midland		154.2					122.8		122.8
Sand Hills (4)		21.0		100	%		21.0		21.0
Versado (7)		25.3		100	%		25.3		25.3
Total Permian Delaware		46.3					46.3		46.3
Permian Midland											174.8	Varies (4)				140.2		140.2
Permian Delaware											45.7		100	%		45.7		45.7
Total Permian		200.5					169.1		169.1		220.5					185.9		185.9

SouthTX		35.4	Varies (8) (9)				28.6		35.4		54.1	Varies (5)				36.7		54.1
North Texas		29.3		100	%		29.3		29.3		25.9		100	%		25.9		25.9
SouthOK		42.7	Varies (10)				34.6		42.7		48.9	Varies (6)				40.4		48.9
WestOK		20.7		100	%		20.7		20.7		19.4		100	%		19.4		19.4
Total Central		128.1					113.2		128.1		148.3					122.4		148.3

Badlands		9.0		100	%		9.0		9.0		10.2		100	%		10.2		10.2
Total Field		337.6					291.3		306.2		379.0					318.5		344.4

Three Months Ended September 30, 2016

Operating statistics:

Plant natural gas inlet, MMcf/d (1),(2)

Gross Volume (3)

Ownership %

Net Volume (3)

Actual Reported

SAOU

262.5

100
%

262.5

262.5

WestTX (4)

695.0

73
%

506.0

506.0

Total Permian Midland

957.5

768.5

768.5

Sand Hills

140.9

100
%

140.9

140.9

Versado (5)

180.6

63
%

113.8

180.6

Total Permian Delaware

321.5

254.7

321.5

Total Permian

1,279.0

1,023.2

1,090.0

SouthTX

218.0

Varies (6)

205.6

218.0

North Texas

315.2

100
%

315.2

315.2

SouthOK

469.8

Varies (7)

392.8

469.8

WestOK

434.4

100
%

434.4

434.4

Total Central

1,437.4

1,348.0

1,437.4

Badlands (8)

53.8

100
%

53.8

53.8

Total Field

2,770.2

2,425.0

2,581.2

Gross NGL production, MBbl/d (2)

SAOU

32.8

100
%

32.8

32.8

WestTX (4)

92.9

73
%

67.6

67.6

Total Permian Midland

125.7

100.4

100.4

Sand Hills

15.2

100
%

15.2

15.2

Versado (5)

21.8

��
63
%

13.7

21.8

Total Permian Delaware

37.0

28.9

37.0

Total Permian

162.7

129.3

137.4

SouthTX

20.9

Varies (6)

19.7

20.9

North Texas

36.2

100
%

36.2

36.2

SouthOK

42.4

Varies (7)

39.1

42.4

WestOK

27.2

100
%

27.2

27.2

Total Central

126.7

122.2

126.7

Badlands

7.8

100
%

7.8

7.8

Total Field

297.2

259.3

271.9

		Three Months Ended September 30,									Nine Months Ended September 30,
		2017		2016		2017 vs. 2016					2017		2016		2017 vs. 2016						Three Months Ended March 31,
																					2018		2017		2018 vs. 2017
	(In millions)																			(In millions)
Gross margin		$	180.0	$	186.7	$	(6.7	)	(4	%)	$	553.3	$	594.6	$	(41.3	)	(7	%)		$	206.9	$	196.4	$	10.5		5	%
Operating expenses			64.1		60.7		3.4		6	%		194.8		170.0		24.8		15	%			68.5		66.3		2.2		3	%
Operating margin		$	115.9	$	126.0	$	(10.1	)	(8	%)	$	358.5	$	424.6	$	(66.1	)	(16	%)		$	138.4	$	130.1	$	8.3		6	%
Operating statistics MBbl/d (1):
Fractionation volumes (2)(3)			329.3		313.2		16.1		5	%		324.3		312.8		11.5		4	%			383.3		304.9		78.6		26	%
LSNG treating volumes (2)			27.2		25.6		1.6		6	%		31.6		23.3		8.3		36	%			30.1		34.5		(4.4	)	(13	%)
Benzene treating volumes (2)			16.1		20.2		(4.1	)	(20	%)		20.5		21.4		(0.9	)	(4	%)			13.4		23.5		(10.1	)	(43	%)
Export volumes, MBbl/d (4)			154.5		156.7		(2.2	)	(1	%)		175.5		173.0		2.5		1	%			201.9		217.5		(15.6	)	(7	%)
NGL sales, MBbl/d			463.4		452.4		11.0		2	%		468.1		466.3		1.8		—				514.8		502.0		12.8		3	%
Average realized prices:
NGL realized price, $/gal		$	0.67	$	0.46	$	0.21		46	%	$	0.64	$	0.45	$	0.19		42	%		$	0.76	$	0.66	$	0.10		15	%

Three Months Ended ~~September 30, 2017~~March 31, 2018 Compared to Three Months Ended ~~September 30, 2016~~March 31, 2017

Logistics and Marketing gross margin ~~decreased~~increased due to ~~lower LPG export margin partially offset by~~ higher fractionation margin, higher marketing gains, ~~and~~higher domestic marketing margin, higher terminaling and storage ~~throughput.~~throughput, partially offset by lower LPG export margin ~~decreased primarily due to~~and lower fees. LPG export volumes decreased due to the deferral to the fourth quarter of 2017 of 12.5 MBbl/d of export volumes due to the temporary closure of the Houston Ship Channel resulting from Hurricane Harvey.treating margin. Fractionation margin increased due to higher supply volume and higher system product ~~gains, higher supply volume despite the deferral to the fourth quarter of 2017 of 29.3 MBbl/d of supply volumes due to the temporary operational issues related to Hurricane Harvey, and higher fees.~~gains. Fractionation ~~gross~~ margin was partially impacted by the variable effects of ~~lower~~ fuel and power that are largely reflected in operating expenses (see footnote (2) above). Domestic marketing margin increased due to higher terminal margins and volumes. LPG export margin decreased due to lower fees and volumes. Treating margin and volumes decreased primarily due to the temporary shutdown of the treating units for planned maintenance.

