UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



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

For the Quarterly Period Ended September 30, ~~2016~~2017



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

Commission file number 001-37365

Tallgrass Energy GP, LP

(Exact name of registrant as specified in its charter)



Delaware				46-3159268
(State or other Jurisdiction of Incorporation or Organization)				(IRS Employer Identification Number)

4200 W. 115th Street, Suite 350
Leawood, Kansas				66211
(Address of Principal Executive Offices)				(Zip Code)

(913) 928-6060

(Registrant's Telephone Number, Including Area Code)

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 x 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 x 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", ~~and~~ "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer	¨x	Accelerated filer	¨

Non-accelerated filer	x¨ (Do not check if a smaller reporting company)	Smaller reporting company	¨

		Emerging growth company	¨

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

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

On November 2, ~~2016,~~2017, the Registrant had ~~47,725,000~~58,075,000 Class A shares and ~~109,504,440~~99,154,440 Class B shares outstanding.

TALLGRASS ENERGY GP, LP

TABLE OF CONTENTS

Glossary of Common Industry and Measurement Terms

Bakken oil production area: Montana and North Dakota in the United States and Saskatchewan and Manitoba in Canada.

Barrel (or bbl): ~~forty two~~forty-two U.S. gallons.

Base Gas (or Cushion Gas): the volume of gas that is intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates.

BBtu: one billion British Thermal Units.

Bcf: one billion cubic feet.

British Thermal Units or Btus: the amount of heat energy needed to raise the temperature of one pound of water by one degree Fahrenheit.

Commodity sensitive contracts or arrangements: contracts or other arrangements, including tariff provisions, that are directly ~~expose our cash flows~~tied to increases and decreases in the price of commodities such as crude oil, natural gas and NGLs. Examples are Keep Whole Processing Contracts and Percent of Proceeds Processing Contracts, as well as pipeline loss allowances on our pipelines.

Condensate: aan NGL with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

Contract barrels: barrels of crude oil that our customers have contractually agreed to ship in exchange for firm service assurance of capacity and deliverability to delivery points.

Delivery point: any point at which product in a pipeline is delivered to or for the account of a customer.

Dry gas: a gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

Dth: a dekatherm, which is a unit of energy equal to 10 therms or one million British thermal units.

End-user markets: the ultimate users and consumers of transported energy products.

EPA: the United States Environmental Protection Agency.

FERC: Federal Energy Regulatory Commission.

Firm fee contracts: ~~firm fee~~ contracts or other arrangements, including tariff provisions, that generally obligate our customers to pay a fixed recurring charge to reserve an agreed upon amount of capacity and/or deliverability on our assets, regardless if the contracted capacity is actually used by the customer. Such contracts are also commonly known as "take-or-pay" contracts.

Firm services: services pursuant to which customers receive firm assurances regarding the availability of capacity and/or deliverability of natural gas, crude oil or other hydrocarbons or water on our assets up to a contracted amount.

Fractionation: the process by which NGLs are further separated into individual, typically more valuable components including ethane, propane, butane, isobutane and natural gasoline.

GAAP: generally accepted accounting principles in the United States of America.

GHGs: greenhouse gases.

Header system: networks of medium-to-large-diameter high pressure pipelines that connect local gathering systems to large diameter high pressure long-haul transportation pipelines.

Interruptible services: services pursuant to which customers receive limited, or no, assurances regarding the availability of capacity and deliverability in our assets.

Keep Whole Processing Contracts: natural gas processing contracts in which we are required to replace the Btu content of the NGLs extracted from inlet wet gas processed with purchased dry natural gas.

Line fill: the volume of oil, in barrels, in the pipeline from the origin to the destination.

Liquefied natural gas or LNG: natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times.

Local distribution company or LDC: LDCs are involved in the delivery of natural gas to ~~consumers~~end users within a specific geographic area.

Long-term: with respect to any contract, a contract with an initial duration greater than one year.

MMBtu: one million British Thermal Units.

Mcf: one thousand cubic feet.

MDth: one thousand dekatherms.

MMcf: one million cubic feet.

Natural gas liquids or NGLs: those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally, such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).

Natural Gas Processing: the separation of natural gas into pipeline-quality natural gas and a mixed NGL stream.

Non-contract barrels (or walk-up barrels): barrels of crude oil that our customers ship based solely on availability of capacity and deliverability with no assurance of future capacity.

No-notice service: those services pursuant to which customers receive the right to transport or store natural gas on assets outside of the daily nomination cycle without incurring penalties.

NYMEX: New York Mercantile Exchange.

Park and loan services: those services pursuant to which customers receive the right to store natural gas in (park), or borrow gas from (loan), our ~~facilities on a seasonal basis.~~facilities.

Percent of Proceeds Processing Contracts: natural gas processing contracts in which we process our customer's natural gas, sell the resulting NGLs and residue gas and divide the proceeds of those sales between us and the customer. Some percent of proceeds contracts may also require our customers to pay a monthly reservation fee for processing capacity.

PHMSA: the United States Department of Transportation's Pipeline and Hazardous Materials Safety Administration.

Play: a proven geological formation that contains commercial amounts of hydrocarbons.

Produced water: all water removed from a well as a byproduct of the production of hydrocarbons and water removed from a well in connection with operations being conducted on the well, including naturally occurring water in the recovery formation, flow back water recovered during completion and fracturing operations and water entering the recovery formation through water flooding techniques.

Receipt point: the point where a product is received by or into a gathering system, processing facility, or transportation pipeline.

Reservoir: a porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (such as crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system.

Residue gas: the natural gas remaining after being processed or treated.

Shale gas: natural gas produced from organic (black) shale formations.

Tailgate: the point at which processed natural gas and NGLs leave a processing facility for transportation to end-user markets.

TBtu: one trillion British Thermal Units.

Tcf: one trillion cubic feet.

Throughput: the volume of products, such as crude oil, natural gas or water, transported or passing through a pipeline, plant, terminal or other facility during a particular period.

Uncommitted shippers (or walk-up shippers): customers that have not signed long-term shipper contracts and have rights under the FERC tariff as to rates and capacity allocation that are different than long-term committed shippers.

Volumetric fee contracts: ~~volumetric fee~~ contracts or other arrangements, including tariff provisions, that generally obligate a customer to pay fees based upon the extent to which such customer utilizes our assets for midstream energy services. Unlike firm fee contracts, under volumetric fee contracts our customers are not generally required to pay a charge to reserve an agreed upon amount of capacity and/or deliverability.

Wellhead: the equipment at the surface of a well that is used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground.

Working gas: the volume of gas in the storage reservoir that is in addition to the cushion or base gas. It may or may not be completely withdrawn during any particular withdrawal season. Conditions permitting, the total working capacity could be used more than once during any season.

Working gas storage capacity: the maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Effective working gas storage capacity excludes base gas and non-cycling working gas.

X/d: the applicable measurement metric per day. For example, MMcf/d means one million cubic feet per day.

PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


	September 30, 2016		December 31, 2015		September 30, 2017		December 31, 2016
	(in thousands)				(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1,359	$	2,234	$	3,279	$	2,459
Accounts receivable, net	53,085		57,757		95,629		59,536
Gas imbalances	890		1,227		1,020		1,597
Inventories	13,375		13,793		10,173		13,093
Derivative assets at fair value	25,690		—
Derivative assets					—		10,967
Prepayments and other current assets	3,838		2,835		3,407		7,628
Total Current Assets	98,237		77,846		113,508		95,280
Property, plant and equipment, net	2,003,532		2,025,018		2,350,830		2,079,232
Goodwill	343,288		343,288		404,838		343,288
Intangible asset, net	94,280		96,546
Unconsolidated investment	455,401		—
Intangible assets, net					98,876		93,522
Unconsolidated investments					922,280		475,625
Deferred tax asset	439,638		452,430		496,472		521,454
Deferred financing costs, net	7,014		6,638		13,326		6,042
Deferred charges and other assets	10,816		14,894		3,016		11,037
Total Assets	$	3,452,206	$	3,016,660	$	4,403,146	$	3,625,480
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)	$	17,046	$	22,218
Accounts payable					$	69,620	$	24,449
Accounts payable to related parties	6,097		7,755		5,955		5,824
Gas imbalances	1,117		1,605		1,119		1,239
Derivative liabilities at fair value	197		—
Derivative liabilities					473		556
Accrued taxes	20,676		13,844		22,890		16,996
Accrued liabilities	10,273		10,206		11,183		16,755
Deferred revenue	52,138		26,511		87,979		60,757
Other current liabilities	6,725		6,880		6,690		6,446
Total Current Liabilities	114,269		89,019		205,909		133,022
Long-term debt, net	1,546,003		901,000		2,261,086		1,555,981
Other long-term liabilities and deferred credits	7,341		5,143		18,396		7,063
Total Long-term Liabilities	1,553,344		906,143		2,279,482		1,563,044
Commitments and Contingencies
Equity:
Class A Shareholders (47,725,000 shares outstanding at September 30, 2016 and December 31, 2015)	168,058		422,310
Class B Shareholders (109,504,440 shares outstanding at September 30, 2016 and December 31, 2015)	—		—
Class A Shareholders (58,075,000 shares outstanding at September 30, 2017 and December 31, 2016)					234,241		250,967
Class B Shareholders (99,154,440 shares outstanding at September 30, 2017 and December 31, 2016)					—		—
Predecessor Equity					—		82,295
Total Partners' Equity	168,058		422,310		234,241		333,262
Noncontrolling interests	1,616,535		1,599,188		1,683,514		1,596,152
Total Equity	1,784,593		2,021,498		1,917,755		1,929,414
Total Liabilities and Equity	$	3,452,206	$	3,016,660	$	4,403,146	$	3,625,480

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015			2017			2016			2017			2016
	(in thousands, except per share amounts)												(in thousands, except per unit amounts)
Revenues:
Crude oil transportation services	$	91,387		$	81,928		$	279,281		$	206,331		$	86,180		$	91,387		$	260,366		$	279,281
Natural gas transportation services	31,444			29,431			89,406			90,620			30,256			31,444			91,370			89,406
Sales of natural gas, NGLs, and crude oil	20,758			20,252			51,514			62,132			32,215			20,487			70,514			51,243
Processing and other revenues	8,536			6,557			24,260			26,730			27,218			9,950			58,882			29,521
Total Revenues	152,125			138,168			444,461			385,813			175,869			153,268			481,132			449,451
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	18,590			18,186			48,116			54,959			26,984			18,319			58,740			47,845
Cost of transportation services (exclusive of depreciation and amortization shown below)	13,528			14,862			43,924			39,069			10,538			10,842			38,799			35,946
Operations and maintenance	14,714			14,071			41,055			36,054			17,412			15,146			45,569			42,374
Depreciation and amortization	20,831			20,802			64,099			61,762			23,782			21,177			67,276			65,074
General and administrative	13,715			12,321			41,710			38,711			16,489			13,981			46,040			42,863
Taxes, other than income taxes	6,717			5,521			19,862			16,547			6,661			6,860			21,799			20,293
Loss on disposal of assets	—			—			1,849			4,483
Contract termination													—			—			—			8,061
(Gain) loss on disposal of assets													—			—			(1,264		)	1,849
Total Operating Costs and Expenses	88,095			85,763			260,615			251,585			101,866			86,325			276,959			264,305
Operating Income	64,030			52,405			183,846			134,228			74,003			66,943			204,173			185,146
Other Income (Expense):
Interest expense, net	(12,157		)	(4,982		)	(31,275		)	(12,901		)	(24,408		)	(12,157		)	(61,539		)	(31,275		)
Unrealized (loss) gain on derivative instrument	(4,419		)	—			5,588			—			—			(4,419		)	1,885			5,588
Equity in earnings of unconsolidated investment	12,066			—			35,387			—
Equity in earnings of unconsolidated investments													123,642			12,764			187,121			37,495
Gain on remeasurement of unconsolidated investment													9,728			—			9,728			—
Other income, net	480			502			1,267			1,983			454			480			796			1,267
Total Other (Expense) Income	(4,030		)	(4,480		)	10,967			(10,918		)
Total Other Income (Expense)													109,416			(3,332		)	137,991			13,075
Net income before tax	60,000			47,925			194,813			123,310			183,419			63,611			342,164			198,221
Deferred income tax expense	(3,209		)	(1,828		)	(12,792		)	(3,600		)	(12,642		)	(3,209		)	(24,982		)	(12,792		)
Net income	56,791			46,097			182,021			119,710			170,777			60,402			317,182			185,429
Net income attributable to noncontrolling interests	(49,750		)	(41,674		)	(163,943		)	(105,431		)	(154,911		)	(49,750		)	(280,534		)	(163,943		)
Net income attributable to TEGP	$	7,041		$	4,423		$	18,078		$	14,279		$	15,866		$	10,652		$	36,648		$	21,486
Allocation of income for the three and nine months ended September 30, 2015:
Net income attributable to TEGP from the beginning of the period to May 11, 2015				$	—					$	7,393
Net income attributable to TEGP from May 12, 2015 to September 30, 2015				4,423						6,886
Allocation of income:
Net income attributable to TEGP													$	15,866		$	10,652		$	36,648		$	21,486
Predecessor operations interest in net income													—			(3,611		)	—			(3,408		)
Net income attributable to TEGP, excluding predecessor operations interest													15,866			7,041			36,648			18,078
Basic net income per Class A share	$	0.15		$	0.09		$	0.38		$	0.14		$	0.27		$	0.15		$	0.63		$	0.38
Diluted net income per Class A share	$	0.15		$	0.09		$	0.38		$	0.14		$	0.27		$	0.15		$	0.63		$	0.38
Basic average number of Class A shares outstanding	47,725			47,725			47,725			47,725			58,075			47,725			58,075			47,725
Diluted average number of Class A shares outstanding	47,775			47,808			47,740			47,812			58,192			47,775			58,193			47,740

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

Nine Months Ended September 30,
2016 2015
(in thousands)
Cash Flows from Operating Activities:
Net income $ 182,021
$ 119,710
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization 69,008
64,755
Equity in earnings of unconsolidated investment (35,387 ) —
Distributions from unconsolidated investment 35,387
—
Noncash change in fair value of derivative financial instruments (5,391 ) (217 )
Deferred tax expense 12,792
3,600
Noncash compensation expense 4,405
4,183
Loss on disposal of assets 1,849
4,483
Changes in components of working capital:
Accounts receivable and other 7,940
(11,538 )
Inventories (867 ) (5,265 )
Accounts payable and accrued liabilities 4,690
6,883
Deferred revenue 25,303
13,995
Other operating, net (779 ) (5,142 )
Net Cash Provided by Operating Activities 300,971
195,447
Cash Flows from Investing Activities:
Acquisition of unconsolidated affiliate (436,022 ) —
Acquisition of Pony Express membership interest (49,118 ) (700,000 )
Capital expenditures (45,252 ) (65,146 )
Contributions to unconsolidated investment (35,452 ) —
Distributions from unconsolidated investment in excess of cumulative earnings 16,073
—
Other investing, net 205
(4,625 )
Net Cash Used in Investing Activities (549,566 ) (769,771 )
Cash Flows from Financing Activities:
Acquisition of Pony Express membership interest (425,882 ) —
Proceeds from issuance of long-term debt 400,000
—
Proceeds from public offering of TEP common units, net of offering costs 290,474
551,243
Borrowings under revolving credit facility, net 252,000
285,000
Distributions to noncontrolling interests (177,449 ) —
Partial exercise of call option (151,434 ) —
Proceeds from private placement of TEP common units, net of offering costs 90,009
—
TEGP distributions to Class A shareholders (29,971 ) (3,484 )
Contributions from noncontrolling interests 8,700
19,303
Proceeds from initial public offering of Class A shares, net —
1,314,741
Acquisition of Acquired TEP Units —
(953,600 )
Distribution of Excess Proceeds to Exchange Right Holders —
(334,068 )
Distributions to TEP unitholders —
(74,843 )
Acquisition of additional Tallgrass Equity units —
(171,948 )
Distributions to TEGP Predecessor, net —
(13,533 )
Tallgrass Equity distributions to noncontrolling interests —
(12,969 )
Other financing, net (8,727 ) (13,376 )
Net Cash Provided by Financing Activities 247,720
592,466
Net Change in Cash and Cash Equivalents (875 ) 18,142
Cash and Cash Equivalents, beginning of period 2,234
867
Cash and Cash Equivalents, end of period $ 1,359
$ 19,009

Schedule of Noncash Investing and Financing Activities:
Property, plant and equipment acquired via the cash management agreement with Tallgrass Development, LP $ —
$ 120,254
Contributions from noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP $ —
$ 43,401
Distribution to noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP $ —
$ 44,142



	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Cash Flows from Operating Activities:
Net income	$	317,182		$	185,429
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	73,087			70,583
Equity in earnings of unconsolidated investments	(187,121		)	(37,495		)
Distributions from unconsolidated investments	187,624			37,361
Deferred income tax expense	24,982			12,792
Gain on remeasurement of unconsolidated investment	(9,728		)	—
Changes in components of working capital:
Accounts receivable and other	(34,189		)	8,220
Accounts payable and accrued liabilities	42,680			4,916
Deferred revenue	26,898			25,303
Other current assets and liabilities	5,032			(1,032		)
Other operating, net	3,930			(14		)
Net Cash Provided by Operating Activities	450,377			306,063
Cash Flows from Investing Activities:
Acquisition of Rockies Express membership interest	(400,000		)	(436,022		)
Acquisition of Terminals and NatGas	(140,000		)	—
Acquisition of Douglas Gathering System	(128,526		)	—
Capital expenditures	(88,050		)	(55,397		)
Acquisition of Deeprock Development	(57,202		)	—
Distributions from unconsolidated investments in excess of cumulative earnings	41,886			16,073
Acquisition of PRB Crude System	(36,030		)	—
Contributions to unconsolidated investments	(31,570		)	(35,515		)
Acquisition of Pony Express membership interest	—			(49,118		)
Other investing, net	(13,449		)	205
Net Cash Used in Investing Activities	(852,941		)	(559,774		)
Cash Flows from Financing Activities:
Proceeds from issuance of long-term debt	850,000			400,000
Distributions to noncontrolling interests	(229,710		)	(177,449		)
(Repayments) borrowings under revolving credit facilities, net	(136,000		)	252,000
Proceeds from public offering of TEP common units, net of offering costs	112,393			290,474
Partial exercise of call option	(72,381		)	(151,434		)
TEGP distributions to Class A shareholders	(52,704		)	(29,971		)
Repurchase of TEP common units from TD	(35,335		)	—
Acquisition of Pony Express membership interest	—			(425,882		)
Proceeds from private placement of TEP common units, net of offering costs	—			90,009
Other financing, net	(32,879		)	5,089
Net Cash Provided by Financing Activities	403,384			252,836
Net Change in Cash and Cash Equivalents	820			(875		)
Cash and Cash Equivalents, beginning of period	2,459			2,234
Cash and Cash Equivalents, end of period	$	3,279		$	1,359

Schedule of Noncash Investing and Financing Activities:
TEP common units issued as partial consideration to acquire additional 9% membership interest in Deeprock Development	$	6,617		$	—
Increase in accrual for payment of property, plant and equipment	$	1,342		$	—

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

TEGP Predecessor Partners' Equity (excluding noncontrolling interests) Noncontrolling Interests Total Equity
Class A Shares Class B Shares
(in thousands)
Balance at January 1, 2016 $ —
$ 422,310
$ —
$ 1,599,188
$ 2,021,498
Net income —
18,078
—
163,943
182,021
Acquisition of additional 31.3% membership interest in Pony Express —
(255,617 ) —
(173,422 ) (429,039 )
Issuance of TEP common units to public, net of offering costs —
24,543
—
265,931
290,474
Distributions to noncontrolling interests —
—
—
(177,449 ) (177,449 )
Partial exercise of call option —
(20,427 ) —
(156,865 ) (177,292 )
Issuance of TEP common units in a private placement, net of offering costs —
7,592
—
82,417
90,009
TEGP distributions to Class A shareholders —
(29,971 ) —
—
(29,971 )
Contributions from noncontrolling interests —
—
—
8,700
8,700
Noncash compensation expense —
1,060
—
5,931
6,991
Acquisition of membership interest in BNN —
(464 ) —
(5,536 ) (6,000 )
Contributions from TD —
1,611
—
3,697
5,308
Costs associated with equity issuance —
(657 ) —
—
(657 )
Balance at September 30, 2016 $ —
$ 168,058
$ —
$ 1,616,535
$ 1,784,593

