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, ~~or a~~ smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated ~~filer”~~filer,” “smaller reporting company,” and ~~“smaller reporting~~“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~~July 31, ~~2016, there were 243,520,639 common units representing limited partner interests and 4,969,807 general partner units outstanding. As of October 31, 2016,~~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 June 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 “Part II- Other Information, Item 1A. Risk Factors.” in this Quarterly Report and~~ 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,			December 31,
					2016			2015								June 30, 2017			December 31, 2016
					(Unaudited)											(Unaudited)
					(In millions)											(In millions)
ASSETS	ASSETS										ASSETS
Current assets:	Current assets:										Current assets:
Cash and cash equivalents	Cash and cash equivalents				$	129.9		$	135.4		Cash and cash equivalents					$	72.1		$	68.0
Trade receivables, net of allowances of $0.1 million						546.2			514.8
Trade receivables, net of allowances of $0.2 and $0.9 million at June 30, 2017 and December 31, 2016											Trade receivables, net of allowances of $0.2 and $0.9 million at June 30, 2017 and December 31, 2016						548.5			673.2
Inventories	Inventories					150.3			141.0		Inventories						197.7			137.7
Assets from risk management activities	Assets from risk management activities					34.8			92.2		Assets from risk management activities						35.7			16.8
Other current assets	Other current assets					16.4			10.0		Other current assets						21.9			31.5
Total current assets	Total current assets					877.6			893.4		Total current assets						875.9			927.2
Property, plant and equipment	Property, plant and equipment					12,347.7			11,928.2		Property, plant and equipment						13,306.7			12,511.9
Accumulated depreciation	Accumulated depreciation					(2,667.6	)		(2,225.6	)	Accumulated depreciation						(3,080.0	)		(2,821.0	)
Property, plant and equipment, net	Property, plant and equipment, net					9,680.1			9,702.6		Property, plant and equipment, net						10,226.7			9,690.9
Intangible assets, net	Intangible assets, net					1,693.0			1,810.1		Intangible assets, net						2,264.7			1,654.0
Goodwill, net	Goodwill, net					393.0			417.0		Goodwill, net						256.6			210.0
Long-term assets from risk management activities	Long-term assets from risk management activities					12.4			34.9		Long-term assets from risk management activities						17.3			5.1
Investments in unconsolidated affiliates	Investments in unconsolidated affiliates					246.9			258.9		Investments in unconsolidated affiliates						218.4			240.8
Other long-term assets	Other long-term assets					5.2			9.9		Other long-term assets						14.3			16.9
Total assets	Total assets				$	12,908.2		$	13,126.8		Total assets					$	13,873.9		$	12,744.9

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				$	657.5		$	635.8		Accounts payable and accrued liabilities					$	823.9		$	773.9
Accounts payable to Targa Resources Corp.	Accounts payable to Targa Resources Corp.					41.8			30.1		Accounts payable to Targa Resources Corp.						55.1			61.0
Liabilities from risk management activities	Liabilities from risk management activities					13.0			5.2		Liabilities from risk management activities						9.5			49.1
Accounts receivable securitization facility						225.0			219.3
Current debt obligations											Current debt obligations						500.1			275.0
Total current liabilities	Total current liabilities					937.3			890.4		Total current liabilities						1,388.6			1,159.0
Long-term debt	Long-term debt					4,297.1			5,125.7		Long-term debt						3,502.5			4,177.0
Long-term liabilities from risk management activities	Long-term liabilities from risk management activities					17.6			2.4		Long-term liabilities from risk management activities						5.5			26.1
Deferred income taxes, net	Deferred income taxes, net					27.1			27.2		Deferred income taxes, net						26.9			26.9
Other long-term liabilities	Other long-term liabilities					151.6			178.2		Other long-term liabilities						574.2			205.3

Contingencies (see Note 15)
Contingencies (see Note 16)											Contingencies (see Note 16)

Owners' equity:	Owners' equity:										Owners' equity:
Series A preferred limited partners	Issued		Outstanding			120.6			120.6		Series A preferred limited partners	Issued		Outstanding			120.6			120.6
September 30, 2016		5,000,000		5,000,000
December 31, 2015		5,000,000		5,000,000
June 30, 2017											June 30, 2017		5,000,000		5,000,000
December 31, 2016											December 31, 2016		5,000,000		5,000,000
Common limited partners	Issued		Outstanding			5,178.6			4,550.4		Common limited partners	Issued		Outstanding			7,047.9			5,939.9
September 30, 2016		243,520,639		243,520,639
December 31, 2015	185,083,420		184,870,693
June 30, 2017											June 30, 2017		275,168,410		275,168,410
December 31, 2016											December 31, 2016		275,168,410		275,168,410
General partner						1,733.1			1,735.3		General partner	Issued		Outstanding			819.4			796.7
September 30, 2016		4,969,807		4,969,807
December 31, 2015		3,772,871		3,772,871
June 30, 2017											June 30, 2017		5,629,136		5,629,136
December 31, 2016											December 31, 2016		5,629,136		5,629,136
Accumulated other comprehensive income (loss)						(4.3	)		86.8		Accumulated other comprehensive income (loss)						34.6			(61.8	)
Treasury units at cost (0 units and 212,727 units as of September 30, 2016 and December 31, 2015)						-			(10.3	)
						7,028.0			6,482.8								8,022.5			6,795.4
Noncontrolling interests in subsidiaries						449.5			420.1		Noncontrolling interests in subsidiaries						353.7			355.2
Total owners' equity	Total owners' equity					7,477.5			6,902.9		Total owners' equity						8,376.2			7,150.6
Total liabilities and owners' equity	Total liabilities and owners' equity				$	12,908.2		$	13,126.8		Total liabilities and owners' equity					$	13,873.9		$	12,744.9

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 June 30,						Six Months Ended June 30,
	2016			2015			2016			2015			2017			2016			2017			2016
	(Unaudited)												(Unaudited)
	(In millions, except per unit amounts)												(In millions)
Revenues:
Sales of commodities	$	1,398.7		$	1,321.3		$	3,882.9		$	4,119.6		$	1,623.8		$	1,312.9		$	3,481.7		$	2,484.0
Fees from midstream services		253.6			310.8			795.5			891.6			243.9			270.7			498.6			542.0
Total revenues		1,652.3			1,632.1			4,678.4			5,011.2			1,867.7			1,583.6			3,980.3			3,026.0
Costs and expenses:
Product purchases		1,222.7			1,163.3			3,378.9			3,650.0			1,420.6			1,145.2			3,074.8			2,156.2
Operating expenses		143.0			142.7			413.9			409.5			155.2			138.9			307.1			270.9
Depreciation and amortization expenses		184.0			165.8			563.6			448.3
General and administrative expenses		44.0			42.9			132.3			130.1
Depreciation and amortization expense														203.4			186.1			394.6			379.6
General and administrative expense														47.5			44.9			92.9			88.3
Goodwill impairment		—			—			24.0			—			—			—			—			24.0
Other operating (income) expense		4.9			0.1			6.1			0.6			0.3			0.1			16.5			1.1
Income from operations		53.7			117.3			159.6			372.7			40.7			68.4			94.4			105.9
Other income (expense):
Interest expense, net		(57.9	)		(61.6	)		(171.2	)		(171.1	)		(58.9	)		(66.4	)		(117.5	)		(113.3	)
Equity earnings (loss)		(2.2	)		(1.6	)		(11.4	)		(1.1	)		(4.2	)		(4.4	)		(16.8	)		(9.2	)
Gain (loss) from financing activities		—			(0.5	)		21.4			(0.5	)		(10.7	)		(3.3	)		(10.7	)		21.4
Other		1.3			(0.7	)		1.1			(15.2	)
Other, net														4.4			(0.1	)		(4.0	)		(0.2	)
Income (loss) before income taxes		(5.1	)		52.9			(0.5	)		184.8			(28.7	)		(5.8	)		(54.6	)		4.6
Income tax (expense) benefit		(1.0	)		0.4			—			(0.4	)		(0.5	)		0.9			4.2			1.1
Net income (loss)		(6.1	)		53.3			(0.5	)		184.4			(29.2	)		(4.9	)		(50.4	)		5.7
Less: Net income attributable to noncontrolling interests		4.7			4.8			13.5			17.3			10.2			5.8			16.2			8.8
Net income (loss) attributable to Targa Resources Partners LP	$	(10.8	)	$	48.5		$	(14.0	)	$	167.1		$	(39.4	)	$	(10.7	)	$	(66.6	)	$	(3.1	)

Net income attributable to preferred limited partners	$	2.8		$	—		$	8.4		$	—		$	2.8		$	2.8		$	5.6		$	5.6
Net income attributable to general partner		29.0			44.9			68.2			132.0
Net income (loss) attributable to general partner														(0.8	)		24.4			(1.4	)		39.2
Net income (loss) attributable to common limited partners		(42.6	)		3.6			(90.6	)		35.1			(41.4	)		(37.9	)		(70.8	)		(47.9	)
Net income (loss) attributable to Targa Resources Partners LP	$	(10.8	)	$	48.5		$	(14.0	)	$	167.1		$	(39.4	)	$	(10.7	)	$	(66.6	)	$	(3.1	)

	Three Months Ended September 30,								Nine Months Ended September 30,
		2016			2015			2016				2015					Three Months Ended June 30,								Six Months Ended June 30,
		(Unaudited)															2017				2016				2017			2016
		(In millions)															(Unaudited)								(Unaudited)
																	(In millions)								(In millions)
Net income (loss)		$	(6.1	)	$	53.3		$		(0.5	)	$	184.4		Net income (loss)		$	(29.2	)		$	(4.9	)		$	(50.4	)	$	5.7
Other comprehensive income (loss):															Other comprehensive income (loss):
Commodity hedging contracts:															Commodity hedging contracts:
Change in fair value			12.9			50.7				(40.5	)		77.6		Change in fair value			29.8				(60.2	)			96.0			(53.5	)
Settlements reclassified to revenues			(8.1	)		(24.5	)			(50.6	)		(59.3	)
Settlements reclassified to net income																Settlements reclassified to net income			(5.7	)			(18.3	)			0.4			(42.4	)
Other comprehensive income (loss)			4.8			26.2				(91.1	)		18.3		Other comprehensive income (loss)			24.1				(78.5	)			96.4			(95.9	)
Comprehensive income (loss)			(1.3	)		79.5				(91.6	)		202.7		Comprehensive income (loss)			(5.1	)			(83.4	)			46.0			(90.2	)
Less: Comprehensive income attributable to noncontrolling interests			4.7			4.8				13.5			17.3		Less: Comprehensive income attributable to noncontrolling interests			10.2				5.8				16.2			8.8
Comprehensive income (loss) attributable to Targa Resources Partners LP		$	(6.0	)	$	74.7		$		(105.1	)	$	185.4		Comprehensive income (loss) attributable to Targa Resources Partners LP		$	(15.3	)		$	(89.2	)		$	29.8		$	(99.0	)

Accumulated

Limited

Limited

General

Receivables

Other

Treasury

Non-

Partner

Partner

Partner

From Unit

Comprehensive

Units

controlling

Preferred

Amount

Common

Amount

Units

Amount

Issuances

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

Balance December 31, 2014

—

$
—

118,586

$
2,384.1

2,420

$
78.6

$
(1.0
)

$
60.3

67

$
(4.8
)

$
171.2

$
2,688.4

Compensation on equity grants

—

—

—

12.8

—

—

—

—

—

—

—

12.8

Distribution equivalent rights

—

—

—

(1.9
)

—

—

—

—

—

—

—

(1.9
)
Issuance of common units under compensation program

—

—

405

—

—

—

—

—

—

—

—

—

Units tendered for tax
   withholding obligations

—

—

(135
)

—

—

—

—

—

135

(5.2
)

—

(5.2
)
Equity offerings

—

—

7,377

315.4

—

—

—

—

—

—

—

315.4

Contributions from Targa
   Resources Corp.

—

—

—

—

1,352

59.1

1.0

—

—

—

—

60.1

Acquisition of APL

—

—

58,614

2,583.1

—

—

—

—

—

—

113.4

2,696.5

Contributions from
   noncontrolling interests

—

—

—

—

—

—

—

—

—

—

16.4

16.4

Distributions to
   noncontrolling interests

—

—

—

—

—

—

—

—

—

—

(8.7
)

(8.7
)
Targa contribution - Special General Partner Interest

—

—

—

—

—

1,612.4

—

—

—

—

—

1,612.4

Other comprehensive
   income (loss)

—

—

—

—

—

—

—

18.3

—

—

—

18.3

Net income

—

—

—

35.1

—

132.0

—

—

—

—

17.3

184.4

Distributions

—

—

—

(397.1
)

—

(134.6
)

—

—

—

—

—

(531.7
)
Balance September 30, 2015

—

$
—

184,847

$
4,931.5

3,772

$
1,747.5

$
—

$
78.6

202

$
(10.0
)

$
309.6

$
7,057.2

																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.		—		—			—		1,572.8			—		32.2			—			—		—		—			1,605.0
Purchase of noncontrolling interests in subsidiary		—		—			—		—			—		—			—			—		—		(12.5	)		(12.5	)
Distributions to noncontrolling interests		—		—			—		—			—		—			—			—		—		(21.7	)		(21.7	)
Contributions from noncontrolling interests		—		—			—		—			—		—			—			—		—		16.5			16.5
Other comprehensive income (loss)		—		—			—		—			—		—			96.4			—		—		—			96.4
Net income (loss)		—	5.6				—		(70.8	)		—		(1.4	)		—			—		—		16.2			(50.4	)
Distributions		—		(5.6	)		—		(394.0	)		—		(8.1	)		—			—		—		—			(407.7	)
Balance June 30, 2017		5,000	$	120.6			275,168	$	7,047.9			5,629	$	819.4		$	34.6			—	$	—	$	353.7		$	8,376.2

										Six Months Ended June 30,
		Nine Months Ended September 30,								2017			2016
		2016			2015
	(Unaudited)								(Unaudited)
	(In millions)								(In millions)
Cash flows from operating activities								Cash flows from operating activities
Net income (loss)		$	(0.5	)	$	184.4		Net income (loss)		$	(50.4	)	$	5.7
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			9.8			9.3		Amortization in interest expense			4.7			6.6
Compensation on equity grants			2.2			12.8		Compensation on equity grants			—			2.2
Depreciation and amortization expense			563.6			448.3		Depreciation and amortization expense			394.6			379.6
Goodwill impairment			24.0			—		Goodwill impairment			—			24.0
Accretion of asset retirement obligations			3.5			3.9		Accretion of asset retirement obligations			2.2			2.3
Change in redemption value of mandatorily redeemable preferred interest			(18.8	)		—
Increase (decrease) in redemption value of mandatorily redeemable preferred interests								Increase (decrease) in redemption value of mandatorily redeemable preferred interests			6.9			(14.6	)
Deferred income tax expense (benefit)			—			(0.3	)	Deferred income tax expense (benefit)			—			(1.1	)
Equity (earnings) loss of unconsolidated affiliates			11.4			1.1		Equity (earnings) loss of unconsolidated affiliates			16.8			9.2
Distributions of earnings received from unconsolidated affiliates			1.8			10.1		Distributions of earnings received from unconsolidated affiliates			4.0			—
Risk management activities			11.7			53.2		Risk management activities			10.0			3.2
(Gain) loss on sale or disposition of assets			5.7			(0.2	)	(Gain) loss on sale or disposition of assets			16.2			0.9
(Gain) loss from financing activities			(21.4	)		0.5		(Gain) loss from financing activities			10.7			(21.4	)
Change in contingent considerations included in Other expense								Change in contingent considerations included in Other expense			1.2			—
Changes in operating assets and liabilities, net of business acquisitions:								Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets			(28.3	)		126.7		Receivables and other assets			140.9			29.8
Inventories			(27.8	)		31.2		Inventories			(68.6	)		12.4
Accounts payable and other liabilities			31.8			(143.2	)	Accounts payable and other liabilities			(93.8	)		23.0
Net cash provided by operating activities			568.7			737.8		Net cash provided by operating activities			395.4			461.8
Cash flows from investing activities								Cash flows from investing activities
Outlays for property, plant and equipment			(425.0	)		(625.3	)	Outlays for property, plant and equipment			(527.6	)		(307.7	)
Outlays for business acquisition, net of cash acquired			—			(828.7	)	Outlays for business acquisition, net of cash acquired			(570.8	)		—
Investment in unconsolidated affiliates			(4.6	)		(6.6	)
Investments in unconsolidated affiliates								Investments in unconsolidated affiliates			(0.6	)		—
Return of capital from unconsolidated affiliates			3.4			1.1		Return of capital from unconsolidated affiliates			3.2			3.9
Other, net			4.2			(3.0	)	Other, net			(12.8	)		(1.4	)
Net cash used in investing activities			(422.0	)		(1,462.5	)	Net cash used in investing activities			(1,108.6	)		(305.2	)
Cash flows from financing activities								Cash flows from financing activities
Debt obligations:								Debt obligations:
Proceeds from borrowings under credit facility			1,110.0			1,646.0		Proceeds from borrowings under credit facility			1,016.0			835.0
Repayments of credit facility			(1,390.0	)		(1,211.0	)	Repayments of credit facility			(1,166.0	)		(1,060.0	)
Proceeds from borrowings under accounts receivable securitization facility			121.4			275.5		Proceeds from borrowings under accounts receivable securitization facility			218.5			121.4
Repayments of accounts receivable securitization facility			(115.7	)		(322.8	)	Repayments of accounts receivable securitization facility			(243.5	)		(115.7	)
Proceeds from issuance of senior notes			—			1,700.0
Open market purchases of senior notes			(534.3	)		—		Open market purchases of senior notes			—			(534.3	)
Redemption of APL senior notes			—			(1,168.8	)
Redemption of senior notes								Redemption of senior notes			(287.6	)		—
Costs incurred in connection with financing arrangements			(7.5	)		(20.7	)	Costs incurred in connection with financing arrangements			—			(7.5	)
Proceeds from sale of common and preferred units			—			318.6
Repurchase of common units under compensation plans			(0.1	)		(5.2	)	Repurchase of common units under compensation plans			—			(0.1	)
Contributions from General Partner			23.8			60.1
Purchase of noncontrolling interests in subsidiary								Purchase of noncontrolling interests in subsidiary			(12.5	)		—
Contributions from general partner								Contributions from general partner			32.2			19.5
Contributions from TRC			1,167.2			—		Contributions from TRC			1,572.8			956.5
Contributions from noncontrolling interests			32.7			16.4		Contributions from noncontrolling interests			16.5			19.1
Distributions to noncontrolling interests								Distributions to noncontrolling interests			(21.4	)		(6.3	)
Distributions to unitholders			(542.6	)		(531.7	)	Distributions to unitholders			(407.7	)		(360.8	)
Payments of distribution equivalent rights			(0.3	)		(2.5	)	Payments of distribution equivalent rights			—			(0.3	)
Distributions to noncontrolling interests			(16.8	)		(8.7	)
Net cash provided by (used in) financing activities			(152.2	)		745.2		Net cash provided by (used in) financing activities			717.3			(133.5	)
Net change in cash and cash equivalents			(5.5	)		20.5		Net change in cash and cash equivalents			4.1			23.1
Cash and cash equivalents, beginning of period			135.4			72.3		Cash and cash equivalents, beginning of period			68.0			135.4
Cash and cash equivalents, end of period		$	129.9		$	92.8		Cash and cash equivalents, end of period		$	72.1		$	158.5

~~The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.~~ 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”~~“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 bypursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such ~~transaction,~~transactions, the “TRC/TRP Merger”), by and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“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 TRC/TRP Merger Agreement, Merger Sub merged with and into TRP ~~(the “TRC/TRP Merger”),~~ 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.

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 ~~will be~~became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the ~~IDRs~~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~~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.

Areas of gathering and processing operations include the Permian Basin in 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 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 assets are predominately located in Mont Belvieu and Galena Park, TX, Lake Charles, LA, and Tacoma, WA. See Note 1719 – Segment Information for certain financial information ~~for~~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~~six months ended ~~September~~June 30, ~~2016 and 2015,~~2017 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~~six months ended ~~September~~June 30, ~~2016~~2017 are not necessarily indicative of the results that may be expected for the full year.

As described in Note 4 – Business Acquisitions, the February 27, 2015 Atlas mergers involved two separate legal transactions involving different groups of equity holders. For GAAP reporting purposes, these two mergers are viewed as a single integrated transaction. As such, the financial effects of the Targa consideration related to the ATLS merger have been reflected in these financial statements. As further described in Note 4 – Business Acquisitions, our partnership agreement (the “Partnership Agreement”) was amended to provide for the issuance of the Special GP Interest in us equal to the tax basis of the APL GP Interests acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation.

~~Revisions of Previously Reported Activity in our Consolidated Statements of Comprehensive Income (Loss)~~

During the first quarter of 2016 we concluded that activity related to our commodity hedge contracts was not reported properly in our Consolidated Statements of Comprehensive Income (Loss) during 2015. The errors resulted in misstatements of the statement caption “Change in fair value” and equal offsetting misstatements of the caption “Settlements reclassified to revenues.” Related income tax effects were also misstated.

We concluded that these misstatements were not material to any of the periods affected, as reported “Total Other Comprehensive Income” is unchanged. However, we have revised previous Consolidated Statements of Comprehensive Income (Loss) reported during 2015 to properly reflect changes in fair value and settlements reclassified to revenues. There is no impact on previously reported net income, total comprehensive income, cash flows, financial position or other profitability measures.

The following table displays the impact of these revisions to activity reported in our Consolidated Statements of Comprehensive Income (Loss) during the three and nine months ended September 30, 2015 and the year ended December 31, 2015.

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 on Form 10-K.~~Report. There were no significant updates or revisions to our policies during the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2017, except as noted below.

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard 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 ~~retroactively~~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 ~~amendment~~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.

~~We expect to adopt these updates in their entirety on January 1, 2018, and are continuing to evaluate the impact on our revenue recognition practices.~~

In ~~February 2015,~~December 2016, the FASB issued ASU ~~2015-02,~~2016-20, ~~Consolidation (Topic 810): Amendments~~Technical Corrections and Improvements to ~~the Consolidation Analysis~~. The amendments are intended to simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities and modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities. The amendments were effective for us in 2016Topic 606, Revenue from Contracts with ~~no impact on our consolidated financial statements.~~

~~In April 2015, the FASB issued ASU 2015-03,~~ ~~Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs~~Customers. The amendments in this update ~~require that debt issuance costs related to a recognized debt liability (other than line-of-credit or other revolving credit facilities) be presented in~~clarify the ~~Consolidated Balance Sheet as a direct deduction~~disclosure requirements for performance obligations, provide optional exemptions from the ~~carrying amount~~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 ~~that debt liability, consistent with debt discounts. This update dealt solely with financial statement display matters;~~capitalized contract costs.