Operating expenses increased ~~primarily~~ due to higher ~~labor,~~compensation and benefits, higher ~~repairs~~fuel and ~~maintenance,~~power costs that are largely passed through, partially offset by lower ~~fuel and power that is largely passed through.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~

The gross margin results for the nine months ended September 30, 2017 were impacted by the same factors as discussed above for the three months ended September 30, 2017, with the exception of fuel and power, which were higher. Additional factors were lower commercial transportation margin and lower domestic marketing margin. Commercial transportation margin decreased primarily due to lower barge activity. Domestic marketing margin decreased primarily due to lower terminal margins.

Operating expenses increased primarily due to higher fuel and power which is largely passed through, higher labor associated with Train 5, and higher maintenance associated with unusual one-time events in the first quarter of 2017.maintenance.

	Three Months Ended September 30,								Nine Months Ended September 30,							Three Months Ended March 31,
	2017			2016		2017 vs. 2016			2017		2016		2017 vs. 2016			2018			2017			2018 vs. 2017
	(In millions)															(In millions)
Gross margin	$	(1.0	)	$	11.2	$	(12.2	)	$	3.9	$	56.9	$	(53.0	)	$	(17.8	)	$	(1.0	)	$	(16.8	)
Operating margin	$	(1.0	)	$	11.2	$	(12.2	)	$	3.9	$	56.9	$	(53.0	)	$	(17.8	)	$	(1.0	)	$	(16.8	)

Other contains the results ~~(including any hedge ineffectiveness)~~ 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~~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, 2017								Three Months Ended September 30, 2016												Three Months Ended March 31, 2018								Three Months Ended March 31, 2017
	(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)			2017 vs. 2016			Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)			Gain (Loss)			2018 vs. 2017
Natural gas (BBtu)		17.3	$	0.23		$	4.0			13.8		$	0.37		$	5.1		$	(1.1	)		17.4	$	0.33		$	5.8			10.5	$	0.02		$	0.2		$	5.6
NGL (MMgal)		74.8		(0.09	)		(6.7	)		(7.2	)		(0.25	)		1.8			(8.5	)		87.2		(0.11	)		(9.4	)		43.3		(0.04	)		(1.8	)		(7.6	)
Crude oil (MBbl)		0.4		6.29			2.3			0.3			14.40			4.7			(2.4	)		0.4		(10.30	)		(4.6	)		0.2		5.35			1.2			(5.8	)
Non-hedge accounting (2)							(0.6	)								(0.1	)		(0.5	)							(9.6	)							(0.8	)		(8.8	)
Ineffectiveness (3)							-									(0.3	)		0.3								-								0.2			(0.2	)
						$	(1.0	)							$	11.2		$	(12.2	)						$	(17.8	)						$	(1.0	)	$	(16.8	)

	Nine Months Ended September 30, 2017								Nine Months Ended September 30, 2016
	(In millions, except volumetric data and price amounts)
	Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled			Price Spread (1)			Gain (Loss)			2017 vs. 2016
Natural gas (BBtu)		43.3	$	0.15		$	6.6			34.0		$	0.94		$	31.9		$	(25.3	)
NGL (MMgal)		177.5		(0.04	)		(7.7	)		20.2			0.34			6.9			(14.6	)
Crude oil (MBbl)		0.9		6.29			5.8			0.8			20.02			16.2			(10.4	)
Non-hedge accounting (2)							(0.9	)								2.5			(3.4	)
Ineffectiveness (3)							0.1									(0.6	)		0.7
						$	3.9								$	56.9		$	(53.0	)

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~~$3.0 million for the three ~~and nine~~ months ended September 30, 2017 and $5.8 million and $20.9 million for the three and nine months ended September 30, 2016, related to these novated contracts. From the acquisition date through September 30, 2017, we haveMarch 31, 2017. The final settlement was received ~~total derivative settlements of $100.9 million.~~ ~~The remainder of the novated contracts will settle by the end of~~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, 2017,~~March 31, 2018, we had ~~$103.9~~$206.7 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 Securitization Facility, and access to debt markets. We may supplement these sources of liquidity with proceeds from potential asset sales and/or joint ventures. 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.

		October 31, 2017				May 1, 2018
		(In millions)				(In millions)
Cash on hand	Cash on hand	$	196.3		Cash on hand	$	298.5
Total availability under the TRP Revolver	Total availability under the TRP Revolver		1,600.0		Total availability under the TRP Revolver		1,600.0
Total availability under the Securitization Facility	Total availability under the Securitization Facility		350.0		Total availability under the Securitization Facility		344.3
			2,146.3				2,242.8

Less:	Outstanding borrowings under the TRP Revolver		—		Outstanding borrowings under the TRP Revolver		—
	Outstanding borrowings under the Securitization Facility		(270.0	)	Outstanding borrowings under the Securitization Facility		—
	Outstanding letters of credit under the TRP Revolver		(24.6	)	Outstanding letters of credit under the TRP Revolver		(65.8	)
	Total liquidity	$	1,851.7		Total liquidity	$	2,177.0

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 ~~that are~~ tied to commodity sales and purchases are relatively balanced, with receivables from NGL ~~and natural gas~~ customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: ~~(1)~~(i) our cash position; ~~(2)~~(ii) liquids inventory levels and valuation, which we closely manage; ~~(3)~~(iii) changes in the fair value of the current portion of derivative contracts; (iv) monthly swings in borrowings under the Securitization Facility; and ~~(4)~~(v) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth projects.