TEGP Predecessor Partners' Equity (excluding noncontrolling interests) Noncontrolling Interests Total Equity
Class A Shares Class B Shares
(in thousands)
Balance at January 1, 2015 $ 146,866
$ —
$ —
$ 1,648,285
$ 1,795,151
Net income for the period from January 1, 2015 to May 11, 2015 7,393
—
—
32,196
$ 39,589
Issuance of TEP common units to the public, net of offering costs 63,477
—
—
487,766
$ 551,243
Acquisition of additional 33.3% Pony Express membership interest (98,446 ) —
—
(601,554 ) $ (700,000 )
Distributions to TEGP Predecessor (4,108 ) —
—
(9,425 ) $ (13,533 )
Consolidation of TEGP Predecessor assets (115,182 ) 115,182
—
—
$ —
Issuance of Class A shares to the public, net of offering costs —
1,314,741
—
—
$ 1,314,741
Acquisition of Acquired TEP Units from TD —
(953,600 ) —
—
$ (953,600 )
Distribution of excess Offering proceeds to Exchange Right Holders —
(334,068 ) —
—
$ (334,068 )
Acquisition of Tallgrass Equity units from Exchange Right Holders —
(171,948 ) —
—
$ (171,948 )
Deferred tax asset —
445,128
—
—
$ 445,128
Net income for the period from May 12, 2015 to September 30, 2015 —
6,886
—
73,235
$ 80,121
Issuance of common units under TEP LTIP plan —
(661 ) —
(5,901 ) $ (6,562 )
TEGP distributions to Class A Shareholders —
(3,484 ) —
—
$ (3,484 )
Noncash compensation expense —
195
—
7,325
$ 7,520
Contributions from noncontrolling interests —
—
—
110,553
$ 110,553
Distributions to noncontrolling interests —
—
—
(132,355 ) $ (132,355 )
Distributions to TEP GP Members —
(7,465 ) —
—
$ (7,465 )
Acquisition of noncontrolling interests —
—
—
(600 ) $ (600 )
Balance at September 30, 2015 $ —
$ 410,906
$ —
$ 1,609,525
$ 2,020,431



	Predecessor Equity			Partners' Capital					Noncontrolling Interests			Total Equity
	Predecessor Equity			Class A Shares			Class B Shares		Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2017	$	82,295		$	250,967		$	—	$	1,596,152		$	1,929,414
Acquisition of Terminals and NatGas	(82,295		)	(21,314		)	—		(36,391		)	(140,000		)
Net income	—			36,648			—		280,534			317,182
Issuance of TEP units to the public, net of offering costs	—			11,350			—		101,043			112,393
TEGP distributions to Class A shareholders	—			(52,704		)	—		—			(52,704		)
Noncash compensation expense	—			1,186			—		6,169			7,355
TEP LTIP units tendered by employees to satisfy tax withholding obligations	—			(1,263		)	—		(11,139		)	(12,402		)
Partial exercise of call option	—			(12,052		)	—		(72,890		)	(84,942		)
Repurchase of TEP common units from TD	—			(3,618		)	—		(31,717		)	(35,335		)
Acquisition of additional 24.99% membership interest in Rockies Express	—			23,522			—		40,159			63,681
Acquisition of additional 40% membership interest in Deeprock Development	—			—			—		45,869			45,869
Acquisition of noncontrolling interests	—			669			—		(7,109		)	(6,440		)
Contributions from TD	—			850			—		1,451			2,301
Contributions from noncontrolling interest	—			—			—		1,093			1,093
Distributions to noncontrolling interest	—			—			—		(229,710		)	(229,710		)
Balance at September 30, 2017	$	—		$	234,241		$	—	$	1,683,514		$	1,917,755

	Predecessor Equity			Partners' Capital					Noncontrolling Interests			Total Equity
	Predecessor Equity			Class A Shares			Class B Shares		Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2016	$	71,564		$	422,310		$	—	$	1,599,188		$	2,093,062
Net income	3,408			18,078			—		163,943			185,429
Issuance of TEP units to the public, net of offering costs	—			24,543			—		265,931			290,474
Issuance of TEP common units in a private placement, net of offering costs	—			7,592			—		82,417			90,009
TEGP distributions to Class A Shareholders	—			(29,971		)	—		—			(29,971		)
Noncash compensation expense	—			1,060			—		5,931			6,991
Acquisition of additional 31.3% Pony Express membership interest	—			(255,617		)	—		(173,422		)	(429,039		)
Partial exercise of call option	—			(20,427		)	—		(156,865		)	(177,292		)
Contributions from TD	—			1,611			—		3,697			5,308
Contributions from noncontrolling interest	—			—			—		8,700			8,700
Distributions to noncontrolling interest	—			—			—		(177,449		)	(177,449		)
Contribution from Predecessor Entities, net	5,116			—			—		—			5,116
Acquisition of noncontrolling interests	—			(464		)	—		(5,536		)	(6,000		)
Cost associated with equity issuance	—			(657		)	—		—			(657		)
Balance at September 30, 2016	$	80,088		$	168,058		$	—	$	1,616,535		$	1,864,681

TALLGRASS ENERGY GP, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Description of Business

Tallgrass Energy GP, LP ("TEGP" or the "Partnership") is a limited partnership that has elected to be treated as a corporation for U.S. federal income tax purposes. "We," "us," "our" and similar terms refer to TEGP was formed as part of the reorganization of entities controlled by Tallgrass Equity, LLC ("Tallgrass Equity") to effect the initial public offering of Class A shares of TEGP (the "Offering"), which was completed on May 12, 2015.together with its consolidated subsidiaries. TEGP's sole cash-generating asset as of September 30, 2017 is an approximate ~~30.35%~~36.94% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of direct and indirect partnership interests in Tallgrass Energy Partners, LP ("TEP"), as described ~~below:~~below, that were historically owned by entities controlled by Tallgrass Equity, including Tallgrass Development, LP ("TD"):

100% of the outstanding membership interests in Tallgrass MLP GP, LLC ("TEP GP"), which owns the general partner interest in TEP as well as all of the TEP incentive distribution rights ("IDRs"). The general partner interest in TEP is represented by 834,391 general partner units, representing an approximate 1.13% general partner interest in TEP at September 30, ~~2016.~~2017.

20,000,000 TEP common units, representing an approximate ~~27.18%~~27.02% limited partner interest in TEP at September 30, ~~2016.~~

The term "TEGP Predecessor" refers to TEGP, as recast to show the effects of the reorganization, for the periods prior to completion of the Offering on May 12, 2015. "We," "us," "our" and similar terms refer to TEGP together with its consolidated subsidiaries or to TEGP Predecessor together with its consolidated subsidiaries, as the context requires, including, in both cases, Tallgrass Equity and TEP (and their respective subsidiaries).2017.

TEP is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. ~~TEP currently provides crude oil transportation~~TEP's operations are located in and provide services to ~~customers in Wyoming, Colorado,~~certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the ~~surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns~~Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations.

Our reportable business segments are:

Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities;

Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline ~~commencing in Guernsey, Wyoming~~system; and ~~terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado,~~

Gathering, Processing & Terminalling—the ownership and ~~interconnects with~~operation of natural gas gathering, processing, treating and fractionation facilities; crude oil gathering, storage and terminalling facilities; the ~~pipeline just east~~provision of ~~Sterling, Colorado (the "Pony Express System").~~ water business services primarily to the oil and gas exploration and production industry; and the transportation of NGLs.

Natural Gas Transportation. TEP provides natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) ~~TEP's 25%~~its 49.99% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), ~~a Delaware limited liability company~~ which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio (the "Rockies Express Pipeline"), inclusive of the additional 24.99% membership interest acquired from TD effective March 31, 2017 as discussed in Note 4 – Acquisitions, and TEP's 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas") acquired effective January 1, 2017, which operates the Rockies Express Pipeline, (2) the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and (3) the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline").

Crude Oil Transportation. TEP ~~also~~currently provides crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a FERC-regulated crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma, and includes a lateral in Northeast Colorado commencing in Weld County, Colorado that interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System").

Gathering, Processing & Terminalling. TEP provides natural gas gathering and processing services for customers in Wyoming atthrough: (1) a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System") that was acquired on June 5, 2017, as discussed in Note 4 – Acquisitions, (2) the Casper and Douglas natural gas processing facilities, and (3) the West Frenchie Draw natural gas treating ~~facility (collectively,~~facility. TEP also provides crude oil gathering services for customers in Wyoming through a crude oil gathering system in the ~~"Midstream Facilities"~~Powder River Basin (the "PRB Crude System"), that was acquired on August 3, 2017, as discussed in Note 4 – Acquisitions; and NGL transportation services in Northeast ~~Colorado.~~Colorado and Wyoming. TEP performs water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, and ~~Texas~~Wyoming through BNN Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through TEP's 100% membership interest in Tallgrass Terminals, LLC ("Terminals") acquired effective January 1, 2017, which owns and operates crude oil terminals near Sterling, Colorado (the "Sterling Terminal") and in Weld County, Colorado (the "Buckingham Terminal"). ~~TEP's operations are strategically located~~Terminals also owns a 69% membership interest in ~~and provide services~~Deeprock Development, LLC

("Deeprock Development"), which owns a crude oil terminal in Cushing, Oklahoma (the "Cushing Terminal"), inclusive of an additional 49% membership interest in Deeprock Development acquired in July 2017 as discussed in Note 4 – Acquisitions. The Gathering, Processing & Terminalling segment also includes newly formed Stanchion Energy, LLC ("Stanchion"), which transacts in crude oil.

The term "Terminals Predecessor" refers to ~~certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins~~Terminals and the ~~Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus~~term "NatGas Predecessor" refers to NatGas prior to their acquisition by TEP on January 1, 2017. Terminals Predecessor and ~~Utica shale formations.~~NatGas Predecessor are collectively referred to as the Predecessor Entities, as further discussed in Note 2 – Summary of Significant Accounting Policies. Financial results for all prior periods have been recast to reflect the operations of the Predecessor Entities. Predecessor Equity as presented in the condensed consolidated financial statements represents the capital account activity of Terminals Predecessor and NatGas Predecessor prior to January 1, 2017. For additional information regarding these acquisitions, see Note 4 – Acquisitions.

~~Our reportable business segments are:~~

~~Crude Oil Transportation & Logistics—the ownership and operation of a FERC-regulated crude oil pipeline system;~~

~~Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; and~~

Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, the provision of water business services primarily to the oil and gas exploration and production industry and the transportation of NGLs.

2. Summary of Significant Accounting Policies

Basis of Presentation

These condensed consolidated financial statements and related notes for the three and nine months ended September 30, ~~2016~~2017 and ~~2015~~2016 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America ("GAAP") for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three and nine months ended September 30, ~~2016~~2017 and ~~2015~~2016 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.

Our financial results for the three and nine months ended September 30, ~~2016~~2017 are not necessarily indicative of the results that may be expected for the full year ending December 31, ~~2016.~~2017. The accompanying condensed consolidated interim financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016 ("~~2015~~2016 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February ~~17, 2016.~~15, 2017.

The condensed consolidated financial statements ~~of TEGP for~~include the ~~three and nine months ended September 30, 2015 include historical cost basis~~ accounts ~~of the assets~~ of TEGP and ~~were prepared in contemplation of TEGP's initial public offering of Class A shares completed on May 12, 2015~~its subsidiaries and ~~the acquisition of an approximately 30.35% interest in Tallgrass Equity as described in Note 1 –~~ ~~Description of Business, which was accounted for as a transaction between entities under common control in accordance with ASC 805.~~controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Both TEGP and TEGP Predecessor are considered entities under common control and, as such, the transfer between the entities of the assets and liabilities has been recorded by TEGP at historical cost. TEGP, as used herein, refers to the consolidated financial results and operations for TEGP Predecessor prior to the completion of the Offering and to TEGP thereafter.

Net income or loss from consolidated subsidiaries that are not wholly-owned by TEGP is attributed to TEGP and noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the allocation of cash distributions and may not follow the respective ownership percentages held by TEGP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Pony Express effective September 1, 2014, TEP, Tallgrass Development, LP ("TD"), and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million (prorated to approximately $5.4 million for the quarter ended September 30, 2014) through the quarter ended September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ended December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 are attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests.

As further discussed in Note 4 – Acquisitions, TEP closed the acquisition of Terminals and NatGas effective January 1, 2017. As the acquisitions of Terminals and NatGas are considered transactions between entities under common control, and a change in reporting entity, the financial information presented has been recast to include Terminals and NatGas for all periods presented. Net equity distributions of the Predecessor Entities included in the condensed consolidated financial statements represent transfers of cash as a result of TD's centralized cash management system prior to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the subsidiaries of TD. These loans were then periodically recorded as equity distributions.

The accompanying condensed consolidated financial statements of TEGP include historical cost-basis accounts of the assets and liabilities of the Predecessor Entities for the periods prior to January 1, 2017, the date TEP acquired Terminals and NatGas from TD, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. TEGP, TEP, and the Predecessor Entities are all considered "entities under common control" as defined under GAAP and, as such, the transfers between the entities of the assets and liabilities have been recorded by TEGP at historical cost.

A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. We have presented separately in our condensed consolidated balance sheets, to the extent material, the liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Our consolidated VIEs do not have material assets that can only be used to settle specific obligations of the consolidated VIEs. Tallgrass Equity is considered to be a VIE under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, we have determined that we are the primary beneficiary as we have the right to receive benefits of Tallgrass Equity that could potentially be significant to Tallgrass Equity. ~~Also, as discussed further under "New Accounting Pronouncements" below, under the new authoritative guidance effective January 1, 2016,~~ TEP is also considered to be a ~~VIE.~~VIE under the applicable authoritative guidance. Based on a qualitative analysis, we have determined that TEP GP is the primary beneficiary of TEP and we continue to consolidate TEP accordingly. Pony Express was considered to be a VIE under the applicable authoritative guidance prior to our acquisition of an additional 31.3% membership interest effective January 1, 2016. Effective January 1, 2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in Pony Express.

Use of Estimates

Certain amounts included in or affecting these condensed consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts reported for assets, liabilities, revenues, and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Management evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from these estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Accounting ~~Pronouncements Not Yet~~Pronouncement Recently Adopted

~~Revenue Recognition~~ASU No. 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business"

In ~~May 2014,~~January 2017, the FASB issued Accounting Standards Update ("ASU") No. ~~2014-09, Revenue from Contracts~~2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. ASU 2017-01 clarifies the definition of a business with ~~Customers (Topic 606). ASU 2014-09 provides~~the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing a ~~comprehensive and converged~~screen to determine when an integrated set of ~~principles-based revenue recognition guidelines which supersede the existing industry~~assets and ~~transaction-specific standards.~~activities is not a business. The ~~core principle~~screen requires that when substantially all of the ~~new guidance~~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 ~~an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects~~need to be ~~entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify~~further evaluated. The ASU also narrows the ~~contract~~definition of the term "output" so that the term is consistent with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract.

~~Throughout the first half of 2016, the FASB has issued a series of subsequent updates to~~how outputs are described under the revenue recognition guidance in Topic 606, including ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, and ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients.606.

The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, and ASU 2016-12 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. In light of this recently issued accounting guidance, we have started the process of reviewing our existing revenue contracts. Due to the early stage of this process, we are currently not in a position to estimate the impact the guidance will have on our consolidated financial statements. We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts as of January 1, 2018 through a cumulative adjustment to equity. Consolidated revenues for periods prior to January 1, 2018 would not be revised.

~~ASU No. 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory"~~

In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory. ASU 2015-11 establishes a "lower of cost and net realizable value" model for the measurement of most inventory balances. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.

~~The amendments in ASU 2015-11~~2017-01 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, ~~2016.~~2017. Early adoption is ~~permitted.~~permitted in certain circumstances. We ~~are currently evaluating~~elected to adopt the ~~impact of~~guidance in ASU ~~2015-11, but do not anticipate a material impact on our consolidated financial statements.~~2017-01 effective April 1, 2017.

ASU No. ~~2016-02, "Leases~~2017-04, "Intangibles - Goodwill and Other (Topic ~~842)"~~350): Simplifying the Test for Goodwill Impairment"

In ~~February 2016,~~January 2017, the FASB issued ASU No. ~~2016-02, Leases (Topic 842). ASU 2016-02 provides~~2017-04, which simplifies the subsequent measurement of goodwill by eliminating "Step 2" from the goodwill impairment test, which involved calculating the implied fair value of goodwill by determining the fair value at the impairment testing date of a ~~comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease~~reporting unit's assets and ~~lease liabilities on~~liabilities. Instead, under the ~~balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition~~simplified test approach, an entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of ~~a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.~~goodwill allocated to that reporting unit.

The amendments in ASU ~~2016-02~~2017-04 are effective for public entities for annual ~~reporting~~periods and interim periods within those annual periods beginning after December 15, ~~2018, and~~2019. Early adoption is permitted for interim ~~periods within that reporting period. Early application is permitted.~~or annual goodwill impairment tests performed on testing dates after January 1, 2017. We ~~are currently evaluating~~elected to adopt the ~~impact~~guidance in ASU 2017-04 effective April 1, 2017, and as a result applied the new guidance to our annual goodwill impairment tests performed as of ~~ASU 2016-02.~~August 31, 2017.

ASU No. 2016-09, "Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting"

In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Among other changes, ASU 2016-09 allows an entity to make an entity-wide accounting policy election to either estimate the number of awards expected to vest (consistent with current GAAP) or account for forfeitures when they occur.

The amendments in ASU 2016-09 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We ~~are currently evaluating~~adopted the ~~impact~~guidance in ASU 2016-09 effective January 1, 2017 and made a policy election to account for forfeitures when they occur. The adoption of ASU 2016-09 ~~but do~~did not ~~anticipate~~have a material impact on our consolidated financial statements.

Accounting Pronouncements ~~Recently~~Not Yet Adopted

~~ASU No. 2016-15, "Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments"~~Revenue Recognition

In ~~August 2016,~~May 2014, the FASB issued ASU No. ~~2016-15, Statement~~2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of ~~Cash Flows (Topic 230), Classification~~principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of ~~Certain Cash Receipts~~the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and ~~Cash Payments.~~(5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU ~~2016-15 provides explicit guidance on accounting for eight specific~~2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash ~~flow issues~~flows arising from contracts with ~~the objective of reducing diversity~~customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in ~~practice, including debt prepayment or debt extinguishment costs, settlement of certain debt instruments, contingent consideration payments made after a business combination, proceeds~~judgments, and assets recognized from the ~~settlement~~costs to obtain or fulfill a contract.

Throughout 2015 and 2016, the FASB has issued a series of ~~insurance claims, proceeds~~subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from the settlement of corporate owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and applicationContracts with Customers (Topic 606): Deferral of the ~~predominance principle.~~Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers.

The amendments in ASU ~~2016-015~~2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 are effective for public entities for ~~fiscal years~~annual reporting periods beginning after December 15, 2017, and for interim periods within ~~those fiscal years.~~that reporting period. Early ~~adoption~~application is permitted ~~including adoption in an interim period.~~ for annual reporting periods beginning after December 15, 2016.

We ~~adopted~~are currently evaluating the ~~standard effective January 1, 2016. The~~impact of our pending adoption of the revised guidance. The status of our implementation is as follows:

We have formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain revenue contract types, and project status.

We have reviewed contracts for each revenue stream identified within each of our business segments and we are currently determining and documenting expected changes in revenue recognition upon adoption of the revised guidance.

We are evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from our contract review process.

We plan to provide internal training and awareness related to the revised guidance to the key stakeholders throughout our organization.

While we have tentatively concluded that the implementation of ASU ~~2016-15 did~~2014-09 will not have a material impact on our revenue recognition policies for a substantial number of our contracts, management has identified several areas of potential impact through the contract review process currently underway, including the accounting for non-cash consideration, particularly in our Crude Oil Transportation and Gathering, Processing & Terminalling segments, and the timing of revenue recognition with respect to deficiency payments received in our Crude Oil Transportation segment. We are currently working

with an industry group to develop positions regarding these outstanding items. We are in the process of quantifying the impact of adoption, but we cannot reasonably estimate the full impact of the standard until the industry reaches consensus on these issues. We do anticipate significant changes to our disclosures based on the additional requirements prescribed by the standard. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities. Additionally, we are currently evaluating our business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new revenue guidance.

We will continue to conduct our contract review process throughout 2017 and, as a result, additional areas of impact may be identified. We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to equity. Consolidated revenues presented in our comparative financial ~~position and results of operations.~~statements for periods prior to January 1, 2018 would not be revised.

ASU No. ~~2015-17, "Income Taxes~~2016-02, "Leases (Topic ~~740): Balance Sheet Classification of Deferred Taxes"~~842)"

In ~~November 2015,~~February 2016, the FASB issued ASU No. ~~2015-17, Income Taxes~~2016-02, Leases (Topic ~~740): Balance Sheet Classification of Deferred Taxes.~~842). ASU ~~2015-17 simplifies~~2016-02 provides a comprehensive update to the ~~presentation of deferred income taxes.~~lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ~~this update require that deferred tax liabilities and assets be classified~~ASU 2016-02 include a revised definition of a lease as ~~noncurrent in a classified statement of financial position.~~well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

The amendments in ASU 2015-17 are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The adoption of ASU 2015-17 did not have a material impact on our financial position and results of operations.