We expect to adopt this new revenue recognition ~~and measurement of debt issuance costs were unaffected. We adopted the amendments~~standard on January 1, ~~2016~~2018, presenting a cumulative effect adjustment in the period the standard is adopted. We also anticipate electing the practical expedient to apply the guidance retrospectively to only those contracts that are not completed contracts at the date of initial application. We have disaggregated contracts within our two segments and ~~have reclassified unamortized debt issuance costs~~are in the process of ~~$38.3 million on~~reviewing contracts and transaction types with counterparties in order to evaluate how the new standard would impact our ~~Consolidated Balance Sheet~~current revenue recognition and disclosure policies upon adoption. In addition, we are also evaluating the implications around principal versus agent considerations, as well as whether certain contracts within our gathering and processing segment create relationships with counterparties akin to suppliers or involve significant sharing of ~~December 31, 2015~~risks that would exclude such contracts from ~~Other long-term assets to Long-term debt to conform to current year presentation. Our Consolidated Balance Sheet as~~the scope of ~~September 30, 2016 has $29.4 million in unamortized debt issuance costs classified in Long-term debt.~~Topic 606.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, 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. We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.

~~In March 2016, the FASB issued ASU 2016-09,~~ ~~Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting~~. The amendments in this update provide, among other things, that (1) all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit in the income statement with the tax effects of exercised or vested awards treated as discrete items in the reporting period in which they occur and recognition of excess tax benefits regardless of whether the benefit reduces taxes payable in the current period; (2) excess tax benefits should be classified along with other income tax cash flows as an operating activity; (3) an entity can make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur; (4) the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and (5) cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a financing activity on the statement of cash flows. We adopted the applicable amendments in the second quarter of 2016; however there was no impact to our consolidated financial statements.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. These amendments 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 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. We expect to adopt this guidance on January 1, 2019, and are continuing to evaluate the impact on our measurement of credit losses.

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). These amendments clarify how entities should classify certain cash receipts and cash payments on 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. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The amendments in this update are intended to improve the accounting 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. The amendments 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. 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. 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 has the option to perform the qualitative assessment for a reporting unit to determine if 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 as of November 30, 2017, or earlier if events or changes in circumstances indicate that an interim goodwill impairment test is necessary.

In February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from 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 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. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of ~~the~~such amendments on our consolidated financial ~~statements and related disclosures.~~statements.

Stock Compensation – ~~Business Acquisitions~~Scope of Modification Accounting

~~On February 27, 2015, Targa completed the transactions contemplated by the Agreement and Plan~~In May 2017, FASB issued ASU 2017-09, Compensation—Stock Compensation (Topic 718): Scope of ~~Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”)~~Modification Accounting, by and among (i) Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of Targa (“GP Merger Sub”), Atlas Energy L.P., a Delaware limited partnership (“ATLS”) and Atlas Energy GP, LLC, a Delaware limited liability company and the general partner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the transactions contemplated by the Agreement and Plan of Merger (the “APL Merger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, the Partnership’s general partner, Trident MLP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of the Partnership (“MLP Merger Sub”), ATLS, Atlas Pipeline Partners L.P., a Delaware limited partnership (“APL”) and Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL (“APL GP”). Pursuantwhich 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 ~~conditions set forth~~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 second quarter of 2017 and will apply the new guidance prospectively to 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 ~~ATLS Merger Agreement, GP Merger Sub merged (the “ATLS merger”)~~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, 2018, with ~~and into ATLS, with ATLS continuing as~~early adoption permitted. We early adopted the ~~surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth~~applicable amendments in the ~~APL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APL continuing as the surviving entity and as~~second quarter of 2017 on a ~~subsidiary of the Partnership. While the Atlas mergers were two separate legal transactions, for GAAP reporting purposes, they are viewed as a single integrated transaction. As such, the~~retrospective basis noting no effect on our consolidated financial ~~effects of the ATLS Merger Consideration (as defined below) paid by Targa have been reflected in these financial~~ statements. ~~In connection with the Atlas mergers, APL changed its name to “Targa Pipeline Partners LP,” which we refer to as TPL, and ATLS changed its name to “Targa Energy LP.”~~

On March 1, 2017, we completed the ~~completion~~purchase of 100% of the ~~Atlas mergers, ATLS, pursuant to a separation~~membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and ~~distribution agreement entered into by and among ATLS, ATLS GP and Atlas Energy Group,~~Outrigger Midland Operating, LLC ~~a Delaware limited liability company~~ (“~~AEG”), on February 27, 2015, (i) transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro~~

~~rata distribution to the ATLS unitholders of AEG common units representing a 100% interest in AEG (collectively, the “Spin-Off”~~New Midland” and together with New Delaware, the ~~Atlas mergers, the “Atlas Transactions”~~“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 ~~Partnership Agreement was amended~~“initial purchase price”). Contributions from TRC were used to ~~provide for~~fund the ~~issuance~~cash portion of ~~a special general partner interest in~~ the ~~Partnership (the “Special GP Interest”) representing the contribution~~Permian Acquisition purchase price. Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the ~~Partnership~~sellers of ~~the APL GP interest acquired~~New Delaware and New Midland in ~~the ATLS merger totaling $1.6 billion, which is reflected within General partner equity~~potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from contracts that existed on the Consolidated Balance Sheets. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation.March 1, 2017.

We acquired all of the outstanding units of APL for a total purchase price of approximately $5.3 billion (including $1.8 billion of acquired debt and all other assumed liabilities). Of the $1.8 billion of debt acquired and other liabilities assumed, approximately $1.2 billion of the acquired debt was tendered and settled upon the closing of the Atlas mergers via our January 2015 cash tender offers. These tender offers were in connection with, and conditioned upon, the consummation of the merger with APL. The merger with APL, however, was not conditioned on the consummation of the tender offers. On that same date, Targa acquired ATLS for a total purchase price of approximately $1.6 billion (including all assumed liabilities).

Pursuant to the APL Merger Agreement, our general partner entered into an amendment to our Partnership Agreement, which we refer to as the IDR Giveback Amendment, in order to reduce aggregate distributions to TRC, as the holder of the Partnership’s ~~incentive distribution rights (“IDRs”)~~ by (a) $9,375,000 per quarter during the first four quarters following the APL merger, (b) $6,250,000 per quarter for the next four quarters, (c) $2,500,000 per quarter for the next four quarters and (d) $1,250,000 per quarter for the next four quarters, with the amount of such reductions to be distributed pro rata to the holders of our outstanding common units.

~~TPL is a provider of natural~~New Delaware’s gas gathering and processing and ~~treating services primarily in the Anadarko, Arkoma and Permian Basins~~crude gathering assets are located in ~~the southwestern~~Loving, Winkler, Pecos and ~~mid-continent regions of the United States and~~Ward counties in ~~the Eagle Ford Shale in South~~ Texas. The ~~Atlas mergers added TPL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian~~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 ~~to the Partnership’s existing operations. In total, TPL added 2,053~~include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the New Delaware system. Since March 1, 2017, financial and ~~12,220 miles~~statistical data of ~~additional pipeline.~~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 ~~operating results~~operations are backed by producer dedications of ~~TPL are reported in our Gathering and Processing segment.~~

~~The APL merger was a unit-for-unit transaction~~more than 105,000 acres under long-term, largely fee-based contracts, with an ~~exchange ratio~~average weighted contract life of ~~0.5846~~13 years. The New Midland assets include 10 MMcf/d of our common units (the “APL Unit Consideration”) and $1.26 in cash for each APL common unit (the “APL Cash Consideration” and, with the APL Unit Consideration, the “APL Merger Consideration”), a $128.0 million total cash payment,processing capacity. Currently, there is 40,000 Bbl/d of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion of retained employees’ APL phantom awards. We issued 58,614,157 of our common units and awarded 629,231 replacement phantom unit awards with a combined value of approximately $2.6 billion as consideration for the APL merger (basedcrude gathering capacity on the ~~$43.82 closing market price~~New Midland system. Since March 1, 2017, financial and statistical data of ~~a common unit on~~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 ~~NYSE on February 27, 2015). The cash component~~first quarter of 2017 and we expect that New Midland’s gas gathering and processing assets will be connected to our existing WestTX system during 2017. We believe connecting the ~~APL merger also included $701.4 million for the mandatory repayment~~acquired assets to our legacy Permian footprint creates operational and ~~extinguishment at closing of the APL Senior Secured Revolving Credit Facility that was to mature~~capital synergies, and will afford enhanced flexibility in May 2017 (the “APL Revolver”), $28.8 million of payments related to change of control and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March 2015, Targa contributed $52.4 million to us to maintain its 2% general partner interest.

In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the effective time of the APL merger.

The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS Stock Consideration”), and $9.12 in cash for each ATLS common unit (the ATLS Cash Consideration” and, with the ATLS Stock Consideration, the “ATLS Merger Consideration”), (a $514.7 million total cash payment). Targa issued 10,126,532 of its common shares and awarded 81,740 replacement restricted stock units with a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSE on February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million of payments related to change of control and cash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for reimbursement of certain transaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vesting of a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date.

~~ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Targa’s acquisition of ATLS resulted in Targa acquiring these common units (converted to 3,363,935 of~~serving our common units) valued at approximately $147.4 million (based on the $43.82 closing market price of our common units on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, which reduced the consolidated purchase price by approximately $154.7 million.producer customers.

All outstanding ATLS equity awards, whether vested or unvested, were adjusted in connection with the Spin-Off on the terms and conditions set forth in an Employee Matters Agreement entered into by ATLS, ATLS GP and AEG on February 27, 2015. Following the Spin-Off-related adjustment and at the effective time of the ATLS merger, each outstanding ATLS option and ATLS phantom unit award, whether vested or unvested, held by a person who became an employee of AEG became fully vested (to the extent not vested) and was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). Each outstanding vested ATLS option held by an employee of APL who became an employee of Targa in connection with the Atlas Transactions (a “Midstream Employee”) was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the vested ATLS option, net of the applicable exercise price. Each outstanding unvested ATLS option and each outstanding ATLS phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the ATLS Cash Consideration in respect of each ATLS common unit underlying such ATLS option or phantom unit award and (2) a TRC restricted stock unit award with respect to a number of shares of TRC Common Stock equal to the product of the ATLS Stock Consideration multiplied by the number of ATLS common units underlying such ATLS option or phantom unit award (in the case of options, net of the applicable exercise price).

In connection with the APL merger, each outstanding APL phantom unit award held by an employee of AEG became fully vested and was cancelled and converted into the right to receive the APL Merger Consideration in respect of each APL common unit underlying the APL phantom unit award. Each outstanding APL phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the APL Cash Consideration in respect of each APL common unit underlying such APL phantom unit award and (2) a Partnership phantom unit award with respect to a number of our common units equal to the product of the APL Unit Consideration multiplied by the number of APL common units underlying such APL phantom unit award.

The acquired ~~business~~businesses contributed revenues of ~~$1,065.7~~$36.4 million and a net loss of ~~$1.0~~$12.6 million to us for the period from ~~February 27, 2015~~March 1, 2017 to ~~September~~June 30, ~~2015,~~2017, and isare reported in our Gathering and Processing segment. As of ~~September~~June 30, ~~2015,~~2017, we had incurred ~~$19.3~~$5.2 million of acquisition-related costs. These expenses are included in ~~other~~Other expense in our Consolidated Statements of Operations for the ~~nine~~six months ended ~~September~~June 30, ~~2015. As of September 30, 2016, cumulative acquisition-related costs totaled $19.4 million.~~2017.

Pro Forma Impact of ~~Atlas Mergers~~Permian Acquisition on Consolidated Statement of Operations

The following summarized unaudited pro forma Consolidated Statement of Operations information for the ~~nine~~six months ended ~~September~~June 30, ~~2015~~2017 and June 30, 2016 assumes that ~~our acquisition of APL and Targa’s acquisition of ATLS had~~the Permian Acquisition occurred as of January 1, ~~2014.~~2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma ~~financial results~~information may not be indicative of the results that would have occurred ifhad we ~~had~~ completed ~~the APL merger~~this acquisition as of January 1, ~~2014,~~2016, or that ~~the results that will~~would be attained in the future. ~~Amounts presented below are in millions:~~

	September 30, 2015		June 30, 2017			June 30, 2016
	Pro Forma		Pro Forma			Pro Forma
Revenues	$	5,299.9	$	3,994.4		$	3,034.3
Net income		181.6
Net income (loss)				(52.3	)		(26.4	)

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

The following table summarizes the consideration transferred to acquire ~~ATLS~~New Delaware and ~~APL, which are viewed together as a single integrated transaction for GAAP reporting purposes:~~New Midland:

~~Our final fair value determination~~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 ~~Atlas mergers was~~Permian Acquisition were recorded at their fair values as ~~follows:~~of the closing date of March 1, 2017. The fair values below are preliminary and subject to revisions pending the finalization of our review of the valuation. These and other estimates are subject to change as additional information becomes available and is assessed by us. The preliminary fair value of the assets acquired and liabilities assumed at the acquisition date is shown below:

Fair value determination:	February 27, 2015			March 1, 2017
Trade and other current receivables, net	$	181.1		$	6.7
Other current assets		24.4			0.6
Assets from risk management activities		102.1
Property, plant and equipment		4,616.9			255.8
Investments in unconsolidated affiliates		214.5
Intangible assets		1,354.9			692.3
Other long-term assets		5.5
Current liabilities		(258.8	)		(14.1	)
Long-term debt		(1,573.3	)
Deferred income tax liabilities, net		(13.6	)
Other long-term liabilities		(119.1	)		(0.8	)
Total identifiable net assets		4,534.6			940.5
Noncontrolling interest in subsidiaries		(216.9	)
Current liabilities retained by Targa		(0.5	)
Goodwill		707.0			46.6
Total fair value of consideration transferred	$	5,024.2		$	987.1

~~During~~Under the ~~three months ended~~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. As of June 30, ~~2015, we recorded measurement-period adjustments~~2017, this determination is based on our preliminary valuation and is subject to ~~our acquisition date fair values due to~~revisions pending the ~~refinement~~finalization of our ~~valuation models, assumptions and inputs.~~review of the valuation. As a result, goodwill is also preliminary. The preliminary goodwill is attributable to expected operational and capital synergies. The goodwill is expected to be amortizable for tax purposes. The attribution of the ~~Consolidated Statement of Operations~~goodwill to reporting units for the ~~three months ended March 31, 2015 was retrospectively adjusted for~~purpose of required future impairment assessments will be completed in conjunction with our finalization of the impact of measurement-period adjustments to property, plant and equipment, intangible assets, and investments in unconsolidated affiliates. These adjustments resulted in a decrease in depreciation and amortization expense of $1.0 million, and an increase in equity earnings of $0.3 million from the amounts previously reported in our Form 10-Q for the quarter ended March 31, 2015.fair value determination.

During the three months ended September 30, 2015, we recorded additional measurement-period adjustments to our acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. In accordance with ASU 2015-16, we recognized these measurement-period adjustments in the third quarter of 2015, with the effect on the Consolidated Statements of Operations

~~resulting from the change to the provisional amounts calculated as if the acquisition had been completed at February 27, 2015. During the three months ended September 30, 2015, the acquisition date~~The preliminary fair value of ~~property, plant and equipment increased by $9.9~~assets acquired included trade receivables of $6.7 million, investments in unconsolidated affiliates increased by $5.5 million, intangible assets decreased by $5.0 million, current liabilities increased by $2.4 million, other assets decreased by $1.0 million, and other current assets decreased by $0.6 million,substantially all of which resulted in a decrease in goodwill of $6.4 million. These adjustments resulted in increased revenues of $0.6 million, a reduction of operating expenses of $1.9 million, depreciation and amortization expense of $0.1 million and equity losses of $0.1 million recorded in the three months ended September 30, 2015, which, under the prior accounting standard, would havehas been ~~reflected in previous reporting periods.~~subsequently collected.

During the three months ended December 31, 2015, we recorded additional measurement-period adjustments to our acquisition date fair values due to the refinement of our valuation models, assumptions and inputs, as well as adjustments to previously reported preliminary fair values as a result of our review procedures over the development and application of inputs, assumptions and calculations used in cash-flow based fair value measurements associated with business combinations not operating as designed (as previously disclosed in our 2015 Annual Report on Form 10-K). We recognized these adjustments in the fourth quarter of 2015, with the effect on the Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at February 27, 2015. During the three months ended December 31, 2015, the acquisition date fair value of intangible assets increased $155.9 million, noncontrolling interest in subsidiaries increased $103.5 million, other long-term liabilities increased $110.1 million, property, plant and equipment decreased by $86.2 million, investments in unconsolidated affiliates decreased by $5.2 million, deferred tax liabilities increased by $5.0 million, current liabilities increased by $1.3 million, other assets decreased by $0.1 million and other current assets decreased by $0.1 million, which resulted in an increase in goodwill of $155.6 million. These adjustments resulted in depreciation and amortization expenses of $2.0 million, a net decrease to interest expense of $26.2 million, equity earnings of $0.2 million, and a reduction of general and administrative expenses of $0.4 million, recorded in the three months ended December 31, 2015, which, under the prior accounting standard, would have been reflected in previous reporting periods.

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 1314 – 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 ~~excess~~measurement period adjustments are based upon information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of the ~~purchase price over~~amounts recognized at that date. We have recognized these measurement period adjustments in the current reporting period, with the effect on 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, ~~assets acquired was approximately $707.0~~increased by $0.4 million, which ~~was~~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 ~~as goodwill. The determination of goodwill is attributable to~~in the ~~workforce of the acquired business and the expected synergies with us and Targa. The goodwill is amortizable for tax purposes.~~three months ended June 30, 2017.

The fair value of assets acquired included trade receivables of $178.1 million. The gross amount due under contracts was $178.1 million, all of which was expected to be collectible. The fair value of assets acquired included other receivables of $3.0 million reported in current receivables and $4.5 million reported in other long-term assets related to a contractual settlement with a counterparty.

Other long-term liabilities acquired included $109.3 million related to mandatorily redeemable preferred interests held by our partner in two joint ventures (see Note 10 – Other Long-Term Liabilities).

A contingent consideration liability arising from potential earn-out payments in connection with the ~~contingent consideration for APL’s previous acquisition of a gas gathering system and related assets~~Permian Acquisition has been recognized at its preliminary fair value. ~~APL~~We agreed to pay up to an additional ~~$6.0~~$935.0 million ~~if certain volumes are achieved on the acquired gathering system within a specified time period.~~in potential earn-out payments that may occur in 2018 and 2019. The preliminary acquisition date fair value of the ~~remaining contingent payment is~~potential earn-out payments of $416.3 million was recorded within ~~other long term~~Other long-term liabilities on our Consolidated Balance Sheets. The range of the undiscounted amount that we could pay related to the remaining contingent payment is between $0.0 and $6.0 million. We finalized our acquisition analysis and modeling of this contingent liability during the three months ended June 30, 2015, which resulted in an acquisition date fair value of $4.2 million. Subsequent changesChanges in the fair value of this liability, excluding any measurement period adjustments of the acquisition date fair value, are included in earnings.

~~In connection with~~ During the ~~Atlas mergers,~~six months ended June 30, 2017, we ~~awarded replacement phantom units in accordance with and~~recognized $1.1 million as ~~required by the Atlas Merger Agreements to those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained~~

unchanged from the existing APL awards, and vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 33% per year over the original three year term.

Each replacement phantom unit will entitle the grantee to common stock of TRC on the vesting date and is an equity-settled award. The replacement phantom units include distribution equivalent rights (“DERs”). When we declare and pay cash distributions, the holders of replacement phantom units are entitled within 60 days to receive cash payment of DERs in an amount equal to the cash distributions the holders would have received if they were the holders of record on the record date of the number of our common unitsOther expense related to the ~~replacement phantom units.~~

~~The~~change in fair value of the ~~replacement phantom units was based on~~contingent consideration. See Note 14 – Fair Value Measurements for additional discussion of the ~~closing price of our units at the close of trading on February 27, 2015. The~~ fair value ~~was allocated between~~methodology.

As of June 30, 2017, the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award.

~~We recognized goodwill at a~~ fair value of ~~approximately $707.0~~the first potential earn-out payment of $40.6 million ~~associated with~~has been recorded as a component of accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. As of June 30, 2017, the ~~Atlas mergers as~~fair value of the second potential earn-out payment of $376.8 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets.

On May 9, 2017, we purchased all 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 preliminary adjustment to the base purchase price paid to Boardwalk at closing was an additional $4.7 million. Final adjustments and settlement will occur within 90 days of closing. As part of the acquisition ~~date on February 27, 2015. Goodwill~~(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 intend to move 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 a preliminary allocation of $51.5 million of property, plant and equipment, $8.5 million of intangible assets for customer contracts and $4.7 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.) the remaining 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 ~~attributed to the WestTX, SouthTX and SouthOK reporting units~~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 will continue to operate the Venice gathering system for up to four months after closing pursuant to a Transition Services Agreement with VGS.

As a result ~~any level~~ of ~~decrease~~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 ~~forecasted cash flows~~VGS net assets to its fair value. As such, the VGS divestiture had no impact on our net income for the three months ended June 30, 2017 and its primary impact was the removal of the VGS assets and liabilities from our Consolidated Balance Sheet.

Intangible assets consist of customer contracts and customer relationships acquired in the Permian and Flag City Acquisitions 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 ~~would likely result~~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.

The intangible assets acquired in the Permian Acquisition were recorded at a preliminary fair value of $692.3 million pending completion of final valuations. For the ~~reporting unit to fall below~~purposes of preparing the ~~carrying~~accompanying financial statements (which include four months of amortization of these intangible assets), we are amortizing these intangible assets over a 15-year life using the straight-line method. The amortization method and lives for the Permian Acquisition intangibles will be reviewed and possibly revised as we finalize the valuations over the upcoming months.