Our working capital, exclusive of current debt obligations, increased ~~$34.7~~$70.8 million from December 31, ~~2016~~2017 to ~~September 30, 2017.~~March 31, 2018. The major items contributing to this increase were ~~the increase in inventory due to~~a higher ~~prices and volumes, additional collateral posted with our futures broker due to~~cash balance, an increase ~~in commodity prices, and greater cash on hand. This increase was partially offset by an increase in capital expenditure accruals driven primarily by the Permian activities, and a decrease~~ in our net risk management working capital position due to changes in the forward prices of ~~commodities.~~commodities, and a decrease in accounts payable, partially offset by a reduction in inventory

primarily attributable to a decrease in volumes in storage. The ~~increase~~decrease of ~~$253.4~~$50.0 million in current debt obligations was mainly due to the ~~reclassification~~reduction in the balance of ~~the remaining 5% Notes due 2018 to short-term. These notes were redeemed on October 30, 2017.~~AR Securitization.

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 ~~quarterly~~ cash distributions to Targa for at least the next twelve months.

In February 2018, we formed three DevCo JVs with Stonepeak, which committed a maximum of ~~long-term debt obligations and preferred units.~~approximately $960 million of capital to the DevCo JVs. For the three months ended March 31, 2018, total contributions from Stonepeak were $222.3 million, which 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 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. As of September 30, 2017 and December 31, 2016, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $3,957.6 million and $4,206.8 million, respectively. ~~In October 2017, we issued $750.0 million aggregate principal amount of 5% Senior Notes due 2028, with net proceeds of $744.4 million after costs,~~ ~~and redeemed our outstanding 5% Senior Notes due 2018 at face value plus accrued interest through the redemption date.~~

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.~~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, 2017,~~March 31, 2018, we dodid not have any interest rate hedges.

In April 2018, we issued $1.0 billion aggregate principal amount of the 5⅞% Senior Notes due 2026. We used the net proceeds of $992.3 million after costs from this offering to repay borrowings under its credit facilities and for general partnership purposes.

To date, we do not believe our debt balances have adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 109 - 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.”

In October 2015, we completed an offering of 5,000,000 Preferred Units at a price of $25.00 per unit. We received net proceeds after costs of approximately $121.1 million. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.” 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 ~~holders of the~~ Preferred ~~Units (“Preferred Unitholders”)~~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, 2017,~~March 31, 2018, we were in compliance with the covenants contained in our various debt agreements.

The ~~Consolidated Statements~~primary drivers of ~~Cash Flows included in our historical consolidated financial statements employs the traditional indirect method of presenting~~ cash flows from operating ~~activities. Under~~activities are (i) the ~~indirect method, net~~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 of NGLs and natural gas, and (iii) 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 to 2018 mainly caused by the impact of higher commodity prices and volumes, higher capitalized interest, partially offset by increased payments of operating ~~activities is derived~~expenses. The increase in commodity prices and volumes resulted in higher cash collections from customers, partially offset by ~~adjusting our net income for non-cash items~~higher product purchases. The rising commodity prices also contributed to excess margin withdrawals related to ~~operating activities. An alternative GAAP presentation employs~~our derivative contracts. Higher capitalized interest resulted in lower interest payments. Expanded operations from the ~~direct method~~ Permian activities and new construction projects in ~~which the actual cash receipts and outlays comprising cash flow are presented.~~

~~The following table displays our operating cash flows using the direct method as a supplement~~2018 contributed to ~~the presentation~~increases in ~~our consolidated financial statements:~~

~~Higher commodity prices were the primary contributor to increased cash collections and~~ payments for product purchases in 2017 compared to 2016. Cash received from derivative settlements was lower as commodity price spreads between the prices paid to counterparties and the fixed prices we received on those derivative contracts were lower in 2017 in comparison to 2016. Interest payments are lower this year largely due to lower average outstanding debt balances, offset by the timing of payments of interest on two new series of notes we issued in 2016. ~~Cash payments for operating expenses and general and administrative expenses increased primarily due to higher~~ compensation and benefits ~~contractor and other professional services, coupled with~~as well as higher utilities and ~~higher maintenance.~~ ~~Other cash payments in 2017 were higher mainly due to transaction expenses associated with the~~ ~~Permian Acquisition in 2017.~~maintenance costs.

Nine Months Ended September 30,
2017			2016			2017 vs. 2016
Three Months Ended March 31,									Three Months Ended March 31,
2018									2018		2017			2018 vs. 2017
(In millions)	(In millions)								(In millions)
$	(1,457.5	)	$	(422.0	)	$	(1,035.5	)	(677.3	)	$	(625.5	)	$	(51.8	)

Cash used in investing activities increased in ~~2017~~2018 compared to ~~2016,~~2017, primarily due to higher capital expenditures of $451.7 million during 2018 primarily related to the ~~$570.8~~construction of Grand Prix, and an $87.5 million increase in contributions to unconsolidated affiliates mainly due to the construction activities in GCX and Little Missouri 4. The increase was partially offset by the $480.8 million outlay for the cash portion due at the closing of the Permian Acquisition ~~consideration. Capital expenditures increased $441.6 million during~~consideration in 2017, ~~reflecting~~whereas there was no business acquisition in the ~~spending for major growth projects during 2017 and the acquisition~~first quarter of ~~the Flag City Plant.~~2018.

	Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2018			2017
Source of Financing Activities, net	(In millions)						(In millions)
Debt, including financing costs							$	310.0		$	(140.1	)
Contributions from noncontrolling interests								280.1			8.9
Contributions from TRC and General Partner	$	1,620.0		$	1,191.0			60.0			655.0
Distributions		(633.1	)		(542.9	)		(228.5	)		(198.1	)
Debt, including financing costs		(4.6	)		(808.6	)
Equity offerings, net of financing costs		-			(7.5	)
Other		47.9			15.8			(16.5	)		(9.7	)
Net cash provided by (used in) financing activities	$	1,030.2		$	(152.2	)	$	405.1		$	316.0

In 2018, we realized a net source of cash from financing activities primarily due to borrowings under the TRP Revolver and contributions from noncontrolling interests partially offset by the payments of distributions to TRC. The contributions from noncontrolling interests were primarily from Stonepeak and Blackstone to fund growth projects.