~~ASU No. 2015-16, "Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments"~~

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. ASU 2015-16 simplifies the accounting for measurement-period adjustments for provisional amounts recognized in a business combination by eliminating the requirement for an acquirer to retrospectively account for measurement-period adjustments. Under the updated guidance, the acquirer must recognize adjustments in the reporting period in which the adjustment amounts are determined and the effect on earnings as a result of the change to the provisional amounts must be calculated as if the accounting had been completed at the acquisition date.

~~The amendments in ASU 2015-16~~2016-02 are effective for public entities for annual ~~periods and interim periods within those annual~~reporting periods beginning after December 15, ~~2015. The adoption of ASU 2015-16 did not have a material impact on our financial position~~2018, and ~~results of operations.~~

~~ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis"~~

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis. ASU 2015-02 changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 modifies the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, and changes certain aspects of the consolidation analysis for ~~reporting entities that are involved with VIEs, particularly for those with fee arrangements and related party relationships.~~

~~The amendments in ASU 2015-02 are effective for public entities for annual periods and~~ interim periods within ~~those annual periods beginning after December 15, 2015. The adoption~~that reporting period. Early application is permitted. We are currently evaluating the impact of ASU ~~2015-02 did not have a material impact on our financial position and results of operations.~~

ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period"

In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved.

ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2014-12 did not have a material impact on our financial position and results of operations.2016-02.

3. Variable Interest Entities

~~As discussed in Note 2 –~~ ~~Summary of Significant Accounting Policies,~~ ~~upon adoption of the accounting guidance in ASU 2015-02 effective January 1, 2016, we determined that~~ TEP is a VIE of which TEP GP, our consolidated subsidiary, is the primary beneficiary. We continue to consolidate TEP accordingly. We have not provided any additional financial support other than TEP GP's initial capital contribution to acquire the general partner interest in TEP and have no contractual commitments or obligations to provide additional financial support to TEP.

TEGP, as the managing member of Tallgrass Equity, has voting rights disproportionate to its ownership interest. As a result, we have determined that Tallgrass Equity is a VIE of which we are the primary beneficiary and we consolidate Tallgrass Equity accordingly. We have not provided any additional financial support to Tallgrass Equity other than our initial capital contribution to acquire a portion of ~~the approximate 30.35%~~our controlling interest in Tallgrass Equity and have no contractual commitments or obligations to provide additional financial support to Tallgrass Equity.

Pony Express was considered to be a VIE under the applicable authoritative guidance prior to our acquisition of an additional 31.3% membership interest effective January 1, 2016. Effective January 1, 2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in Pony Express.

Other than TEGP's deferred tax asset of approximately ~~$439.6~~$496.5 million and ~~$452.4~~$521.5 million at September 30, ~~2016~~2017 and December 31, ~~2015,~~2016, respectively, the assets and liabilities included in our condensed consolidated balance sheets at September 30, ~~2016~~2017 and December 31, ~~2015~~2016 represent the consolidated assets and liabilities of Tallgrass Equity, including the assets and liabilities of TEP.

4. Acquisitions

TEP Acquisition of Outrigger Powder River Operating, LLC

On August 3, 2017, TEP acquired 100% of the membership interests of Outrigger Powder River Operating, LLC (subsequently renamed as Tallgrass Crude Gathering, LLC, "TCG"), which owns the PRB Crude System, a crude oil gathering system in the Powder River Basin with approximately 34 miles of gathering lines and ~~Pony Express.~~approximately 150,000 acres dedicated on a long-term fee-based contract, for approximately $36 million, subject to working capital adjustments. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.

~~4. Acquisitions~~

~~Acquisition of a 25% Membership Interest in Rockies Express Pipeline LLC~~

On March 29, 2016, TD's indirect wholly owned subsidiary Rockies Express Holdings, LLC ("REX Holdings") signed a purchase agreement (the "REX Purchase Agreement") with a unit of Sempra U.S. Gas and Power ("Sempra") to acquire Sempra's 25% membership interest in Rockies Express for cash consideration of $440 million, subject to adjustment under the REX Purchase Agreement.

On April 28, 2016, we announced that TD offered TEP the right to assume the rights and obligations of REX Holdings under the REX Purchase Agreement. On May 6, 2016, TEP REX Holdings, LLC ("TEP REX"), an indirect wholly-owned subsidiary of TEP, and REX Holdings entered into an Assignment and Assumption Agreement pursuant to which REX Holdings assigned to TEP REX all of its rights under the REX Purchase Agreement and, in exchange, TEP REX assumed all of the rights and obligations of REX Holdings under the REX Purchase Agreement. Subsequently on May 6, 2016, TEP REX closed the purchase of a 25% membership interest in Rockies Express from Sempra pursuant to the REX Purchase Agreement for cash consideration of approximately $436.0 million, after making the adjustments to the purchase price required by the REX Purchase Agreement.

Our investment in Rockies Express is recorded under the equity method of accounting and reported as "Unconsolidated investment" on our condensed consolidated balance sheet. As of May 6, 2016, the difference betweenThe following represents the fair value of ~~our investment in Rockies Express of $436.0 million~~assets acquired and the book value of the underlying net assets of approximately $840.7 million results in a negative basis difference of approximately $404.7 million. The basis difference has been allocated to property, plant and equipment and long-term debt based on their respective fair valuesliabilities assumed at the date of acquisition. The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years, which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. The basis difference at September 30, 2016 was allocated as follows:August 3, 2017 (in thousands):

Basis Difference Amortization Period
(in thousands)
Long-term debt $ 7,878
2 - 25 years
Property, plant and equipment (406,987 ) 35 years
Total basis difference $ (399,109 )



Accounts receivable	$	117
Property, plant and equipment	29,306
Intangible asset	6,694			⁽¹⁾
Accounts payable and accrued liabilities	(87		)
Net identifiable assets acquired	$	36,030


⁽¹⁾	The $6.7 million intangible asset acquired represents a major customer contract. This intangible asset is amortized on a straight-line basis over a period of 8 years, the remaining term of the contract at the time of acquisition.

~~During the period from May 6, 2016 to~~At September 30, 2016, we recognized equity in earnings from Rockies Express of $35.4 million, inclusive of the amortization of the negative basis difference discussed above, and received distributions from and made contributions to Rockies Express of $51.5 million and $35.5 million, respectively.

~~Summarized financial information for Rockies Express is as follows:~~

September 30, 2016
(in thousands)
Current assets $ 170,472
Noncurrent assets $ 6,058,941
Current liabilities $ 173,447
Noncurrent liabilities $ 2,638,071
Members' equity $ 3,417,895

Three Months Ended September 30, 2016 Period from May 6, 2016 to September 30, 2016
(in thousands)
Revenue $ 159,421
$ 257,582
Operating income $ 66,436
$ 110,268
Net income to Members $ 34,184
$ 118,925

~~Acquisition of Additional 31.3% Membership Interest in Pony Express~~

Effective January 1, 2016, TEP acquired an additional 31.3% membership interest in Pony Express in exchange for cash consideration of $475 million and 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of TEP's common units) issued to TD for total consideration of approximately $743.6 million. The transaction increased TEP's aggregate membership interest in Pony Express to 98.0%. As part of the transaction, TD granted TEP an 18 month call option covering the newly issued 6,518,000 common units at a price of $42.50. On the effective date of the acquisition, the call option was valued at $46.0 million. As discussed in Note 9 – ~~Risk Management,~~ on July 21, 2016, TEP partially exercised the option covering 3,563,146 of the common units. On October 31, 2016, TEP partially exercised the option covering 1,251,760 of the common units, leaving 1,703,094 remaining common units subject to the call option as of November 2, 2016. As a result of the partial exercise on July 21, 2016, TEP derecognized a portion of the derivative asset balance, recognizing approximately $25.9 million through equity during the nine months ended September 30, 2016.

The acquisition of the additional 31.3% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction has not been recast to reflect the additional 31.3% membership interest.

Cash outflows to acquire an additional noncontrolling interest in Pony Express are classified as an investing activity in the accompanying condensed consolidated statements of cash flows to the extent the consideration paid was used to directly fund the construction of the underlying assets by the noncontrolling member. Cash outflows to acquire an additional noncontrolling interest in excess of the cost to construct the underlying assets are classified as financing activities. For the nine months ended September 30, 2016, $49.1 million of the $475 million paid to acquire the additional 31.3% membership interest in Pony Express was classified as an investing activity and $425.9 million was classified as a financing activity.

~~TEP Acquisition of BNN Western, LLC~~

On December 16, 2015, Whiting Oil and Gas Corporation ("Whiting"), BNN Redtail, LLC ("Redtail"), and BNN Western, LLC ("Western"), a newly formed Delaware limited liability company, entered into a definitive Transfer, Purchase and Sale Agreement, pursuant to which Redtail acquired 100% of the outstanding membership interests of Western from Whiting in exchange for total cash consideration of $75 million. Western's assets consist of a fresh water delivery and storage system and produced water gathering and produced water disposal system, which together comprise 62 miles of pipeline along with associated fresh water ponds and disposal wells. As part of the transaction with Whiting, Whiting also executed a five-year fresh water service contract and a nine-year gathering and disposal contract.

~~At December 31, 2015,~~2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. ~~The $75 million purchase price~~TEP is in the process of ~~the assets was allocated entirely~~obtaining additional information to ~~property, plant~~identify and ~~equipment. No adjustments were made to these provisional amounts and the allocation of~~measure all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. Actual revenue and net loss attributable to TEP from TCG of less than $1 million was ~~considered final as~~recognized in the accompanying condensed consolidated statements of income for the period from August 3, 2017 to September 30, ~~2016.~~2017.

~~TEGP's unaudited~~Acquisitions of Additional Interests in Deeprock Development

On July 20, 2017, TEP acquired an additional 40% membership interest in Deeprock Development from Kinder Morgan Cushing, LLC for cash consideration of approximately $57.2 million, net of cash acquired. TEP subsequently acquired an additional 9% membership interest in Deeprock Development from Deeprock Energy Resources LLC ("DER") on July 21, 2017, as discussed further below.

Upon closing of the acquisition of the 40% membership interest on July 20, 2017, TEP obtained a controlling financial interest in Deeprock Development and accordingly has accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEP remeasured its previously held 20% equity interest in Deeprock Development to its fair value of $22.9 million, recognized a gain of $9.7 million in "Gain on remeasurement of unconsolidated investment" in the condensed consolidated statements of income, and consolidated Deeprock Development in its condensed consolidated financial statements. The 40% equity interest in Deeprock Development held by noncontrolling interests was recorded at its acquisition date fair value of $45.9 million. The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow analysis and adjusted for lack of control. These fair value measurements are based on significant inputs, such as forecasted cash flows and discount rates, that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820.

The following represents the fair value of assets acquired and liabilities assumed at July 20, 2017 (in thousands):



Accounts receivable	$	968
Other current assets	598
Property, plant and equipment	70,148
Accounts payable	(712		)
Deferred revenue	(6,546		)
Net identifiable assets acquired	64,456
Goodwill	61,550
Net assets acquired (excluding cash)	$	126,006

At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. TEP is in the process of obtaining additional information to identify and measure all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. The goodwill recognized of $61.6 million is primarily attributed to synergies expected from combining the operations of TEP and Deeprock Development. All of the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TEP from Deeprock Development of $2.4 million and $1.1 million, respectively, was recognized in the accompanying condensed consolidated statements of income for the period from July 20, 2017 to September 30, 2017.

On July 21, 2017, subsequent to the acquisition of an additional 40% membership interest discussed above, TEP acquired an additional 9% membership interest in Deeprock Development from DER for total consideration valued at approximately $13.1 million, consisting of approximately $6.4 million in cash and the issuance of 128,790 TEP common units (valued at approximately $6.7 million based on the July 20, 2017 closing price of TEP's common units), which was accounted for as an acquisition of noncontrolling interest. Subsequent to the closing of the transaction, our aggregate membership interest in Deeprock Development is 69%.

Pro Forma Financial Information

Unaudited pro forma revenue and net income attributable to ~~partners~~TEGP for the three and nine months ended September 30, ~~2015~~2017 and 2016 is presented below as if the ~~acquisition~~acquisitions of ~~Western~~TCG and Deeprock Development had been completed on January 1, ~~2015:~~2016.


					Three Months Ended September 30,				Nine Months Ended September 30,
	Three Months Ended September 30, 2015		Nine Months Ended September 30, 2015		2017		2016		2017		2016
	(in thousands)				(in thousands)
Revenue	$	138,651	$	387,245	$	177,022	$	158,642	$	492,625	$	465,232
Net income attributable to TEGP	$	4,440	$	14,330
Net income attributable to partners					$	6,083	$	10,787	$	25,951	$	21,896

The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TEGP would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project the results of operations or financial position of TEGP for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The pro forma revenue and net income includes adjustments to give effect to ~~TEGP's consolidated interest in~~ the estimated results of operations of ~~Western~~TCG and Deeprock Development for the periods ~~presented.~~presented, as well as to eliminate the equity in earnings and gain on remeasurement of unconsolidated investment associated with our previously held 20% membership interest in Deeprock Development.

TEP Acquisition of DCP Douglas, LLC

On June 5, 2017, TEP acquired 100% of the membership interests in DCP Douglas, LLC (subsequently renamed as Tallgrass Midstream Gathering, LLC), which owns the Douglas Gathering System, a natural gas gathering system in the Powder River Basin with approximately 1,500 miles of gathering pipeline connected to the Douglas processing plant, for approximately $128.5 million, subject to working capital adjustments. The acquisition has been accounted for as an asset acquisition, with substantially all of the fair value allocated to the long-lived assets acquired based on their relative fair values.

TEP Acquisition of an Additional 24.99% Membership Interest in ~~Water Solutions~~Rockies Express

On ~~July 1, 2016,~~March 31, 2017, TEP, TD, and Rockies Express Holdings, LLC, entered into a definitive Purchase and Sale Agreement, pursuant to which TEP acquired an additional 24.99% membership interest in Rockies Express from TD in exchange for cash consideration of $400 million. Together with the 25% membership interest in Rockies Express that TEP acquired from a unit of Sempra U.S. Gas and Power on May 6, 2016, this transaction increases TEP’s aggregate membership interest in Rockies Express to 49.99%.

The transfer of the Rockies Express membership interest between TD and TEP is considered a transaction between entities under common control, but does not represent a change in reporting entity. TEP's investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our condensed consolidated balance sheets. As a result of the common control nature of the transaction, the 24.99% membership interest in Rockies Express was transferred to TEP at TD's historical carrying amount, including the remaining ~~8% noncontrolling equity~~unamortized basis difference driven by the difference between the fair value of the investment and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD. For additional information, see Note 8 – Investments in Unconsolidated Affiliates.

As of March 31, 2017, the negative basis difference carried over from TD was approximately $386.8 million. The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years, which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. The basis difference associated with the recently acquired 24.99% membership interest in ~~Water Solutions~~Rockies Express at September 30, 2017 was allocated as follows:



	Basis Difference			Amortization Period
	(in thousands)
Long-term debt	$	19,078		2 - 25 years
Property, plant and equipment	(399,667		)	35 years
Total basis difference	$	(380,589	)

TEP Acquisition of Tallgrass Terminals, LLC and ~~additional~~Tallgrass NatGas Operator, LLC

Effective January 1, 2017, TEP acquired 100% of the issued and outstanding membership interests in ~~certain~~Terminals and 100% of ~~Water Solutions' subsidiaries~~the issued and outstanding membership interests in NatGas from ~~Regency Investments I, LLC and BSEG Water Group LLC~~TD for total cash consideration of ~~$6.0 million, which will be accounted~~$140 million. These acquisitions are considered transactions between entities under common control, and a change in reporting entity.

Terminals owns several fully operational assets providing storage capacity and additional injection points for ~~as an~~the Pony Express System, including the Sterling Terminal near Sterling, Colorado, the Buckingham Terminal in northeast Colorado, and a 69% interest in the Deeprock Development Terminal in Cushing, Oklahoma following the acquisition of ~~noncontrolling interest. Subsequent to the closing of the transaction, our~~an aggregate additional 49% membership interest in ~~Water Solutions~~Deeprock Development in July 2017 discussed above. Terminals also owns acreage in Cushing, Oklahoma and Guernsey, Wyoming, which is ~~100%.~~under development to provide additional storage capacity and other potential opportunities.

NatGas is the operator of the Rockies Express Pipeline and receives a fee from Rockies Express as compensation for its services.

Historical Financial Information

The results of our acquisitions of Terminals and NatGas are included in the condensed consolidated balance sheets as of September 30, 2017 and December 31, 2016. The following table presents our previously reported December 31, 2016 condensed consolidated balance sheet, adjusted for the acquisitions of Terminals and NatGas:



	December 31, 2016
	TEGP (As previously reported)		Consolidate Terminals		Consolidate NatGas		TEGP (As currently reported)
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	2,459	$	—	$	—	$	2,459
Accounts receivable, net	59,469		38		29		59,536
Gas imbalances	1,597		—		—		1,597
Inventories	12,805		288		—		13,093
Derivative assets	10,967		—		—		10,967
Prepayments and other current assets	6,820		808		—		7,628
Total Current Assets	94,117		1,134		29		95,280
Property, plant and equipment, net	2,012,263		66,969		—		2,079,232
Goodwill	343,288		—		—		343,288
Intangible assets, net	93,522		—		—		93,522
Unconsolidated investments	461,915		13,710		—		475,625
Deferred tax asset	521,454		—		—		521,454
Deferred financing costs, net	6,042		—		—		6,042
Deferred charges and other assets	9,637		1,400		—		11,037
Total Assets	$	3,542,238	$	83,213	$	29	$	3,625,480
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	24,403	$	46	$	—	$	24,449
Accounts payable to related parties	5,768		56		—		5,824
Gas imbalances	1,239		—		—		1,239
Derivative liabilities	556		—		—		556
Accrued taxes	16,328		668		—		16,996
Accrued liabilities	16,578		177		—		16,755
Deferred revenue	60,757		—		—		60,757
Other current liabilities	6,446		—		—		6,446
Total Current Liabilities	132,075		947		—		133,022
Long-term debt, net	1,555,981		—		—		1,555,981
Other long-term liabilities and deferred credits	7,063		—		—		7,063
Total Long-term Liabilities	1,563,044		—		—		1,563,044
Equity:
Net Equity	1,847,119		82,266		29		1,929,414
Total Equity	1,847,119		82,266		29		1,929,414
Total Liabilities and Equity	$	3,542,238	$	83,213	$	29	$	3,625,480

The results of our acquisitions of Terminals and NatGas are included in the condensed consolidated statements of income for the three and nine months ended September 30, 2017 and 2016. The following tables present the previously reported condensed consolidated statements of income for the three and nine months ended September 30, 2016, adjusted for the acquisitions of Terminals and NatGas:



	Three Months Ended September 30, 2016
	TEGP (As previously reported)			Consolidate Terminals		Consolidate NatGas		Elimination				TEGP (As currently reported)
	(in thousands)
Revenues:
Crude oil transportation services	$	91,387		$	—	$	—	$	—			$	91,387
Natural gas transportation services	31,444			—		—		—				31,444
Sales of natural gas, NGLs, and crude oil	20,758			—		—		(271		)	⁽¹⁾	20,487
Processing and other revenues	8,536			3,116		1,182		(2,884		)	⁽²⁾	9,950
Total Revenues	152,125			3,116		1,182		(3,155		)		153,268
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	18,590			—		—		(271		)	⁽¹⁾	18,319
Cost of transportation services (exclusive of depreciation and amortization shown below)	13,528			198		—		(2,884		)	⁽²⁾	10,842
Operations and maintenance	14,714			432		—		—				15,146
Depreciation and amortization	20,831			346		—		—				21,177
General and administrative	13,715			266		—		—				13,981
Taxes, other than income taxes	6,717			143		—		—				6,860
Total Operating Costs and Expenses	88,095			1,385		—		(3,155		)		86,325
Operating Income (Loss)	64,030			1,731		1,182		—				66,943
Other Income (Expense):
Interest expense, net	(12,157		)	—		—		—				(12,157		)
Unrealized loss on derivative instrument	(4,419		)	—		—		—				(4,419		)
Equity in earnings of unconsolidated investments	12,066			698		—		—				12,764
Other income, net	480			—		—		—				480
Total Other (Expense) Income	(4,030		)	698		—		—				(3,332		)
Net income before tax	60,000			2,429		1,182		—				63,611
Deferred income tax expense	(3,209		)	—		—		—				(3,209		)
Net income	56,791			2,429		1,182		—				60,402
Net income attributable to noncontrolling interests	(49,750		)	—		—		—				(49,750		)
Net income attributable to TEGP	$	7,041		$	2,429	$	1,182	$	—			$	10,652



	Nine Months Ended September 30, 2016
	TEGP (As previously reported)			Consolidate Terminals				Consolidate NatGas		Elimination				TEGP (As currently reported)
	(in thousands)
Revenues:
Crude oil transportation services	$	279,281		$	—			$	—	$	—			$	279,281
Natural gas transportation services	89,406			—				—		—				89,406
Sales of natural gas, NGLs, and crude oil	51,514			—				—		(271		)	⁽¹⁾	51,243
Processing and other revenues	24,260			8,982				4,855		(8,576		)	⁽²⁾	29,521
Total Revenues	444,461			8,982				4,855		(8,847		)		449,451
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	48,116			—				—		(271		)	⁽¹⁾	47,845
Cost of transportation services (exclusive of depreciation and amortization shown below)	43,924			598				—		(8,576		)	⁽²⁾	35,946
Operations and maintenance	41,055			1,319				—		—				42,374
Depreciation and amortization	64,099			975				—		—				65,074
General and administrative	41,710			1,153				—		—				42,863
Taxes, other than income taxes	19,862			431				—		—				20,293
Contract termination	—			8,061			⁽³⁾	—		—				8,061
Loss on disposal of assets	1,849			—				—		—				1,849
Total Operating Costs and Expenses	260,615			12,537				—		(8,847		)		264,305
Operating Income	183,846			(3,555		)		4,855		—				185,146
Other Income (Expense):
Interest expense, net	(31,275		)	—				—		—				(31,275		)
Unrealized gain on derivative instrument	5,588			—				—		—				5,588
Equity in earnings of unconsolidated investments	35,387			2,108				—		—				37,495
Other income, net	1,267			—				—		—				1,267
Total Other Income	10,967			2,108				—		—				13,075
Net income (loss) before tax	194,813			(1,447		)		4,855		—				198,221
Deferred income tax expense	(12,792		)	—				—		—				(12,792		)
Net income (loss)	182,021			(1,447		)		4,855		—				185,429
Net income attributable to noncontrolling interests	(163,943		)	—				—		—				(163,943		)
Net income (loss) attributable to TEGP	$	18,078		$	(1,447	)		$	4,855	$	—			$	21,486


⁽¹⁾	Represents the elimination of revenue and cost of sales associated with the purchase of crude oil from Pony Express by Terminals.