The intangible assets acquired in the Flag City Acquisition were recorded at a preliminary fair value of $8.5 million pending completion of the ~~reporting unit,~~final valuation. For the purposes of preparing the accompanying financial statements (which include two months of amortization of these intangible assets), we are amortizing these intangible assets over a 10-year life using the straight-line method. The amortization method and lives for the Flag City Acquisition intangibles will be reviewed and possibly revised as we finalize the valuation.

The intangible assets acquired in the Atlas mergers are being amortized over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could ~~result~~not be identified. Amortization expense attributable to our intangible assets 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, including the provisional Permian and Flag City valuations is approximately $188.4 million, $182.7 million, $171.7 million, $159.5 million and $149.6 million for each of the years 2017 through 2021.

The changes in ~~an impairment of that reporting unit’s goodwill.~~our intangible assets are as follows:

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. As of December 31, 2015, we had not completed our November 30, 2015 impairment assessment. Based on the results of that preliminary evaluation, we recorded a provisional goodwill impairment of $290.0 million during the fourth quarter of 2015. The provisional goodwill impairment reduced the carrying value of goodwill to $417.0 million on our Consolidated Balance Sheets as of December 31, 2015.

During the first quarter of 2016, we finalized our ~~evaluation of goodwill for~~2015 impairment assessment and recorded additional impairment expense of $24.0 million inon our Consolidated Statement of ~~Operations and reduced the carrying value of goodwill to $393.0 million on our Consolidated Balance Sheets.~~Operations. The impairment of goodwill iswas 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. Our evaluation as of November 30, 2015 utilized the income approach (a discounted cash flow analysis (“DCF”)) to estimate the fair values of our reporting units. The future cash flows for our reporting units are based on our estimates, at that time, of future revenues, income from operations and other factors, such as working capital and capital expenditures. We take into account current and expected industry and market conditions, commodity pricing and volumetric forecasts in the basins in which the reporting units operate. The discount rates used in our DCF analysis are based on a weighted average cost of capital determined from relevant market comparisons.

Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: a 75% interest in T2 LaSalle, a gas gathering company; a 50% interest in T2 Eagle Ford, a gas gathering company; and a 50% interest in T2 EF Cogen (“Cogen”), which owns a cogeneration facility, (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with the joint interest owners, which cover their costs of operations (excluding depreciation and amortization). 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 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 six months ended June 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 gathering 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 June 30, 2017, $26.9 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.

Accounts payable and accrued liabilities includes $42.9 million and $30.2 million of liabilities to creditors to whom we have issued checks that remain outstanding as of June 30, 2017 and December 31, 2016. The estimated current portion of the Permian Acquisition contingent consideration represents the fair value as of June 30, 2017, of the first potential earn-out payment that may occur in May 2018. The estimated remaining portion would be payable in May 2019 and is recorded within Other long-term liabilities on our Consolidated Balance Sheets.

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the six months ended June 30, 2017:

As of June 30, 2017, 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 June 30, 2017, there was $250.0 million outstanding under the Securitization Facility.

In June 2017, we redeemed our outstanding 6⅜% 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 on 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.

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 redemption will not be required until at least 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 June 30, 2017.

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

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., a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we will build and operate a 35,000 barrel per day crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 barrels of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 barrels per day 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 by the first half of 2018, and has an estimated total cost of approximately $140.0 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. The deferred revenue 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.

Deferred revenue also includes 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 assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. Because the gas contract amendment will require future performance by Targa, we have recorded the consideration received as deferred revenue. The deferred revenue related to this amendment is being recognized on a straight-line basis through the end of the agreement’s term in 2030.

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.

The ~~sustained decrease~~following table shows the changes in deferred revenue:

A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its preliminary fair value. We agreed to pay up to an additional $935.0 million in potential earn-out payments that may occur in 2018 and ~~uncertain outlook~~2019. The first potential earn-out payment would occur in ~~commodity prices~~May 2018 and ~~volumes have adversely impacted~~the second potential earn-out payment would occur in May 2019. The preliminary acquisition date fair value of the potential earn-out payments of $461.6 million was recorded within Other long-term liabilities on our ~~customers and their future capital and operating plans. A continued or prolonged~~Consolidated Balance Sheets as of March 31, 2017. During the second quarter of 2017, we recorded a measurement period adjustment to reduce the preliminary acquisition date fair value of ~~lower commodity prices could result in further deterioration of reporting unit fair values and~~the potential ~~further impairment charges related~~earn-out payment to ~~goodwill and property, plant and equipment. There were no impairment triggers identified or further impairment charges recognized~~$416.3 million. Subsequent changes in the ~~third quarter~~fair value of ~~2016.~~this liability, excluding any measurement period adjustments of the acquisition date fair value, are included in earnings.

For the four months ended June 30, 2017, we had an increase in the fair value of this liability of $1.1 million, bringing the total Permian Acquisition contingent consideration to $417.4 million. As of June 30, 2017, the fair value of the first potential earn-out payment of $40.6 million has been recorded as a component of accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. As of June 30, 2017, the fair value of the second potential earn-out payment of $376.8 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. See Note 14 – 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 available Partnership distributions on the Partnership’s common units after payment 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.

The following details the distributions declared or paid by us during the six months ended June 30, 2017:

Subsequent to December 1, 2016, the effective date of the Third A&R Partnership Agreement, no units will be issued for capital contributions to us, but all capital contributions will continue to be allocated 98% to the limited partner and 2% to the general partner. During the six months ended June 30, 2017, TRC made total capital contributions to us of $1,605.0 million.

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

Distributions on our 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 $5.6 million of distributions to the holders of preferred units (“Preferred Unitholders”) during the three and six months ended June 30, 2017. The Preferred Units are reported as noncontrolling interests in our financial statements.

On October 31, 2016, we executed a Membership Interest Sale and Purchase Agreement with Chevron U.S.A. Inc. to acquire their 37% membership interest in Versado Gas Processors, L.L.C. (“Versado”). Targa held a 63% controlling interest in Versado prior to this transaction and consolidated Versado. As we continue to control Versado, the change in our ownership interest will be accounted

~~for as an equity transaction and no gain or loss will be recognized in our Consolidated Statements of Operations as a result. See Note 15 – Contingencies.~~

Intangible assets consist of customer contracts and customer relationships acquired in the Atlas mergers in 2015 and our Badlands business 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.

The fair values of intangible assets acquired in the Atlas mergers have been recorded at a fair value of $1,354.9 million and are being amortized over a 20 year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. Amortization expense attributable to our intangible assets 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.

Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: 75% interest in T2 LaSalle; 50% interest in T2 Eagle Ford; and 50% interest in T2 EF Cogen (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. 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. Our maximum exposure to loss as a result of our involvement with the T2 Joint Ventures includes our equity investment, any additional capital contribution commitments, and our share of any operating expenses incurred by the T2 Joint Ventures.

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

The recorded value of the T2 Joint Ventures is based on fair values at the date of acquisition which results in an excess fair value of $36.7 million over the book value of the joint venture capital accounts as of September 30, 2016. This basis difference is attributable to depreciable tangible assets and is being amortized over the estimated useful lives of the underlying assets of 20 years on a straight-line basis and is included as a component of equity earnings. See Note 4 – Business Acquisitions for further information regarding the fair value determinations related to the Atlas mergers.

Accounts payable and accrued liabilities includes $23.4 million and $34.0 million of liabilities to creditors to whom we have issued checks that remain outstanding as of September 30, 2016 and December 31, 2015.

~~The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the nine months ended September 30, 2016:~~

~~As of September 30, 2016, we were in compliance with the covenants contained in our various debt agreements.~~

~~During the nine months ended September 30, 2016, we repurchased on the open market a portion of our outstanding senior notes (the “Senior Notes”) as follows:~~

We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. See “Subsequent Events – Issuance of Senior Notes and Concurrent Senior Notes Tender Offers” and “Subsequent Events – Note Redemptions.”

~~The following table shows the contractually scheduled maturities of our Senior Notes as of September 30, 2016, for five consecutive years, and in total thereafter:~~

In ~~October 2016, we issued $500.0 million of~~ ~~5⅛%~~ ~~Senior Notes due February 2025 and $500.0 million of~~ ~~5⅜%~~ ~~Senior Notes due February 2027 (collectively, the “2016 Senior Notes”), yielding net proceeds of approximately $496.2 million and $496.2 million, respectively. The 2016~~ ~~Senior~~ Notes have substantially similar terms and covenants as our other series of Senior Notes. The net proceeds from the offering of the 2016 Senior Notes (the “October 2016 Offering”), along with borrowings under the TRP Revolver were used to fund concurrent tender offers for certain other series of senior notes.

Concurrently with the October 2016 Offering, we commenced tender offers (the “Tender Offers”) to purchase for cash, subject to certain conditions, up to specified aggregate maximum purchase amounts of our 5% Senior Notes due January 2018 (the “5% Notes”), 6⅝~~% Senior Notes due October 2020 (the “6~~⅝~~% Notes”) and 6~~⅞~~% Senior Notes due February 2021 (the “6~~⅞~~% Notes” and together with the 5% Notes and 6~~⅝% Notes, the “Tender Notes”). The total consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that was tendered as of the early tender date of October 5, 2016. The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date.

As a result of the Tender Offers, we will record during the fourth quarter of 2016 a loss due to debt extinguishment of approximately $59.2 million comprised of the $41.8 million premium paid, the write-off of $5.8 million of debt issuance costs, $15.1 million of debt discounts and $3.5 million of debt premiums.

~~Subsequent to the closing of the Tender Offers in October 2016, we~~ ~~issued notices of full redemption (the “Note Redemptions”) to the trustees and noteholders of the 6⅝% Notes~~ ~~and the 6~~⅞~~% Notes for the note balances remaining after the Tender Offers. In addition, we issued notice of full redemption to the trustees of the 6⅝% APL Notes due October 2020. The redemption price for the~~ ~~6⅝% Notes and the 6⅝%~~ ~~APL Notes due October 2020 was 103.313% of the principal amount, while the redemption price for the 6~~⅞% Notes was 103.438% of the principal amount. The aggregate principal amount outstanding of all three series of notes totaling $146.2 million will be redeemed on November 15, 2016 for a total redemption payment of $151.1 million, excluding accrued interest. The redemption date for each series of notes is November 15, 2016. As a result of the Note Redemptions, we will record during the fourth quarter of 2016 a loss due to debt extinguishment of approximately $9.7 million comprised of the $4.9 million premium paid, the write-off of $1.1 million of debt issuance costs, $4.2 million of debt discounts and $0.5 million of debt premiums.

In October 2016, we entered into the Second Amendment and Restatement Agreement (the “Restatement”) to effectuate the Third Amended and Restated Credit Agreement (the “TRP Credit Agreement”). The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity date from OctoberJuly 2017, to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while our ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. The TRP Revolver continues to bear interest costs that are dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA, and the covenants also remained substantially the same. The TRP Credit Agreement designates TPL and certain of its subsidiaries as “Restricted Subsidiaries” and provides for certain changes to occur upon our receiving an investment grade credit rating from Moody’s or S&P, including the release of the security interests in all collateral at our request. As a result of the TRP Credit Agreement, during the fourth quarter of 2016, we will record a partial write-off of $0.9 million of debt issuance costs associated with the TRP Revolver as a result of a change in syndicate members under the TRP Revolver. The remaining deferred debt issuance costs associated with the TRP Revolver along with debt issuance costs incurred with this amendment will be amortized on a straight-line basis over the life of the TRP Revolver.

Subsequent to entering into the TRP Credit Agreement, we executed supplemental indentures relating to all of our outstanding series of Senior Notes to designate TPL and those subsidiaries as Restricted Subsidiaries under the TRP Credit Agreement as guarantors of such Senior Notes.

Our asset retirement obligations (“ARO”) primarily relate to certain gas gathering pipelines and processing facilities, and are included in our Consolidated Balance Sheets as a component of other long-term liabilities. The changes in our ARO are as follows:

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

On February 17, 2016, TRC completed the TRC/TRP Merger, indirectly acquiring all of the outstanding common units not already owned by TRC and its subsidiaries. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units.

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 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, our common units were delisted from the NYSE and deregistered under the Exchange Act and our common units are no longer publicly traded. Our 5,000,000 Preferred Units remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE.

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%.

~~The Preferred Units will, with respect to anticipated monthly distributions, rank:~~

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”) have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our Partnership Agreement. If we exercise (or a third party with our prior written consent exercises) our redemption rights relating to any Preferred Units, the holders of those Preferred Units will not have the conversion right described above with respect to the Preferred Units called for redemption. Holders of Preferred Units have no voting rights except for certain exceptions set forth in our Partnership Agreement.

We paid $8.4 million of distributions to Preferred Unitholders during the nine months ended September 30, 2016. We have accrued distributions to our Preferred Unitholders of $0.9 million for the nine months ended September 30, 2016.

~~On October 17, 2016,~~ the board of directors of our general partner declared a ~~monthly~~ cash distribution of $0.1875 per Preferred ~~Unit for October 2016.~~Unit. This distribution will be paid on ~~November~~August 15, ~~2016.~~2017.

During the nine months ended September 30, 2016, Targa made capital contributions to us of $1,191.0 million. Related to these capital contributions, we issued to Targa 58,621,036 common units, and Targa issued general partner units of 1,196,346 to maintain its 2% general partner interest.

The TRC/TRP Merger did not trigger the acceleration of any time-based vesting of any of our outstanding long-term equity incentive compensation awards under the Targa Resource Partners Long-Term Incentive Plan. Upon completion of the TRC/TRP Merger, on February 17, 2016, Targa assumed, adopted and amended the Targa Resource Partners Long-Term Incentive Plan (“TRP LTIP”), and has changed the name of the plan to the Targa Resources Corp. Equity Compensation Plan (the “Plan”). All outstanding performance unit awards previously granted under the TRP LTIP, were converted and restated into comparable awards based on Targa’s common shares. Specifically, each outstanding performance unit award was converted and restated, effective as of the effective time of the TRC/TRP Merger, into an award to acquire, pursuant to the same time-based vesting schedule and forfeiture and termination provisions, a comparable number of Targa common shares determined by multiplying the number of performance units subject to each award by the exchange ratio in the TRC/TRP Merger (0.62), rounded down to the nearest whole share. The performance factor has been eliminated as it was based on the performance of our common units versus peer MLPs. All amounts previously credited as distribution equivalent rights under any outstanding performance unit award continue to remain so credited and will be payable on the payment date set forth in the applicable award agreement, subject to the same time-based vesting schedule previously included in the performance unit award, but without application of any performance factor.

The conversion on February 17, 2016 of outstanding equity-settled performance units and replacement phantom units outstanding to equity-settled restricted stock units and replacement phantom shares was considered modification of awards under ASC 718, ~~Accounting for Stock-Based Compensation~~ (“ASC 718”). The incremental change of $3.9 million in fair value between the original grant date fair value and the fair value as of February 17, 2016 will be recognized prospectively in general and administrative expense over the remaining service period of each award.

The conversion on February 17, 2016 of outstanding cash-settled performance units outstanding to cash-settled restricted stock units was considered modification of awards under ASC 718. The incremental change in fair value between the original grant date fair value and the fair value as of February 17, 2016 resulted in recognition of additional compensation costs during the first quarter of $4.8 million. The remaining compensation cost will be recognized in general and administrative expense over the remaining service period of each award.

In accordance with the Partnership Agreement, the Partnership must distribute all of its available cash, as defined in the Partnership Agreement, and as determined by the general partner, to Preferred Unitholders monthly and to common unitholders of record within 45 days after the end of each quarter. As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. The following details the distributions declared or paid by the Partnership, net of the IDR Giveback, during 2016:

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 ~~segment and (ii) NGL and condensate equity volumes predominately in our Gathering and Processing segment~~operations that result from percent-of-proceeds processing ~~arrangements.~~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 ~~necessarily~~ 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 ~~APL~~TPL derivative contracts with a fair value of $102.1 million as of ~~the acquisition date~~February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. ~~Derivative~~We received derivative settlements of ~~$67.9~~$1.9 million and ~~$20.9~~$4.9 million for the three and six months ended June 30, 2017 and $6.3 million and $15.1 million for the three and six months ended June 30, 2016, related to these novated contracts. From the acquisition date through June 30, 2017, we have received derivative settlements of $99.5 million. The remainder of the novated contracts ~~were received during~~will settle by the ~~year ended December 31, 2015~~ ~~and the nine months ended September 30, 2016.~~ end of 2017. These settlements were reflected as a reduction of the acquisition date fair value of the ~~APL~~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 gains (losses) of less than $(0.1) million and $0.1 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016, we recorded $0.3~~2017 and $(0.2) million and ~~$0.5~~less than $0.1 million ~~of ineffectiveness losses~~for the three and six months ended June 30, 2016, related to otherwise qualifying ~~APL~~TPL derivatives, which are primarily natural gas swaps.

~~At September 30, 2016, the notional volumes of our commodity derivative contracts were:~~

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

At June 30, 2017, the notional volumes of our commodity derivative contracts were:

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 in 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, 2016				Fair Value as of December 31, 2015					Fair Value as of June 30, 2017				Fair Value as of December 31, 2016
	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	$	34.7	$	12.8	$	92.1	$	2.1	Current	$	35.4	$	8.6	$	16.7	$	48.6
	Long-term		12.4		17.6		34.9		2.4	Long-term		17.3		5.5		5.1		26.1
Total derivatives designated as hedging instruments		$	47.1	$	30.4	$	127.0	$	4.5		$	52.7	$	14.1	$	21.8	$	74.7
Derivatives not designated as hedging instruments
Commodity contracts	Current	$	0.1	$	0.2	$	0.1	$	3.1	Current	$	0.3	$	0.9	$	0.1	$	0.5
Total derivatives not designated as hedging instruments		$	0.1	$	0.2	$	0.1	$	3.1		$	0.3	$	0.9	$	0.1	$	0.5
Total current position		$	34.8	$	13.0	$	92.2	$	5.2		$	35.7	$	9.5	$	16.8	$	49.1
Total long-term position			12.4		17.6		34.9		2.4			17.3		5.5		5.1		26.1
Total derivatives		$	47.2	$	30.6	$	127.1	$	7.6		$	53.0	$	15.0	$	21.9	$	75.2

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

		Gross Presentation				Pro forma net presentation					Gross Presentation								Pro forma net presentation
December 31, 2015		Asset		Liability		Asset		Liability
June 30, 2017										June 30, 2017	Asset		Liability			Collateral			Asset		Liability
Current Position	Current Position									Current Position
	Counterparties with offsetting positions	$	86.9	$	5.2	$	81.7	$	-	Counterparties with offsetting positions or collateral	$	34.6	$	(9.2	)	$	(5.5	)	$	26.0	$	(6.1	)
	Counterparties without offsetting positions - assets		5.3		-		5.3		-	Counterparties without offsetting positions - assets		1.1		-			-			1.1		-
	Counterparties without offsetting positions - liabilities		-		-		-		-	Counterparties without offsetting positions - liabilities		-		(0.3	)		-			-		(0.3	)
			92.2		5.2		87.0		-			35.7		(9.5	)		(5.5	)		27.1		(6.4	)
Long Term Position	Long Term Position									Long Term Position
	Counterparties with offsetting positions		34.2		2.4		31.8		-	Counterparties with offsetting positions or collateral		16.5		(4.6	)		-			11.9		-
	Counterparties without offsetting positions - assets		0.7		-		0.7		-	Counterparties without offsetting positions - assets		0.8		-			-			0.8		-
	Counterparties without offsetting positions - liabilities		-		-		-		-	Counterparties without offsetting positions - liabilities		-		(0.9	)		-			-		(0.9	)
			34.9		2.4		32.5		-			17.3		(5.5	)		-			12.7		(0.9	)
Total Derivatives	Total Derivatives									Total Derivatives
	Counterparties with offsetting positions		121.1		7.6		113.5		-	Counterparties with offsetting positions or collateral		51.1		(13.8	)		(5.5	)		37.9		(6.1	)
	Counterparties without offsetting positions - assets		6.0		-		6.0		-	Counterparties without offsetting positions - assets		1.9		-			-			1.9		-
	Counterparties without offsetting positions - liabilities		-		-		-		-	Counterparties without offsetting positions - liabilities		-		(1.2	)		-			-		(1.2	)
		$	127.1	$	7.6	$	119.5	$	-		$	53.0	$	(15.0	)	$	(5.5	)	$	39.8	$	(7.3	)

											Gross Presentation								Pro forma net presentation
December 31, 2016										December 31, 2016	Asset		Liability			Collateral			Asset		Liability
Current Position										Current Position
										Counterparties with offsetting positions or collateral	$	16.8	$	(46.1	)	$	7.0		$	5.7	$	(28.0	)
										Counterparties without offsetting positions - assets		-		-			-			-		-
										Counterparties without offsetting positions - liabilities		-		(3.0	)		-			-		(3.0	)
												16.8		(49.1	)		7.0			5.7		(31.0	)
Long Term Position										Long Term Position
										Counterparties with offsetting positions or collateral		5.1		(18.7	)		-			-		(13.6	)
										Counterparties without offsetting positions - assets		-		-			-			-		-
										Counterparties without offsetting positions - liabilities		-		(7.4	)		-			-		(7.4	)
												5.1		(26.1	)		-			-		(21.0	)
Total Derivatives										Total Derivatives
										Counterparties with offsetting positions or collateral		21.9		(64.8	)		7.0			5.7		(41.6	)
										Counterparties without offsetting positions - assets		-		-			-			-		-
										Counterparties without offsetting positions - liabilities		-		(10.4	)		-			-		(10.4	)
											$	21.9	$	(75.2	)	$	7.0		$	5.7	$	(52.0	)

Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the ~~Partnership’s senior secured indebtedness~~TRP Revolver that ranks equal in right of payment with liens granted in favor of ~~its~~our senior secured lenders. Some of our hedges are futures contracts executed through a broker that clears the hedges through an exchange. OnWe maintain a

~~daily basis, our cash balance~~ margin deposit with the broker ~~is used~~in an amount sufficient enough to ~~offset~~cover the fair value of our open futures positions. The ~~net of our cash on~~margin deposit ~~and open futures positions~~is considered collateral, which is located within other current assets on our Consolidated Balance Sheets ~~as a broker receivable.~~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 asset of ~~$16.6~~$38.0 million as of ~~September~~June 30, ~~2016.~~2017. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year 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 ~~settled~~margined daily and do not require any credit adjustment.