In 2017, we realized a net source of cash from financing activities, primarily due to contributions from TRC, ~~and General Partner,~~ partially offset by ~~a net reduction of debt borrowings and~~ payments of distributions to ~~TRC. We reduced net debt borrowings through~~

TRC and 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 received a total of $75.0 million in contributions from Blackstone.~~

In 2016, we incurred a net use of cash from financing activities primarily due to a net reduction of debt outstanding and payment of distributions to TRC, offset by contributions from TRC and our general partner. With the contributions from TRC, we repurchased a portion of our senior notes through open market repurchases generally at a discount to par values and repaid a portion of the outstanding borrowings under the TRP Revolver.credit facilities.

~~As a result of the TRC/TRP Merger,~~ TRC is entitled to receive all available Partnership distributions after ~~payment~~payments of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement, as to whether to distribute all available cash for any period. See Note 1 – Organization and Operations of the “Consolidated Financial Statements” included in this quarterly report.

The following table details the distributions declared and/or paid by us during the three ~~and nine~~ months ended ~~September 30, 2017.~~March 31, 2018.

Distributions on our Preferred Units are declared and paid monthly. As of ~~September 30, 2017,~~March 31, 2018, we have 5,000,000 Preferred Units outstanding. For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2018, $2.8 ~~million and $8.4~~ 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 16, ~~2017.~~2018.

In ~~October 2017,~~April 2018, 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, ~~2017.~~2018.

Our capital requirements relate to capital expenditures, which are classified as ~~expansion~~growth capital expenditures, ~~(including~~ business ~~acquisitions),~~acquisitions, and maintenance expenditures. ~~Expansion~~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.

We currently estimate that we will invest ~~approximately $1,320.0~~at least $2,180 million in net growth capital expenditures (exclusive of outlays for business acquisitions) and contributions to investments in unconsolidated affiliates for announced projects in ~~2017.~~2018. 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 ~~expansion~~growth capital expenditures may vary significantly based on investment opportunities. We ~~continue to~~ expect that ~~2017~~2018 net maintenance capital expenditures will be approximately ~~$110.0~~$120 million.

~~Our expansion~~Total growth capital expenditures increased for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 as compared to the ~~nine~~three months ended ~~September 30, 2016,~~March 31, 2017, primarily due to spending related to Grand Prix, additional processing plants and associated infrastructure in the Permian Basin, ~~the Grand Prix NGL pipeline~~ and ~~the Channelview Splitter, as well as the acquisition of the Flag City. The increase was partially offset by the impact of the substantial completion of the CBF~~ Train ~~5 project in the second quarter of 2016. Our~~6. Total maintenance capital expenditures ~~increased~~were relatively flat for ~~2017 as compared to 2016, primarily due to higher volumes processed on our system.~~ the comparable periods.

As of ~~September 30, 2017,~~March 31, 2018, there were ~~$38.3~~$49.2 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 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 through 2020. 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 ~~NGLs~~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, 2017,~~March 31, 2018, 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 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 natural gas and NGL hedges’ fair values 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 hedging transactions are typically 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.

Our operating revenues increased (decreased) by ~~net hedge adjustments on commodity derivative contracts of $(3.6)~~$(38.8) million and ~~$7.5~~$(6.7) million during the three months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016, and $(4.9) million and $46.4 million, during the nine months ended September 30, 2017 and 2016,~~ 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 position of ~~$53.3~~$38.2 million at December 31, ~~2016~~2017 to a net ~~liability~~asset position of ~~$63.4~~$32.9 million at ~~September 30, 2017.~~March 31, 2018. 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.

As of ~~September 30, 2017,~~March 31, 2018, we had the following derivative instruments that will settle during the years shown below:

Instrument		Price																				Price
Type	Index	$/MMBtu					MMBtu/d											Fair Value			Index	$/MMBtu				MMBtu/d								Fair Value
							2017			2018			2019			2020		(In millions)								2018			2019			2020		(In millions)
Gathering & Processing	Gathering & Processing																				Gathering & Processing
Swap	IF-Waha		2.8740					103,600			-			-			-	$	2.7		IF-Waha		2.6470				93,600			-			-	$	27.4
Swap	IF-Waha		2.6470					-			93,600			-			-		4.0		IF-Waha		2.6327				-			65,383			-		27.4
Swap	IF-Waha		2.6327					-			-			65,383			-		6.2
								103,600			93,600			65,383			-										93,600			65,383			-

Swap	IF-PB		2.6602					40,900			-			-			-		0.5
Swap	IF-PB		2.4802					-			45,900			-			-		0.2		IF-PB		2.4802				45,900			-			-		12.3
Swap	IF-PB		2.3700					-			-			35,000			-		0.9		IF-PB		2.3700				-			35,000			-		11.8
								40,900			45,900			35,000			-										45,900			35,000			-

Swap	IF-PEPL		2.6835					16,000			-			-			-		0.1		IF-PEPL		2.5960				31,370			-			-		4.4
Swap	IF-PEPL		2.6835					-			16,000			-			-		0.6		IF-PEPL		2.5333				-			31,370			-		5.8
Swap	IF-PEPL		2.6835					-			-			16,000			-		1.5
								16,000			16,000			16,000			-

Swap	NG-NYMEX		3.9900					9,783			-			-			-		0.8
																											31,370			31,370			-

		Put Price			Call Price																	Put Price		Call Price
Collar	IF-Waha		3.0000			3.6700		7,500			-			-			-		0.3		IF-PB		3.0000		3.6500		5,096			-			-		2.2
Collar	IF-Waha		3.2500			4.2000		-			1,849			-			-		0.3
								7,500			1,849			-			-