⁽²⁾	Represents the elimination of revenue and cost of transportation services associated with the lease of the Sterling Terminal facilities by Pony Express.


⁽³⁾	Represents a one-time charge related to the termination of an operating agreement at the Sterling Terminal.

5. Related Party Transactions

As a result of our relationship with TD and its affiliates, we have entered into a number of related party transactions. The following disclosure includes those related party transactions which are not otherwise disclosed in these notes to our condensed consolidated financial statements.

We have no employees. TD, through its wholly-owned subsidiary Tallgrass Operations, LLC ("Tallgrass Operations"), provided and charged us for direct and indirect costs of services provided to us or incurred on our behalf including employee labor costs, information technology services, employee health and retirement benefits, and all other expenses necessary or appropriate to the conduct of our business. We recorded these costs on the accrual basis in the period in which TD incurred them. On May 17, 2013, inIn connection with the closing of ~~TEP's~~the TEP initial public offering on May 17, 2013, TEP and its general partner entered into an Omnibus Agreement with TD and certain of its affiliates, including Tallgrass Operations, LLC (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse TD and its affiliates for all expenses they incur and payments they make on TEP's behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by TD, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the closing of ~~the Offering,~~our initial public offering on May 12, 2015 (the "TEGP IPO"), TEGP entered into an Omnibus Agreement (the "TEGP Omnibus Agreement") with TEGP Management, LLC, Tallgrass Equity and Tallgrass Energy Holdings, LLC (which ~~acts as~~is the general partner of TD).

Pursuant to the TEGP Omnibus Agreement, Tallgrass Equity pays a reimbursement to TD for costs associated with TEGP being a public company beginning in the second quarter of 2015, which was $500,000 for the third quarter of ~~2016.~~2017. This amount ~~will be~~is periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEGP.

~~There was no interest income from TD recognized for the three and nine months ended September 30, 2016. During the nine months ended September 30, 2015 we recognized interest income from TD~~Totals of ~~$0.4 million on the receivable balance under the Pony Express cash management agreement in effect through December 31, 2015.~~

~~Transactions~~transactions with affiliated companies, excluding transactions ~~otherwise~~ disclosed elsewhere in these notes, are as follows:

Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
(in thousands)
Cost of transportation services $ 7,313
$ 7,180
$ 21,864
$ 17,771
Charges to TEGP: ⁽¹⁾

Property, plant and equipment, net $ 432
$ 958
$ 1,953
$ 3,859
Operation and maintenance $ 6,317
$ 6,077
$ 18,778
$ 17,325
General and administrative $ 9,718
$ 10,041
$ 29,361
$ 28,862



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Processing and other revenues ⁽¹⁾	$	3,338	$	1,182	$	6,662	$	4,855
Cost of transportation services ⁽²⁾	$	1,062	$	4,630	$	10,476	$	13,888
Charges to TEGP: ⁽³⁾
Property, plant and equipment, net	$	765	$	688	$	1,568	$	2,255
Operations and maintenance	$	7,973	$	6,560	$	21,680	$	19,117
General and administrative	$	11,960	$	10,423	$	32,628	$	30,066


⁽¹⁾	Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline.


⁽²⁾	Reflects rent expense for the crude oil storage at the Deeprock Terminal prior to our consolidation of Deeprock Development during the third quarter of 2017, as discussed in Note 4 – Acquisitions.


⁽³⁾	Charges to TEGP, inclusive of Tallgrass Equity ~~TEP,~~ and ~~Pony Express,~~TEP, include directly charged wages and salaries, other compensation and benefits, and shared services.

Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows:


	September 30, 2016		December 31, 2015		September 30, 2017		December 31, 2016
	(in thousands)				(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	126	$	15	$	1,052	$	590
Total receivable from related parties	$	126	$	15	$	1,052	$	590
Accounts payable to related parties:
Tallgrass Operations, LLC	$	6,097	$	7,731	$	5,955	$	5,811
Rockies Express Pipeline LLC	—		7
Deeprock Development, LLC	—		17		—		13
Total accounts payable to related parties	$	6,097	$	7,755	$	5,955	$	5,824

~~Balances of gas~~Gas imbalances with affiliated shippers are as follows:


	September 30, 2016		December 31, 2015		September 30, 2017		December 31, 2016
	(in thousands)				(in thousands)
Affiliate gas imbalance receivables	$	82	$	92	$	17	$	177
Affiliate gas imbalance payables	$	161	$	227	$	43	$	—

6. Inventory

The components of inventory at September 30, ~~2016~~2017 and December 31, ~~2015~~2016 consisted of the following:


	September 30, 2016		December 31, 2015		September 30, 2017		December 31, 2016
	(in thousands)				(in thousands)
Crude oil	$	4,223	$	2,661	$	2,115	$	5,462
Materials and supplies	6,505		8,581		5,993		6,383
Natural gas liquids	255		395		543		265
Gas in underground storage	2,392		2,156		1,522		983
Total inventory	$	13,375	$	13,793	$	10,173	$	13,093

7. Property, Plant and Equipment

A summary of net property, plant and equipment by classification is as follows:


	September 30, 2016			December 31, 2015			September 30, 2017			December 31, 2016
	(in thousands)						(in thousands)
Crude oil pipelines	$	1,182,806		$	1,172,684		$	1,219,913		$	1,202,125
Gathering, processing and terminalling assets ⁽¹⁾							667,379			397,701
Natural gas pipelines	553,437			550,710			577,343			572,150
Processing and treating assets	256,331			254,073
Water business assets	81,507			81,098
General and other	71,190			69,181			98,860			82,510
Construction work in progress	38,454			30,699			45,223			20,606
Accumulated depreciation and amortization	(180,193		)	(133,427		)	(257,888		)	(195,860		)
Total property, plant and equipment, net	$	2,003,532		$	2,025,018		$	2,350,830		$	2,079,232


⁽¹⁾	Includes approximately $138.2 million of assets associated with the Douglas Gathering System acquired in June 2017, approximately $68.4 million of assets associated with the acquisition of the aggregate additional 49% membership interest in Deeprock Development in July 2017, and approximately $29.3 million of assets associated with the PRB Crude System acquired in August 2017.

8. Investments in Unconsolidated Affiliates

Rockies Express

Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our condensed consolidated balance sheets. During the nine months ended September 30, 2017, we recognized equity in earnings associated with our 49.99% membership interest in Rockies Express of $185.7 million, inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $227.5 million and $29.5 million, respectively. As discussed in Note 4 – Acquisitions, we acquired an additional 24.99% membership interest in Rockies Express from TD on March 31, 2017.

Summarized financial information for Rockies Express is as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Revenue	$	216,756	$	159,421	$	625,243	$	551,323
Operating income	$	123,965	$	66,436	$	344,037	$	267,847
Net income to Members	$	233,990	$	34,184	$	371,185	$	226,847

Deeprock Development

As discussed in Note 4 – Acquisitions, on July 20, 2017, TEP acquired an additional 40% membership interest in Deeprock Development. As a result of the acquisition, TEP consolidated Deeprock Development and effective July 20, 2017 will no longer account for its investment in Deeprock Development under the equity method of accounting.

9. Goodwill

Reconciliation of Goodwill

The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the reporting period:



	Three and Nine Months Ended September 30,
	2017							2016
	Natural Gas Transportation		Gathering, Processing & Terminalling			Total		Natural Gas Transportation		Gathering, Processing & Terminalling		Total
	(in thousands)
Balance at beginning of period	$	255,558	$	87,730		$	343,288	$	255,558	$	87,730	$	343,288
Goodwill acquired	—		61,550		⁽¹⁾	61,550		—		—		—
Balance at end of period	$	255,558	$	149,280		$	404,838	$	255,558	$	87,730	$	343,288


⁽¹⁾	The $61.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Deeprock Development on July 20, 2017 as discussed further in Note 4 – Acquisitions.

Annual Goodwill Impairment Analysis

We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. We evaluate goodwill for impairment at the reporting unit level, which is the same as, or one level below, an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or proceeding directly to the ~~two-step~~quantitative impairment test ~~approach~~ depending on facts and circumstances of the reporting unit. If we, after performing the qualitative assessment, determine it is “more likely than not” that the fair value of a reporting unit is greater than its carrying amount, ~~the two-step impairment test~~then goodwill is ~~unnecessary.~~not considered impaired. When goodwill is evaluated for impairment using the ~~two-step~~quantitative impairment test, the carrying amount of the reporting unit is compared to its fair ~~value in Step 1 and if~~value. If the fair value exceeds the carrying amount, ~~Step 2~~goodwill is ~~unnecessary.~~not considered impaired. If the carrying amount exceeds the reporting unit's fair value, ~~this could indicate potential~~then the reporting unit should recognize an impairment ~~and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure~~charge for the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable sources of fair value, as appropriate. Ifby which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill ~~exceeds its implied fair value, the excess is recognized as an impairment loss.~~

allocated to that reporting unit.

We did not elect to apply the qualitative assessment option during our ~~2016~~2017 annual goodwill impairment testing; instead we proceeded directly to the ~~two-step~~ quantitative impairment test. ~~In Step 1 of the two-step quantitative test, we~~We compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of

which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the ~~Step 1~~quantitative impairment ~~analysis~~test indicated no ~~potential~~ impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, ~~Step 2 of~~we did not record a goodwill impairment during the ~~impairment analysis was not necessary as part of the annual impairment analysis in 2016.~~nine months ended September 30, 2017. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary.

9.10. Risk Management

We ~~occasionally~~ enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs.

Fair Value of Derivative Contracts

The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets:

Balance Sheet
Location September 30, 2016 December 31, 2015
(in thousands)
Call option derivative ⁽¹⁾
Current assets $ 25,690
$ —
Natural gas derivative contracts ⁽²⁾
Current liabilities $ 190
$ —
Crude oil derivative contract ⁽³⁾
Current liabilities $ 7
$ —



	Balance Sheet Location	September 30, 2017		December 31, 2016
		(in thousands)
Natural gas derivative contracts ⁽¹⁾	Current assets	$	—	$	291
Call option derivative ⁽²⁾	Current assets	$	—	$	10,676
Crude oil derivative contracts ⁽³⁾	Current liabilities	$	472	$	440
Natural gas derivative contracts ⁽¹⁾	Current liabilities	$	1	$	116


⁽¹⁾	As of September 30, 2017, the fair value shown for natural gas derivative contracts was comprised of derivative volumes for long natural gas fixed-price swaps totaling 0.1 Bcf. As of December 31, 2016, the fair value shown for natural gas derivative contracts was comprised of derivative volumes for short and long natural gas fixed-price swaps totaling 0.3 Bcf and 0.4 Bcf, respectively.


⁽²⁾	As discussed ~~in Note 4 –~~ ~~Acquisitions~~,below, in conjunction with TEP's acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted TEP an 18 month call option covering the 6,518,000 TEP common units issued to TD.


⁽²⁾	As of ~~September 30, 2016,~~February 1, 2017, no common units remained subject to the fair value shown for natural gas derivative contracts was comprised of derivative volumes for short natural gas fixed-price swaps totaling 0.8 Bcf. As of December 31, 2015 there were no natural gas derivative contracts outstanding.call option.

⁽³⁾

As of September 30, 2017, the fair value shown for crude oil derivative contracts represents the purchase and sale of 323,620 barrels which will settle throughout 2017 and the first quarter of 2018. As of December 31, 2016, the fair value shown for crude oil derivative contracts ~~was comprised of~~represents the sale of ~~30,000~~125,000 barrels ~~in October 2016. As~~ of ~~December 31, 2015 there were no~~ crude oil ~~derivative contracts outstanding.~~which settled throughout 2017.

Effect of Derivative Contracts in the Statements of Income

The following table summarizes the impact of derivative contracts not designated as hedging contracts for the three and nine months ended September 30, ~~2016~~2017 and ~~2015:~~2016:


Contract Type												Location of gain (loss) recognized in income on derivatives	Amount of gain (loss) recognized in income on derivatives
													Three Months Ended September 30,						Nine Months Ended September 30,
													2017			2016			2017		2016
	Location of gain (loss) recognized in income on derivatives	Amount of gain (loss) recognized in income on derivatives											(in thousands)
		Three Months Ended September 30,					Nine Months Ended September 30,
		2016			2015		2016			2015
		(in thousands)
Derivatives not designated as hedging contracts:
Crude oil derivative contracts												Sales of natural gas, NGLs, and crude oil	$	175		$	318		$	1,065	$	466
Natural gas derivative contracts												Sales of natural gas, NGLs, and crude oil	$	(22	)	$	161		$	84	$	(190	)
Call option derivative	Unrealized (loss) gain on derivative instrument	$	(4,419	)	$	—	$	5,588		$	—	Unrealized (loss) gain on derivative instrument	$	—		$	(4,419	)	$	1,885	$	5,588
Natural gas derivative contracts	Sales of natural gas, NGLs, and crude oil	$	161		$	252	$	(190	)	$	211
Crude oil derivative contract	Sales of natural gas, NGLs, and crude oil	$	318		$	—	$	466		$	—

~~Exercise of~~ Call Option Derivative

OnAs part of TEP's acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted TEP an 18 month call option at an exercise price of $42.50 per TEP common unit covering the 6,518,000 TEP common units issued to TD as a portion of the consideration. In July ~~21,~~2016 and October 2016, TEP partially exercised the call option ~~granted by TD in January 2016 as discussed in Note 4 –~~ ~~Acquisitions~~covering 3,563,146 and 1,251,760 common units, respectively, for cash payments of $151.4 million and $53.2 million, respectively. On February 1, 2017, TEP exercised the remainder of the call option covering an additional 1,703,094 common units for a cash payment of ~~$151.4 million. On October 31, 2016, TEP partially exercised the call option again covering an additional 1,251,760 common units for a cash payment of $53.2~~$72.4 million. These common units were deemed canceled upon the exercise of the call option and as of ~~such~~the applicable exercise date were no longer issued and outstanding. ~~As of November 2, 2016, 1,703,094 common units remained subject to the call option.~~

Credit Risk

We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our crude oil and natural gas derivatives consist of major financial institutions. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. The counterparty to our call option derivative iswas TD.

Our over-the-counter swaps are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with financial institutions with investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. As of September 30, ~~2016,~~2017, the fair value of our crude oil and natural gas derivative contracts were a liability position, resulting in no credit exposure from TEP's counterparties as of that date.

As of September 30, ~~2016~~2017 we had $0.8 million and $3.0 million of cash in margin accounts and outstanding letters of credit, respectively, in support of our commodity derivative contracts. As of December 31, ~~2015,~~2016, we did not have any outstanding letters of credit or cash in margin accounts in support of our hedging of commodity price risks associated with ~~the sale of natural gas nor did we have any margin deposits with counterparties associated with natural gas contract positions.~~our commodity derivative contracts.

Fair Value

Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. We value exchange-traded derivative contracts using quoted market prices for identical securities.

OTC commodity derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy. The call option granted by TD iswas valued using a Black-Scholes option pricing model. Key inputs to the valuation model ~~include~~included the term of the option, risk free rate, the exercise price and current market price, expected volatility and expected distribution yield of the underlying units. The call option valuation iswas classified within Level 2 of the fair value hierarchy as the value iswas based on significant observable inputs.

Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management's best estimate is used.

The following table summarizes the fair value measurements of our derivative contracts as of September 30, 2017 and December 31, 2016 based on the fair value ~~hierarchy established by the Codification:~~hierarchy:

Asset Fair Value Measurements Using
Total Quoted prices in
active markets
for identical
assets
(Level 1) Significant
other observable
inputs
(Level 2) Significant
unobservable
inputs
(Level 3)
(in thousands)
As of September 30, 2016:
Call option derivative $ 25,690
$ —
$ 25,690
$ —

Liability Fair Value Measurements Using
Total Quoted prices in
active markets
for identical
assets
(Level 1) Significant
other observable
inputs
(Level 2) Significant
unobservable
inputs
(Level 3)
(in thousands)
As of September 30, 2016:
Natural gas derivative contracts $ 190
$ —
$ 190
$ —
Crude oil derivative contract $ 7
$ —
$ 7
$ —



			Asset Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of December 31, 2016:
Call option derivative	$	10,676	$	—	$	10,676	$	—
Natural gas derivative contracts	$	291	$	—	$	291	$	—

			Liability Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of September 30, 2017:
Crude oil derivative contracts	$	472	$	—	$	472	$	—
Natural gas derivative contracts	$	1	$	—	$	1	$	—
As of December 31, 2016:
Crude oil derivative contracts	$	440	$	—	$	440	$	—
Natural gas derivative contracts	$	116	$	—	$	116	$	—

~~10.~~11. Long-term Debt

Long-term debt consisted of the following at September 30, ~~2016~~2017 and December 31, ~~2015:~~2016:


	September 30, 2016			December 31, 2015		September 30, 2017			December 31, 2016
	(in thousands)					(in thousands)
Tallgrass Equity revolving credit facility	$	148,000		$	148,000	$	146,000		$	148,000
TEP revolving credit facility	1,005,000			753,000		881,000			1,015,000
TEP 5.50% senior notes due September 15, 2024	400,000			—		750,000			400,000
TEP 5.50% senior notes due January 15, 2028						500,000			—
Less: Deferred financing costs, net⁽¹⁾	(6,997		)	—		(15,914		)	(7,019		)
Total long-term debt, net	$	1,546,003		$	901,000	$	2,261,086		$	1,555,981


⁽¹⁾	Deferred financing costs, net as presented above relate solely to the 2024 and 2028 Notes. Deferred financing costs associated with our revolving credit ~~facility~~facilities are presented in noncurrent assets on our condensed consolidated balance sheets.

TEP Senior Unsecured Notes

On September ~~1, 2016,~~15, 2017, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 15, 2017 (the "2028 Indenture") pursuant to which the Issuers issued $500 million in aggregate principal amount of 5.50% senior notes due 2028 (the "2028 Notes").

The 2028 Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all of TEP’s properties to, another person. As of September 30, 2017, TEP is in compliance with the covenants required under the 2028 Notes.