The following tables reflect amounts recorded in Other Comprehensive Income ~~(“OCI”)~~ and amounts reclassified from OCI to revenue 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 June 30,					Six Months Ended June 30,
Hedging Relationships	2016		2015		2016			2015		2017		2016			2017		2016
Commodity contracts	$	12.9	$	50.7	$	(40.5	)	$	77.6	$	29.8	$	(60.2	)	$	96.0	$	(53.5	)

	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 June 30,				Six Months Ended June 30,
Location of Gain (Loss)	2016		2015		2016		2015		2017		2016		2017			2016
Revenues	$	8.1	$	24.5	$	50.6	$	59.3	$	5.7	$	18.3	$	(0.4	)	$	42.4

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 June 30,						Six Months Ended June 30,
as Hedging Instruments	Derivatives	2016			2015			2016		2015			Derivatives	2017			2016			2017			2016
Commodity contracts	Revenue	$	(0.3	)	$	(4.0	)	$	1.3	$	(0.9	)	Revenue	$	(0.3	)	$	(0.3	)	$	(1.0	)	$	1.6

~~The following table shows the~~Based on valuations as of June 30, 2017, we expect to reclassify commodity hedge related deferred gains ~~(losses)~~of $35.4 million included in accumulated ~~OCI, which will be reclassified~~other comprehensive income into earnings before income taxes through the end of 2019, ~~based on valuations as~~with $23.7 million of gains to be reclassified over the ~~balance sheet date:~~next twelve months.

See Note 1314 – Fair Value Measurements 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 in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in 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~~June 30, ~~2016,~~2017, a net asset position of ~~$16.6~~$38.0 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 ~~$27.7~~$31.1 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of ~~$61.4~~$107.7 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:

~~We have a contingent~~Contingent consideration ~~liability for APL’s previous acquisition of a gas gathering system and~~liabilities related ~~assets, which is~~to business acquisitions are carried at fair ~~value (see Note 4 – Business Acquisitions).~~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 in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:

		September 30, 2016																June 30, 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:
Assets from commodity derivative contracts (1)		$	46.3		$	46.3		$	—		$	44.0		$	2.3	Assets from commodity derivative contracts (1)		$	51.1		$	51.1		$	—		$	45.5		$	5.6
Liabilities from commodity derivative contracts (1)			29.7			29.7			—			27.3			2.4	Liabilities from commodity derivative contracts (1)			13.1			13.1			—			11.0			2.1
TPL contingent consideration (2)			2.7			2.7			—			—			2.7
Permian Acquisition contingent consideration (2)																			417.4			417.4			—			—			417.4
TPL contingent consideration (3)																TPL contingent consideration (3)			2.7			2.7			—			—			2.7
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			129.9			129.9			—			—			—	Cash and cash equivalents			72.1			72.1			—			—			—
TRP Revolver			—			—			—			—			—	TRP Revolver			—			—			—			—			—
Senior unsecured notes			4,326.5			4,447.8			—			4,447.8			—	Senior unsecured notes			3,778.5			3,869.7			—			3,869.7			—
Accounts receivable securitization facility			225.0			225.0			—			225.0			—	Accounts receivable securitization facility			250.0			250.0			—			250.0			—

	December 31, 2015																December 31, 2016
				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:
Assets from commodity derivative contracts (1)		$	127.1		$	127.1		$	—		$	123.1		$	4.0	Assets from commodity derivative contracts (1)		$	21.0		$	21.0		$	—		$	19.6		$	1.4
Liabilities from commodity derivative contracts (1)			7.6			7.6			—			7.3			0.3	Liabilities from commodity derivative contracts (1)			74.2			74.2			—			69.3			4.9
TPL contingent consideration (2)			3.0			3.0			—			—			3.0
TPL contingent consideration (3)																TPL contingent consideration (3)			2.6			2.6			—			—			2.6
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			135.4			135.4			—			—			—	Cash and cash equivalents			68.0			68.0			—			—			—
TRP Revolver			280.0			280.0			—			280.0			—	TRP Revolver			150.0			150.0			—			150.0			—
Senior unsecured notes			4,884.0			4,192.0			—			4,192.0			—	Senior unsecured notes			4,057.3			4,101.6			—			4,101.6			—
Accounts receivable securitization facility			219.3			219.3			—			219.3			—	Accounts receivable securitization facility			275.0			275.0			—			275.0			—

Additional Information Regarding Level 3 Fair Value Measurements Included in 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~~June 30, ~~2016,~~2017, we had 2127 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. ~~These probability-based~~The inputs for both models are not observable; therefore, the entire ~~valuation~~valuations of the contingent ~~consideration is~~considerations are categorized in Level 3. Changes in the fair value of ~~this liability~~these liabilities are included in Other ~~Income~~income (expense) on the 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:

For the nine months ended September 30, 2016, we had no transfers of financial instruments out of Level 3 and into Level 2. Historically, transfers relate to long-term over-the-counter swaps for natural gas and NGL products with deliveries for which observable market prices were available.

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 June 30,				Six Months Ended June 30,
	2016		2015		2016		2015		2017		2016		2017		2016
Targa billings of payroll and related costs included in operating expense	$	42.6	$	41.4	$	125.0	$	118.3	$	47.6	$	42.2	$	94.6	$	82.5
Targa allocation of general and administrative expense		40.1		39.4		117.7		118.3		41.5		37.6		83.6		77.6
Cash distributions to Targa based on IDR and unit ownership		178.9		61.4		395.1		172.0
Cash contributions from Targa for issuance of common units		210.7		—		1,167.2		—
Cash distributions to Targa based on IDR, general partner and limited partner ownership (1)										206.8		154.8		402.1		216.2
Cash contributions from Targa related to limited partner ownership (2)										930.9		171.5		1,572.8		956.5
Cash contributions from Targa to maintain its 2% general partner ownership		4.3		1.4		23.8		60.1		19.1		3.5		32.2		19.5

On December 16, 2015, two purported unitholders of TRP (the “State Court Plaintiffs”) filed a putative class action and derivative lawsuit challenging the TRC/TRP Merger against TRC, TRP (as a nominal defendant), TRP GP, the members of the board of TRP GP (the “TRP GP Board”) and Merger Sub (collectively, the “State Court Defendants”). This lawsuit is styled ~~Leslie Blumberg et al. v. TRC Resources Corp., et al., Cause No. 2015-75481, in the 234~~^th ~~Judicial District Court of Harris County, Texas (the “State Court Lawsuit”). The State Court Plaintiffs amended the State Court Lawsuit on July 26, 2016.~~

The State Court Plaintiffs allege several causes of action challenging the TRC/TRP Merger. Generally, the State Court Plaintiffs allege that (i) the members of the TRP GP Board breached express and/or implied duties under the Partnership Agreement and (ii) TRC, TRP GP, and Merger Sub aided and abetted in these alleged breaches of duties. The State Court Plaintiffs further allege, in general, that (a)

the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair, (e) the TRP GP Board had conflicts of interest due to TRC’s control of TRP GP, (f) the TRP GP Conflicts Committee’s financial advisor was conflicted and conducted flawed analyses, and (g) the joint proxy statement/prospectus filed in connection with the TRC/TRP Merger (the “Proxy”) failed to disclose allegedly material information concerning, among other things, (i) the TRC and TRP projections included in the Proxy, and (ii) the analyses conducted by the TRP GP Conflicts Committee’s financial advisor in connection with the TRC/TRP Merger.

Based on these allegations, the State Court Plaintiffs seek damages and attorneys’ fees. On February 26 and 29, 2016, the State Court Defendants filed general denials and asserted affirmative defenses. On August 26, 2016, the State Court Defendants filed Special Exceptions and a Motion for Summary Judgment seeking to have the State Court Lawsuit dismissed in its entirety with prejudice. The

~~Special Exceptions and Motion for Summary Judgment are pending before the Court.~~

The State Court Defendants cannot predict the outcome of this or any other lawsuits that might be filed subsequent to the date of the filing of this report, nor can the State Court Defendants predict the amount of time and expense that will be required to resolve such litigation. The State Court Defendants believe the State Court Lawsuit is without merit and intend to defend vigorously against this lawsuit and any other actions that challenge the TRC/TRP Merger.

On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014. The Monument Gas Plant is owned and operated by Versado Gas Processors, L.L.C., which was a joint venture in which we owned a 63% interest and Targa Midstream Services LLC served as operator until October 31, 2016, when we acquired the remaining 37% membership interest from Chevron U.S.A Inc. The Partnership is in discussions with the New Mexico Environment Department to resolve the alleged violations. The Partnership anticipates that this matter could result in a monetary sanction in excess of $100,000 but less than $300,000.

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

We operate in two primary ~~segments (previously referred to as divisions):~~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. Concurrent with the completion of the TRC/TRP Merger in the first quarter of 2016, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of aggregation for our reportable segments. The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream ~~Business~~ and its leadership by a consolidated executive management team. The Gathering and Processing division was previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing. The Logistics and Marketing division (also referred to as the Downstream Business) was previously disaggregated into two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution.

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 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.

~~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.~~

Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington.

Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating 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.

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

~~The following table shows a reconciliation of operating margin to net income (loss) for the periods presented:~~

~~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, 2015 (“Annual Report”), as well as the unaudited consolidated financial statements and Notes hereto included in this Quarterly Report on Form 10-Q.

Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by TRC. Our common units were listed on the NYSE under the symbol “NGLS.” Our Preferred Units are listed 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 of our outstanding common units.

We are a leading United States provider of midstream natural gas and NGL services, with a growing presence in crude oil gathering and petroleum terminaling. Our common units were listed on the NYSE under the symbol “NGLS” prior to TRC's acquisition on February 17, 2016 of all of 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.”

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

Concurrent with the TRC/TRP Merger, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of disclosure. The Gathering and Processing division was previously disaggregated into two reportable segments—(a) Field Gathering and Processing and (b) Coastal Gathering and Processing. The Logistics and Marketing division (also referred to as the Downstream Business) was previously disaggregated into two reportable segments—(a) Logistics Assets and (b) Marketing and Distribution. The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business and its leadership by a consolidated executive management team.

Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage 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.

~~The~~ Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing ~~operations~~segment and are predominantly located in Mont Belvieu and Galena Park, ~~Texas,~~Texas; Lake Charles, Louisiana and Tacoma, Washington.

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

The following table shows a reconciliation of operating margin to net income (loss) for the periods presented:

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

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

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 necessary to convert mixed NGLs into NGL products and provides certain 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.

Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segment and are predominantly located in Mont Belvieu and Galena Park, Texas; Lake Charles, Louisiana and Tacoma, Washington.

Other contains the results (including any hedge ineffectiveness) of our commodity derivative activities ~~which~~that are included in operating margin.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and natural gas reserves. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Prices of oil and natural gas have been volatile, and we expect this volatility to continue. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related reduced activity levels from our customers. Beginning in the fourth quarter of 2014, oil and natural gas prices declined significantly primarily due to global supply and demand imbalances. Oil and natural gas prices continued to decline in 2015 and have remained depressed in 2016 as compared to 2014 levels.

In June 2016, we commissioned an additional fractionator, Train 5, at our 88%-owned Cedar Bayou Fractionator (“CBF”) in Mont Belvieu, Texas. This expansion added 100 MBbl/d of fractionation capacity at CBF, and is fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network of connections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park on the Houston Ship Channel. The gross cost of Train 5 was approximately $328 million (our net cost was approximately $297 million).

On December 27, 2015, we and Noble entered into the Splitter Agreement under which we will build and operate a 35,000 barrel per day crude and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”). The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of crude 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 is expected to be completed by early 2018, and has an estimated total cost of approximately $140 million. As contemplated by the December 2014 Agreement, the Splitter Agreement completes and terminates the December 2014 Agreement, while retaining our economic benefits from that agreement. The first annual payment due under the Splitter Agreement was received in October 2016 and will be reflected as deferred revenue as a component of Other long-term liabilities on our Consolidated Balance Sheet.

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 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 may occur in 2018 and 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. 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 an uninstalled 60 MMcf/d plant, known as the Oahu Plant, which we are in the process of installing in the Delaware Basin ~~Buffalo Plant~~with expectations of commencing operations in late 2017. Currently, there is 40,000 Bbl/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 40,000 Bbl/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 we expect that New Midland's gas gathering and processing assets will be connected to our existing WestTX system during 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.

In ~~April~~November 2016, we ~~commenced commercial operations~~announced plans 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 a new 200 MMcf/d cryogenic processing plant, known as the ~~Buffalo Plant,~~Johnson plant, which is expected to begin operations in ~~our WestTX system. This project also included~~ the ~~laying~~third quarter of ~~new high and low pressure gathering lines in Martin and Andrews counties of Texas. Total~~2018. We expect total net growth capital expenditures for the ~~Buffalo~~Johnson Plant ~~were~~to be approximately ~~$140 million (our~~$100 million.

Also in May 2017, we announced plans to build a new plant and expand the gathering footprint of our Permian Delaware system in the Delaware Basin. 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. We expect total net growth capital expenditures ~~were~~for the Wildcat Plant to be approximately $102 million). The addition of the Buffalo Plant will enable us to meet increasing production from our joint venture partner in WestTX, Pioneer (the largest active driller in the Spraberry and Wolfberry Trends), and from other producers in the area.$130 million.

In October 2015, we announced that we had entered into ~~joint venture agreements~~the Carnero Joint Ventures with Sanchez Energy Corporation (“Sanchez”) to construct ~~a new 200MMcf/~~the 200 MMcf/d ~~cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Plant”)~~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. ~~("SPP")~~, and in ~~October~~November 2016, ~~announced an agreement to sell~~sold its interest in the processing joint venture to ~~SPP. We~~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 ~~Sanchez's~~SNMP's Catarina gathering system to the plant. We hold ~~a portion of~~ the ~~transportation~~ capacity on the ~~pipeline,~~high pressure gathering pipelines, and pay the gathering joint venture ~~receives~~ fees for transportation. ~~We expect to invest approximately $125 million of growth capital expenditures related to the joint ventures.~~

The Raptor Plant ~~will accommodate~~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 of the Raptor Plant to 260 MMcf/d, which we expect to be completed in the third 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 ~~lines~~pipelines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We ~~will~~ manage ~~construction and~~ operations of the ~~plant and~~ high pressure gathering lines and the ~~plant is expected to begin operations in early 2017.~~plant. Prior to the plant being placed in service, we ~~benefit~~benefited from Sanchez natural gas volumes that ~~are~~were processed at our Silver Oak facilities in Bee County, Texas.

~~Additional WestTX System~~Eagle Ford Shale Acquisition of Flag City Natural Gas Processing ~~Capacity~~Plant

In ~~November 2016,~~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 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 will continue to operate the Venice gathering system for up to four months after closing pursuant to a Transition Services Agreement with VGS.

On May 25, 2017, we announced plans to restart the currently idled 45 MMcf/d Benedum cryogenic processing plant in our WestTX system. The Benedum Plant was idled in September 2014 after the start-up of the 200 MMcf/d Edward Plant. Also in November 2016, we announced plans to buildconstruct a new ~~200 MMcf/d cryogenic processing~~common carrier NGL pipeline (“Grand Prix”), which will transport volumes from the Permian Basin and from our North Texas system to our fractionation and storage complex in the NGL market hub at Mont Belvieu. Grand Prix will be supported by our plant ~~in WestTX. The new plant~~volumes and other third party customer commitments, and is expected to be ~~completed by~~in service in the ~~end~~second quarter of ~~2017. Also in November 2016, we announced that we were adding 20 MMcf/~~2019. The initial capacity of the pipeline from the Permian Basin will be approximately 300 MBbl/d and will be expandable to 550 MBbl/d with the addition of ~~capacity at our Midkiff plant, increasing overall plant capacity from 60 MMcf/d to 80 MMcf/d.~~

~~In addition to the major projects noted above, we have other~~pump stations. We expect total net growth capital expenditures for Grand Prix to be approximately $1.3 billion, with approximately $330 million of spending in 2016 related to the continued build out of our gathering and processing infrastructure and logistics capabilities. On October 31, 2016, we acquired the remaining 37% membership interest in Versado Gas Processors, L.L.C. from Chevron U.S.A. Inc. In the current environment, we will continue to evaluate other potential projects based on return profile, capital requirements and strategic need and may choose to defer projects depending on expected activity levels.2017.

~~During~~On February 23, 2017, we amended our account receivable securitization facility (“Securitization Facility”) to increase the ~~nine months ended September 30, 2016, we repurchased a portion of our outstanding senior notes on the open market, paying $534.3~~facility size to $350.0 million ~~plus accrued interest to repurchase $559.2 million of the notes. The repurchases resulted in a $21.4 million net gain, which included the write-off of $3.5 million in related debt issuance costs.~~from $275.0 million.

In October 2016, we issued $500.0 million of 5⅛% Senior Notes due February 2025 and $500.0 million of 5⅜% Senior Notes due February 2027 (collectively, the “2016 Senior Notes”), yielding net proceeds of approximately $496.2 million and $496.2 million, respectively. The net proceeds from the offering of the 2016 Senior Notes (the “October 2016 Offering”), along with borrowings under the TRP Revolver were used to fund concurrent tender offers for other series of senior notes.

Concurrently with the October 2016 offering, we commenced tender offers (the “Tender Offers”) to purchase for cash, subject to certain conditions, up to specified aggregate maximum purchase amounts of our 5% Senior Notes due January 2018 (the “5% Notes”), 6⅝% Senior Notes due October 2020 (the “6⅝% Notes”) and 6⅞% Senior Notes due February 2021 (the “6⅞% Notes” and together with the 5% Notes and 6⅝% Notes, the “Tender Notes”). The total consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that was tendered as of the early tender date of October 5, 2016. The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date.

Subsequent to the closing of the Tender Offers in October 2016, we issued notices of full redemption to the trustees and noteholders of the 6⅝% Notes and the 6⅞% Notes for the note balances remaining after the Tender Offers. In addition,May 2017, we issued notice of full redemption to the ~~trustees~~trustee of ~~the 6⅝~~our 6⅜% ~~APL~~Senior Notes due ~~October 2020.~~August 2022 (“6⅜% Senior Notes”). The redemption price ~~for the 6⅝% Notes and the 6⅝% APL Notes due October 2020~~ was ~~103.313% of the principal amount, while the redemption price for the 6⅞% Notes was 103.438%~~103.188% of the principal amount. The ~~aggregate~~$278.7 million principal amount outstanding ~~of all three series of notes totaling $146.2 million will be~~was redeemed on ~~November 15, 2016~~June 26, 2017 for a total redemption payment of ~~$151.1~~$287.6 million, excluding accrued interest.

Subsequent to entering into the TRP Credit Agreement, we executed supplemental indentures relating to all of our outstanding series of Senior Notes to designate the TPL subsidiaries as Restricted Subsidiaries under the TRP Credit Agreement as guarantors of the Senior Notes.

~~In May 2014, the Financial~~For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting ~~Standards Board ("FASB") issued~~Pronouncements” included within Note 3 – Significant Accounting ~~Standard Update (“ASU”) No. 2014-09,~~ ~~Revenue from Contracts with Customers (Topic 606), which supersedes the revenue recognition requirements~~Policies 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 identifying the contracts with customers, identifying the performance obligations in the contracts, determining the transaction price, allocating the transaction price to the performance obligations, and 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 retroactively 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 amendment 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.

~~We expect to adopt these updates in their entirety on January 1, 2018, and are continuing to evaluate the impact on our revenue recognition practices.~~

~~In February 2015, the FASB issued ASU 2015-02,~~ ~~Consolidation (Topic 810): Amendments to the Consolidation Analysis~~. The amendments are intended to simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities and modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities. The amendments were effective for us in 2016 with no impact on our consolidated financial statements.

~~In April 2015, the FASB issued ASU 2015-03,~~ ~~Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs~~. The amendments in this update require that debt issuance costs related to a recognized debt liability (other than line-of-credit or other revolving credit facilities) be presented in the Consolidated Balance Sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update dealt solely with financial statement display matters; recognition and measurement of debt issuance costs were unaffected. We adopted the amendments on January 1, 2016 and have reclassified unamortized debt issuance costs of $38.3 million on our Consolidated Balance Sheet as of December 31, 2015 from Other long-term assets to Long-term debt to conform to current year presentation. Our Consolidated Balance Sheet as of September 30, 2016 has $29.4 million in unamortized debt issuance costs classified in Long-term debt.

~~In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases (Topic 842)~~. The amendments in this update require, among other things, 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. ~~We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.~~

~~In March 2016, the FASB issued ASU 2016-09,~~ ~~Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting~~. The amendments in this update provides, among other things, that (1) all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit in the income statement with the tax effects of exercised or vested awards treated as discrete items in the reporting period in which they occur and recognition of excess tax benefits regardless of whether the benefit reduces taxes payable in the current period; (2) excess tax benefits should be classified along with other income tax cash flows as an operating activity; (3) an entity can make an entity-wide accounting policy election to either estimate the number of awards that are expected to vest or account for forfeitures when they occur; (4) the threshold to qualify for equity classification permits withholding up to the maximum statutory tax rates in the applicable jurisdictions; and (5) cash paid by an employer when directly withholding shares for tax-withholding purposes should be classified as a financing activity on the statement of cash flows. We adopted the applicable amendments in the second quarter of 2016; however there was no impact to our consolidated financial statements.

~~In June 2016, the FASB issued ASU 2016-13,~~ ~~Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.~~ These amendments 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 loans, 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 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. We expect to adopt this guidance on January 1, 2019, and are continuing to evaluate the impact on our measurement of credit losses.

~~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)~~. These amendments clarify how entities should classify certain cash receipts and cash payments on 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. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.Statements.

~~In October 2016, the FASB issued ASU 2016-16,~~ ~~Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory~~. The amendments in this update are intended to improve the accounting 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 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. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and related disclosures.

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. Our growth strategy, based on expansion of existing facilities as well as third-party acquisitions of businesses and assets, has increased the percentage of our revenues 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.

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

Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third-parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, 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 related to natural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases.

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; income taxes; depreciation and amortization; impairment of goodwill; 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 ~~APL merger;~~mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015; non-cash compensation on ~~TRP~~ 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 depreciation and amortization ~~expenses.~~expense. 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 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, with 2015 amounts presented for comparative purposes.~~indicated.