		Put Price			Call Price
Collar	IF-PB		2.8000			3.5000		15,400			-			-			-		0.4
Collar	IF-PB		3.0000			3.6500		-			7,637			-			-		1.5
								15,400			7,637			-			-


Basis Swap	EP-PERMIAN		(0.1444	)				4,891			-			-			-		0.2

Basis Swap	PEPL		(0.3308	)				4,891			-			-			-		0.0

Gathering & Processing total	Gathering & Processing total							202,965			164,986			116,383			0	$	20.2		Gathering & Processing total						175,966			131,753			-	$	91.3

Other (1)	Other (1)																				Other (1)
Swap	NG-NYMEX		(3.1680	)				(229	)		(173	)		(247	)		-	$	(0.0	)	NG-NYMEX		2.9000				(131	)		-			-	$	(0.0	)
Swap	IF-Waha		3.0647					(9,707	)		(4,227	)		-			-		(0.5	)	NG-NYMEX		2.8367				-			(247	)		-		(0.0	)
																											(131	)		(247	)		-

Basis Swap	Various	Various						82,418			15,726			12,500			10,445		(1.3	)	Various	Various					138,009			78,062			10,417		(12.2	)
Future	Various		3.2640					-			1,103			-			-		(0.0	)
Other total	Other total							72,482			12,429			12,253			10,445	$	(1.8	)	Other total						137,878			77,815			10,417	$	(12.2	)

																		$	18.4															$	79.1

Instrument

Price

Type
Index
$/gal

Bbl/d

Fair Value

2017

2018

2019

(In millions)

Gathering & Processing

Swap
C2-OPIS-MB

0.2778

6,030

-

-

$
0.0

Swap
C2-OPIS-MB

0.2816

-

4,118

-

(0.4
)
Swap
C2-OPIS-MB

0.2951

-

-

3,460

(1.0
)
Total

6,030

4,118

3,460

Swap
C3-OPIS-MB

0.6598

10,382

-

-

(9.7
)
Swap
C3-OPIS-MB

0.6274

-

5,510

-

(8.5
)
Swap
C3-OPIS-MB

0.5530

-

-

2,650

(3.8
)
Total

10,382

5,510

2,650

Swap
IC4-OPIS-MB

0.8570

1,400

-

-

(1.1
)
Swap
IC4-OPIS-MB

0.8053

-

560

-

(0.6
)
Swap
IC4-OPIS-MB

0.7133

-

-

170

(0.2
)
Total

1,400

560

170

Swap
NC4-OPIS-MB

0.8538

3,930

-

-

(2.9
)
Swap
NC4-OPIS-MB

0.7969

-

1,530

-

(1.4
)
Swap
NC4-OPIS-MB

0.6989

-

-

460

(0.6
)
Total

3,930

1,530

460

Swap
C5-OPIS-MB

1.0997

1,690

-

-

(0.7
)
Swap
C5-OPIS-MB

1.0703

-

1,140

-

(2.1
)
Swap
C5-OPIS-MB

1.0783

-

-

659

(0.9
)
Total

1,690

1,140

659

Put Price

Call Price

Collar
C2-OPIS-MB

0.240

0.290

410

-

-

(0.0
)

Put Price

Call Price

Collar
C3-OPIS-MB

0.570

0.68625

380

-

-

(0.3
)
Collar
C3-OPIS-MB

0.530

0.65000

-

900

-

(1.7
)
Total

380

900

-

Put Price

Call Price

Collar
IC4-OPIS-MB

0.650

0.840

-

110

-

(0.2
)
Collar
IC4-OPIS-MB

0.640

0.800

-

-

110

(0.2
)
Total

-

110

110

Put Price

Call Price

Collar
NC4-OPIS-MB

0.650

0.800

-

300

-

(0.6
)
Collar
NC4-OPIS-MB

0.640

0.760

-

-

300

(0.4
)
Total

-

300

300

Put Price

Call Price

Collar
C5-OPIS-MB

1.210

1.415

130

-

-

0.0

Collar
C5-OPIS-MB

1.230

1.385

-

32

-

0.0

Total

130

32

-

Gathering & Processing total

24,352

14,200

7,809

$
(37.3
)

Other (1)(2)

Future
C2-OPIS-MB

0.2741

13,804

-

-

$
(0.1
)
Future
C2-OPIS-MB

0.3007

-

1,534

-

0.2

Future
C2-OPIS-MB

0.3138

-

-

329

(0.0
)
Total

13,804

1,534

329

Future
C3-OPIS-MB

0.6394

13,120

-

-

(13.5
)
Future
C3-OPIS-MB

0.6074

-

2,918

-

(15.3
)
Total

13,120

2,918

-

Instrument										Price
Type									Index	$/gal				Bbl/d						Fair Value
														2018		2019		2020		(In millions)
Gathering & Processing									Gathering & Processing
Swap									C2-OPIS-MB		0.2829				5,199		-		-		0.9
Swap									C2-OPIS-MB		0.2955				-		4,610		-		1.1
Swap									C2-OPIS-MB		0.3016				-		-		1,577		0.1
Total															5,199		4,610		1,577

Swap									C3-OPIS-MB		0.7124				9,870		-		-		(6.8	)
Swap									C3-OPIS-MB		0.6455				-		5,480		-		(3.9	)
Swap									C3-OPIS-MB		0.6213				-		-		1,700		(0.9	)
Total															9,870		5,480		1,700

Swap									IC4-OPIS-MB		0.8824				1,320		-		-		(0.2	)
Swap									IC4-OPIS-MB		0.8111				-		540		-		0.0
Swap									IC4-OPIS-MB		0.7190				-		-		230		(0.2	)
Total															1,320		540		230