On September 1, 2016, the Issuers, the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016 (the ~~"Indenture"~~"2024 Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). ~~TEP used the net proceeds of the offering to repay outstanding borrowings under its existing senior secured revolving credit facility.~~

The 2024 Notes are general unsecured senior obligations of the Issuers. The 2024 Notes are unconditionally guaranteed jointly and severally on a senior unsecured basis by TEP's existing direct and indirect wholly owned subsidiaries (other than the Co-Issuer) and certain of TEP's future subsidiaries (the "Guarantors"). The 2024 Notes rank equal in right of payment with all existing and future senior indebtedness ofOn May 16, 2017, the Issuers ~~and senior~~issued an additional $350 million in ~~right~~aggregate principal amount of ~~payment to any future subordinated indebtedness of the Issuers. The 2024 Notes will mature on September 15, 2024 and interest on~~ the 2024 Notes ~~is payable in cash semi-annually in arrears on each March 15 and September 15, commencing March 15, 2017. TEP may redeem~~which are also governed by the 2024 ~~Notes prior to their scheduled maturity at~~Indenture. The notes issued on September 1, 2016 and May 16, 2017 are treated as a single class of debt securities and have identical terms, other than the ~~applicable redemption~~issue date, offering price ~~set forth in the Indenture, plus accrued~~ and ~~unpaid interest.~~first interest payment date.

The 2024 Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests in the event of default or noncompliance with the covenants required, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. As of September 30, ~~2016, the Issuers and Guarantors are~~2017, TEP is in compliance with the covenants required under the 2024 Notes.

Tallgrass Equity Revolving Credit Facility

The following table sets forth the available borrowing capacity under the Tallgrass Equity revolving credit facility as of September 30, ~~2016~~2017 and December 31, ~~2015:~~2016:


	September 30, 2016			December 31, 2015			September 30, 2017			December 31, 2016
	(in thousands)						(in thousands)
Total capacity under the Tallgrass Equity revolving credit facility	$	150,000		$	150,000
Total capacity under Tallgrass Equity revolving credit facility							$	150,000		$	150,000
Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility	(148,000		)	(148,000		)	(146,000		)	(148,000		)
Available capacity under the Tallgrass Equity revolving credit facility	$	2,000		$	2,000		$	4,000		$	2,000

In connection with the ~~Offering,~~TEGP IPO, Tallgrass Equity entered into a $150 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on May 12, 2020. Among various other covenants and restrictive provisions, Tallgrass Equity is required to maintain a total leverage ratio of not more than 3.00 to 1.00. As of September 30, ~~2016,~~2017, Tallgrass Equity ~~was~~is in compliance with the covenants required under the revolving credit facility.

The unused portion of the revolving credit facility is subject to a commitment fee of 0.50%. As of September 30, ~~2016,~~2017, the weighted average interest rate on outstanding borrowings under the Tallgrass Equity revolving credit facility was ~~3.03%~~3.74%. During the nine months ended September 30, ~~2016,~~2017, Tallgrass Equity's weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was ~~3.28%~~3.88%.

TEP Revolving Credit Facility

~~Effective January 4, 2016, in connection~~On June 2, 2017, TEP entered into a $1.75 billion Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent and collateral agent, and a syndicate of lenders (the "Amended Credit Agreement"). The Amended Credit Agreement amends and restates TEP's existing revolving credit facility. The Amended Credit Agreement, among other things, extends the ~~acquisition~~maturity date of ~~an additional 31.3% membership interest in Pony Express, TEP exercised the committed accordion feature to increase the total capacity of its~~TEP's existing revolving credit facility from ~~$1.1 billion~~May 13, 2018 to ~~$1.5 billion.~~June 2, 2022, and provides for an uncommitted accordion in an amount up to an additional $250 million, subject to the satisfaction of certain other conditions. In ~~connection with~~addition, the ~~acquisition of a 25% membership interest in Rockies Express, TEP amended its~~ revolving credit facility ~~to increase the total capacity to $1.75 billion, which increase became effective May 6, 2016.~~includes a $60 million sublimit for swing line loans and a $75 million sublimit for letters of credit.

The following table sets forth the available borrowing capacity under the TEP revolving credit facility as of September 30, ~~2016~~2017 and December 31, ~~2015:~~

2016:


	September 30, 2016			December 31, 2015			September 30, 2017			December 31, 2016
	(in thousands)						(in thousands)
Total capacity under the TEP revolving credit facility	$	1,750,000		$	1,100,000		$	1,750,000		$	1,750,000
Less: Outstanding borrowings under the TEP revolving credit facility ⁽¹⁾	(1,005,000		)	(753,000		)	(881,000		)	(1,015,000		)
Less: Letters of credit issued under the TEP revolving credit facility							(3,094		)	—
Available capacity under the TEP revolving credit facility	$	745,000		$	347,000		$	865,906		$	735,000


⁽¹⁾	~~As of October 31, 2016, our outstanding borrowings under the revolving credit facility were approximately $1.003 billion.~~

TEP's revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP's ability (as well as the ability of its restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions, ~~(including~~including distributions from available cash, if a default or event of default under the credit agreement then exists or would result, ~~from making such a distribution),~~therefrom, change the nature of its business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than ~~4.75~~5.00 to 1.00 (which will be increased to ~~5.25~~5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions), a consolidated senior secured leverage ratio of not more than 3.75 to 1.00 and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of September 30, ~~2016,~~2017, TEP is in compliance with the covenants required under its revolving credit facility.

The unused portion of TEP's revolving credit facility is subject to a commitment fee, which ranges from ~~0.300%~~0.250% to 0.500%, based on TEP's total leverage ratio. As of September 30, ~~2016,~~2017, the weighted average interest rate on outstanding borrowings under the TEP revolving credit facility was ~~2.28%~~3.24%. During the nine months ended September 30, ~~2016,~~2017, the weighted average effective interest rate under the TEP revolving credit facility, including the interest on outstanding borrowings under TEP's revolving credit facility, commitment fees, and amortization of deferred financing costs, was ~~2.72%~~3.25%.

Fair Value

The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of September 30, ~~2016~~2017 and December 31, ~~2015,~~2016, but for which fair value is disclosed:


	Fair Value										Fair Value
	Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Carrying Amount		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Carrying Amount
	(in thousands)										(in thousands)
As of September 30, 2016:
As of September 30, 2017:
Revolving credit facilities	$	—	$	1,153,000	$	—	$	1,153,000	$	1,153,000	$	—	$	1,027,000	$	—	$	1,027,000	$	1,027,000
2024 Notes	$	—	$	403,752	$	—	$	403,752	$	393,003	$	—	$	772,028	$	—	$	772,028	$	739,444
As of December 31, 2015:
2028 Notes											$	—	$	508,660	$	—	$	508,660	$	494,642
As of December 31, 2016:
Revolving credit facilities	$	—	$	901,000	$	—	$	901,000	$	901,000	$	—	$	1,163,000	$	—	$	1,163,000	$	1,163,000
2024 Notes											$	—	$	398,000	$	—	$	398,000	$	392,981

The long-term debt borrowed under the revolving credit facilities is carried at amortized cost. As of September 30, ~~2016~~2017 and December 31, ~~2015,~~2016, the fair value of borrowings under the revolving credit facilities approximates the carrying amount of the borrowings using a discounted cash flow analysis. The 2024 and 2028 Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the 2024 and 2028 Notes is based upon quoted market prices adjusted for illiquid markets.

We are not aware of any factors that would significantly affect the estimated fair value subsequent to September 30, ~~2016.~~2017.

~~11.~~12. Partnership Equity and Distributions

~~Tallgrass Development Purchase Program~~

On February 17, 2016, we announced that the Board of Directors of Tallgrass Energy Holdings, LLC, the sole member of TEGP's general partner and the general partner of TD, has authorized an equity purchase program under which TD may initially purchase up to an aggregate of $100 million of the outstanding Class A shares of TEGP or the outstanding common units of TEP. TD may purchase Class A shares or Common Units from time to time on the open market or in negotiated purchases. The timing and amounts of any such purchases will be subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The purchase plan does not obligate TD to acquire any specific number of Class A shares or Common Units and may be discontinued at any time. No purchases were made under this program during the nine months ended September 30, 2016.

~~TEGP Partnership Agreement and~~ Distributions to Holders of Class A Shares

In connection with the Offering on May 12, 2015, TEGP entered into an amended and restated partnership agreement. The partnership agreement requires TEGP to distribute its available cash to Class A shareholders on a quarterly basis, subject to certain terms and conditions, beginning with the quarter ended June 30, 2015. The following table details the distributions for the periods indicated:


Three Months Ended	Date Paid	Distributions to Class A Shareholders		Distributions per Class A Share			Date Paid	Distributions to Class A Shareholders		Distributions per Class A Share
		(in thousands)						(in thousands)
September 30, 2017							November 14, 2017 ⁽¹⁾	$	20,617	$	0.3550
June 30, 2017							August 14, 2017	19,891		0.3425
March 31, 2017							May 15, 2017	16,697		0.2875
December 31, 2016							February 14, 2017	16,116		0.2775
September 30, 2016	November 14, 2016 ⁽¹⁾	$	12,528	$	0.2625		November 14, 2016	12,528		0.2625
June 30, 2016	August 12, 2016	11,693		0.2450			August 12, 2016	11,693		0.2450
March 31, 2016	May 13, 2016	10,022		0.2100			May 13, 2016	10,022		0.2100
December 31, 2015	February 12, 2016	8,256		0.1730
September 30, 2015	November 13, 2015	6,872		0.1440
June 30, 2015	August 17, 2015	3,484		0.0730		⁽²⁾


⁽¹⁾	The distribution announced on October ~~5, 2016~~10, 2017 for the third quarter of ~~2016~~2017 will be paid on November 14, ~~2016~~2017 to Class A shareholders of record at the close of business on October 31, ~~2016.~~


⁽²⁾	~~The first quarterly distribution declared on July 15, 2015 was prorated for the number of days between the closing of TEGP's initial public offering on May 12, 2015 and the end of the second quarter.~~2017.

Subsidiary Distributions

TEP Distributions. The following table shows the ~~TEP~~ distributions for the periods indicated:


		Distributions											Distributions
		Limited Partner Common Units		General Partner						Distributions per Limited Partner Unit			Limited Partner Common Units		General Partner						Distributions per Limited Partner Common Unit
Three Months Ended	Date Paid	Limited Partner Common Units		Incentive Distribution Rights		General Partner Units		Total		Distributions per Limited Partner Unit		Date Paid	Limited Partner Common Units		Incentive Distribution Rights		General Partner Units		Total		Distributions per Limited Partner Common Unit
		(in thousands, except per unit amounts)											(in thousands, except per unit amounts)
September 30, 2017												November 14, 2017 ⁽¹⁾	$	69,174	$	37,744	$	1,219	$	108,137	$	0.9450
June 30, 2017												August 14, 2017	67,671		36,342		1,186		105,199		0.9250
March 31, 2017												May 15, 2017	60,486		29,840		1,040		91,366		0.8350
December 31, 2016												February 14, 2017	58,793		28,358		1,008		88,159		0.8150
September 30, 2016	November 14, 2016 ⁽¹⁾	$	57,332	$	26,987	$	976	$	85,295	$	0.7950	November 14, 2016	57,332		26,987		976		85,295		0.7950
June 30, 2016	August 12, 2016	54,442		24,262		911		79,615		0.7550		August 12, 2016	54,442		24,262		911		79,615		0.7550
March 31, 2016	May 13, 2016	48,238		19,816		830		68,884		0.7050		May 13, 2016	48,238		19,816		830		68,884		0.7050
December 31, 2015	February 12, 2016	42,984		15,332		724		59,040		0.6400
September 30, 2015	November 13, 2015	36,347		11,567		660		48,574		0.6000
June 30, 2015	August 14, 2015	35,135		10,418		627		46,180		0.5800
March 31, 2015	May 14, 2015	31,322		6,934		530		38,786		0.5200


⁽¹⁾	The distribution announced on October ~~5, 2016~~10, 2017 for the third quarter of ~~2016~~2017 will be paid on November 14, ~~2016~~2017 to unitholders of record at the close of business on October 31, ~~2016.~~2017.

Repurchase of TEP Common Units Owned by TD

Following an offer received from TD with respect to TEP common units owned by TD not subject to the call option, TEP repurchased 736,262 TEP common units from TD at an aggregate price of approximately $35.3 million, or $47.99 per common unit, on February 1, 2017, which was approved by the conflicts committee of the board of directors of TEP's general partner. These common units were deemed canceled upon TEP's purchase and as of such transaction date were no longer issued and outstanding.

TEP Equity Distribution Agreements

~~On October 31, 2014,~~As of September 30, 2017, TEP ~~entered into an~~had active equity distribution ~~agreement~~agreements pursuant to which it may sell from time to time through a group of managers, as its sales agents, TEP common units representing limited partner interests having an aggregate offering price of up to ~~$200 million. On May 13, 2015 the amount was subsequently amended to~~ $100.2 million in order to account for follow-on equity offerings under TEP's S-3 shelf registration statement. On May 17, 2016, TEP entered into a new equity distribution agreement allowing for the sale of common units with an aggregate offering price of up toand $657.5 million. Sales of common units, if any, will be made by means of ordinary brokers' transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by TEP and one or more of the managers. TEP intends to use the netNet cash proceeds from any sale of the TEP common units may be used for general partnership purposes, which ~~may include,~~includes, among other things, TEP's exercise of the call option with respect to the 6,518,000 common units issued to TD in connection with TEP's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to working capital.

~~During~~TEP did not issue common units under the equity distribution agreements during the three months ended September 30, ~~2016,~~2017. During the nine months ended September 30, 2017, TEP issued and sold ~~622,846~~2,341,061 common units with a weighted average sales price of ~~$47.39~~$48.82 per unit under its equity distribution agreements for net cash proceeds of approximately ~~$28.7~~$112.4 million (net of approximately $0.8 million in commissions and professional service expenses). During the nine months ended September 30, 2016, TEP issued and sold 6,703,984 common units with a weighted average sales price of $43.98 per unit under its equity distribution agreements for net cash proceeds of approximately $290.5 million (net of approximately $4.4 million in commissions and professional service expenses). During the period from October 1, 2016 to November 2, 2016, TEP issued and sold an additional 628,914 common units with a weighted average sales price of $48.05 per unit under its equity distribution agreement for net cash proceeds of approximately $29.9 million (net of approximately $0.3$1.9 million in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes as described above.

~~Private Placement~~

On April 28, 2016, TEP issued an aggregate of 2,416,987 common units for net cash proceeds of $90.0 million in a private placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C. The units were subsequently registered pursuant to TEP's Form S-3/A (File No. 333-210976) filed with the SEC on May 6, 2016, which became effective May 17, 2016.

Noncontrolling Interests

As of September 30, ~~2016,~~2017, noncontrolling interests in our subsidiaries consisted of a ~~69.65%~~63.06% interest in Tallgrass Equity held by the Exchange Right Holders, as defined in Note 1213 – Net Income per Class A Share, the ~~72.50%~~72.67% limited partner interest in TEP held by TD and the public TEP unitholders and, a 31% membership interest in Deeprock Development, and the 2.0% membership interest in Pony Express held by TD. During the nine months ended September 30, ~~2016,~~2017, we recognized contributions from and distributions to noncontrolling interests of ~~$8.7~~$1.1 million and ~~$177.4~~$229.7 million, respectively. Contributions from noncontrolling interests consisted primarily of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of ~~$103.7~~$135.4 million, Tallgrass Equity distributions to the Exchange Right Holders of ~~$68.7~~$90.0 million, and distributions to Pony Express ~~and Water Solutions~~ noncontrolling interests of ~~$5.0~~$4.3 million.

During the nine months ended September 30, ~~2015,~~2016, we received contributions from and made distributions to noncontrolling interests of ~~$110.6~~$8.7 million and ~~$132.4~~$177.4 million, respectively. Contributions from noncontrolling ~~interest~~interests primarily consisted of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of ~~$74.8~~$103.7 million, Tallgrass Equity distributions to Exchange Right Holders of ~~$13.0~~$68.7 million and distributions ~~of $44.5 million from~~to Pony Express ~~to TD.~~noncontrolling interests in the aggregate of $5.0 million.

Other Contributions and Distributions

During the nine months ended September 30, 2017 and 2016, TEP received contributions from TD of $2.3 million and $5.3 million, respectively, primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 1415 – Legal and Environmental ~~Matters~~. During the nine months ended September 30, 2015, we distributed $334.1 million of proceeds from the Offering to the Exchange Right Holders as part of the reorganization of entities effective concurrent with the Offering and distributed $13.5 million to the TEGP Predecessor. In addition, we received $7.5 million of TEP general partner and IDR distributions received related to periods prior to the Offering which were distributed to the previous owners of the sole member of TEP GP, and $13.0 million of TEP distributions received which were distributed by Tallgrass Equity to the Exchange Right Holders.Matters.

~~12.~~13. Net Income per Class A Share

Basic net income per Class A share is determined by dividing net income attributable to TEGP by the weighted average number of outstanding Class A shares during the period. Class B shares do not share in the earnings of the Partnership. Accordingly, basic and diluted net income per Class B share has not been presented.

Diluted net income per Class A share is determined by dividing net income attributable to TEGP by the weighted average number of outstanding diluted Class A shares during the period. For purposes of calculating diluted net income per Class A share, we considered the impact of possible future exercises of the Exchange Right by the Exchange Right Holders on both net income attributable to TEGP and the diluted weighted average number of Class A shares outstanding. The Exchange Right Holders refers to the group of persons who collectively own all of TEGP's outstanding Class B shares and an equivalent number of Tallgrass Equity units. The Exchange Right Holders are entitled to exercise the right to exchange their Tallgrass Equity units (together with an equivalent number of TEGP Class B shares) for TEGP Class A shares at an exchange ratio of one TEGP Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right Holders primarily consist of Kelso & Company and its affiliated investment funds, The Energy & Minerals Group and its affiliated investment funds, and Tallgrass KC, LLC, which is an entity owned by certain members of TEGP's and TEP's management.

Pursuant to the TEGP partnership agreement and the Tallgrass Equity limited liability company agreement, our capital structure and the capital structure of Tallgrass Equity will generally replicate one another in order to maintain the one-for-one exchange ratio between the Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other hand. As a result, the ~~potential~~ exchange of any Class B shares for Class A shares does not have a dilutive effect on basic net income per Class A share. However, for the nine months ended September 30, 2017 and 2016, the potential issuance of TEGP Equity Participation Shares would have had a dilutive effect on basic net income per Class A share.

All net income or loss from Terminals and NatGas prior to TEP's acquisition on January 1, 2017 is allocated to predecessor operations in the condensed consolidated statements of income. Accordingly, no net income or loss from Terminals and NatGas is allocated to our Class A shareholders. We present the financial results of any transferred business prior to the transaction date in the line item "Predecessor operations interest in net income" in the condensed consolidated statements of income.

The following table illustrates the calculation of ~~basic and diluted~~ net income per Class A share for the three and nine months ended September 30, ~~2016~~2017 and ~~2015:~~2016:


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015		2017		2016		2017		2016
	(in thousands, except per share data)								(in thousands, except per share data)
Basic Net Income per Class A Share:
Net income attributable to TEGP	$	7,041	$	4,423	$	18,078	$	14,279
Net income attributable to TEGP from the beginning of the period to May 11, 2015	—		—		—		7,393
Net income attributable to TEGP subsequent to May 12, 2015	$	7,041	$	4,423	$	18,078	$	6,886
Basic Net Income per Class A Share
Net income attributable to TEGP, excluding predecessor operations interest									$	15,866	$	7,041	$	36,648	$	18,078
Basic weighted average Class A Shares outstanding	47,725		47,725		47,725		47,725		58,075		47,725		58,075		47,725
Basic net income per Class A share	$	0.15	$	0.09	$	0.38	$	0.14	$	0.27	$	0.15	$	0.63	$	0.38
Diluted Net Income per Class A Share:
Net income attributable to TEGP subsequent to May 12, 2015	$	7,041	$	4,423	$	18,078	$	6,886
Diluted Net Income per Class A Share
Net income attributable to TEGP, excluding predecessor operations interest									$	15,866	$	7,041	$	36,648	$	18,078
Incremental net income attributable to TEGP including the effect of the assumed issuance of Equity Participation Shares	3		2		3		2		64		3		132		3
Net income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares	$	7,044	$	4,425	$	18,081	$	6,888	$	15,930	$	7,044	$	36,780	$	18,081
Basic weighted average Class A Shares outstanding	47,725		47,725		47,725		47,725		58,075		47,725		58,075		47,725
Equity Participation Shares equivalent shares	50		83		15		87		117		50		118		15
Diluted weighted average Class A Shares outstanding	47,775		47,808		47,740		47,812		58,192		47,775		58,193		47,740
Diluted net income per Class A Share	$	0.15	$	0.09	$	0.38	$	0.14	$	0.27	$	0.15	$	0.63	$	0.38

~~13.~~14. Regulatory Matters

There are ~~currently~~ no regulatory proceedings challenging the ~~currently effective transportation~~ rates of Pony Express, Rockies Express, Tallgrass Interstate Gas Transmission, LLC ("TIGT") or Trailblazer Pipeline Company LLC ("Trailblazer"). ~~On October 30, 2015, Tallgrass Interstate Gas Transmission, LLC ("TIGT") filed a general rate case~~We have made certain regulatory filings with the FERC, ~~pursuant to Section 4 of~~including the Natural Gas Act ("NGA"), discussed in more detail below. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable law, to challenge the rates that we charge at our regulated entities. Further, applicable law governing service byfollowing:

Pony Express

On May 22, 2017 and May 31, 2017, Pony Express ~~allows parties having standing to file complaints in regard to existing~~made tariff rates and provisions. If the complaint is not resolved, the FERC may conduct a hearing and order a crude oil pipeline like the Pony Express System to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. We can provide no assurance that current rates will remain unchallenged. Any successful challenge could have a material, adverse effect on our future earnings and cash flows.