	Three Months Ended September 30,								Nine Months Ended September 30,								Three Months Ended June 30,						Six Months Ended June 30,
	2016				2015				2016				2015				2017			2016			2017			2016
	(In millions)																(In millions)
Reconciliation of TRP Gross Margin and
Operating Margin to Net Income:
Gross margin		$	429.6			$	468.8			$	1,299.5			$	1,361.2
Operating expenses			(143.0	)			(142.7	)			(413.9	)			(409.5	)
Operating margin			286.6				326.1				885.6				951.7
Depreciation and amortization expenses			(184.0	)			(165.8	)			(563.6	)			(448.3	)
General and administrative expenses			(44.0	)			(42.9	)			(132.3	)			(130.1	)
Reconciliation of Net Income (loss) to TRP Operating Margin and Gross Margin:
Net income (loss)																	$	(29.2	)	$	(4.9	)	$	(50.4	)	$	5.7
Depreciation and amortization expense																		203.4			186.1			394.6			379.6
General and administrative expense																		47.5			44.9			92.9			88.3
Goodwill impairment			-				-				(24.0	)			-			—			—			—			24.0
Interest expense, net			(57.9	)			(61.6	)			(171.2	)			(171.1	)		58.9			66.4			117.5			113.3
Income tax (expense) benefit			(1.0	)			0.4				-				(0.4	)
Gain (loss) on sale or disposition of assets			(4.7	)			-				(5.7	)			0.2
Gain (loss) from financing activities			-				(0.5	)			21.4				(0.5	)
Income tax expense (benefit)																		0.5			(0.9	)		(4.2	)		(1.1	)
(Gain) loss on sale or disposition of assets																		0.1			—			16.2			0.9
(Gain) loss from financing activities																		10.7			3.3			10.7			(21.4	)
Other, net			(1.1	)			(2.4	)			(10.7	)			(17.1	)		—			4.6			21.1			9.6
Net income (loss)		$	(6.1	)		$	53.3			$	(0.5	)		$	184.4
Operating margin																		291.9			299.5			598.4			598.9
Operating expenses																		155.2			138.9			307.1			270.9
Gross margin																	$	447.1		$	438.4		$	905.5		$	869.8

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 June 30,												Six Months Ended June 30,
		2016			2015			2016 vs. 2015						2016			2015			2016 vs. 2015							2017			2016			2017 vs. 2016						2017			2016			2017 vs. 2016
	($ in millions, except operating statistics and price amounts)																									(In millions, except operating statistics and price amounts)
Revenues:
Sales of commodities		$	1,398.7		$	1,321.3		$	77.4			6	%	$	3,882.9		$	4,119.6		$	(236.7	)		(6	%)		$	1,623.8		$	1,312.9		$	310.9			24	%	$	3,481.7		$	2,484.0		$	997.7			40	%
Fees from midstream services			253.6			310.8			(57.2	)		(18	%)		795.5			891.6			(96.1	)		(11	%)			243.9			270.7			(26.8	)		(10	%)		498.6			542.0			(43.4	)		(8	%)
Total revenues			1,652.3			1,632.1			20.2			1	%		4,678.4			5,011.2			(332.8	)		(7	%)			1,867.7			1,583.6			284.1			18	%		3,980.3			3,026.0			954.3			32	%
Product purchases			1,222.7			1,163.3			59.4			5	%		3,378.9			3,650.0			(271.1	)		(7	%)			1,420.6			1,145.2			275.4			24	%		3,074.8			2,156.2			918.6			43	%
Gross margin (1)			429.6			468.8			(39.2	)		(8	%)		1,299.5			1,361.2			(61.7	)		(5	%)			447.1			438.4			8.7			2	%		905.5			869.8			35.7			4	%
Operating expenses			143.0			142.7			0.3			0	%		413.9			409.5			4.4			1	%			155.2			138.9			16.3			12	%		307.1			270.9			36.2			13	%
Operating margin (1)			286.6			326.1			(39.5	)		(12	%)		885.6			951.7			(66.1	)		(7	%)			291.9			299.5			(7.6	)		(3	%)		598.4			598.9			(0.5	)		—
Depreciation and amortization expenses			184.0			165.8			18.2			11	%		563.6			448.3			115.3			26	%
General and administrative expenses			44.0			42.9			1.1			3	%		132.3			130.1			2.2			2	%
Depreciation and amortization expense																												203.4			186.1			17.3			9	%		394.6			379.6			15.0			4	%
General and administrative expense																												47.5			44.9			2.6			6	%		92.9			88.3			4.6			5	%
Goodwill impairment			—			—			—			—			24.0			—			24.0			—				—			—			—			—			—			24.0			(24.0	)		(100	%)
Other operating expenses			4.9			0.1			4.8		NM				6.1			0.6			5.5		NM
Other operating (income) expense																												0.3			0.1			0.2			200	%		16.5			1.1			15.4		NM
Income from operations			53.7			117.3			(63.6	)		(54	%)		159.6			372.7			(213.1	)		(57	%)			40.7			68.4			(27.7	)		(40	%)		94.4			105.9			(11.5	)		(11	%)
Interest expense, net			(57.9	)		(61.6	)		3.7			6	%		(171.2	)		(171.1	)		(0.1	)		%				(58.9	)		(66.4	)		7.5			11	%		(117.5	)		(113.3	)		(4.2	)		4	%
Equity earnings (loss)			(2.2	)		(1.6	)		(0.6	)		38	%		(11.4	)		(1.1	)		(10.3	)	NM					(4.2	)		(4.4	)		0.2			5	%		(16.8	)		(9.2	)		(7.6	)		83	%
Gain (loss) from financing activities			—			(0.5	)		0.5			100	%		21.4			(0.5	)		21.9		NM					(10.7	)		(3.3	)		(7.4	)		224	%		(10.7	)		21.4			(32.1	)		(150	%)
Other income (expense)			1.3			(0.7	)		2.0			286	%		1.1			(15.2	)		16.3			107	%
Other income (expense), net																												4.4			(0.1	)		4.5		NM				(4.0	)		(0.2	)		(3.8	)	NM
Income tax (expense) benefit			(1.0	)		0.4			(1.4	)	NM				—			(0.4	)		0.4			100	%			(0.5	)		0.9			(1.4	)		(156	%)		4.2			1.1			3.1			282	%
Net income (loss)			(6.1	)		53.3			(59.4	)		(111	%)		(0.5	)		184.4			(184.9	)		(100	%)			(29.2	)		(4.9	)		(24.3	)	NM				(50.4	)		5.7			(56.1	)	NM
Less: Net income (loss) attributable to noncontrolling interests			4.7			4.8			(0.1	)		(2	%)		13.5			17.3			(3.8	)		(22	%)
Net income (loss) attributable to limited and general partners		$	(10.8	)	$	48.5		$	(59.3	)		(122	%)	$	(14.0	)	$	167.1		$	(181.1	)		(108	%)
Less: Net income attributable to noncontrolling interests																												10.2			5.8			4.4			76	%		16.2			8.8			7.4			84	%
Net income (loss) attributable to Targa Resources Partners LP																											$	(39.4	)	$	(10.7	)	$	(28.7	)		268	%	$	(66.6	)	$	(3.1	)	$	(63.5	)	NM
Financial and operating data:
Financial data:
Adjusted EBITDA (1)		$	240.3		$	307.1		$	(66.8	)		(22	%)	$	753.2		$	862.4		$	(109.2	)		(13	%)		$	250.7		$	252.0		$	(1.3	)		(1	%)	$	519.9		$	512.9		$	7.0			—
Capital expenditures			134.6			186.2			(51.6	)		(28	%)		426.5			571.0			(144.5	)		(25	%)			434.5			114.9			319.6			278	%		609.1			291.8			317.3			109	%
Business acquisitions			—			—			—			—			—			5,024.2			(5,024.2	)		(100	%)
Business acquisition (2)																												—			—			—			—			987.1			—			987.1			—
Operating statistics:(3)
Crude oil gathered, MBbl/d			103.9			108.9			(5.0	)		(5	%)		105.7			105.4			0.3			0	%
Plant natural gas inlet, MMcf/d (2)(3)(4)			3,370.1			3,452.5			(82.4	)		(2	%)		3,432.9			3,163.5			269.4			9	%
Gross NGL production, MBbl/d (4)			310.4			284.5			25.9			9	%		305.4			256.8			48.6			19	%
Export volumes, MBbl/d (5)			156.7			184.1			(27.4	)		(15	%)		173.0			180.0			(7.0	)		(4	%)
Natural gas sales, BBtu/d (3)(4)(6)			1,993.0			1,932.3			60.7			3	%		1,975.4			1,721.4			254.0			15	%
NGL sales, MBbl/d (4)(6)			497.3			500.1			(2.8	)		(1	%)		520.6			501.5			19.1			4	%
Condensate sales, MBbl/d (4)			10.0			10.8			(0.8	)		(7	%)		10.3			9.5			0.8			8	%
Crude oil gathered, Badlands, MBbl/d																												112.5			105.2			7.3			7	%		113.0			106.6			6.4			6	%
Crude oil gathered, Permian, MBbl/d (4)																												28.6			—			28.6			—			18.9			—			18.9			—
Plant natural gas inlet, MMcf/d (5)(6)																												3,391.2			3,511.4			(120.2	)		(3	%)		3,304.6			3,452.1			(147.5	)		(4	%)
Gross NGL production, MBbl/d																												321.2			321.0			0.3			—			305.0			302.8			2.2			1	%
Export volumes, MBbl/d (7)																												155.3			181.3			(26.0	)		(14	%)		186.2			181.2			5.0			3	%
Natural gas sales, BBtu/d (6)(8)																												1,957.3			1,958.4			(1.1	)		—			1,885.7			1,966.5			(80.8	)		(4	%)
NGL sales, MBbl/d (8)																												473.9			516.8			(42.9	)		(8	%)		503.6			532.3			(28.7	)		(5	%)
Condensate sales, MBbl/d																												12.1			11.4			0.7			6	%		11.5			10.4			1.1			11	%

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

Three Months Ended ~~September~~June 30, ~~2016~~2017 Compared to Three Months Ended ~~September~~June 30, ~~2015~~2016

The increase in ~~revenues~~commodity sales was primarily due to higher ~~NGL~~commodity prices ($~~104.0~~386.8 million) and higher ~~natural gas sales~~petroleum products and condensate volumes ($~~14.3~~13.7 million), partially offset by decreased ~~fee-based~~NGL sales volumes ($77.0 million) and the impact of hedge settlements ($12.6 million). Fee-based and other revenues ~~($57.1 million) from~~decreased primarily due to lower ~~fractionation and~~ export fees and ~~lower~~volumes, partially offset by higher crude gathering and ~~natural~~ gas ~~prices ($11.3 million).~~processing fees.

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

The ~~lower operating margin and~~higher gross margin in ~~2016 was primarily attributable to decreased~~2017 reflects increased segment margin results for ~~Logistics and Marketing. Improved margins in our~~ Gathering and Processing, ~~segment were essentially~~partially offset by ~~lower commodity derivative~~

decreased Logistics and Marketing segment margins. ~~settlement revenues~~Operating margin decreased as the increases in ~~Other.~~operating expenses more than offset the increases in gross margin. Operating expenses ~~were relatively flat in 2016 as~~increased compared to ~~2015.~~2016 due to higher fuel and power and higher maintenance in the Logistics and Marketing segment and the impact of the Permian Acquisition and other plant and system expansions in the Gathering and Processing segment. 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 depreciation and amortization ~~expenses primarily~~expense reflects the impact of the Permian Acquisition and other growth investments, ~~from system expansions.~~partially offset by the impact of fully depreciated property assets and lower scheduled amortization on the Badlands intangibles.

General and administrative ~~expenses were relatively flat in 2016 as compared to 2015.~~

~~Other operating expenses in 2016 include the loss on decommissioning of two storage wells at our Hattiesburg facility and an acid gas injection well at our Versado facility.~~

~~The decrease in net interest~~ expense ~~in 2016 is~~increased primarily due to ~~$4.2~~higher compensation and benefits, partially offset by lower professional services.

Net interest expense decreased primarily due to the impact of lower average outstanding borrowings during 2017.

During 2017, we recorded a loss from financing activities of $10.7 million ~~of non-cash interest income resulting from~~on the ~~change in estimated~~ redemption ~~value~~ of the ~~mandatorily redeemable preferred interests for the three months ended September 30, 2016.~~outstanding 6⅜% Senior Notes, whereas in 2016 we recorded a loss of $3.3 million on open debt market repurchases.

Net income attributable to noncontrolling interests was ~~primarily attributable~~higher in 2017 due to ~~overall lower~~increased earnings ~~for the third quarter of 2016~~ at our joint ~~ventures.~~ventures as compared with 2016.

Six Months Ended ~~September~~June 30, ~~2016~~2017 Compared to ~~Nine~~Six Months Ended ~~September~~June 30, ~~2015~~2016

The ~~decrease~~increase in ~~revenues~~commodity sales was primarily due to ~~lower~~higher commodity prices ($~~521.6~~1,148.6 million) and higher petroleum products and condensate volumes ($18.3 million), partially offset by decreased NGL and natural gas sales volumes ($131.1 million) and the ~~favorable~~ impact of ~~inclusion of two additional months of operations of TPL during 2016~~hedge settlements ($~~270.1~~38.1 million). ~~Additionally, fee-based~~Fee-based and other revenues decreased primarily due to lower ~~fractionation and~~ export ~~fees ($97.9 million), partially offset by the impact of an additional two months of TPL’s fee revenue in 2016 ($40.9 million).~~

~~Lower commodity prices brought a commensurate reduction in product purchases, partially offset by the inclusion of two additional months of operations from TPL in 2016 ($137.5 million).~~fees.

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

The higher gross margin in ~~2016~~2017 reflects ~~decreased~~increased segment margin results for Gathering and Processing, partially offset by decreased Logistics and Marketing ~~partially~~segment margins. Operating margin was relatively flat as compared to 2016 as the increases in gross margin were offset by ~~increased Gathering and Processing margins.~~ the increases in operating expenses. Operating expenses ~~were relatively flat~~increased compared to ~~2015~~2016 due to higher maintenance, higher fuel and power, and higher labor in the ~~inclusion of TPL’s operations for an additional two months in 2016, offset by a continued focused cost reduction effort throughout our operating areas.~~Logistics and Marketing segment and plant and system expansions. 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 depreciation and amortization ~~expenses is primarily due to an additional two~~expense reflects four months of ~~TPL~~ operations from the Permian Acquisition in ~~2016,~~2017 and the impact of other growth investments, ~~from other system expansions including~~primarily CBF Train 5 which went into service in the ~~Buffalo Plant, compressor stations~~second quarter of 2016, partially offset by the impact of fully depreciated property assets and ~~pipelines, and higher~~lower scheduled amortization ofon the Badlands ~~intangible assets.~~intangibles.

General and administrative ~~expenses, which include TPL operations for an additional two months in 2016, reflect operational synergies, including integrating TPL into Targa’s insurance program.~~expense increased primarily due to higher compensation and benefits, partially offset by lower professional services.

We recognized an ~~additional~~ impairment of goodwill in the first quarter of 2016 of $24.0 million to finalize the ~~$290.0 million~~2015 provisional impairment ~~recorded during~~of goodwill. The impairment charge related to goodwill acquired in the ~~fourth quarter of 2015.~~mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”).

Other operating ~~expenses~~(income) expense in ~~2016 include~~2017 includes the loss ~~on decommissioning~~due to the reduction in the carrying value of ~~two storage wells at~~ our ~~Hattiesburg facility and an acid gas injection well at our Versado facility.~~ownership interest in the Venice Gathering System in connection with the April 4, 2017 sale.

Net interest expense ~~was relatively flat, resulting from~~in 2017 increased primarily due to higher non-cash interest expense from an increase in borrowings primarily from the September 2015 issuance of $600.0 million of 6¾% Senior Notes, offset by $18.8 million of non-cash interest income from a reduction in the estimated redemption value ofrelated to the mandatorily redeemable preferred interests liability that is revalued quarterly at the estimated redemption value as of the reporting date, partially offset by lower average outstanding borrowings during 2017.

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 ~~and lower interest expense resulting from $534.3~~we recorded a gain of $21.4 million ofon open market debt ~~repurchases during 2016.~~repurchases.

~~The decrease in equity earnings (loss) is due to lower operating results from GCF and the inclusion of an additional two months of equity losses from the T2 Joint Ventures in 2016.~~

~~During the nine months ended September 30, 2016, we repurchased $534.3 million of debt in open market purchases, which generated a net gain of $21.4 million.~~

~~Other expense in 2015 was primarily attributable to non-recurring transaction costs related to the APL merger.~~

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

	Three Months Ended September 30,									Nine Months Ended September 30,										Three Months Ended June 30,									Six Months Ended June 30,
	2016		2015		2016 vs. 2015					2016		2015			2016 vs. 2015					2017		2016		2017 vs. 2016					2017		2016			2017 vs. 2016
Gross margin	$	231.7	$	224.0	$	7.7		3	%	$	648.0	$	609.0	$		39.0		6	%	$	264.2	$	222.4	$	41.8		19	%	$	527.4	$	416.5	$		110.9		27	%
Operating expenses		82.3		83.5		(1.2	)	(1	%)		243.9		237.0			6.9		3	%		90.7		83.3		7.4		9	%		176.3		161.8			14.5		9	%
Operating margin	$	149.4	$	140.5	$	8.9		6	%	$	404.1	$	372.0	$		32.1		9	%	$	173.5	$	139.1	$	34.4		25	%	$	351.1	$	254.7	$		96.4		38	%
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
SAOU (4)		262.5		240.2		22.3		9	%		255.1		231.6			23.5		10	%		311.6		259.2		52.4		20	%		293.7		251.3			42.4		17	%
WestTX ~~(5)~~		519.4		460.2		59.2		13	%		491.3		344.3			147.0		43	%		541.6		481.4		60.2		13	%		526.5		464.7			61.8		13	%
Total Permian Midland																					853.2		740.6		112.6					820.2		716.0			104.2
Sand Hills (4)		140.9		168.1		(27.2	)	(16	%)		142.6		166.1			(23.5	)	(14	%)		181.7		135.8		45.9		34	%		160.7		143.4			17.3		12	%
Versado		180.6		187.8		(7.2	)	(4	%)		176.5		182.3			(5.8	)	(3	%)		196.5		168.8		27.7		16	%		197.5		174.4			23.1		13	%
Total Permian Delaware																					378.2		304.6		73.6					358.2		317.8			40.4
Total Permian		1,103.4		1,056.3		47.1					1,065.5		924.3			141.2					1,231.4		1,045.2		186.2					1,178.4		1,033.8			144.6

SouthTX (5)		218.0		139.1		78.9		57	%		219.7		113.2			106.5		94	%
SouthTX																					222.6		265.4		(42.8	)	(16	%)		197.4		220.5			(23.1	)	(10	%)
North Texas		315.2		339.1		(23.9	)	(7	%)		323.4		351.7			(28.3	)	(8	%)		277.1		327.5		(50.4	)	(15	%)		279.8		327.5			(47.7	)	(15	%)
SouthOK (5)		469.8		473.8		(4.0	)	(1	%)		466.1		378.2			87.9		23	%
WestOK (5)		434.4		563.4		(129.0	)	(23	%)		455.6		458.6			(3.0	)	(1	%)
SouthOK																					479.0		470.7		8.3		2	%		459.8		464.3			(4.5	)	(1	%)
WestOK																					387.4		445.6		(58.2	)	(13	%)		390.3		466.3			(76.0	)	(16	%)
Total Central		1,437.4		1,515.4		(78.0	)				1,464.8		1,301.7			163.1					1,366.1		1,509.2		(143.1	)				1,327.3		1,478.6			(151.3	)

Badlands (6)		53.8		50.7		3.1		6	%		52.9		46.6			6.3		14	%
Badlands (5)																					52.2		51.2		1.0		2	%		49.1		52.5			(3.4	)	(6	%)
Total Field		2,594.6		2,622.4		(27.8	)				2,583.2		2,272.6			310.6					2,649.7		2,605.6		44.1					2,554.8		2,564.9			(10.1	)

Coastal		775.5		830.1		(54.6	)	(7	%)		849.7		891.0			(41.3	)	(5	%)		741.6		905.8		(164.2	)	(18	%)		749.9		887.2			(137.3	)	(15	%)

Total		3,370.1		3,452.5		(82.4	)	(2	%)		3,432.9		3,163.6			269.3		9	%		3,391.3		3,511.4		(120.1	)	(3	%)		3,304.7		3,452.1			(147.4	)	(4	%)
Gross NGL production, MBbl/d (3)
SAOU (4)		32.8		28.6		4.2		15	%		31.4		27.2			4.2		15	%		37.9		32.2		5.7		18	%		35.6		30.7			4.9		16	%
WestTX (5)		67.6		53.6		14.0		26	%		60.7		40.1			20.6		51	%
WestTX																					74.9		61.9		13.0		21	%		70.7		57.2			13.5		24	%
Total Permian Midland																					112.8		94.1		18.7					106.3		87.9			18.4
Sand Hills (4)		15.2		17.5		(2.3	)	(13	%)		15.0		17.6			(2.6	)	(15	%)		20.0		14.1		5.9		42	%		17.4		14.9			2.5		17	%
Versado		21.8		24.0		(2.2	)	(9	%)		21.3		23.5			(2.2	)	(9	%)		22.9		20.2		2.7		13	%		23.0		21.1			1.9		9	%
Total Permian Delaware																					42.9		34.3		8.6					40.4		36.0			4.4
Total Permian		137.4		123.7		13.7					128.4		108.4			20.0					155.7		128.4		27.3					146.7		123.9			22.8

SouthTX (5)		20.9		13.7		7.2		53	%		25.1		13.2			11.9		90	%
SouthTX																					23.5		31.4		(7.9	)	(25	%)		20.1		27.3			(7.2	)	(26	%)
North Texas		36.2		39.0		(2.8	)	(7	%)		36.3		40.2			(3.9	)	(10	%)		31.1		37.0		(5.9	)	(16	%)		31.5		36.3			(4.8	)	(13	%)
SouthOK (5)		42.4		30.3		12.1		40	%		39.3		23.4			15.9		68	%
WestOK (5)		27.2		27.9		(0.7	)	(3	%)		27.9		22.9			5.0		22	%
SouthOK																					38.5		47.3		(8.8	)	(19	%)		39.7		37.6			2.1		6	%
WestOK																					23.5		29.7		(6.2	)	(21	%)		23.1		28.3			(5.2	)	(18	%)
Total Central		126.7		110.9		15.8					128.6		99.7			28.9					116.6		145.4		(28.8	)				114.4		129.5			(15.1	)