Swap									NC4-OPIS-MB		0.8780				3,850		-		-		(0.6	)
Swap									NC4-OPIS-MB		0.8041				-		1,560		-		0.1
Swap									NC4-OPIS-MB		0.7125				-		-		660		(0.4	)
Total															3,850		1,560		660

Swap									C5-OPIS-MB		1.2034				2,540		-		-		(6.1	)
Swap									C5-OPIS-MB		1.1418				-		1,259		-		(2.9	)
Swap									C5-OPIS-MB		1.0825				-		-		400		(0.5	)
Total															2,540		1,259		400

										Put Price		Call Price
Collar									C3-OPIS-MB		0.530		0.650		900		-		-		(1.5	)

										Put Price		Call Price
Collar									IC4-OPIS-MB		0.650		0.840		110		-		-		(0.1	)
Collar									IC4-OPIS-MB		0.640		0.800		-		110		-		(0.1	)
Total															110		110		-

										Put Price		Call Price
Collar									NC4-OPIS-MB		0.650		0.800		300		-		-		(0.5	)
Collar									NC4-OPIS-MB		0.640		0.760		-		300		-		(0.4	)
Total															300		300		-

Gathering & Processing total									Gathering & Processing total						24,089		13,859		4,567	$	(22.9	)

Other (1)(2)									Other (1)(2)
Future	IC4-OPIS-MB	0.7706	1,033	-	-		(1.1	)	C2-OPIS-MB		0.2599				6,018		-		-	$	(0.6	)
Future	IC4-OPIS-MB	0.7825	-	55	-		(0.2	)	C2-OPIS-MB		0.2804				-		1,342		-		0.0
Total			1,033	55	-										6,018		1,342		-

Future	NC4-OPIS-MB	0.8314	9,946	-	-		(8.2	)	C3-OPIS-MB		0.7474				1,669		-		-		(0.7	)
Future	NC4-OPIS-MB	0.8027	-	1,616	-		(5.3	)	C3-OPIS-MB		0.7658				-		41		-		(0.0	)
Total			9,946	1,616	-										1,669		41		-

Future	C5-OPIS-MB	1.1285	978	-	-		(0.3	)	IC4-OPIS-MB		0.8525				218		-		-		(0.1	)

Future	C5-OPIS-MB	1.0890	-	466	-		(0.8	)	NC4-OPIS-MB		0.8630				545		-		-		(0.2	)
Total			978	466	-

	Put Price
Option	C2-OPIS-MB	0.2694	2,174	-	-		0.1
Option	C2-OPIS-MB	0.2963	-	1,644	-		1.1
Total			2,174	1,644	-
Future									C5-OPIS-MB		1.3381				473		-		-		(0.4	)

Other total	Other total		41,055	8,233	329	$	(43.4	)	Other total						8,923		1,383		-	$	(2.0	)

						$	(80.7	)												$	(24.9	)

Instrument		Price														Price
Type	Index	$/Bbl				Bbl/d						Fair Value			Index	$/Bbl				Bbl/d						Fair Value
						2017		2018		2019		(In millions)								2018		2019		2020		(In millions)
Gathering & Processing	Gathering & Processing														Gathering & Processing
Swap	WTI-NYMEX		53.50				3,150		-		-	$	0.4		WTI-NYMEX		53.38				4,990		-		-	$	(13.4	)
Swap	WTI-NYMEX		48.76				-		2,420		-		(2.7	)	WTI-NYMEX		52.95				-		2,653		-		(5.5	)
Swap	WTI-NYMEX		50.86				-		-		1,293		(0.0	)
							3,150		2,420		1,293										4,990		2,653		-

																Put Price		Call Price
		Put Price		Call Price
Collar	WTI-NYMEX		54.04		64.09		1,380		-		-		0.5
Collar	WTI-NYMEX		49.76		58.50		-		691		-		0.4		WTI-NYMEX		48.00		56.25		590		-		-		(1.3	)
Collar	WTI-NYMEX		48.00		56.25		-		-		590		0.3		WTI-NYMEX		48.00		56.25		-		590		-		(1.1	)
							1,380		691		590										590		590		-

Total							4,530		3,111		1,883										5,580		3,243		-

												$	(1.1	)												$	(21.3	)

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). For derivative instruments not designated as cash flow hedges, these contracts are marked-to-market and recorded in revenues.

We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. For the contracts that have inputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those contracts which we are unable to obtain quoted prices for at least 90% of the full term of the commodity contract, the valuations are classified as Level 3

within the fair value hierarchy. See Note 1413 - Fair Value Measurements in this Quarterly Report for more information regarding classifications within the fair value hierarchy.

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, 2017,~~March 31, 2018, 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, 2017,~~March 31, 2018, we had ~~$708.1~~$680.0 million in outstanding variable rate borrowings under the TRP Revolver and 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 ~~$7.1~~$6.8 million.

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 all 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 ~~$32.4~~$71.7 million as of ~~September 30, 2017.~~March 31, 2018. The range of losses attributable to our individual counterparties would be between ~~$0.3~~$0.4 million and ~~$8.2~~$39.7 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, 2017,~~March 31, 2018, our operating income would decrease by ~~$7.1~~$7.5 million in the year of the assessment.

During the three months ended March 31, 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 14% of our consolidated revenues. No customer comprised greater than 10% of our consolidated revenues in the three months ended March 31, 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 March 31, 2018, 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.~~reporting, during our most recent fiscal quarter.