~~TIGT~~

~~General Rate Case Filing – FERC Docket RP16-137~~

~~On October 30, 2015, TIGT filed a general rate case~~filings with the FERC pursuant to Section 4 of the NGA. The rate case proposed a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT. In addition, TIGT proposed certain changes to the transportation rate design of its system to replace the current rate zone structure with a single "postage stamp" rate. TIGT also proposed new incremental charges, including (i) a charge for deliveries made to points without certain electronic flow measurement equipment, and (ii) a Cost Recovery Mechanism ("CRM") charge to completely or partially reimburse TIGT for certain costs it incurred to maintain system safety, environmental compliance and reliability. TIGT also proposed to replace its fixed fuel and lost and unaccounted for ("FL&U") charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period's under/over collection and the forecasted FL&U expense for the upcoming period. TIGT also proposed to implement a power cost tracker to recover the actual power costs incurred by TIGT to power its compressors. Finally, TIGT proposed certain revisions to its FERC Gas Tariff addressing a number of other rate and non-rate matters. Under the NGA and the FERC's regulations, TIGT's shippers and other interested parties, including the FERC's Trial Staff, had a right to challenge any aspect of TIGT's rate case filing. Accordingly, numerous TIGT customers protested aspects of TIGT's NGA Section 4 rate filing.

On November 30, 2015, the FERC issued an order accepting and suspending the proposed rates and certain proposed tariff records to be effective upon motion May 1, 2016, subject to refund, certain modifications to TIGT's proposed CRM charge, and the outcome of an evidentiary hearing before a FERC Administrative Law Judge (the "Suspension Order"). In the Suspension Order, the FERC also accepted two tariff records related to force majeure events and reservation charge crediting to be effective December 1, 2015, subject to certain modifications. On December 21, 2015, TIGT made a compliance filing with the FERC to modify TIGT's proposed CRM charge and update the tariff records related to force majeure events and reservation charge crediting as directed by the FERC in the Suspension Order. No comments or protests were filed in response to the compliance filing and the FERC accepted the compliance filing on February 1, 2016. On March 22, 2016, a Settlement Judge was appointed in the case to assist the participants in exploring the possibility of settlement. On March 31, 2016, the FERC issued an order denying certain rehearing requests concerning the CRM, granting in part a motion to remove certain pro forma tariff records from the hearing, and also requested comments in order to assess the need for a technical conference. The FERC also retained for resolution through hearing the pro forma tariff records related to TIGT's proposed charge at delivery points lacking electronic flow measurement and removed from hearing the other issues related to the pro forma tariff records. Whether any issues will be resolved through technical conference is pending. The FERC also directed TIGT to provide additional information related to certain pro forma tariff records, which TIGT filed on April 14, 2016. On June 23, 2016, the FERC approved the implementation of TIGT's filed postage stamp rates, subject to refund, effective on May 1, 2016.

TIGT has reached an agreement in principle with customers representing a majority of firm fee revenue on the TIGT System for the year ended December 31, 2015 to settle all rate related issues set for hearing in its existing FERC rate case, including the issues of a cost recovery mechanism and a non-Electronic Flow Measurement charge. On May 5, 2016, the Acting Chief Administrative Law Judge issued an Order suspending the procedural schedule in the case as a result of the agreement in principle. On June 8, 2016, TIGT filed with the FERC its offer of settlement which resolves all issues in the case, with the exception of certain non-rate related tariff issues which remain subject to the FERC's review and approval. On June 9, 2016, the Presiding Administrative Law Judge issued an Order shortening the period for any comments on the settlement, such that comments were due by June 13, 2016. No adverse comments were filed. The offer of settlement was certified to the FERC by the Administrative Law Judge on July 14, 2016. The Judge found that the settlement is uncontested, presents no issues of first impression, has no FERC policy implications, and appears to be just, reasonable, and in the public interest. The FERC issued an order on November 2, 2016 approving the settlement, finding that it appears to be fair and reasonable and in the public interest.

~~Trailblazer~~

~~2016 Annual Fuel Tracker Filing – FERC Docket Nos. RP16-814-000 and RP16-814-001~~

On April 1, 2016, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2016 in Docket No. RP16-814-000. The FERC accepted this filing on April 18, 2016. On May 19, 2016, Trailblazer filed its refund report associated with the April 1, 2016 annual fuel tracker filing, which the FERC accepted on July 11, 2016.

On September 7, 2016, Trailblazer filed an adjustment to its April 1, 2016 fuel tracker filing. As a result of this adjustment, Trailblazer proposed to issue additional cash-out refunds to applicable shippers and also reflect this adjustment in its applicable fuel accounts. The FERC accepted this filing on October 3, 2016. On October 14, 2016, Trailblazer filed its refund report associated with its September 7, 2016 adjustment filing.

~~Rockies Express~~

~~Annual FERC Fuel Tracking Filings – FERC Docket Nos. RP16-702-000 and RP16-1301-000~~

On September 30, 2016, Rockies Express elected to make an interim fuel tracker filing with a proposed effective date of November 1, 2016 in Docket No. RP16-1301-000. This interim filing proposes increases to most applicable fuel and power rates as a result of increased system utilization. On October 12, 2016, certain shippers filed a protest with the FERC regarding the proposed increases. Rockies Express filed a response to the protest on October 20, 2016, to which the shippers replied on October 25, 2016. On October 20, 2016, Rockies Express also filed an errata to rates applicable to a pooling and wheeling service. The FERC set a November 1, 2016 comment deadline on the errata filing. The interim filing remains pending before the FERC.

~~Seneca Lateral Facilities Conversion – FERC Docket No. CP15-102-000~~

On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with the FERC an application for (1) authorization to convert certain existing and operating pipeline and compression facilities located in Noble and Monroe Counties, Ohio (Seneca Lateral Facilities described in Docket Nos. ~~CP13-539-000~~IS17-263-000, IS17-464-00, and ~~CP14-194-000) from Natural Gas Policy Act~~IS17-465-000 to increase the contract and non-contract rates by an amount reflecting the most recent FERC annual index adjustment of ~~1978 Section 311 authority to Natural Gas Act Section 7 jurisdiction, and (2) issuance of a certificate of public convenience and necessity authorizing~~ approximately 0.2%, which became effective July 1, 2017.

Rockies Express to operate and maintain the Seneca Lateral Facilities. On April 7, 2016, the FERC issued a Certificate to Rockies Express granting its requested authorizations. As directed by the FERC, Rockies Express filed revised rates for Natural Gas Act service on the Seneca Lateral, and the Seneca Lateral commenced Natural Gas Act service on June 1, 2016.

Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000

On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The ~~proposed~~ facilities ~~will increase~~increased the Rockies Express Zone 3 east-to-west mainline capacity by ~~800,000 Dth/d from receipts at Clarington, Ohio to corresponding deliveries of 520,000 Dth/d and 280,000 Dth/d to Lebanon, Ohio and Moultrie County, Illinois, respectively.~~0.8 Bcf/d. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities. The project was placed in-service for the full 0.8 Bcf/d on January 6, 2017.

2016 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP16-702 and RP17-240

On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702. The FERC issued an order accepting the filing on March 25, 2016. On December 1, 2016, Rockies Express made an interim fuel tracker filing with a proposed effective date of January 1, 2017 in Docket No. RP17-240. The FERC issued an order accepting the filing on December 29, 2016.

Electric Power Charge Clarification - FERC Docket No. RP17-285

On December 21, 2016, in Docket No. RP17-285, Rockies Express proposed certain revisions to the General Terms and Conditions of its tariff to clarify that the electric power costs associated with the operation of gas coolers installed in association with the Zone 3 Capacity Enhancement Project, at both electric and gas powered stations, will be included in the Power Cost Tracker. Several shippers submitted comments on the proposal. The FERC issued an order on January 19, 2017 accepting the proposed revisions permitting the recovery of electric power costs from the operation of both gas and electric powered compressor stations, subject to certain clarifications.

2017 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP17-401 and RP17-1064

On February 13, 2017, in Docket No. RP17-401, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2017. The FERC issued an order accepting the filing, including certain requested waivers, on March 21, 2017. On September 20, 2017, Rockies Express made its interim fuel tracker filing in Docket No. RP17-1064 with a proposed effective date of November 1, 2017. The FERC issued an order accepting the filing on October 18, 2017.

TIGT

General Rate Case Filing - FERC Docket No. RP16-137-000, et seq.

On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to Section 4 of the National Gas Act ("NGA"). The rate case proposed, among other things, a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT, certain changes to the transportation rate design of its system, a fixed fuel and lost and unaccounted for ("FL&U") and power cost tracker, and certain pro forma tariff records reflecting revisions to TIGT's Tariff.

On June 8, 2016, TIGT filed an Offer of Settlement (the "TIGT Rate Case Settlement") with the FERC, which resolved all issues the FERC had set for hearing. Following certification by the Administrative Law Judge and approval by the FERC, TIGT filed revised tariff records to implement the TIGT Rate Case Settlement, which the FERC subsequently approved on December 23, 2016. Per the terms of the TIGT Rate Case Settlement, TIGT is required to file a new general rate case on May 1, 2019 (provided that such rate case is not pre-empted by a pre-filing settlement).

On February 3, 2017, the FERC accepted TIGT’s pro forma tariff records, subject to conditions, and directed TIGT to file the actual tariff records within 30 days. TIGT subsequently submitted a compliance filing to implement the actual tariff records and restate its tariff to be effective April 1, 2017 and also filed to cancel its existing tariff (which was ultimately superseded by the new tariff). On March 16, 2017, the FERC accepted both filings.

2017 Annual Fuel Tracker Filing - FERC Docket No. RP17-428-000

On February 27, 2017, in Docket No. RP17-428-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2017. The filing incorporated the FL&U tracker and power cost tracker mechanisms agreed to in the TIGT Rate Case Settlement. The FERC accepted the filing on March 21, 2017.

Electric Power Charge Clarification - FERC Docket No. RP17-1051

On September 15, 2017, in Docket No. RP17-1051, TIGT proposed certain revisions to the General Terms and Conditions of its tariff to clarify, amongst other things, that the electric power costs associated with the operation of gas coolers at both electric and gas powered stations are properly included in the Power Cost Tracker. The FERC issued an order on October 3, 2017 accepting the proposed revisions.

Trailblazer

2017 Annual and Interim Fuel Tracker Filings - FERC Docket Nos. RP17-549 and RP17-1052

On March 22, 2017, in Docket No. RP17-549, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2017. The FERC accepted the filing on April 19, 2017. On September 15, 2017, Trailblazer made its interim fuel tracker filing in Docket No. RP17-1052 with a proposed effective date of November 1, 2017. The FERC accepted the filing on October 13, 2017.

~~14.~~15. Legal and Environmental Matters

Legal

In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on our business, financial position, results of operations, or cash flows.

We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, ~~had~~have recorded no reserve for legal claims as of September 30, ~~2016~~2017 or December 31, ~~2015.~~2016.

Rockies Express

~~Mineral Management Service Lawsuit~~

On June 30, 2009, Rockies Express filed claims against Mineral Management Service, a former unit of the U.S. Department of Interior (collectively "Interior") for breach of its contractual obligation to sign transportation service agreements for pipeline capacity that it had agreed to take on Rockies Express. The Civilian Board of Contract Appeals ("CBCA") conducted a trial and ruled that Interior was liable for breach of contract, but limited the damages Interior was required to pay. On September 13, 2013, the United States Court of Appeals for the Federal Circuit issued a decision affirming that Interior was liable for its breach of contract, but reversing the CBCA's decision to limit damages. The case was remanded to the CBCA for the purpose of calculating damages at a hearing. On May 20, 2016, Rockies Express and Interior agreed to resolve the claims in this matter in exchange for a $65 million cash payment to Rockies Express. Interior paid the amount due Rockies Express on June 23, 2016.

Ultra Resources

In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, ~~in which Rockies Express seeks~~seeking approximately $303 million in damages and other relief. Specifically, Rockies Express has asserted that Ultra owes approximately $303 million for past transportation service charges and for reservation charge fees that Rockies Express would have received over the term of the service agreement had Ultra not defaulted, in addition to other amounts owed under law or equity.

On April 29, 2016, Ultra and certain of its debtor affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District of ~~Texas. On May 10, 2016, Ultra filed a notice of bankruptcy in the Harris County state court proceeding,~~Texas, which ~~asserted that pursuant to section 362(a) of the Bankruptcy Code, the filing of Ultra's Chapter 11 petition~~ operated as a stay of the Harris County state court proceeding. ~~Accordingly,~~

On January 12, 2017, Rockies Express ~~intends~~and Ultra entered into an agreement to ~~pursue its~~settle Rockies Express' approximately $303 million claim against Ultra. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37 per dth/d, or approximately $26.8 million annually. TEP received its proportionate distribution from the cash settlement payment in ~~Ultra's Chapter 11 proceeding.~~July 2017.

Michels Corporation

On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels ~~seeks~~sought unspecified damages from Rockies Express and ~~asserts~~asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels ~~has~~ also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due. ~~The case is currently scheduled to go to trial in April 2017.~~

On February 2, 2017, Rockies Express ~~also previously filed Petition~~and Michels agreed to resolve Michels' claims for ~~Declaratory Judgment, Injunctive Relief and Damages against Michels in Johnson County, Kansas. That claim~~a $10 million cash payment by Rockies Express. The cash payment was ~~dismissed without prejudice in September 2015.~~inclusive of approximately $5.9 million that Rockies Express ~~believes Michels' claims are without merit~~had been withholding from Michels. Subsequently, Rockies Express and ~~plans~~Michels entered into a definitive agreement with respect to ~~continue~~the settlement and Rockies Express made the $10 million cash payment to ~~vigorously contest all of the claims in this matter.~~Michels on February 16, 2017.

Environmental, Health and Safety

We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of ~~$4.3~~$7.7 million and ~~$4.8~~$4.0 million at September 30, ~~2016~~2017 and December 31, ~~2015,~~2016, respectively.

TMID

Casper Plant, EPA Notice of Violation

In August 2011, the EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, Tallgrass Midstream, LLC ("TMID") received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including the expected inclusion of TIGT as a party to any possible settlement as a result of TIGT owning a compressor that is located adjacent to the Casper Gas Plant site.

Casper Mystery Bridge Superfund Site

The Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed and we have requested that the portion of the site attributable to us be delisted from the National Priorities List. On July 3, 2017, our partial delisting request was published by the EPA in the Federal Register. On August 3, 2017, there were no adverse public comments, therefore on August 29, 2017, the Casper Gas Plant portion of the Casper Mystery Bridge Superfund Site was delisted from the National Priorities List. A work plan has been developed to permanently close the associated monitoring wells, which is scheduled to be completed during the fourth quarter of 2017.

Casper Gas Plant

On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing.

Trailblazer

Pipeline Integrity Management Program

~~In 2014 and 2015,~~ Trailblazer ~~conducted~~is currently operating at less than its current maximum allowable operating pressure ("MAOP"), public notice of which was first provided in June 2014. As a result of smart tool surveys ~~and preliminary analysis on segments of its natural gas pipeline to evaluate the growth rate of corrosion downstream of compressor stations.~~conducted in 2014, Trailblazer ~~currently believes that~~identified approximately 25 - 35 miles of pipe that will likely need to be repaired or replaced in order for the pipeline to operate at its ~~maximum allowable operating pressure~~MAOP of 1,000 pounds per square ~~inch.~~inch across all segments of the Trailblazer Pipeline. Such repair or replacement will likely occur over a period of years, depending upon ~~final assessment of corrosion growth rates and~~ the remediation and repair plan implemented by Trailblazer. Segments of the Trailblazer ~~is currently operating at~~Pipeline that require full replacement could cost as much as $2.7 million per mile and repair costs on sections of the pipeline that do not require full replacement are expected to be less ~~than its current maximum allowable operating pressure, public notice of which was first provided in June 2014.~~on a per mile basis. The current pressure reduction is not expected to prevent Trailblazer from fulfilling its firm service obligations at existing subscription levels and to date it has not had a material adverse financial impact on ~~TEP.~~us.

~~During 2015,~~With respect to the approximately 25 - 35 miles of pipe that has been identified, Trailblazer completed 32 excavation digs in 2015 at an aggregate cost of approximately $1.3 ~~million based on preliminary analysis of the smart tool surveys performed in 2014. Segments of the~~million. Trailblazer Pipeline that require full replacement are currently expected to cost in the range of approximately $2.2 million to $2.7 million per mile. Repair costs on sections of the pipeline that do not require full replacement are expected to be less on a per mile basis. Trailblazer is continuing to develop a remediationcompleted additional excavation digs and ~~repair plan, which involves, among other things, finalizing cost recovery options, establishing project scope and timing and setting an overall project budget. In 2016, Trailblazer intends to replace~~replaced approximately 8 miles of pipe ~~install additional ground beds,~~at an aggregate cost of approximately $19.0 million during 2016, and ~~continue remediating areas with external control anomalies~~intends to complete the pipe replacement project in 2017 at an estimated cost of ~~$21.5~~$2.5 million. Trailblazer is currently exploring all possible cost recovery ~~options. It may not ultimately be able~~options to recover ~~any or all of~~ such out of pocket costs, ~~unless and until Trailblazer recovers them~~including recovery through a general rate increase, ~~or other FERC-approved recovery mechanism, or through~~ negotiated rate agreements with its ~~customers.~~customers, or other FERC-approved recovery mechanisms.

In connection with ~~TEP's~~our acquisition of the Trailblazer Pipeline, TD agreed to contractually indemnify TEP for ~~any~~certain out of pocket costs ~~incurred between April 1, 2014 and April 1, 2017~~ related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions ~~are~~were necessitated by external corrosion caused by the pipeline's disbonded Hi-Melt CTE coating. The contractual indemnity provided ~~to TEP~~ by TD ~~is currently~~was capped at $20 million and iswas subject to ~~an annual~~a $1.5 million deductible. ~~During~~TEP has received $20 million from TD pursuant to the contractual indemnity as of September 30, 2017.

Pony Express

Pipeline Integrity

In connection with certain crack tool runs on the Pony Express System completed in 2015 and 2016, Pony Express completed approximately $9.8 million of remediation for anomalies identified on the Pony Express System associated with the initial conversion and commissioning of portions of the pipeline converted from natural gas to crude oil service, and has substantially completed additional remediation on the Pony Express System of approximately $9 million during the nine months ended September 30, ~~2016, TEP received contributions~~2017.

Terminals

System Failures

In January 2017, approximately 10,000 bbls of ~~$5.3 million from TD related~~crude oil were released at the Sterling Terminal as the result of a defective roof drain system on a storage tank. The release was restricted to the ~~indemnity.~~containment area designed for such purpose and approximately 9,000 bbls were recovered. Remediation was complete as of June 30, 2017. The total cost to remediate the release was approximately $600,000.

~~15. Reporting~~16. Reportable Segments

Our operations are located in the United States. During the third quarter of 2017, management revised the operational reporting used by the chief operating decision maker in light of recent acquisitions and commercial management reorganization. As a result of this internal change, our reportable segments were updated to ensure that segment classification remains aligned with operational reporting. We are organized into three ~~reporting~~reportable segments: (1) Natural Gas Transportation, (2) Crude Oil Transportation, and (3) Gathering, Processing & ~~Logistics, (2)~~Terminalling.

Natural Gas Transportation

The Natural Gas Transportation ~~& Logistics,~~segment is engaged in the ownership and ~~(3) Processing & Logistics.~~operation of FERC-regulated interstate natural gas pipelines and an integrated natural gas storage facility that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. The Natural Gas Transportation segment includes our 100% membership interest in NatGas acquired effective January 1, 2017 and our 49.99% membership interest in Rockies Express, including the additional 24.99% membership interest acquired effective March 31, 2017.

Crude Oil Transportation ~~& Logistics~~

The Crude Oil Transportation ~~& Logistics~~ segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, and other nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado and was placed in service in the second quarter of 2015.