Badlands		7.8		7.4		0.4		5	%		7.5		6.3			1.2		19	%		7.7		7.0		0.7		10	%		6.6		7.3			(0.7	)	(10	%)
Total Field		271.9		242.0		29.9					264.5		214.4			50.1					280.0		280.8		(0.8	)				267.7		260.7			7.0

Coastal		38.6		41.4		(2.8	)	(7	%)		41.0		41.0			-		-			41.2		40.1		1.1		3	%		37.3		42.2			(4.9	)	(12	%)

Total		310.5		283.4		27.1		10	%		305.5		255.4			50.1		20	%		321.2		320.9		0.3		—			305.0		302.9			2.1		1	%
Crude oil gathered, MBbl/d		103.9		108.9		(5.0	)	(5	%)		105.7		105.4			0.3		0	%
Crude oil gathered, Badlands, MBbl/d																					112.5		105.2		7.3		7	%		113.0		106.6			6.4		6	%
Crude oil gathered, Permian, MBbl/d (4)																					28.6		—		28.6		—			18.9		—			18.9		—
Natural gas sales, BBtu/d (3)		1,617.6		1,746.2		(128.6	)	(7	%)		1,636.8		1,540.1			96.7		6	%		1,655.2		1,605.8		49.6		3	%		1,601.6		1,646.5			(44.9	)	(3	%)
NGL sales, MBbl/d		248.4		223.4		25.0		11	%		241.3		198.5			42.8		22	%		249.2		256.1		(6.9	)	(3	%)		238.4		237.7			0.7		—
Condensate sales, MBbl/d		9.7		10.6		(0.9	)	(8	%)		10.0		9.3			0.7		8	%		12.1		10.9		1.3		12	%		11.4		10.2			1.3		13	%
Average realized prices (7):
Average realized prices (6):
Natural gas, $/MMBtu		2.49		2.52		(0.03	)	(1	%)		1.96		2.49			(0.53	)	(21	%)		2.70		1.64		1.06		65	%		2.79		1.70			1.09		64	%
NGL, $/gal		0.36		0.32		0.04		13	%		0.33		0.36			(0.03	)	(8	%)		0.46		0.36		0.10		28	%		0.48		0.32			0.16		50	%
Condensate, $/Bbl		38.29		40.68		(2.39	)	(6	%)		34.18		44.02			(9.84	)	(22	%)		42.74		37.94		4.81		13	%		43.79		32.21			11.58		36	%

Three Months Ended ~~September~~June 30, ~~2016~~2017 Compared to Three Months Ended ~~September~~June 30, ~~2015~~2016

The increase in gross margin was primarily due to higher commodity prices and higher Permian volumes, including those associated with the Permian Acquisition in 2017. Inlet volumes for Field Gathering and Processing were higher primarily due to increases at WestTX, SAOU, Sand Hills and Versado, partially offset by decreases at the other areas. The inlet volume decrease for Coastal Gathering and Processing, which generates significantly lower margins, more than offset the Field Gathering and Processing inlet volume increase. Higher NGL ~~prices~~production in the Permian region was more than offset by lower NGL production in the other areas. Natural gas sales increased primarily due to increased Field Gathering and Processing inlet ~~volumes and lower condensate prices. Plant inlet~~volumes. Total crude oil gathered volumes increased in the Permian region ~~driven by WestTX~~due to the Permian Acquisition. Total Badlands crude oil gathered volumes and ~~SAOU. The volume increase at SouthTX partially offset an overall inlet volume decrease in the Central region. Despite overall lower inlet~~natural gas volumes ~~NGL production~~ increased primarily due to ~~additional ethane recovery at SouthOK. Natural gas sales volumes decreased due to lower inlet volumes. Badlands natural gas volumes increased due to~~system expansions.

The increase in operating expenses was primarily driven by the inclusion of the Permian Acquisition, plant and system expansions ~~for specific gas~~in the Permian region and ~~oil producers while crude oil volumes decreased due to reduced producer activity by crude oil only producers.~~the June 2017 commencement in operations of the Raptor Plant at SouthTX.

Operating expenses decreased primarily due to a continued focus on cost reductions, which more than offset increased expenses associated with the commencement of commercial operations in April 2016 at the Buffalo plant in WestTX, other system expansions and an operational issue at Versado.

~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~2017 Compared to ~~Nine~~Six Months Ended ~~September~~June 30, ~~2015~~2016

The increase in gross margin was primarily due to ~~the inclusion of the TPL volumes for three quarters of 2016 partially offset by lower~~higher commodity prices and ~~lower inlet~~higher Permian volumes, ~~on our other systems. The plant~~including those associated with the Permian Acquisition in 2017. Field Gathering and Processing inlet volume increases in the Permian region, ~~attributable to~~specifically at WestTX, SAOU, Versado and Sand Hills, were offset by ~~reduced producer activity~~decreases at the other areas. The inlet volume decrease for Coastal Gathering and ~~operational issues at Sand Hills~~Processing, which generates significantly lower margins than does Field Gathering and ~~Versado~~Processing, accounted for over 93% of the overall inlet volume decrease. Despite overall lower inlet volumes, NGL production and NGL sales increased slightly primarily due to increased plant recoveries including additional ethane recovery. Natural gas sales decreased due to lower inlet volumes and increased ethane recovery. Total crude oil gathered volumes increased in the ~~Central~~Permian region ~~by reduced producer activity and volumes in North Texas. Badlands~~due to the Permian Acquisition. Total crude oil ~~and~~gathered in the Badlands increased due to system expansions. Badlands natural gas volumes ~~increased~~decreased primarily due to the impact of the severe winter weather in the first quarter of 2017.

The increase in operating expenses was primarily driven by plant and system ~~expansions. Coastal plant inlet volumes decreased due to current market conditions~~expansions in the Permian region, the inclusion of the Permian Acquisition and the ~~decline~~June 2017 commencement in operations of ~~off-system volumes partially offset by additional higher GPM volumes.~~the Raptor Plant at SouthTX.

Excluding the impact of including operating expenses for TPL for an additional two months in 2016 and system expansions, operating expenses for most areas were significantly lower due to a continued focused cost reduction effort.

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, 2016									Three Months Ended June 30, 2017
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)		262.5		100	%		262.5		262.5		311.6		100	%		311.6		311.6
WestTX (5)(6)(7)		713.4		73	%		519.4		519.4
WestTX (5) (6)											743.9		73	%		541.6		541.6
Total Permian Midland											1,055.5					853.2		853.2
Sand Hills (4)		140.9		100	%		140.9		140.9		181.7		100	%		181.7		181.7
Versado (8)		180.6		63	%		113.8		180.6
Versado (7)											196.5		100	%		196.5		196.5
Total Permian Delaware											378.2					378.2		378.2
Total Permian		1,297.4					1,036.6		1,103.4		1,433.7					1,231.4		1,231.4

SouthTX (5)		218.0	Varies (9)				205.6		218.0
SouthTX											222.6	Varies (8) (9)				199.1		222.6
North Texas		315.2		100	%		315.2		315.2		277.1		100	%		277.1		277.1
SouthOK (5)		469.8	Varies (10)				392.8		469.8
WestOK (5)		434.4		100	%		434.4		434.4
SouthOK											479.0	Varies (10)				382.6		479.0
WestOK											387.4		100	%		387.4		387.4
Total Central		1,437.4					1,348.0		1,437.4		1,366.1					1,246.2		1,366.1

Badlands (11)		53.8		100	%		53.8		53.8		52.2		100	%		52.2		52.2
Total Field		2,788.6					2,438.4		2,594.6		2,852.0					2,529.8		2,649.7

Gross NGL production, MBbl/d (2)
SAOU (4)		32.8		100	%		32.8		32.8		37.9		100	%		37.9		37.9
WestTX (5)(6)(7)		92.9		73	%		67.6		67.6
WestTX (5) (6)											102.9		73	%		74.9		74.9
Total Permian Midland											140.8					112.8		112.8
Sand Hills (4)		15.2		100	%		15.2		15.2		20.0		100	%		20.0		20.0
Versado (8)		21.8		63	%		13.7		21.8
Versado (7)											22.9		100	%		22.9		22.9
Total Permian Delaware											42.9					42.9		42.9
Total Permian		162.7					129.3		137.4		183.7					155.7		155.7

SouthTX (5)		20.9	Varies (9)				19.7		20.9
SouthTX											23.5	Varies (8) (9)				20.8		23.5
North Texas		36.2		100	%		36.2		36.2		31.1		100	%		31.1		31.1
SouthOK (5)		42.4	Varies (10)				39.1		42.4
WestOK (5)		27.2		100	%		27.2		27.2
SouthOK											38.5	Varies (10)				31.4		38.5
WestOK											23.5		100	%		23.5		23.5
Total Central		126.7					122.2		126.7		116.6					106.8		116.6

Badlands		7.8		100	%		7.8		7.8		7.7		100	%		7.7		7.7
Total Field		297.2					259.3		271.9		308.0					270.2		280.0

Three Months Ended September 30, 2015

Operating statistics:

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

Gross Volume (3)

Ownership %

Net Volume (3)

Actual Reported

SAOU (4)

240.2

100
%

240.2

240.2

WestTX (5)(6)

632.1

73
%

460.2

460.2

Sand Hills (4)

168.1

100
%

168.1

168.1

Versado (7)

187.8

63
%

118.3

187.8

Total Permian

1,228.2

986.8

1,056.3

SouthTX (5)

139.1

100
%

139.1

139.1

North Texas

339.1

100
%

339.1

339.1

SouthOK (5)

473.8

Varies (8)

397.1

473.8

WestOK (5)

563.4

100
%

563.4

563.4

Total Central

1,515.4

1,438.7

1,515.4

Badlands (9)

50.7

100
%

50.7

50.7

Total Field

2,794.3

2,476.2

2,622.4

Gross NGL production, MBbl/d (2)

SAOU (4)

28.6

100
%

28.6

28.6

WestTX (5)(6)

73.6

73
%

53.6

53.6

Sand Hills (4)

17.5

100
%

17.5

17.5

Versado (7)

24.0

63
%

15.1

24.0

Total Permian

143.7

114.8

123.7

SouthTX (5)

13.7

100
%

13.7

13.7

North Texas

39.0

100
%

39.0

39.0

SouthOK (5)

30.3

Varies (8)

27.0

30.3

WestOK (5)

27.9

100
%

27.9

27.9

Total Central

110.9

107.6

110.9

Badlands

7.4

100
%

7.4

7.4

Total Field

262.0

229.8

242.0

	Three Months Ended June 30, 2016
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)	Gross Volume (3)		Ownership %			Net Volume (3)		Actual Reported
SAOU		259.2		100	%		259.2		259.2
WestTX (4)		661.2		73	%		481.4		481.4
Total Permian Midland		920.4					740.6		740.6
Sand Hills		135.8		100	%		135.8		135.8
Versado (5)		168.8		63	%		106.3		168.8
Total Permian Delaware		304.6					242.1		304.6
Total Permian		1,225.0					982.7		1,045.2

SouthTX		265.4	Varies (6)				251.9		265.4
North Texas		327.5		100	%		327.5		327.5
SouthOK		470.7	Varies (7)				393.7		470.7
WestOK		445.6		100	%		445.6		445.6
Total Central		1,509.2					1,418.7		1,509.2

Badlands (8)		51.2		100	%		51.2		51.2
Total Field		2,785.4					2,452.6		2,605.6

Gross NGL production, MBbl/d (2)
SAOU		32.2		100	%		32.2		32.2
WestTX (4)		85.0		73	%		61.9		61.9
Total Permian Midland		117.2					94.1		94.1
Sand Hills		14.1		100	%		14.1		14.1
Versado (5)		20.2		63	%		12.7		20.2
Total Permian Delaware		34.3					26.8		34.3
Total Permian		151.5					120.9		128.4

SouthTX		31.4	Varies (6)				30.2		31.4
North Texas		37.0		100	%		37.0		37.0
SouthOK		47.3	Varies (7)				44.0		47.3
WestOK		29.7		100	%		29.7		29.7
Total Central		145.4					140.9		145.4

Badlands		7.0		100	%		7.0		7.0
Total Field		303.9					268.8		280.8

		Three Months Ended September 30,									Nine Months Ended September 30,										Three Months Ended June 30,									Six Months Ended June 30,
		2016		2015		2016 vs. 2015					2016		2015		2016 vs. 2015						2017		2016		2017 vs. 2016					2017		2016		2017 vs. 2016

	($ in millions)																			(In millions)
Gross margin		$	186.7	$	223.3	$	(36.6	)	(16	%)	$	594.6	$	692.0	$	(97.4	)	(14	%)		$	176.9	$	197.6	$	(20.7	)	(10	%)	$	373.2	$	407.9	$	(34.7	)	(9	%)
Operating expenses			60.7		59.5		1.2		2	%		170.0		173.0		(3.0	)	(2	%)			64.5		55.8		8.7		16	%		130.8		109.4		21.4		20	%
Operating margin		$	126.0	$	163.8	$	(37.8	)	(23	%)	$	424.6	$	519.0	$	(94.4	)	(18	%)		$	112.4	$	141.8	$	(29.4	)	(21	%)	$	242.4	$	298.5	$	(56.1	)	(19	%)
Operating statistics MBbl/d (1):
Fractionation volumes (2)(3)			313.2		344.6		(31.4	)	(9	%)		312.8		347.7		(34.9	)	(10	%)			338.5		329.8		8.7		3	%		321.8		312.7		9.1		3	%
LSNG treating volumes (2)			25.6		23.8		1.8		8	%		23.3		22.8		0.5		2	%			33.3		23.1		10.2		44	%		33.9		22.0		11.9		54	%
Benzene treating volumes (2)			20.2		23.8		(3.6	)	(15	%)		21.4		22.8		(1.4	)	(6	%)			22.1		23.1		(1.0	)	(4	%)		22.8		22.0		0.8		4	%
Export volumes, MBbl/d (4)			156.7		184.1		(27.4	)	(15	%)		173.0		180.0		(7.0	)	(4	%)			155.3		181.3		(26.0	)	(14	%)		186.2		181.2		5.0		3	%
NGL sales, MBbl/d			452.4		392.1		60.3		15	%		466.3		416.3		50.0		12	%			439.4		463.6		(24.2	)	(5	%)		470.5		472.8		(2.3	)	—
Average realized prices:
NGL realized price, $/gal		$	0.46	$	0.41	$	0.06		15	%	$	0.45	$	0.47	$	(0.02	)	(4	%)		$	0.58	$	0.48	$	0.10		21	%	$	0.62	$	0.44	$	0.18		41	%

Three Months Ended ~~September~~June 30, ~~2016~~2017 Compared to Three Months Ended ~~September~~June 30, ~~2015~~

Logistics and Marketing gross margin decreased primarily due to lower LPG export margin, the realization in 2015 of contract renegotiation fees related to our crude and condensate splitter project, and various other items, partially offset by increased fractionation margin. LPG export margin decreased due to lower fees and volumes, partially offset by cancellation fees. Fractionation margin increased primarily due to higher system product gains, partially offset by a decrease in supply volume.

~~Operating expenses increased due to higher taxes associated with the start-up of CBF Train 5, partially offset by lower maintenance expense~~ ~~resulting primarily from fewer required well workovers and pipeline integrity tests in the third quarter~~ 2016 ~~compared to the same period last year, with continued focused reductions in nonessential maintenance projects also contributing~~.

~~Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015~~

Logistics and Marketing gross margin decreased due to lower LPG export margin ~~the realization in 2015 of contract renegotiation fees related to our crude and condensate splitter project, lower~~partially offset by higher fractionation margin, ~~and lower~~higher terminaling and storage ~~throughput.~~throughput, and higher treating margin. LPG export margin decreased due to lower fees and ~~volumes, partially offset by cancellation fees.~~volumes. Fractionation margin ~~decreased~~increased due to ~~lower volumes and~~higher fees, an increase in system product gains and higher supply volume. Fractionation margin was partially impacted by the variable effects of fuel and power which are largely reflected in ~~lower~~ operating expenses (see footnote (2) above). Treating margin increased slightly due to higher volumes partially offset by lower fees.

Operating expenses ~~decreased~~increased primarily due to ~~lower~~higher fuel and power, ~~expense,~~which are largely passed through, and ~~lower maintenance expense resulting from continued focused cost reductions in nonessential maintenance projects. These decreases were partially offset by~~ higher ~~taxes~~labor primarily associated with ~~the start-up of CBF~~ Train 5.

The six month gross margin results were impacted by the same factors as discussed above for the quarter except that LPG export volumes were higher.

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

	Three Months Ended September 30,							Nine Months Ended September 30,							Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		2016 vs. 2015			2016		2015		2016 vs. 2015			2017		2016		2017 vs. 2016			2017		2016		2017 vs. 2016
	($ in millions)														(In millions)
Gross margin	$	11.2	$	21.8	$	(10.6	)	$	56.9	$	60.7	$	(3.8	)	$	6.0	$	18.6	$	(12.6	)	$	4.9	$	45.7	$	(40.8	)
Operating margin	$	11.2	$	21.8	$	(10.6	)	$	56.9	$	60.7	$	(3.8	)	$	6.0	$	18.6	$	(12.6	)	$	4.9	$	45.7	$	(40.8	)

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. ~~Eliminations of inter-segment transactions are reflected in the corporate and eliminations column.~~ 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 ~~hedged~~entered into derivative instruments to hedge the commodity price

associated with a portion of our expected ~~(i)~~ natural gas, ~~equity volumes and (ii)~~ NGL and condensate equity volumes in our Gathering and Processing Operations that result from percent of ~~proceeds or liquid~~proceeds/liquids processing ~~arrangements by entering into derivative instruments.~~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, 2016							Three Months Ended September 30, 2015										Three Months Ended June 30, 2017								Three Months Ended June 30, 2016
	(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)			2016 vs. 2015			Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)		Gain (Loss)			2017 vs. 2016
Natural gas (BBtu)		13.8	$	0.37	$	5.1			11.0	$	0.70	$	7.7		$	(2.6	)		15.5	$	0.16		$	2.5			10.7	$	1.27	$	13.6		$	(11.1	)
NGL (MMgal)		15.2		0.12		1.8			9.3		0.93		8.6			(6.8	)		59.4		0.01			0.8			13.1		0.09		1.0			(0.2	)
Crude oil (MBbl)		0.3		14.40		4.7			0.3		32.89		9.0			(4.3	)		0.3		6.93			2.3			0.3		15.72		4.4			(2.1	)
Non-hedge accounting (2)						(0.1	)						(4.1	)		4.0								0.4							(0.1	)		0.5
Ineffectiveness (3)						(0.3	)						0.6			(0.9	)							-							(0.3	)		0.3
					$	11.2						$	21.8		$	(10.6	)						$	6.0						$	18.6		$	(12.6	)

	Nine Months Ended September 30, 2016							Nine Months Ended September 30, 2015										Six Months Ended June 30, 2017								Six Months Ended June 30, 2016
	(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)			2016 vs. 2015			Volume Settled		Price Spread (1)			Gain (Loss)			Volume Settled		Price Spread (1)		Gain (Loss)			2017 vs. 2016
Natural gas (BBtu)		34.0	$	0.94	$	31.9			21.1	$	1.07	$	22.6		$	9.3			26.0	$	0.09		$	2.6			20.2	$	1.33	$	26.9		$	(24.3	)
NGL (MMgal)		74.1		0.09		6.9			24.3		0.74		18.1			(11.2	)		102.7		(0.01	)		(1.1	)		27.3		0.18		5.0			(6.1	)
Crude oil (MBbl)		0.8		20.02		16.2			0.6		30.52		19.4			(3.2	)		0.6		6.29			3.5			0.5		23.82		11.5			(8.0	)
Non-hedge accounting (2)						2.5							(0.7	)		3.2								(0.3	)						2.6			(2.9	)
Ineffectiveness (3)						(0.6	)						1.3			(1.9	)							0.2							(0.3	)		0.5
					$	56.9						$	60.7		$	(3.8	)						$	4.9						$	45.7		$	(40.8	)

As part of the Atlas mergers, outstanding ~~APL~~TPL derivative contracts with a fair value of $102.1 million as of ~~the acquisition date~~February 27, 2015 (the “acquisition date”), were novated to us and included in the acquisition date fair value of assets acquired. ~~Derivative~~We received derivative settlements of ~~$5.8~~$1.9 million and ~~$20.9~~$4.9 million for the three and six months ended June 30, 2017 and $6.3 million and $15.1 million for the three and six months ended June 30, 2016, related to these novated contracts. From the acquisition date through June 30, 2017, we have received total derivative settlements of $99.5 million. The remainder of the novated contracts ~~were received during~~will settle by the ~~three and nine months ended September 30, 2016 and~~end of 2017. These settlements were reflected as a reduction of the acquisition date fair value of the ~~APL~~TPL derivative assets acquired ~~with~~and had no effect on results of operations.

As of June 30, 2017, we had $72.1 million of “Cash and cash equivalents,” on our Consolidated Balance Sheet. 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 ~~weather,~~ 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 ~~our senior secured revolving credit facility (“~~the TRP ~~Revolver”),~~Revolver, borrowings under the ~~accounts receivable securitization facility (“~~Securitization ~~Facility”),~~Facility, and access to debt markets. 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.

Our short-term liquidity as of ~~October 17, 2016 , which reflects the TRP Credit Agreement,~~July 31, 2017, was:

		October 17, 2016				July 31, 2017
		(In millions)				(In millions)
Cash on hand	Cash on hand	$	160.5		Cash on hand	$	150.1
Total commitments under the TRP Revolver			1,600.0
Total availability under the TRP Revolver					Total availability under the TRP Revolver		1,600.0
Total availability under the Securitization Facility	Total availability under the Securitization Facility		225.0		Total availability under the Securitization Facility		274.0
			1,985.5				2,024.1

Less:	Outstanding borrowings under the TRP Revolver		(190.0	)	Outstanding borrowings under the TRP Revolver		(150.0	)
	Outstanding borrowings under the Securitization Facility		(225.0	)	Outstanding borrowings under the Securitization Facility		(274.0	)
	Outstanding letters of credit under the TRP Revolver		(13.5	)	Outstanding letters of credit under the TRP Revolver		(20.4	)
	Total liquidity	$	1,557.0		Total liquidity	$	1,579.7

Other potential capital resources associated with our existing arrangements include:

A portion of our capital resources ~~may be~~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.