The information required for this item is provided in Note 1615 – 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.)~~

~~1000 Louisiana St, Suite 4300, Houston, Texas~~		~~77002~~
~~(Address of principal executive offices)~~		~~(Zip Code)~~

~~Large accelerated filer~~	☐		~~Accelerated filer~~	☐
~~Non-accelerated filer~~	☑	~~(Do not check if a smaller reporting company)~~	~~Smaller reporting company~~	☐
			~~Emerging growth company~~	☐

~~TABLE OF CONTENTS~~ ~~PART I—FINANCIAL INFORMATION~~

~~Item 1. Financial Statements~~		4

~~Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016~~		4

~~Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2016~~		5

~~Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2017 and 2016~~		6

~~Consolidated Statements of Changes in Owners' Equity for the nine months ended September 30, 2017 and 2016~~		7

~~Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016~~		8

~~Notes to Consolidated Financial Statements~~		9

~~Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations~~		36

~~Item 3. Quantitative and Qualitative Disclosures About Market Risk~~		57

~~Item 4. Controls and Procedures~~		62

~~PART II—OTHER INFORMATION~~

~~Item 1. Legal Proceedings~~		63

~~Item 1A. Risk Factors~~		63

~~Item 2. Unregistered Sales of Equity Securities and Use of Proceeds~~		63

~~Item 3. Defaults Upon Senior Securities~~		63

~~Item 4. Mine Safety Disclosures~~		63

~~Item 5. Other Information~~		63

~~Item 6. Exhibits~~		64

~~SIGNATURES~~

~~Signatures~~		66


~~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~~


~~Price Index Definitions~~
~~C2-OPIS-MB~~	~~Ethane, Oil Price Information Service, Mont Belvieu, Texas~~
~~C3-OPIS-MB~~	~~Propane, Oil Price Information Service, Mont Belvieu, Texas~~
~~C5-OPIS-MB~~	~~Natural Gasoline, Oil Price Information Service, Mont Belvieu, Texas~~
~~EP-PERMIAN~~	~~Inside FERC Gas Market Report, El Paso (Permian Basin)~~
~~IC4-OPIS-MB~~	~~Iso-Butane, Oil Price Information Service, Mont Belvieu, Texas~~
~~IF-PB~~	~~Inside FERC Gas Market Report, Permian Basin~~
~~IF-PEPL~~	~~Inside FERC Gas Market Report, Oklahoma Panhandle, Texas-Oklahoma Midpoint~~
~~IF-Waha~~	~~Inside FERC Gas Market Report, West Texas WAHA~~
~~NC4-OPIS-MB~~	~~Normal Butane, Oil Price Information Service, Mont Belvieu, Texas~~
~~NG-NYMEX~~	~~NYMEX, Natural Gas~~
~~WTI-NYMEX~~	~~NYMEX, West Texas Intermediate Crude Oil~~

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)

Large accelerated filer	☐		Accelerated filer	☐
Non-accelerated filer	☑	(Do not check if a smaller reporting company)	Smaller reporting company	☐
			Emerging growth company	☐

TABLE OF CONTENTS PART I—FINANCIAL INFORMATION

Item 1. Financial Statements		4

Consolidated Balance Sheets as of March 31, 2018 and December 31, 2017		4

Consolidated Statements of Operations for the three months ended March 31, 2018 and 2017		5

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

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

Consolidated Statements of Cash Flows for the three months ended March 31, 2018 and 2017		8

Notes to Consolidated Financial Statements		9

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		33

Item 3. Quantitative and Qualitative Disclosures About Market Risk		50

Item 4. Controls and Procedures		54

PART II—OTHER INFORMATION

Item 1. Legal Proceedings		55

Item 1A. Risk Factors		55

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		55

Item 3. Defaults Upon Senior Securities		55

Item 4. Mine Safety Disclosures		55

Item 5. Other Information		55

Item 6. Exhibits		56

SIGNATURES

Signatures		58


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

Price Index Definitions
C2-OPIS-MB	Ethane, Oil Price Information Service, Mont Belvieu, Texas
C3-OPIS-MB	Propane, Oil Price Information Service, Mont Belvieu, Texas
C5-OPIS-MB	Natural Gasoline, Oil Price Information Service, Mont Belvieu, Texas
IC4-OPIS-MB	Iso-Butane, Oil Price Information Service, Mont Belvieu, Texas
IF-PB	Inside FERC Gas Market Report, Permian Basin
IF-PEPL	Inside FERC Gas Market Report, Oklahoma Panhandle, Texas-Oklahoma Midpoint
IF-Waha	Inside FERC Gas Market Report, West Texas WAHA
NC4-OPIS-MB	Normal Butane, Oil Price Information Service, Mont Belvieu, Texas
NG-NYMEX	NYMEX, Natural Gas
WTI-NYMEX	NYMEX, West Texas Intermediate Crude Oil

	Three Months Ended March 31, 2018
	Pre-Adoption		Effect of Adoption			Post-Adoption
Revenues:
Sales of commodities	$	2,260.1	$	(86.4	)	$	2,173.7
Fees from midstream services		288.4		(6.5	)		281.9
Total revenues		2,548.5		(92.9	)		2,455.6
Costs and expenses:
Product purchases		2,033.9		(92.9	)		1,941.0
Income from operations		90.4		—			90.4
Income (loss) before income taxes		56.0		—			56.0
Net income (loss)	$	56.0	$	—		$	56.0

Fair Value of Consideration Transferred:
Cash paid, net of $3.3 million cash acquired	$	570.8
Contingent consideration valuation as of the acquisition date		416.3
Total	$	987.1

Fair value determination (final):	March 1, 2017
Trade and other current receivables, net	$	6.7
Other current assets		0.6
Property, plant and equipment		255.8
Intangible assets		692.3
Current liabilities		(14.1	)
Other long-term liabilities		(0.8	)
Total identifiable net assets		940.5
Goodwill		46.6
Total fair value of assets acquired and liabilities assumed	$	987.1

Balance at December 31, 2016	$	1,654.0
Additions from Permian Acquisition		692.3
Additions from Flag City Acquisition		7.7
Amortization		(139.2	)
Balance at September 30, 2017	$	2,214.8