~~Natural Gas Transportation & Logistics~~

The Natural Gas Transportation & Logistics segment is engaged in the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. The Natural Gas Transportation & Logistics segment includes our 25% membership interest in Rockies Express effective May 6, 2016, as discussed in Note 3 – ~~Acquisitions.~~

Gathering, Processing & ~~Logistics~~Terminalling

The Gathering, Processing & ~~Logistics~~Terminalling segment is engaged in the ownership and operation of natural gas gathering, processing, treating and fractionation facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets, including the Douglas Gathering System acquired on June 5, 2017, as well as water business services provided primarily to the oil and gas exploration and production industry and the transportation of NGLs. The Gathering, Processing & Terminalling segment also includes Stanchion as well as our 100% membership interest in Terminals acquired effective January 1, 2017 and the PRB Crude System acquired on August 3, 2017.

Corporate and Other

Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with our revolving credit ~~facility,~~facilities and the 2024 and 2028 Notes, public company costs, and equity-based compensation expense.

These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for their respective operations.

The following tables set forth our segment information for the periods indicated:

Three Months Ended September 30, 2016 Three Months Ended September 30, 2015
Revenue: Total
Revenue Inter-
Segment External
Revenue Total
Revenue Inter-
Segment External
Revenue
(in thousands)
Crude Oil Transportation & Logistics $ 95,826
$ —
$ 95,826
$ 83,272
$ —
$ 83,272
Natural Gas Transportation & Logistics 33,812
(1,427 ) 32,385
33,636
(1,346 ) 32,290
Processing & Logistics 23,914
—
23,914
22,606
—
22,606
Corporate and Other —
—
—
—
—
—
Total Revenue $ 153,552
$ (1,427 ) $ 152,125
$ 139,514
$ (1,346 ) $ 138,168

Nine Months Ended September 30, 2016 Nine Months Ended September 30, 2015
Revenue: Total
Revenue Inter-
Segment External
Revenue Total
Revenue Inter-
Segment External
Revenue
(in thousands)
Crude Oil Transportation & Logistics $ 283,868
$ —
$ 283,868
$ 208,872
$ —
$ 208,872
Natural Gas Transportation & Logistics 94,949
(4,192 ) 90,757
98,215
(4,036 ) 94,179
Processing & Logistics 69,836
—
69,836
82,762
—
82,762
Corporate and Other —
—
—
—
—
—
Total Revenue $ 448,653
$ (4,192 ) $ 444,461
$ 389,849
$ (4,036 ) $ 385,813

Three Months Ended September 30, 2016 Three Months Ended September 30, 2015
Operating Income: Total
Operating Income Inter-
Segment External
Operating Income Total
Operating Income Inter-
Segment External
Operating Income
(in thousands)
Crude Oil Transportation & Logistics $ 53,227
$ 1,346
$ 54,573
$ 44,069
$ 1,346
$ 45,415
Natural Gas Transportation & Logistics 14,254
(1,427 ) 12,827
10,499
(1,346 ) 9,153
Processing & Logistics 120
81
201
(212 ) —
(212 )
Corporate and Other (3,571 ) —
(3,571 ) (1,951 ) —
(1,951 )
Total Operating Income $ 64,030
$ —
$ 64,030
$ 52,405
$ —
$ 52,405
Reconciliation to Net Income:
Interest expense, net (12,157 ) (4,982 )
Unrealized gain on derivative instrument (4,419 ) —
Equity in earnings of unconsolidated investment 12,066
—
Other income, net 480
502
Net income before income tax $ 60,000
$ 47,925



	Three Months Ended September 30, 2017							Three Months Ended September 30, 2016
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Natural Gas Transportation	$	36,084	$	(1,883	)	$	34,201	$	34,994	$	(1,427	)	$	33,567
Crude Oil Transportation	93,029		(6,947		)	86,082		95,826		(271		)	95,555
Gathering, Processing & Terminalling	57,736		(2,150		)	55,586		27,030		(2,884		)	24,146
Corporate and Other	—		—			—		—		—			—
Total revenue	$	186,849	$	(10,980	)	$	175,869	$	157,850	$	(4,582	)	$	153,268

Nine Months Ended September 30, 2016 Nine Months Ended September 30, 2015
Operating Income: Total
Operating Income Inter-
Segment External
Operating Income Total
Operating Income Inter-
Segment External
Operating Income
(in thousands)
Crude Oil Transportation & Logistics $ 159,619
$ 4,037
$ 163,656
$ 103,857
$ 4,036
$ 107,893
Natural Gas Transportation & Logistics 35,018
(4,192 ) 30,826
32,989
(4,036 ) 28,953
Processing & Logistics (1,074 ) 155
(919 ) 4,508
—
4,508
Corporate and Other (9,717 ) —
(9,717 ) (7,126 ) —
(7,126 )
Total Operating Income $ 183,846
$ —
$ 183,846
$ 134,228
$ —
$ 134,228
Reconciliation to Net Income:
Interest expense, net (31,275 ) (12,901 )
Unrealized gain on derivative instrument 5,588
—
Equity in earnings of unconsolidated investment 35,387
—
Other income, net 1,267
1,983
Net income before income tax $ 194,813
$ 123,310



	Nine Months Ended September 30, 2017							Nine Months Ended September 30, 2016
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Natural Gas Transportation	$	105,622	$	(4,770	)	$	100,852	$	99,804	$	(4,192	)	$	95,612
Crude Oil Transportation	273,768		(6,947		)	266,821		283,868		(271		)	283,597
Gathering, Processing & Terminalling	121,415		(7,956		)	113,459		78,818		(8,576		)	70,242
Corporate and Other	—		—			—		—		—			—
Total revenue	$	500,805	$	(19,673	)	$	481,132	$	462,490	$	(13,039	)	$	449,451

Nine Months Ended September 30,
Capital Expenditures: 2016 2015
(in thousands)
Crude Oil Transportation & Logistics $ 25,985
$ 40,579
Natural Gas Transportation & Logistics 11,146
10,858
Processing & Logistics 8,121
13,709
Corporate and Other —
—
Total capital expenditures $ 45,252
$ 65,146



	Three Months Ended September 30, 2017									Three Months Ended September 30, 2016
Operating Income:	Total Operating Income			Inter- Segment			External Operating Income			Total Operating Income			Inter- Segment			External Operating Income
	(in thousands)
Natural Gas Transportation	$	17,016		$	(1,883	)	$	15,133		$	15,436		$	(1,427	)	$	14,009
Crude Oil Transportation	51,478			(441		)	51,037			53,227			4,230			57,457
Gathering, Processing & Terminalling	9,045			2,324			11,369			1,851			(2,803		)	(952		)
Corporate and Other	(3,536		)	—			(3,536		)	(3,571		)	—			(3,571		)
Total Operating Income	$	74,003		$	—		$	74,003		$	66,943		$	—		$	66,943
Reconciliation to Net Income:
Interest expense, net							(24,408		)							(12,157		)
Unrealized loss on derivative instruments							—									(4,419		)
Equity in earnings of unconsolidated investments							123,642									12,764
Gain on remeasurement of unconsolidated investment							9,728									—
Other income, net							454									480
Net income before tax							$	183,419								$	63,611

Assets: September 30, 2016 December 31, 2015
(in thousands)
Crude Oil Transportation & Logistics $ 1,417,241
$ 1,439,418
Natural Gas Transportation & Logistics 1,155,372
706,576
Processing & Logistics 405,760
409,795
Corporate and Other 473,833
460,871
Total assets $ 3,452,206
$ 3,016,660



	Nine Months Ended September 30, 2017									Nine Months Ended September 30, 2016
Operating Income:	Total Operating Income			Inter- Segment			External Operating Income			Total Operating Income			Inter- Segment			External Operating Income
	(in thousands)
Natural Gas Transportation	$	49,910		$	(4,770	)	$	45,140		$	39,873		$	(4,192	)	$	35,681
Crude Oil Transportation	145,462			8,054			153,516			159,619			12,613			172,232
Gathering, Processing & Terminalling	20,928			(3,284		)	17,644			(4,629		)	(8,421		)	(13,050		)
Corporate and Other	(12,127		)	—			(12,127		)	(9,717		)	—			(9,717		)
Total Operating Income	$	204,173		$	—		$	204,173		$	185,146		$	—		$	185,146
Reconciliation to Net Income:
Interest expense, net							(61,539		)							(31,275		)
Unrealized gain on derivative instruments							1,885									5,588
Equity in earnings of unconsolidated investments							187,121									37,495
Gain on remeasurement of unconsolidated investment							9,728									—
Other income, net							796									1,267
Net income before tax							$	342,164								$	198,221



	Nine Months Ended September 30,
Capital Expenditures:	2017		2016
	(in thousands)
Natural Gas Transportation	$	9,829	$	11,146
Crude Oil Transportation	28,785		25,985
Gathering, Processing & Terminalling	49,436		18,266
Corporate and Other	—		—
Total capital expenditures	$	88,050	$	55,397



Assets:	September 30, 2017		December 31, 2016
	(in thousands)
Natural Gas Transportation	$	1,618,828	$	1,176,147
Crude Oil Transportation	1,384,981		1,410,695
Gathering, Processing & Terminalling	887,089		495,170
Corporate and Other	512,248		543,468
Total assets	$	4,403,146	$	3,625,480

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

The historical financial statements included in this Quarterly Report reflect the consolidated results of operations of ~~Tallgrass Energy GP, LP's ("TEGP") 30.35%~~TEGP's 36.94% interest in Tallgrass Equity, ~~LLC ("Tallgrass Equity"),~~ Tallgrass Equity's 100% membership interest in ~~Tallgrass MLP~~TEP GP, ~~LLC ("TEP GP"),~~ which owns all of the ~~Incentive Distribution Rights ("IDRs"),~~IDRs, and all of the outstanding general partner units in ~~Tallgrass Energy Partners, LP ("TEP"),~~TEP, and Tallgrass Equity's 20 million TEP common units it acquired at the closing of the ~~initial public offering of Class A shares of~~ TEGP (the "Offering"). The following discussion analyzes the financial condition and results of operations of TEGP, which for periods prior to the completion of the Offering on May 12, 2015 includes the financial condition and results of operations of TEGP Predecessor, which refers to TEGP as recast to show the effects of the reorganization transactions in connection with the Offering. In certain circumstances and for ease of reading we discuss the financial results of these entities prior to their respective acquisitions as being "our" financial results during historic periods.IPO. As used in ~~Item 2 of~~ this Quarterly Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TEGP" and similar terms refer to Tallgrass Energy GP, LP, together with its consolidated subsidiaries (including Tallgrass Equity, TEP and their respective subsidiaries). The term our "general partner" refers to TEGP Management, LLC. References to "TD" refer to Tallgrass Development, LP. As discussed further in Note 2 – Summary of Significant Accounting Policies to the accompanying condensed consolidated financial statements, our financial statements for historical periods prior to January 1, 2017 have been recast to reflect the operations of Terminals and NatGas, which were acquired by TEP effective January 1, 2017.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report. Additionally, the following discussion and analysis should be read in conjunction with our audited financial statements and notes thereto, the related "Management's Discussion and Analysis of Financial Condition and Results of Operations," the discussion of "Risk Factors" and the discussion of TEGP's "Business" in our Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016 (our ~~"2015~~"2016 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February ~~17, 2016.~~15, 2017.

A reference to a "Note" herein refers to the accompanying Notes to Condensed Consolidated Financial Statements contained in Item 1.—Financial Statements. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" and "Risk Factors" for information regarding certain risks inherent in our business.

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report and the documents incorporated by reference herein contain forward-looking statements concerning our operations, economic performance and financial condition. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as "could," "will," "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this Quarterly Report include our expectations of plans, strategies, objectives, growth and anticipated financial and operational performance, including guidance regarding our and TD's infrastructure programs, revenue projections, capital expenditures and tax position. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are reasonable. However, when considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

our ability to pay distributions to our Class A shareholders;

our expected receipt of, and amounts of, distributions from Tallgrass Equity;

TEP's ability to complete and integrate acquisitions from TD or from third parties, including its ~~acquisition~~acquisitions of ~~a 25%~~the PRB Crude System in August 2017, an additional 49% membership interest in Deeprock Development in July 2017, the Douglas Gathering System in June 2017, an additional 24.99% membership interest in Rockies Express ~~that was completed~~from TD in ~~May 2016, its purchase of an additional 31.3%~~March 2017 and a 100% membership interest in ~~Pony Express that was completed~~NatGas and Terminals from TD in January ~~2016,~~2017;

the demand for TEP's services, including crude oil transportation, storage, gathering and ~~its acquisition of~~terminalling services; natural gas transportation, storage, gathering and processing services; and water business ~~assets in Weld County, Colorado that was completed in December 2015;~~services, as well as TEP's ability to successfully contract or re-contract with its customers;

large or multiple customer defaults, including defaults resulting from actual or potential insolvencies;

our ability to successfully implement our business plan;

changes in general economic conditions;

competitive conditions in our industry;

the effects of existing and future laws and governmental regulations;

actions taken by third-party operators, processors and transporters;

~~the demand for TEP's services, including crude oil transportation services, natural gas transportation, storage and processing services and water business services;~~

~~our ability to successfully implement our business plan;~~

our ability to complete internal growth projects on time and on budget;

the price and availability of debt and equity financing;

the level of production of crude oil, natural gas and other hydrocarbons and the resultant market prices of crude oil, natural gas, ~~NGLs,~~natural gas liquids, and other hydrocarbons;

the availability and price of natural gas and crude oil, and fuels derived from both, to the consumer compared to the price of alternative and competing fuels;

competition from the same and alternative energy sources;

energy efficiency and technology trends;

operating hazards and other risks incidental to transporting, storing, gathering and terminalling crude ~~oil,~~oil; transporting, storing and processing natural ~~gas,~~gas; and transporting, gathering and disposing of water produced in connection with hydrocarbon exploration and production activities;

environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

natural disasters, weather-related delays, casualty losses and other matters beyond our control;

interest rates;

labor relations;

changes in tax status;

~~the effects of existing and future laws and governmental regulations;~~

the effects of future litigation; and

certain factors discussed elsewhere in this Quarterly Report.

Forward-looking statements speak only as of the date on which they are made. While we may update these statements from time to time, we are not required to do so other than pursuant to the securities laws.

Overview

TEGP is a limited partnership that has elected to be treated as a corporation for U.S. federal income tax purposes. We were formed as part of a reorganization involving entities that were previously controlled by Tallgrass Equity ~~in order~~ to effect the ~~Offering~~TEGP IPO, which was completed on May 12, 2015.

Our sole cash-generating asset is an approximate ~~30.35%~~36.94% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of the direct and indirect partnership interests in TEP as described below:

100% of the outstanding membership interests in TEP GP, which owns all of the general partner interest in TEP ~~and~~as well as all of ~~TEP's~~the TEP IDRs. The general partner interest in TEP is represented by 834,391 general partner units, representing an approximate ~~1.14%~~1.13% general partner interest in TEP at November 2, ~~2016.~~2017.

20,000,000 TEP common units, representing an approximate ~~27.42%~~27.01% limited partner interest in TEP at November 2, ~~2016.~~

2017.

TEP is a publicly traded, growth-oriented limited partnership formed in 2013 to own, operate, acquire and develop midstream energy assets in North America. TEP currently provides crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). TEP provides natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) TEP's 25% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), a Delaware limited liability company which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio, (2) the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and (3) the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). TEP also provides services for customers in Wyoming at the Casper and Douglas natural gas processing facilities and the West Frenchie Draw natural gas treating facility (collectively, the "Midstream Facilities"), and NGL transportation services in Northeast Colorado. TEP performs water business services in Colorado and Texas through BNN Water Solutions, LLC ("Water Solutions"). TEP's operations are ~~strategically~~ located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations.

TEP intends to continue to leverage its relationship with TD and utilize the significant experience of its management team to execute its growth strategy of acquiring midstream assets from TD and third parties, increasing utilization of its existing assets and expanding its systems through construction of additional assets. ~~TEP's~~

Our reportable business segments are:

~~Crude Oil Transportation & Logistics—the ownership and operation of a FERC-regulated crude oil pipeline system;~~

Natural Gas ~~Transportation & Logistics—~~Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities;

Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system; and

Gathering, Processing & ~~Logistics—~~Terminalling—the ownership and operation of natural gas gathering, processing, treating and fractionation ~~facilities,~~facilities; crude oil gathering, storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production ~~industry~~industry; and the transportation of NGLs.

Financial Presentation

TEGP has no operations outside of its indirect ownership interests in TEP. TEGP is the managing member of and therefore controls Tallgrass Equity. Tallgrass Equity, in turn, controls TEP through the direct ownership of 100% of TEP GP, TEP's general partner. As a result, under GAAP, TEGP consolidates Tallgrass Equity, TEP GP, TEP, and TEP's subsidiaries. As such, TEGP's results of operations will not differ materially from the results of operations of TEP. The most noteworthy reconciling items between TEGP's condensed consolidated financial statements and TEP's condensed consolidated financial statements primarily relate to (i) the inclusion of the Tallgrass Equity revolving credit facility, (ii) the impact of TEGP's election to be treated as a corporation for U.S. federal income tax purposes and (iii) the presentation of noncontrolling interests in Tallgrass Equity and TEP. The interests in Tallgrass Equity and TEP that are not directly or indirectly owned by TEGP will be reflected as being attributable to noncontrolling interests in TEGP's condensed consolidated financial statements.

In addition, historical results of operations for periods prior to May 12, 2015 do not reflect TEGP's incremental general and administrative costs associated with becoming a separate publicly traded entity, including expenses associated with (i) compensation for new directors, (ii) incremental director and officer liability insurance, (iii) listing on the NYSE, (iv) investor relations, (v) legal, (vi) tax and (vii) accounting.

Recent Developments

TEGP Distribution Announced

On October ~~5, 2016, we announced~~10, 2017, the Board of Directors of our general partner declared a cash distribution for the quarter ended September 30, ~~2016~~2017 of ~~$0.2625~~$0.3550 per Class A share. The distribution will be paid on November 14, ~~2016,~~2017, to Class A shareholders of record on October 31, ~~2016.~~2017.

TEP Distribution Announced

On October ~~5, 2016, TEP announced~~10, 2017, the Board of Directors of TEP's general partner declared a cash distribution for the quarter ended September 30, ~~2016~~2017 of ~~$0.795~~$0.9450 per common unit. The distribution will be paid on November 14, ~~2016,~~2017, to unitholders of record on October 31, ~~2016.~~

~~Exercise of Call Option~~

~~On October 31, 2016, TEP partially exercised the call option granted by TD in January 2016 as discussed in Note 3 –~~ ~~Acquisitions~~ covering 1,251,760 common units. These common units were deemed canceled upon the exercise of the call option and as of the exercise date were no longer issued and outstanding. As of November 2, 2016, 1,703,094 common units remained subject to the call option.2017.

How We Evaluate Our Operations

We evaluate our results using, among other measures, cash distributions received from Tallgrass Equity, TEP's contract profile and volumes, and operating costs and expenses of TEGP and its consolidated subsidiaries.

Cash Distributions Received from Tallgrass Equity

Our cash flow is currently generated solely by distributions received from Tallgrass Equity. Tallgrass Equity currently receives all of its cash flows from distributions on its direct and indirect partnership interests in TEP. Tallgrass Equity is therefore entirely dependent upon the ability of TEP to make cash distributions to its partners.

TEP's Contract Profile and Volumes

TEP's results are driven primarily by the volume of ~~crude oil transportation capacity,~~ natural gas transportation and storage capacity, crude oil transportation, storage, gathering and terminalling capacity, NGL transportation capacity, and water transportation, gathering and disposal capacity under firm fee contracts, as well as the volume of natural gas that it gathers and processes and the fees assessed for such services.

Operating Costs and Expenses

The primary components of TEP's operating costs and expenses that we evaluate include cost of sales, cost of transportation services, operations and maintenance and general and administrative costs. TEP's operating expenses are driven primarily by expenses related to the operation, maintenance and growth of its asset base.

Results of Operations

The following provides a summary of our operating metrics for the periods indicated:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Natural Gas Transportation Segment:
Gas transportation average firm contracted volumes (MMcf/d)⁽¹⁾	1,646	1,601	1,737	1,625
Crude Oil Transportation Segment:
Crude oil transportation average contracted capacity (Bbls/d)	306,916	298,580	302,476	294,364
Crude oil transportation average throughput (Bbls/d)	269,585	276,138	268,435	284,512
Gathering, Processing & Terminalling Segment:
Natural gas processing inlet volumes (MMcf/d)	111	103	106	102
Freshwater average volumes (Bbls/d)	109,988	31,656	93,885	31,291
Produced water gathering and disposal average volumes (Bbls/d)	43,924	23,784	23,405	18,176


⁽¹⁾	Volumes transported under firm fee contracts, excluding Rockies Express.