~~Issuance of Senior Unsecured Notes and Concurrent Senior Notes Tender Offers~~

In October 2016, we issued $500.0 million of 5⅛% Senior Notes due February 2025 and $500.0 million of 5⅜% Senior Notes due February 2027, yielding net proceeds of approximately $496.2 million and $496.2 million, respectively. The net proceeds from the October 2016 Offering along with borrowings under the TRP Revolver were used to fund concurrent tender offers for certain other series of senior notes.

Concurrently with the October 2016 Offering, we commenced the Tender Offers to purchase for cash, subject to certain conditions, up to specified aggregate maximum purchase amounts of the Tender Notes. The total consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that was tendered as of the early tender date of October 5, 2016. The Tender Offers were fully subscribed and we accepted for purchase all Tender Notes that were validly tendered as of the early tender date, totaling $1,138.3 million of principal, as described in 2016 Developments above.

Subsequent to the closing of the Tender Offers in October 2016, we issued notices of full redemption to the trustees and noteholders of the 6⅝% Notes and the 6⅞% Notes for the note balances remaining after the Tender Offers. In addition, we issued notice of full redemption to the trustees of the 6⅝% APL Notes due October 2020. The redemption price for the 6⅝% Notes and the 6⅝% APL Notes due October 2020 was 103.313% of the principal amount, while the redemption price for the 6⅞% Notes was 103.438% of the principal amount. The aggregate principal amount outstanding of all three series of notes totaling $146.2 million will be redeemed on November 15, 2016 for a total redemption payment of $151.1 million, plus accrued interest.

In October 2016, we entered into the Restatement to effectuate the TRP Credit Agreement. The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity date from October 2017 to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while our ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. The TRP Revolver continues to bear interest costs that are dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA, and the covenants also remained substantially the same. The TRP Credit Agreement designates TPL and certain of its subsidiaries as “Restricted Subsidiaries” and provides for certain changes to occur upon our receiving an investment grade credit rating from Moody’s or S&P, including the release of the security interests in all collateral at our request.

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) our cash position; (2) liquids inventory levels and valuation, which we closely manage; (3) changes in the fair value of the current portion of derivative contracts; and (4) 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, decreased ~~$57.0 million.~~$55.8 million from December 31, 2016 to June 30, 2017. The ~~majority of~~major items contributing to this decrease ~~was~~were the increased capital accruals driven primarily by the Permian activity and the reclassification of a portion of the Permian Acquisition contingent consideration to current, and a decrease in our net commodity receivables due to a lower commodity revenue and reduced commodity purchases, partially offset by an increase in inventory due to price increases, and an increase in our current net risk management ~~working capital~~ position due to changes in the forward prices of commodities. The increase of ~~$5.7~~$225.1 million in current debt obligations was due to ~~increased borrowings under our AR Securitization facility resulting from higher available receivables.~~reclassification of the remaining 5% Notes due January 2018 to short term.

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 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.

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 June 30, 2017 and December 31, 2016, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $3,527.6 million and $4,206.8 million, respectively.

The majority of our long-term debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rate borrowings under the TRP Revolver. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of June 30, 2017, we do not have any interest rate hedges.

To date, we do not believe our debt balances have adversely affected our operations, our ability to grow or our ability to repay or refinance our indebtedness. For additional information about our debt-related transactions, see Note 10 - 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”) have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our Partnership Agreement. If we exercise (or a third party with our prior written consent exercises) our redemption rights relating to any Preferred Units, the holders of those Preferred Units will not have the conversion right described above with respect to the Preferred Units called for redemption.

As of June 30, 2017, we were in compliance with the covenants contained in our various debt agreements.

The Consolidated Statements of Cash Flows included in our historical consolidated financial statements employs the traditional indirect method of presenting cash flows from operating activities. Under the indirect method, net cash provided by operating activities is derived by adjusting our net income for non-cash items related to operating activities. An alternative GAAP presentation employs the direct method 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 to the presentation in our consolidated financial statements:

	Nine Months Ended September 30,								Six Months Ended June 30,
	2016			2015		2016 vs. 2015			2017			2016			2017 vs. 2016
	(In millions)								(In millions)
Cash flows from operating activities:
Cash received from customers	$	4,584.7		$	5,042.3	$	(457.6	)	$	4,109.8		$	2,978.5		$	1,131.3
Cash received from (paid to) derivative counterparties		64.9			101.3		(36.4	)		9.9			51.1			(41.2	)
Cash distributions from equity investments (1)		1.8			10.1		(8.3	)		4.0			—			4.0
Cash outlays for:
Product purchases		3,394.2			3,780.3		(386.1	)		3,185.2			2,096.8			1,088.4
Operating expenses		380.9			338.4		42.5			331.9			256.9			75.0
General and administrative expenses		110.6			137.9		(27.3	)
General and administrative expense										109.0			80.8			28.2
Interest paid, net of amounts capitalized (2)		197.1			147.6		49.5			103.0			132.3			(29.3	)
Income taxes paid, net of refunds		1.2			4.1		(2.9	)		(4.9	)		1.1			(6.0	)
Other cash (receipts) payments		(1.3	)		7.6		(8.9	)		4.1			(0.1	)		4.2
Net cash provided by operating activities	$	568.7		$	737.8	$	(169.1	)	$	395.4		$	461.8		$	(66.4	)

~~Lower~~Higher commodity prices were the primary contributor to ~~decreased~~increased cash collections and payments for product purchases in ~~2016~~2017 compared to ~~2015.~~2016. Cash received from ~~derivatives~~derivative settlements was lower ~~primarily~~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 ~~commodity price spreads in 2016 compared to 2015. Interest payments were higher in 2016, primarily due to~~average outstanding debt balances, offset by the timing of payments of interest ~~payments related to the~~on two new ~~borrowings~~series of notes we issued in ~~2015.~~2016. Cash payments for general and administrative expenses and operating expenses were ~~lower~~higher, primarily due to ~~lower bonus payout~~increases in compensation and ~~lower insurance premium payments.~~benefits, contractor and other professional services, coupled with higher utilities and higher maintenance. Other cash payments in ~~2016~~2017 were ~~lower,~~higher mainly due to transaction expenses associated with the ~~APL merger~~Permian Acquisition in ~~2015.~~2017.

Nine Months Ended September 30,
2016			2015			2016 vs. 2015
Six Months Ended June 30,								Six Months Ended June 30,
2017								2017		2016			2017 vs. 2016
(In millions)	(In millions)							(In millions)
$	(422.0	)	$	(1,462.5	)	$	1,040.5	(1,108.6	)	$	(305.2	)	$	(803.4	)

~~The decrease in net cash~~Cash used in investing activities ~~for the nine months ended September 30, 2016,~~increased in 2017 compared to ~~the nine months ended September 30, 2015, was~~2016, primarily due to the ~~$828.7~~$570.8 million outlay for the cash portion of the ~~Atlas mergers in 2015. Growth~~Permian Acquisition consideration. Capital expenditures increased $219.9 million during 2017 reflecting the spending for major growth projects during 2017 and ~~maintenance capital expenditures decreased $200.3 million for~~ the ~~nine months ended September 30, 2016 as compared to~~acquisition of the ~~nine months ended September 30, 2015.~~Flag City Plant.

~~Net~~In 2017, we realized a net source of cash ~~provided by (used in)~~from financing activities, ~~decreased in~~primarily due to contributions from TRC, partially offset by payments of distributions to TRC, repayments of the ~~nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015. During the nine months ended September 30,~~TRP Revolver and redemption of our 6⅜% Senior Notes.

In 2016, we ~~reduced~~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 ~~debt exposure by repurchasing $534.3 million~~general partner. With the contributions from TRC, we repurchased a portion of our senior notes ~~in the~~through open market along with other net debt repayments of $274.3 million; whereas we incurred net borrowings of $918.9 million during the nine months ended September 30, 2015 primarily associated with the Atlas mergers. We had no public offerings of common units in the nine months ended September 30, 2016 asrepurchases generally at a ~~result~~discount to par values and repaid a portion of the ~~TRC/~~outstanding borrowings under the TRP merger, after which our common units were no longer publicly traded. In comparison, we received $318.6 million of proceeds from the sale of common units in the nine months ended September 30, 2015. Distributions paid to common unitholders increased by $10.9 million for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015.

We received total capital contributions of $1,191.0 million from Targa for the nine months ended September 30, 2016, as compared to $60.1 million for the nine months ended September 30, 2015. Proceeds from these contributions were used for net debt repayments and redemptions of senior notes and other general partnership purposes.

We distribute all available cash from our operating surplus. As a result, we expect that we will rely upon external financing sources, including contributions from TRC and debt issuances, to fund our acquisition and expansion capital expenditures. See Note 9 – Debt Obligations and Note 11 – Partnership Units and Related Matters of the “Consolidated Financial Statements” included in this Quarterly Report.

In accordance with the Partnership Agreement, the Partnership must distribute all of its available cash, as defined in the Partnership Agreement, and as determined by the general partner, to Preferred Unitholders monthly and to common unitholders of record within 45 days after the end of each quarter. As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions ~~from the Partnership~~ after payment 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 ~~Partnership, net of the IDR Giveback, during 2016:~~

We currently estimate that we will invest ~~approximately $525~~at least $1,375 million in net growth capital expenditures (exclusive of outlays for business acquisitions) for announced projects in ~~2016.~~2017. 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 capital expenditures may vary significantly based on investment opportunities. Our expansion capital expenditures ~~decreased~~increased for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 as compared to the ~~nine~~six months ended ~~September~~June 30, ~~2015,~~2016, primarily due to ~~reduced Badlands~~the spending ~~activity~~related to the Joyce Plant, the Johnson Plant, the Wildcat Plant, related Midland Basin and Delaware Basin gas and crude gathering infrastructure expansions, Grand Prix NGL pipeline and the Channelview Splitter, as well as the acquisition of Flag City Plant. The increase is partially offset by the impact of the substantial completion of the CBF ~~Train~~Train 5 construction ~~costs in 2016. Although CBF Train 5 started up~~project in the second quarter of ~~2016, only slightly more than 20% of the construction costs were incurred in~~ 2016. We continue to expect that 2017 net maintenance capital expenditures will be approximately $110.0 million. Our maintenance capital expenditures ~~decreased~~increased for ~~the nine months ended September 30, 2016~~2017 as compared to ~~the nine months ended September 30, 2015,~~2016, primarily due to ~~fewer well connects and lengthened~~higher numbers of compressors reaching the end of their maintenance ~~cycle times resulting from decreases in producer activity, as well as a higher percentage of environmental repairs incurred~~cycles in the ~~first nine months of 2015 versus 2016.~~

Our critical accounting policies and estimates are set forth in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report. There were no significant updates or revisions to these policies during the ninesix months ended ~~September~~June 30, ~~2016. We are supplementing our disclosures to provide additional explanations of estimates~~2017 versus the six months ended June 30, 2016 and ~~assumptions used in accounting for business acquisitions.~~increased well connects.

For business acquisitions, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the acquisition date. Determining fair value requires management’s judgment and involves the use of significant estimates and assumptions with respect to projections of future production volumes, pricing and cash flows, benchmark analysis of comparable public companies, discount rates, expectations regarding customer contracts and relationships, and other management estimates. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition. See Note 4 - Business Acquisitions to our consolidated financial statements.

As of ~~September~~June 30, ~~2016,~~2017, there were ~~$33.9~~$38.4 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.

As of September 30, 2016, there have been no significant changes in the contractual obligations as presented in our 2015 Form 10-K, except as noted for debt repurchases which are disclosed in Note 9 – Debt Obligations in our Consolidated Financial Statements included in this Quarterly Report.

The following table summarizes payment obligations for our Senior Unsecured Notes as of September 30, 2016, after giving effect to debt repurchases during the nine months ended September 30, 2016, but does not include the impact of debt activity occurring after September 30, 2016 disclosed in this Quarterly Report:

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, ~~and~~ changes in interest ~~rates.~~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 2019. The current 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 ~~or equity volumes~~ as payment for services. The prices of natural gas and NGLs 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 ~~the~~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~~June 30, ~~2016,~~2017, we have hedged the commodity price associated with a portion of our expected (i) natural gas, ~~equity volumes in our Gathering and Processing operations and (ii)~~ 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, ~~and we seek to~~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 ~~natural gas and NGL~~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.~~futures on futures exchanges.

~~For all periods presented, we have entered into hedging arrangements for a portion of our forecasted equity volumes. During the three months ended September 30, 2016 and 2015, our~~Our operating revenues increased (decreased) by net hedge adjustments on commodity derivative contracts of ~~$11.2~~$5.4 million and ~~$21.8 million. During~~$17.6 million, during the ~~nine~~three months ended ~~September~~June 30, 2017 and 2016, and ~~2015, our operating revenues increased (decreased) by~~$(1.3) million and $38.9 million, during the six months ended June 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 ~~hedge adjustments~~liability position of $53.3 million at December 31, 2016 to a net asset position of $38.0 million at June 30, 2017. The fixed prices we currently expect to receive on ~~commodity~~ derivative contracts ~~of $56.9 million and $60.7 million.~~are above the aggregate forward prices for commodities related to those contracts, creating this net asset position.

As of ~~September~~June 30, ~~2016,~~2017, we had the following derivative ~~instruments designated as hedging~~ instruments that will settle during the years ~~ending~~shown below:

Instrument		Price					MMBtu/d												Price
Type	Index	$/MMBtu					2016		2017		2018		2019		Fair Value			Index	$/MMBtu					MMBtu/d										Fair Value
															(In millions)									2017			2018			2019				(In millions)

Swap	IF-NGPL MC		3.93					3,456		-		-		-	$	0.4


Gathering & Processing																		Gathering & Processing
Swap	IF-Waha		2.96					77,736		-		-		-		0.3		IF-Waha		2.87					103,600			-			-		$		2.5
Swap	IF-Waha		2.79					-		62,900		-		-		(4.0	)	IF-Waha		2.68					-			73,600			-				3.5
Swap	IF-Waha		2.71					-		-		57,900		-		(2.4	)	IF-Waha		2.77					-			-			45,383				4.8
Swap	IF-Waha		2.87					-		-		-		29,683		1.1
								77,736		62,900		57,900		29,683


		Put Price			Call Price
Collar	IF-Waha		2.85			3.47		7,500		-		-		-		0.0
Collar	IF-Waha		3.00			3.67		-		7,500		-		-		0.6
Collar	IF-Waha		3.25			4.20		-		-		1,849		-		0.2
								7,500		7,500		1,849		-
																									103,600			73,600			45,383

Swap	IF-PB		3.12					18,508		-		-		-		0.4		IF-PB		2.64					25,900			-			-				(0.3	)
Swap	IF-PB		2.51					-		10,900		-		-		(1.5	)	IF-PB		2.50					-			25,900			-				0.2
Swap	IF-PB		2.51					-		-		10,900		-		(0.9	)	IF-PB		2.42					-			-			15,000				(0.0	)
								18,508		10,900		10,900		-											25,900			25,900			15,000

Swap																		IF-PEPL		2.6835					16,000			-			-				(0.1	)
Swap																		IF-PEPL		2.6835					-			16,000			-				0.7
Swap																		IF-PEPL		2.6835					-			-			16,000				1.3
																									16,000			16,000			16,000
		Put Price			Call Price
Collar	IF-PB		2.65			3.31		15,400		-		-		-		(0.0	)
Swap																		NG-NYMEX		3.99					9,783			-			-				1.6


																			Put Price			Call Price
Collar	IF-PB		2.80			3.50		-		15,400		-		-		0.7		IF-Waha		3.00			3.67		7,500			-			-				0.5
Collar	IF-PB		3.00			3.65		-		-		7,637		-		0.9		IF-Waha		3.25			4.20		-			1,849			-				0.3
								15,400		15,400		7,637		-											7,500			1,849			-

																			Put Price			Call Price
Swap	NG-NYMEX		4.12					34,239		-		-		-		3.5
Swap	NG-NYMEX		4.11					-		18,082		-		-		6.4
								34,239		18,082		-		-

Swap	NG-NYMEX-mtm		3.11					497		-		-		-		(0.0	)
Swap	NG-NYMEX-mtm		3.17					-		566		-		-		(0.0	)
Collar																		IF-PB		2.80			3.50		15,400			-			-				0.6
Collar																		IF-PB		3.00			3.65		-			7,637			-				1.5
								497		566		-		-											15,400			7,637			-


Basis Swap	EP_PERMIAN		(0.1703	)				17,120		-		-		-		(0.1	)	EP-PERMIAN		(0.1444	)				4,891			-			-				0.2

Basis Swap	EP_PERMIAN		(0.1444	)				-		9,041		-		-		0.1		PEPL		(0.3308	)				4,891			-			-				0.0
								17,120		9,041		-		-
Gathering & Processing total																		Gathering & Processing total							187,965			124,986			76,383			$	17.3

Other (1)																		Other (1)
Swap																		NG-NYMEX		(3.1680	)				(455	)		(173	)		(247	)		$	(0.0	)
Basis Swap																		Various	Various						111,957			3,226			-				(0.7	)
Future																		Various		3.2640					-			1,103			-				(0.0	)
Other total																		Other total							111,502			4,156			(247	)		$	(0.7	)

																																		$	16.6
Basis Swap	PEPL		(0.3278	)				17,120		-		-		-		(0.2	)
Basis Swap	PEPL		(0.3308	)				-		9,041		-		-		(0.4	)
								17,120		9,041		-		-


Basis Swap	PEPL-mtm		(0.1870	)				16,576		-		-		-		0.1
Basis Swap	PEPL-mtm		(0.2025	)				-		14,959		-		-		(0.1	)
								16,576		14,959		-		-


Basis Swap	TENN_800		(0.0567	)				15,000		-		-		-		(0.0	)
Basis Swap	TENN_800		(0.0575	)				-		12,493		-		-		(0.1	)
								15,000		12,493		-		-

Instrument		Price				Bbl/d												Price
Type	Index	$/gal				2016		2017		2018		2019		Fair Value			Index	$/gal				Bbl/d						Fair Value
														(In millions)								2017		2018		2019		(In millions)
Gathering & Processing																	Gathering & Processing
Swap	C2-OPIS-MB		0.2209				870		-		-		-	$	(0.0	)	C2-OPIS-MB		0.2781				4,830		-		-	$	0.9
Swap																	C2-OPIS-MB		0.2794				-		2,918		-		(0.1	)
Swap																	C2-OPIS-MB		0.2917				-		-		2,260		(0.8	)
Total																							4,830		2,918		2,260

Swap																	C3-OPIS-MB		0.6456				7,802		-		-		1.8
Swap																	C3-OPIS-MB		0.5530				-		2,650		-		(0.4	)
Swap																	C3-OPIS-MB		0.5530				-		-		2,650		0.4
Total																							7,802		2,650		2,650

Swap																	IC4-OPIS-MB		0.8065				740		-		-		0.3
Swap																	IC4-OPIS-MB		0.7487				-		230		-		0.2
Swap																	IC4-OPIS-MB		0.7200				-		-		110		0.1
Total																							740		230		110

Swap																	NC4-OPIS-MB		0.7935				1,800		-		-		0.7
Swap																	NC4-OPIS-MB		0.7388				-		600		-		0.6
Swap																	NC4-OPIS-MB		0.7050				-		-		300		0.2
Total																							1,800		600		300

Swap	C2-OPIS-MB		0.2517				-		1,857		-		-		0.0		C5-OPIS-MB		1.1056				1,510		-		-		0.9
Swap	C2-OPIS-MB		0.2648				-		-		1,318		-		(0.7	)	C5-OPIS-MB		1.0385				-		810		-		(0.1	)
Swap	C2-OPIS-MB		0.2925				-		-		-		660		(0.2	)	C5-OPIS-MB		1.0825				-		-		569		0.4
Total							870		1,857		1,318		660										1,510		810		569

		Put Price																Put Price		Call Price
Option	C2-OPIS-MB	-					-		-		-		-		0.0
Option	C2-OPIS-MB		0.2694				-		548		-		-		0.2
Option	C2-OPIS-MB		0.2963				-		-		1,644		-		0.9
Total							-		548		1,644		-


Future	C2-OPIS-MB		0.2200				707		-		-		-		(0.0	)
Future	C2-OPIS-MB		0.2713				-		411		-		-		(0.1	)
Total							707		411		-		-


Future	C2-ICE		0.1942				24,489		-		-		-		0.0
Future	C2-ICE		0.2593				-		35,482		-		-		0.1
Future	C2-ICE		0.2956				-		-		5,000		-		0.0
Total							24,489		35,482		5,000		-


Swap	C3-OPIS-MB		0.7959				3,883		-		-		-		3.6
Swap	C3-OPIS-MB		0.7396				-		1,528		-		-		4.4
Swap	C3-OPIS-MB		0.5125				-		-		870		-		(0.5	)
Swap	C3-OPIS-MB		0.5125				-		-		-		870		(0.4	)
Total							3,883		1,528		870		870


Future	C3-OPIS-MB		0.4948				435		-		-		-		(0.1	)
Future	C3-OPIS-MB		0.5433				-		603		-		-		(0.2	)
Total							435		603		-		-


Future	C3-ICE		0.4576				36,043		-		-		-		(0.3	)
Future	C3-ICE		0.5237				-		14,060		-		-		0.2
Total							36,043		14,060		-		-


Future	NC4-OPIS-MB		0.6358				2,011		-		-		-		(0.7	)

Future	NC4-ICE		0.6080				22,202		-		-		-		1.1
Future	NC4-ICE	0.56375					-		333		-		-		0.0
							22,202		333		-		-


Swap	C5-OPIS-MB		0.9600				320		-		-		-		(0.2	)
Swap	C5-OPIS-MB		0.9943				-		490		-		-		(0.7	)
Swap	C5-OPIS-MB		0.9943				-		-		490		-		(0.9	)
Swap	C5-OPIS-MB		1.0520				-		-		-		249		(0.3	)
Collar																	C2-OPIS-MB		0.240		0.290		410		-		-		0.0
Total							320		490		490		249										410		-		-