	WestTX		SouthTX		Permian		Total
Balance at December 31, 2016, net	$	174.7	$	35.3	$	—	$	210.0
Permian Acquisition, March 1, 2017		—		—		46.6		46.6
Balance at September 30, 2017, net	$	174.7	$	35.3	$	46.6	$	256.6

	GCF			T2 LaSalle			T2 Eagle Ford			T2 EF Cogen			Cayenne		Total
Balance at December 31, 2016	$	46.1		$	58.6		$	118.6		$	17.5		$	—	$	240.8
Equity earnings (loss)		8.4			(3.7	)		(7.9	)		(13.4	)		—		(16.6	)
Cash distributions (1)		(10.6	)		—			—			—			—		(10.6	)
Acquisition		—			—			—			—			5.0		5.0
Contributions (2)		—			0.4			1.2			0.1			1.8		3.5
Balance at September 30, 2017	$	43.9		$	55.3		$	111.9		$	4.2		$	6.8	$	222.1

Balance at December 31, 2016	$	64.1
Additions (1)		0.8
Reduction due to sale of VGS		(21.6	)
Change in cash flow estimate		3.1
Accretion expense		3.0
Balance at September 30, 2017	$	49.4

Balance at December 31, 2016	$	68.5
Income attributable to mandatorily redeemable preferred interests		3.0
Change in estimated redemption value included in interest expense		8.5
Balance at September 30, 2017	$	80.0

Balance at March 1, 2017 (acquisition date)	$	461.6
Measurement period adjustment of acquisition date value		(45.3	)
Decrease in fair value due to factors occurring after acquisition date		(125.5	)
Balance at September 30, 2017		290.8
Less: Current portion		(5.9	)
Long-term balance at September 30, 2017	$	284.9

Balance at December 31, 2017	$	317.0
Increase in fair value due to factors occurring after acquisition date		56.0
Balance at March 31, 2018		373.0
Less: Current portion		—
Long-term balance at March 31, 2018	$	373.0

Three Months Ended	Date Paid Or to Be Paid		Total Distributions			Distributions to Targa Resources Corp.
September 30, 2017	November 10, 2017	$		225.4	$		222.6
June 30, 2017	August 10, 2017			225.4			222.6
March 31, 2017	May 11, 2017			209.6			206.8
December 31, 2016	February 10, 2017			198.1			195.3

		Commodity
		Derivative Contracts			Contingent
		Asset/(Liability)			Liability

Balance, December 31, 2016		$	(3.6	)	$	(2.6	)
	Change in fair value of TPL contingent consideration		-			0.1
	Fair value of Permian Acquisition contingent consideration (1)		-			(290.8	)
	New Level 3 derivative instruments		(0.8	)		-
	Transfers out of Level 3 (2)		1.6			-
	Settlements included in Revenue		0.4			-
	Unrealized gain/(loss) included in OCI		(3.5	)		-
Balance, September 30, 2017		$	(5.9	)	$	(293.3	)

		2018				2019				2020 and after
Fixed consideration to be recognized as of March 31, 2018		$	322.1			$	368.1			$	1,400.0

		Gathering and Processing		Logistics and Marketing		Other			Total
	(In millions)
Three Months Ended:
September 30, 2017		$	198.3	$	115.9	$	(1.0	)	$	313.2
September 30, 2016			149.4		126.0		11.2			286.6

Nine Months Ended:
September 30, 2017		$	549.3	$	358.5	$	3.9		$	911.7
September 30, 2016			404.1		424.6		56.9			885.6

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*4.2	~~Supplemental~~ Indenture dated ~~June 16, 2017 to Indenture dated January 31, 2012,~~as of April 12, 2018 among the ~~Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation,~~Issuers, the ~~other Subsidiary~~ Guarantors and U.S. Bank National ~~Association.~~Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed April 16, 2018).

4.3*4.3	~~Supplemental Indenture~~Registration Rights Agreement dated ~~June 16, 2017 to Indenture dated October 25, 2012,~~as of April 12, 2018 among the ~~Guaranteeing Subsidiary,~~Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa Resources Partners ~~LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.~~LP’s Current Report on Form 8-K (File No. 001-33303) filed April 16, 2018).

4.4*10.1+	~~Supplemental Indenture dated June 16, 2017~~Targa Resources Corp. 2018 Annual Incentive Compensation Plan (incorporated by reference to ~~Indenture dated May 14, 2013, among the Guaranteeing Subsidiary,~~Exhibit 10.1 to Targa Resources Partners ~~LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.~~LP’s Current Report on Form 8-K filed January 18, 2018 (File No. 001-33303)).

4.5*10.2	~~Supplemental Indenture~~Purchase Agreement dated ~~June 16, 2017 to Indenture dated October 28, 2014,~~as of April 5, 2018, among the ~~Guaranteeing Subsidiary,~~Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners ~~LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.~~

4.6*	Supplemental Indenture dated June 16, 2017 to Indenture dated January 30, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.7*	Supplemental Indenture dated June 16, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.8*	~~Supplemental Indenture dated June 16, 2017 to Indenture dated October~~LP’s Current Report on Form 8-K (File No. 001-33303) filed April 6, ~~2016, among the Guaranteeing Subsidiary, Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.~~2018).

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

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

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

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

~~Number~~		~~Description~~

101.INS*	XBRL Instance Document

101.SCH*	XBRL Taxonomy Extension Schema Document

101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document

Number		Description

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 ~~(Registrant)~~

	By:	Targa Resources GP LLC,
		its general partner

Date: ~~November~~May 3, ~~2017~~2018	By:	/s/ ~~Matthew J. Meloy~~Jennifer R. Kneale
		~~Matthew J. Meloy~~Jennifer R. Kneale
		~~Executive Vice President and~~ Chief Financial Officer
		(~~Authorized Officer and~~ Principal Financial Officer)