		Put Price		Call Price														Put Price		Call Price
Collar	C2-OPIS-MB		0.200		0.235		410		-		-		-		(0.0	)	C3-OPIS-MB		0.570		0.68625		380		-		-		0.0
Collar	C2-OPIS-MB		0.240		0.290		-		410		-		-		0.1		C3-OPIS-MB		0.530		0.65000		-		900		-		0.1
Total							410		410		-		-										380		900		-


		Put Price		Call Price														Put Price		Call Price
Collar	C3-OPIS-MB		0.560		0.68000		380		-		-		-		0.0		IC4-OPIS-MB						-		-		-		0.0
Collar	C3-OPIS-MB		0.570		0.68625		-		380		-		-		0.4		IC4-OPIS-MB		0.650		0.840		-		110		-		0.0
Collar																	IC4-OPIS-MB		0.640		0.800		-		-		110		0.1
Total																							-		110		110

																		Put Price		Call Price
Collar																	NC4-OPIS-MB						-		-		-		0.0
Collar																	NC4-OPIS-MB		0.650		0.800		-		300		-		0.1
Collar																	NC4-OPIS-MB		0.640		0.760		-		-		300		0.1
Total																							-		300		300

																		Put Price		Call Price
Collar																	C5-OPIS-MB		1.210		1.415		130		-		-		0.2
Collar																	C5-OPIS-MB		1.230		1.385		-		32		-		0.1
Total																							130		32		-

Gathering & Processing total																	Gathering & Processing total						17,602		8,550		6,299	$	5.8

Other (1)(2)																	Other (1)(2)
Future																	C2-OPIS-MB		0.2741				5,707		-		-	$	0.7
Future																	C2-OPIS-MB		0.3007				-		1,534		-		0.4
Total																							5,707		1,534		-

Future																	C3-OPIS-MB		0.6520				9,321		-		-		2.2

~~As of September 30, 2016, we had the following derivative instruments that are not designated as hedges and are marked-to-market:~~

Instrument		Price			MMBtu/d												Price
Type	Index	$/MMBtu			2016		2017		2018		2019		Fair Value			Index	$/Bbl				Bbl/d							Fair Value
													(In millions)								2017		2018		2019			(In millions)
Gathering & Processing																Gathering & Processing
Swap																WTI-NYMEX		54.54				2,690		-		-	$		3.8
Swap																WTI-NYMEX		48.79				-		2,190		-			0.4
Swap																WTI-NYMEX		51.19				-		-		1,063			0.7
																						2,690		2,190		1,063
Basis Swap	Various		(0.0597	)		62,235		40,511		-		-	$	(0.2	)


																	Put Price		Call Price
Collar																WTI-NYMEX		54.04		64.09		1,380		-		-			2.1
Collar																WTI-NYMEX		49.76		58.50		-		691		-			1.1
Collar																WTI-NYMEX		48.00		56.25		-		-		590			0.4
																						1,380		691		590

Total																						4,070		2,881		1,653

																												$	8.5

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~~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 ~~swap and options,~~contract, the valuations are classified as Level 3 within the fair value hierarchy. See Note 1314 - 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~~June 30, ~~2016,~~2017, we do not have any interest rate hedges. However, we may ~~in the future~~ enter into interest rate hedges ~~intended~~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~~June 30, ~~2016,~~2017, we had ~~$225.0~~$250.0 million in outstanding variable rate borrowings under the TRP Revolver and ~~the~~ Securitization Facility. A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact our annual interest expense by ~~$2.3~~$2.5 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 ~~settled~~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 of 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 ~~$30.6~~$15.0 million as of ~~September~~June 30, ~~2016.~~2017. The range of losses attributable to our individual counterparties would be between ~~less than $0.5~~$0.4 million and ~~$13.7~~$16.7 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 initial and subsequent credit risk analyses, credit limits and terms and 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 ~~annual~~as of June 30, 2017, our operating income would decrease by $5.5 million in the year of the assessment.

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 ~~this~~such evaluation, ~~the~~our Chief Executive Officer and ~~the~~ Chief Financial Officer have concluded that our disclosure controls and procedures were ~~not~~ effective ~~as a result of a material weakness in our internal control over financial reporting as~~to provide reasonable assurance that information required to be disclosed in our ~~2015 Annual Report on Form 10-K. Management has concluded that~~reports filed or submitted under the ~~material weakness that was present as of December 31, 2015 was also present as of September 30, 2016.~~

~~Previously Identified Material Weakness in Internal Control Over Financial Reporting~~

~~As previously disclosed in our 2015 Annual Report on Form 10-K, we did not maintain adequate controls over~~Exchange Act is (i) recorded, processed, summarized and reported within the ~~valuation of certain assets~~time periods specified in the ~~Atlas mergers. Specifically,~~rules and forms of the SEC and (ii) accumulated and communicated to management, including our ~~review procedures over the development~~Chief Executive Officer and ~~application of inputs, assumptions, and calculations used in cash flow-based fair value measurements associated with business combinations did not operate~~Chief Financial Officer, as ~~designed and at an~~ appropriate, ~~level of detail commensurate with our financial reporting requirements.~~to allow for timely decisions regarding required disclosure.

We have enhanced our internal control framework applicable to business acquisitions to include formal processes covering the development, application and review of inputs, assumptions, and calculations used in cash flow-based value measurements. Cash flow-based fair value measurements are also typically used for asset and goodwill impairment testing. We have not had any events or conditions since December 31, 2015 that have required the use of cash flow-based fair value measurements. As such, neither we nor our external auditors have had the opportunity to fully test the operating effectiveness of our remediated internal control framework. We will be able to fully test our remediated controls over cash flow-based fair value measurements when we perform our annual goodwill impairment testing for the 2016 reporting cycle, or earlier if another need arises for such value measurements.

Changes in Internal Control Over Financial Reporting ~~During the Quarter Ended September 30, 2016~~

~~During the three months ended September 30, 2016, there~~There have ~~not~~ been ~~any~~no changes in our internal control over financial reporting that ~~have~~occurred during the quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

For an in-depth discussion of our risk factors, see “Part I—Item 1A. Risk Factors” of our ~~2015~~ Annual ~~Report, except for the additional risk factor discussed below.~~Report. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

Changes in future business conditions could cause recorded goodwill and property, plant and equipment assets to become further impaired, and our financial condition and results of operations could suffer if there is an additional impairment of goodwill or other intangible assets with indefinite lives, intangible assets with definite lives, or property, plant and equipment assets.

During 2015, global oil and natural gas commodity prices, particularly crude oil, significantly decreased as compared to 2014, and global oil and natural gas commodity prices remained depressed in the third quarter of 2016. This decrease in commodity prices has had, and is expected to continue to have, a negative impact on the demand for our services and our market capitalization. Should energy industry conditions further deteriorate, there is a possibility that goodwill, intangible assets and property, plant and equipment may be impaired in a future period. Any additional impairment charges that we may take in the future could be material to our financial results. We cannot accurately predict the amount and timing of any impairment of goodwill, intangible assets or property, plant and equipment. For a further discussion of our impairments, see Note 4 – Business Acquisitions of the Consolidated Financial Statements included in this Quarterly Report.

On September 30, 2016, Targa and certain of its subsidiaries made capital contributions to us of $215.0 million, for which we issued to Targa and certain of its subsidiaries 6,925,591 common units and 141,338 general partner units. The units were issued pursuant to the exemption offered by Section 4(a)(2) of the Securities Act.

Repurchase of Equity by Targa Resources Partners LP or Affiliated ~~Purchasers~~Purchasers.

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~~June 30, ~~2016~~2017 and December 31, ~~2015~~2016		4

Consolidated Statements of Operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 and ~~2015~~2016		5

Consolidated Statements of Comprehensive Income (Loss) for the three and ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 and ~~2015~~2016		6

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

Consolidated Statements of Cash Flows for the ~~nine~~six months ended ~~September~~June 30, ~~2016~~2017 and ~~2015~~2016		8

Notes to Consolidated Financial Statements		9

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		3632

Item 3. Quantitative and Qualitative Disclosures About Market Risk		5752

Item 4. Controls and Procedures		6457

PART II—OTHER INFORMATION

Item 1. Legal Proceedings		6558

Item 1A. Risk Factors		6558

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		6558

Item 3. Defaults Upon Senior Securities		6558

Item 4. Mine Safety Disclosures		6558

Item 5. Other Information		6558

Item 6. Exhibits		6659

SIGNATURES

Signatures		6860


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
~~/hr~~LACT		~~Per hour~~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~~


~~EP_PERMIAN~~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)
~~ICE~~IC4-OPIS-MB		~~Intercontinental Exchange~~
~~IF-NGPL MC~~		~~Inside FERC Gas Market Report, Natural Gas Pipeline Co. of America, Mid-Continent~~Iso-Butane, Oil Price Information Service, Mont Belvieu, Texas
IF-PB		Inside FERC Gas Market Report, Permian Basin
~~IF-WAHA~~		~~Inside FERC Gas Market Report, West Texas WAHA~~
~~NG-NYMEX~~		~~NYMEX, Natural Gas~~
~~NGPL_TXOK~~		~~Inside FERC Gas Market Report, Natural Gas Pipeline Co. of America, TexOK Zone~~
~~NY-WTI~~		~~NYMEX, West Texas Intermediate Crude Oil~~
~~OPIS-MB~~		~~Oil Price Information Service, Mont Belvieu, Texas~~
~~PEPL~~	IF-PEPL	Inside FERC Gas Market Report, Oklahoma Panhandle, Texas-Oklahoma Midpoint
~~TENN_800~~		~~Tennessee Gas Pipeline Co., 800 Leg~~
~~TRANSCO_Z4~~	IF-WAHA	Inside FERC Gas Market Report, ~~Transco Zone 4~~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

Fair Value of Consideration Transferred by Targa for ATLS:
Cash paid, net of cash acquired (1)	$	745.7
Common shares of TRC		1,008.5
Replacement restricted stock units awarded (3)		5.2
Less: value of APL common units owned by ATLS		(147.4	)
Total	$	1,612.0

Fair Value of Consideration Transferred by Targa for APL:
Cash paid, net of cash acquired (2)	$	828.7
Common units of TRP		2,568.5
Replacement phantom units awarded (3)		15.0
Total	$	3,412.2
Total fair value of consideration transferred	$	5,024.2


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.	—		—		51,695			956.5		1,055		19.5			—		—			—			—			976.0
Distributions to noncontrolling interests	—		—		—			—		—		—			—		—			—			(6.3	)		(6.3	)
Contributions from noncontrolling interests	—		—		—			—		—		—			—		—			—			19.1			19.1
Other comprehensive income (loss)	—		—		—			—		—		—			(95.9	)	—			—			—			(95.9	)
Net income (loss)	—		5.6		—			(47.9	)	—		39.2			—		—			—			8.8			5.7
Distributions	—		(5.6	)	—			(289.5	)	—		(65.7	)		—		—			—			—			(360.8	)
Balance June 30, 2016	5,000	$	120.6		236,595		$	5,161.3		4,828	$	1,728.1		$	(9.1	)	—		$	—		$	441.7		$	7,442.6

		Three Months Ended
		September 30, 2015				September 30, 2015
		As Reported				As Corrected
Commodity hedging contracts:
Change in fair value	$		42.9		$		50.7
Settlements reclassified to revenues			(16.7	)			(24.5	)
Other comprehensive income (loss)	$		26.2		$		26.2

		Nine Months Ended								Year Ended
		September 30, 2015				September 30, 2015				December 31, 2015				December 31, 2015
		As Reported				As Corrected				As Reported				As Corrected
Commodity hedging contracts:
Change in fair value	$		59.4		$		77.6		$		81.2		$		112.7
Settlements reclassified to revenues			(41.1	)			(59.3	)			(54.8	)			(86.3	)
Other comprehensive income (loss)	$		18.3		$		18.3		$		26.4		$		26.4

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

	June 30, 2017		December 31, 2016
Commodities	$	187.8	$	126.9
Materials and supplies		9.9		10.8
	$	197.7	$	137.7

	June 30, 2017			December 31, 2016			Estimated Useful Lives (In Years)
Gathering systems	$	6,849.2		$	6,626.9		5 to 20
Processing and fractionation facilities		3,554.7			3,383.6		5 to 25
Terminaling and storage facilities		1,233.6			1,205.0		5 to 25
Transportation assets		342.7			451.4		10 to 25
Other property, plant and equipment		283.7			274.0		3 to 25
Land		122.3			121.2		—
Construction in progress		920.5			449.8		—
Property, plant and equipment		13,306.7			12,511.9
Accumulated depreciation		(3,080.0	)		(2,821.0	)
Property, plant and equipment, net	$	10,226.7		$	9,690.9

Intangible assets	$	2,737.4		$	2,036.6		10 to 20
Accumulated amortization		(472.7	)		(382.6	)
Intangible assets, net	$	2,264.7		$	1,654.0

Balance at December 31, 2016	$	1,654.0
Additions from Permian Acquisition		692.3
Additions from Flag City Acquisition		8.5
Amortization		(90.1	)
Balance at June 30, 2017	$	2,264.7

	WestTX		SouthTX		Permian		Total
Balance at December 31, 2016, net	$	174.7	$	35.3	$	—	$	210.0
Permian Acquisition, March 1, 2017 (preliminary valuation)		—		—		46.6		46.6
Balance at June 30, 2017, net	$	174.7	$	35.3	$	46.6	$	256.6

	GCF			T2 LaSalle			T2 Eagle Ford			T2 EF Cogen			Total
Balance at December 31, 2016	$	46.1		$	58.6		$	118.6		$	17.5		$	240.8
Equity earnings (loss)		4.0			(2.4	)		(5.4	)		(13.0	)		(16.8	)
Cash distributions (1)		(7.2	)		—			—			—			(7.2	)
Contributions for expansion projects (2)		—			0.4			1.1			0.1			1.6
Balance at June 30, 2017	$	42.9		$	56.6		$	114.3		$	4.6		$	218.4

	June 30, 2017			December 31, 2016

Current:
Accounts receivable securitization facility, due December 2017	$	250.0		$	275.0
Senior unsecured notes, 5% fixed rate, due January 2018 (1)		250.5			—
		500.5			275.0
Debt issuance costs, net of amortization		(0.4	)		—
Current debt obligations		500.1			275.0
Long-term:
Senior secured revolving credit facility, variable rate, due October 2020 (2)		—			150.0
Senior unsecured notes:
5% fixed rate, due January 2018 (1)		—			250.5
4⅛% fixed rate, due November 2019		749.4			749.4
6⅜% fixed rate, due August 2022		—			278.7
5¼% fixed rate, due May 2023		559.6			559.6
4¼% fixed rate, due November 2023		583.9			583.9
6¾% fixed rate, due March 2024		580.1			580.1
5⅛% fixed rate, due February 2025		500.0			500.0
5⅜% fixed rate, due February 2027		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
Unamortized premium		0.4			0.5
		3,528.0			4,207.3
Debt issuance costs, net of amortization		(25.5	)		(30.3	)
Long-term debt		3,502.5			4,177.0
Total debt obligations	$	4,002.6		$	4,452.0
Irrevocable standby letters of credit outstanding	$	20.4		$	13.2

	June 30, 2017		December 31, 2016
Asset retirement obligations	$	48.6	$	64.1
Mandatorily redeemable preferred interests		77.2		68.5
Deferred revenue		68.3		69.8
Permian Acquisition contingent consideration, noncurrent portion		376.8		-
Other liabilities		3.3		2.9
Total long-term liabilities	$	574.2	$	205.3

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		2.2
Balance at June 30, 2017	$	48.6

Balance at December 31, 2016	$	68.5
Income attributable to mandatorily redeemable preferred interests		1.8
Change in estimated redemption value included in interest expense		6.9
Balance at June 30, 2017	$	77.2

	June 30, 2017		December 31, 2016
Splitter agreement	$	43.0	$	43.0
Gas contract amendment		19.0		19.7
Other deferred revenue		6.3		7.1
Total deferred revenue	$	68.3	$	69.8

Balance at December 31, 2016	$	69.8
Additions		-
Revenue recognized		(1.5	)
Balance at June 30, 2017	$	68.3

Balance at March 1, 2017 (acquisition date)	$	461.6
Measurement period adjustment		(45.3	)
Increase in fair value since acquisition date		1.1
Balance at June 30, 2017	$	417.4
Less: Current portion		(40.6	)
Long-term balance at June 30, 2017	$	376.8


Three Months	Date Paid		Total			Distributions to
Ended	Or to Be Paid		Distributions			Targa Resources Corp.

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


Balance at December 31, 2015	$	1,810.1
Amortization		(117.1	)
Balance at September 30, 2016	$	1,693.0

Debt Repurchased	Book Value		Payment			Gain/(Loss)			Write-off of Debt Issuance Costs			Net Gain/(Loss)
5¼% Senior Notes	$	24.1	$	(20.1	)	$	4.0		$	(0.2	)	$	3.8
4¼% Senior Notes		39.5		(31.8	)		7.7			(0.3	)		7.4
6⅞% Senior Notes		4.8		(4.3	)		0.5			(0.1	)		0.4
6⅝% Senior Notes		32.6		(29.5	)		3.1			-			3.1
6⅜% Senior Notes		21.3		(18.7	)		2.6			(0.2	)		2.4
6¾% Senior Notes		19.9		(17.5	)		2.4			(0.2	)		2.2
5% Senior Notes		366.4		(368.2	)		(1.8	)		(2.1	)		(3.9	)
4⅛% Senior Notes		50.6		(44.2	)		6.4			(0.4	)		6.0
	$	559.2	$	(534.3	)	$	24.9		$	(3.5	)	$	21.4

	Scheduled Maturities of Debt
	Total		Remainder of 2016		2017		2018		2019		2020		After 2020
	(in millions)

Senior notes	$	4,341.3	$	-	$	-	$	733.6	$	749.4	$	322.8	$	2,535.5

Senior Notes	Outstanding Note Balance Prior to Tender Offers		Amount Tendered		Premium Paid		Accrued Interest Paid		Total Tender Offer Payments		Note Balance After Tender Offers
5% Senior Notes	$	733.6	$	483.1	$	16.9	$	5.4	$	505.4	$	250.5
6⅝% Senior Notes		309.9		281.7		10.5		0.3		292.5		28.2
6⅞% Senior Notes		478.6		373.5		14.4		4.6		392.5		105.1
	$	1,522.1	$	1,138.3	$	41.8	$	10.3	$	1,190.4	$	383.8

Balance at December 31, 2015	$	69.9
Change in cash flow estimate		(9.2	)
Accretion expense		3.5
Balance at September 30, 2016	$	64.2

Balance at December 31, 2015	$	82.9
Income attributable to mandatorily redeemable preferred interests		0.1
Change in estimated redemption value included in interest expense		(18.8	)
Balance at September 30, 2016	$	64.2

					Cash-Settled Performance Units
					Targa Resources Long-Term Incentive Plan
	Equity-Settled Performance Units		Replacement Phantom Units		2015		2014		2013
Before conversion		675,745		349,451		192,390		119,900		139,700
After conversion		418,903		216,561		119,178		74,248		86,538

Commodity	Instrument	Unit	2016		2017		2018		2019
Natural Gas	Swaps	MMBtu/d		134,436		92,448		68,800		29,683
Natural Gas	Basis Swaps	MMBtu/d		95,979		58,026		-		-
Natural Gas	Options	MMBtu/d		22,900		22,900		9,486		-
NGL	Swaps	Bbl/d		5,073		3,875		2,678		1,779
NGL	Futures	Bbl/d		85,887		50,889		5,000		-
NGL	Options	Bbl/d		920		1,468		1,676		-
Condensate	Swaps	Bbl/d		2,770		1,850		1,350		223
Condensate	Options	Bbl/d		790		1,380		691		590

		September 30, 2016				December 31, 2015
Commodity hedges, before tax (1)		$	9.2			$	86.7

		Commodity
		Derivative Contracts			Contingent
		Asset/(Liability)			Liability

Balance, December 31, 2015		$	3.7		$	(3.0	)

	Change in fair value of TPL contingent consideration		-			0.3
	New Level 3 instruments		1.0			-
	Settlements included in Revenue		(1.0	)		-
	Unrealized gain/(loss) included in OCI		(3.8	)		-
Balance, September 30, 2016		$	(0.1	)	$	(2.7	)

	Three Months Ended September 30, 2016
	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
Fees from midstream services		120.6		133.0		—		—			253.6
		292.8		1,348.3		11.2		—			1,652.3
Intersegment revenues
Sales of commodities		574.8		76.3		—		(651.1	)		—
Fees from midstream services		1.9		6.6		—		(8.5	)		—
		576.7		82.9		—		(659.6	)		—
Revenues	$	869.5	$	1,431.2	$	11.2	$	(659.6	)	$	1,652.3
Operating margin	$	149.4	$	126.0	$	11.2	$	—		$	286.6
Other financial information:
Total assets (1)	$	10,047.3	$	2,737.5	$	47.2	$	76.2		$	12,908.2
Goodwill	$	393.0	$	—	$	—	$	—		$	393.0
Capital expenditures	$	97.1	$	36.2	$	—	$	1.3		$	134.6

		Gathering and Processing		Logistics and Marketing		Other		Total
	(In millions)
Three Months Ended:
September 30, 2016		$	149.4	$	126.0	$	11.2	$	286.6
September 30, 2015			140.5		163.8		21.8		326.1

Nine Months Ended:
September 30, 2016		$	404.1	$	424.6	$	56.9	$	885.6
September 30, 2015			372.0		519.0		60.7		951.7

	Payments Due By Period
			Less Than						More Than
	Total		1 Year		1-3 Years		3-5 Years		5 Years
	(in millions)
Senior Unsecured Notes:
Debt obligations (1)	$	4,341.3	$	-	$	733.6	$	1,550.8	$	2,056.9
Interest on debt obligations (2)		1,161.7		236.9		409.6		296.1		219.1
	$	5,503.0	$	236.9	$	1,143.2	$	1,846.9	$	2,276.0

Basis Swap	NGPL_TXOK	(0.0967	)	10,109	-	-	-		0.0


Basis Swap	WAHA	(0.1283	)	10,109	-	-	-		(0.0	)


Basis Swap	TRANSCO_Z4	0.0225		9,945	-	-	-		0.0
Basis Swap	TRANSCO_Z4	0.0225		-	12,492	-	-		0.1
				9,945	12,492	-	-

Total				253,315	173,374	78,286	29,683

								$	5.1