The following provides a summary of our consolidated results of operations for the periods indicated:

Three Months Ended September 30, Nine Months Ended September 30,
2016 2015 2016 2015
(in thousands, except operating data)
Revenues:
Crude oil transportation services $ 91,387
$ 81,928
$ 279,281
$ 206,331
Natural gas transportation services 31,444
29,431
89,406
90,620
Sales of natural gas, NGLs, and crude oil 20,758
20,252
51,514
62,132
Processing and other revenues 8,536
6,557
24,260
26,730
Total Revenues 152,125
138,168
444,461
385,813
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below) 18,590
18,186
48,116
54,959
Cost of transportation services (exclusive of depreciation and amortization shown below) 13,528
14,862
43,924
39,069
Operations and maintenance 14,714
14,071
41,055
36,054
Depreciation and amortization 20,831
20,802
64,099
61,762
General and administrative 13,715
12,321
41,710
38,711
Taxes, other than income taxes 6,717
5,521
19,862
16,547
Loss on disposal of assets —
—
1,849
4,483
Total Operating Costs and Expenses 88,095
85,763
260,615
251,585
Operating Income 64,030
52,405
183,846
134,228
Other Income (Expense):
Interest expense, net (12,157 ) (4,982 ) (31,275 ) (12,901 )
Unrealized (loss) gain on derivative instrument (4,419 ) —
5,588
—
Equity in earnings of unconsolidated investment 12,066
—
35,387
—
Other income, net 480
502
1,267
1,983
Total Other (Expense) Income (4,030 ) (4,480 ) 10,967
(10,918 )
Net income before tax 60,000
47,925
194,813
123,310
Deferred income tax expense (3,209 ) (1,828 ) (12,792 ) (3,600 )
Net income 56,791
46,097
182,021
119,710
Net income attributable to noncontrolling interests (49,750 ) (41,674 ) (163,943 ) (105,431 )
Net income attributable to TEGP $ 7,041
$ 4,423
$ 18,078
$ 14,279
Operating Data:
Crude oil transportation average throughput (Bbls/d)⁽¹⁾
276,138
252,540
284,512
218,697
Gas transportation average firm contracted volumes (MMcf/d)⁽²⁾
1,440
1,506
1,464
1,543
Natural gas processing inlet volumes (MMcf/d) 103
110
102
128


⁽¹⁾	Approximate average daily throughput for the three and nine months ended September 30, 2015 is reflective of the volumetric ramp up due to commercial in-service of the Pony Express System beginning in October 2014 and delays in the construction and expansion efforts of third-party pipelines with which Pony Express shares joint tariffs.


⁽²⁾	~~Excludes firm contracted volumes of Rockies Express.~~



	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands)
Revenues:
Crude oil transportation services	$	86,180		$	91,387		$	260,366		$	279,281
Natural gas transportation services	30,256			31,444			91,370			89,406
Sales of natural gas, NGLs, and crude oil	32,215			20,487			70,514			51,243
Processing and other revenues	27,218			9,950			58,882			29,521
Total Revenues	175,869			153,268			481,132			449,451
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	26,984			18,319			58,740			47,845
Cost of transportation services (exclusive of depreciation and amortization shown below)	10,538			10,842			38,799			35,946
Operations and maintenance	17,412			15,146			45,569			42,374
Depreciation and amortization	23,782			21,177			67,276			65,074
General and administrative	16,489			13,981			46,040			42,863
Taxes, other than income taxes	6,661			6,860			21,799			20,293
Contract termination	—			—			—			8,061
(Gain) loss on disposal of assets	—			—			(1,264		)	1,849
Total Operating Costs and Expenses	101,866			86,325			276,959			264,305
Operating Income	74,003			66,943			204,173			185,146
Other Income (Expense):
Interest expense, net	(24,408		)	(12,157		)	(61,539		)	(31,275		)
Unrealized (loss) gain on derivative instrument	—			(4,419		)	1,885			5,588
Equity in earnings of unconsolidated investments	123,642			12,764			187,121			37,495
Gain on remeasurement of unconsolidated investment	9,728			—			9,728			—
Other income, net	454			480			796			1,267
Total Other Income (Expense)	109,416			(3,332		)	137,991			13,075
Net income before tax	183,419			63,611			342,164			198,221
Deferred income tax expense	(12,642		)	(3,209		)	(24,982		)	(12,792		)
Net income	170,777			60,402			317,182			185,429
Net income attributable to noncontrolling interests	(154,911		)	(49,750		)	(280,534		)	(163,943		)
Net income attributable to TEGP	$	15,866		$	10,652		$	36,648		$	21,486

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

Revenues. Total revenues were ~~$152.1~~$175.9 million for the three months ended September 30, 2017, compared to $153.3 million for the three months ended September 30, 2016, ~~compared to $138.2 million for the three months ended September 30, 2015,~~ which represents an increase of ~~$14.0~~$22.6 million, or ~~10%~~15%, in total revenues. The overall increase in revenue was largely driven by increased revenues of ~~$12.6~~$30.7 million and ~~$1.3~~$1.1 million in the Gathering, Processing & Terminalling and Natural Gas Transportation segments, respectively, partially offset by decreased revenues of $2.8 million in the Crude Oil Transportation ~~& Logistics and Processing & Logistics segments, respectively,~~segment, as discussed further below.

Operating costs and expenses. Operating costs and expenses were ~~$88.1~~$101.9 million for the three months ended September 30, 2017 compared to $86.3 million for the three months ended September 30, 2016, ~~compared to $85.8 million for the three months ended September 30, 2015,~~ which represents an increase of ~~$2.3~~$15.5 million, or ~~3%.~~18%, in operating costs and expenses. The overall increase in operating costs and expenses ~~was primarily~~is driven by increased operating costs and expenses of ~~$3.4 million, $1.5 million and $1.0~~$23.5 million in the ~~Crude Oil Transportation & Logistics, Corporate and Other, and~~Gathering, Processing & ~~Logistics segments, respectively,~~Terminalling segment, partially offset by decreased operating costs and expenses of ~~$3.6~~$1.0 million and $0.5 million in the Crude Oil Transportation and Natural Gas Transportation ~~& Logistics segment,~~segments, respectively, as discussed further ~~below.~~below, as well as intersegment eliminations.

Interest expense, net. Interest expense of $24.4 million for the three months ended September 30, 2017 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities, the 2024 Notes issued on September 1, 2016 and May 16, 2017, and the 2028 Notes issued on September 15, 2017. Interest expense of $12.2 million for the three months ended September 30, 2016 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities, as well as the 2024 Notes issued on September 1, 2016. ~~Interest expense of $5.0 million for the three months ended September 30, 2015 was primarily composed of interest and fees associated with TEP and Tallgrass Equity's revolving credit facilities.~~ The increase in interest and fees, ~~associated with TEP's revolving credit facility~~ is primarily due to increased borrowings to fund a portion of our acquisitions as discussed further in Note 4 – Acquisitions, as well as the higher borrowing rate on the 2024 and 2028 Notes, the proceeds of which were used to repay borrowings under TEP's December 2015 acquisition of BNN Western, LLC ("Western") and TEP's recent acquisitions of an additional 31.3% membership interest in Pony Express effective January 1, 2016 and 25% membership interest in Rockies Express effective May 6, 2016.revolving credit facility.

Unrealized ~~loss~~(loss) gain on derivative instrument. Unrealized loss on derivative instrument of $4.4 million for the three months ended September 30, 2016 represents the change in fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016. As of February 1, 2017, no TEP common units remained subject to the call option.

Equity in earnings of unconsolidated ~~investment.~~investments. Equity in earnings of unconsolidated ~~investment~~investments was $123.6 million and $12.8 million for the three months ended September 30, 2017 and 2016, respectively. Equity in earnings of ~~$12.1~~unconsolidated investments of $123.6 million for three months ended September 30, 2017 primarily reflects our portion of earnings and the amortization of a negative basis difference of $6.6 million associated with our 49.99% membership interest in Rockies Express. During the three months ended September 30, 2017, Rockies Express recognized a $150 million gain on settlement of the Ultra litigation as discussed in Note 15 – Legal and Environmental Matters. Equity in earnings of unconsolidated investments of $12.8 million for the three months ended September 30, 2016 reflects our portion of earnings and the amortization of a negative basis difference of $3.5 million associated with our acquisition of a 25% membership interest in Rockies Express effective May 6, 2016, as well as $0.7 million related to our 20% membership interest in Deeprock Development during the three months ended September 30, 2016. For additional information, see Note 8 – Investments in Unconsolidated Affiliates.

Gain on remeasurement on unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.7 million for the three months ended September 30, 2017 was related to the remeasurement to fair value of our existing 20% membership interest in Deeprock Development in connection with TEP's acquisition of a controlling financial interest in Deeprock Development in July 2017. For additional information, see Note 4 – Acquisitions.

Deferred income tax expense. Deferred income tax expense for the three months ended September 30, ~~2016~~2017 was ~~$3.2~~$12.6 million, compared to ~~$1.8~~a deferred income tax expense of $3.2 million for the three months ended September 30, ~~2015.~~2016, which represents an increase of $9.4 million, or 294%. The increase in deferred income tax expense was ~~primarily~~ driven by the increase in ~~net~~taxable income, ~~before income taxes as well as a higher effective tax rate for the three months ended September 30, 2016 compared~~primarily attributable to the ~~three months ended September 30, 2015~~increased equity in earnings associated with Rockies Express as a result of ~~our acquisition of a 25% membership interest in Rockies Express during~~ the ~~second quarter of 2016.~~Ultra settlement.

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

Revenues. Total revenues were ~~$444.5~~$481.1 million for the nine months ended September 30, 2017, compared to $449.5 million for the nine months ended September 30, 2016, ~~compared to $385.8 million for the nine months ended September 30, 2015,~~ which represents an increase of ~~$58.6~~$31.7 million, or ~~15%~~7%, in total revenues. The overall increase in revenue was largely driven by increased revenues of ~~$75.0~~$42.6 million and $5.8 million in the Gathering, Processing & Terminalling and Natural Gas Transportation segments, respectively, partially offset by decreased revenues of $10.1 million in the Crude Oil Transportation ~~& Logistics~~ segment, ~~partially offset by decreased revenues of $12.9 million and $3.3 million in the Processing & Logistics and Natural Gas Transportation & Logistics segments, respectively,~~ as discussed further below.

Operating costs and expenses. Operating costs and expenses were ~~$260.6~~$277.0 million for the nine months ended September 30, 2017 compared to $264.3 million for the nine months ended September 30, 2016, ~~compared to $251.6 million for the nine months ended September 30, 2015,~~ which represents an increase of ~~$9.0~~$12.7 million, or 4%5%. The overall increase in operating costs and expenses is ~~primarily~~ driven by increased operating costs and expenses of ~~$19.2~~$17.0 million and $4.1 million in the Gathering, Processing & Terminalling and Crude Oil Transportation ~~& Logistics segment,~~segments, respectively, partially offset by decreased operating costs and expenses of ~~$7.3 million and $5.3~~$4.2 million in the ~~Processing & Logistics and~~ Natural Gas Transportation, ~~& Logistics segments, respectively,~~ as discussed further ~~below.~~below, as well as a $2.4 million increase in corporate general and administrative costs primarily due to payroll taxes associated with the vesting of TEP common units associated with equity-based compensation grants under the general partner's Long-term Incentive Plan as well as new equity-based compensation grants during the nine months ended September 30, 2017.

Interest expense, net. Interest expense of $61.5 million for the nine months ended September 30, 2017 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities, the 2024 Notes issued on September 1, 2016 and May 16, 2017, and the 2028 Notes issued on September 15, 2017. Interest expense of $31.3 million for the nine months ended September 30, 2016 was primarily composed of interest and fees associated with ~~the TEP and Tallgrass Equity~~our revolving credit ~~facilities~~facility and the 2024 Notes issued on September 1, 2016. Interest expense of $12.9 million for the nine months ended September 30, 2015 was primarily composed of interest and fees associated with TEP's revolving credit facility and interest and fees associated with Tallgrass Equity's revolving credit facility for periods subsequent to the closing of the Offering on May 12, 2015, partially offset by interest income of $0.4 million on the cash balance swept to TD under the Pony Express cash management agreement. The increase in interest and fees ~~associated with TEP's revolving credit facility~~ is primarily due to increased borrowings to fund a portion of ~~TEP's 2015~~our acquisitions ~~and recent acquisitions of an additional 31.3% membership interest~~as discussed further in ~~Pony Express effective January 1, 2016 and a 25% membership interest in Rockies Express effective May 6, 2016,~~Note 4 – Acquisitions, as well as ~~a full period~~the higher borrowing rate on the 2024 and 2028 Notes, the proceeds of ~~interest and fees associated with outstanding~~which were used to repay borrowings under ~~the Tallgrass Equity~~TEP's revolving credit facility.

Unrealized (loss) gain on derivative instrument.Unrealized gain on derivative instrument of $1.9 million and $5.6 million for the nine months ended September 30, 2017 and 2016, respectively, represents the change in fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016. As of February 1, 2017, no TEP common units remained subject to the call option.

Equity in earnings of unconsolidated ~~investment.~~investments. Equity in earnings of unconsolidated ~~investment of $35.4~~investments was $187.1 million and $37.5 million for the nine months ended September 30, 2017 and 2016, respectively. Equity in earnings of unconsolidated investments of $187.1 million for nine months ended September 30, 2017 primarily reflects our portion of earnings and the amortization of a negative basis difference of ~~$5.6~~$16.7 million associated with our 49.99% membership interest in Rockies Express, as well as $1.5 million of equity in earnings related to our 20% membership interest in Deeprock Development prior to TEP's acquisition of a controlling financial interest in Deeprock Development in July 2017, as discussed in Note 4 – Acquisitions. During the nine months ended September 30, 2017, Rockies Express recognized the $150 million gain on settlement of the Ultra litigation as discussed in Note 15 – Legal and Environmental Matters. Equity in earnings of unconsolidated investments of $37.5 million for the nine months ended September 30, 2016 represents earnings associated with our acquisition of a 25% membership interest in Rockies Express effective May 6, 2016, as well as $2.1 million related to our 20% membership interest in Deeprock Development during the nine months ended September 30, 2016. ~~The equity~~For additional information, see Note 8 – Investments in ~~earnings~~Unconsolidated Affiliates.

Gain on remeasurement on unconsolidated investment. Gain on remeasurement of unconsolidated investment of $9.7 million for the nine months ended September 30, ~~2016 includes recognition of our portion of the $65 million settlement received by Rockies Express~~2017 was related to the ~~lawsuit between Interior and Rockies Express as discussed~~remeasurement to fair value of our existing 20% membership interest in Deeprock Development in connection with TEP's acquisition of a controlling financial interest in Deeprock Development in July 2017. For additional information, see Note 144 – ~~Legal and Environmental Matters.~~Acquisitions.

Other income, net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income for the nine months ended September 30, ~~2016~~2017 was ~~$1.3~~$0.8 million compared to ~~$2.0~~$1.3 million for the nine months ended September 30, ~~2015.~~2016. The decrease in other income was driven by lower income related to reimbursable projects at TIGT due to contract modifications.

Deferred income tax expense.Deferred income tax expense for the nine months ended September 30, ~~2016~~2017 was ~~$12.8~~$25.0 million, compared to ~~$3.6~~a deferred income tax expense of $12.8 million for the nine months ended September 30, ~~2015.~~2016, which represents an increase of $12.2 million, or 95%. The increase in deferred income tax expense was ~~primarily~~ driven by the increase in ~~net income before income taxes and a full nine months of~~ taxable income, ~~in 2016 compared~~primarily attributable to the period subsequent to the closing of the Offering from May 12, 2015 to September 30, 2015, as well as a higher effective tax rate for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015increased equity in earnings associated with Rockies Express as a result of ~~our acquisition of a 25% membership interest in Rockies Express during~~ the ~~second quarter of 2016.~~Ultra settlement.

The following provides a summary of our ~~Crude Oil~~Natural Gas Transportation ~~& Logistics~~ segment results of operations for the periods indicated:


Segment Financial Data - Crude Oil Transportation & Logistics ⁽¹⁾	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Segment Financial Data - Natural Gas Transportation ⁽¹⁾									Three Months Ended September 30,				Nine Months Ended September 30,
									2017		2016		2017		2016
	(in thousands)								(in thousands)
Revenues:
Crude oil transportation services	$	91,387	$	81,928	$	279,281	$	206,331
Natural gas transportation services									$	32,139	$	32,871	$	96,140	$	93,598
Sales of natural gas, NGLs, and crude oil	4,439		1,344		4,587		2,541		603		935		2,793		1,331
Processing and other revenues									3,342		1,188		6,689		4,875
Total revenues	95,826		83,272		283,868		208,872		36,084		34,994		105,622		99,804
Operating costs and expenses:
Cost of sales	3,487		1,482		3,487		2,468		586		749		2,177		2,268
Cost of transportation services	12,939		13,393		41,586		33,630		1,489		874		2,731		4,171
Operations and maintenance	3,203		2,657		10,244		6,087		7,114		8,025		21,502		21,711
Depreciation and amortization	12,836		12,257		38,448		34,791		4,794		4,876		14,369		16,233
General and administrative	4,866		5,155		15,236		15,465		4,180		3,872		11,534		12,068
Taxes, other than income taxes	5,268		4,259		15,248		12,574		905		1,162		3,399		3,480
Total operating costs and expenses	42,599		39,203		124,249		105,015		19,068		19,558		55,712		59,931
Operating income	$	53,227	$	44,069	$	159,619	$	103,857	$	17,016	$	15,436	$	49,910	$	39,873


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 1516 – ~~Reporting~~Reportable Segments to the accompanying condensed consolidated financial statements.

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

Revenues. ~~Crude Oil~~Natural Gas Transportation ~~& Logistics~~ segment revenues were ~~$95.8~~$36.1 million for the three months ended September 30, 2017, compared to $35.0 million for the three months ended September 30, 2016, ~~compared to $83.3 million for the three months ended September 30, 2015,~~ which represents an increase of ~~$12.6~~$1.1 million, or ~~15%~~3%, in segment ~~revenues. The increase in segment~~ revenues ~~was~~ primarily due to a ~~$9.5~~$2.2 million increase in ~~crude oil transportation services and a $3.1 million~~other revenues driven by an increase in the ~~sales~~fee that NatGas receives as the operator of natural gas, NGLs, and crude oil driven by increased volumes of crude oil sold. The increase in crude oil transportation services revenue was primarily driven by increased revenues of $4.5 million relatedthe Rockies Express Pipeline attributable to ~~increased commitments on two throughput and deficiency agreements during~~ the ~~second quarter of 2016 and $4.3 million due to increased volumes transported under existing commitments~~Ultra settlement recognized during the three months ended September 30, ~~2016 compared to the three months ended September 30, 2015.~~2017, as discussed in Note 14 – Legal and Environmental Matters. The increase in other revenues was partially offset by a $0.7 million decrease in natural gas transportation services driven by lower throughput volumes at TIGT and a $0.3 million decrease in natural gas sales.

Operating costs and expenses. Operating costs and expenses in the ~~Crude Oil~~Natural Gas Transportation ~~& Logistics~~ segment were ~~$42.6~~$19.1 million for the three months ended September 30, 2017, compared to $19.6 million for the three months ended September 30, 2016, ~~compared to $39.2 million for the three months ended September 30, 2015,~~ which represents ~~an increase~~a decrease of ~~$3.4~~$0.5 million, or 9%3%. The overall ~~increase~~decrease in operating costs and expenses was primarily ~~driven~~due to a $0.9 million decrease in operations and maintenance costs due to the timing of pipeline integrity work, partially offset by a ~~$2.0~~$0.6 million increase in cost of sales due to increased volumes of crude oil sold, partially offset by decreased crude oil prices, and a $1.0 million increase in taxes, other than income taxes, as a result of the lateral in Northeast Colorado which was placed in service during the second quarter of 2015.transportation services.

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

Revenues. ~~Crude Oil~~Natural Gas Transportation ~~& Logistics~~ segment revenues were ~~$283.9~~$105.6 million for the nine months ended September 30, 2017, compared to $99.8 million for the nine months ended September 30, 2016, ~~compared to $208.9 million for the nine months ended September 30, 2015,~~ which represents an increase of ~~$75.0~~$5.8 million, or ~~36%~~6%, in segment revenues due to a $2.5 million increase in natural gas transportation services, a $1.8 million increase in other revenue, and a $1.5 million increase in sales of natural gas. The $2.5 million increase in natural gas transportation services was driven by increased tariff rates at TIGT, partially offset by a change in the fuel recovery structure, beginning May 1, 2016 as a result of the rate case settlement discussed in Note 13 – Regulatory Matters, as well as increased throughput volumes at Trailblazer. The $1.8 million increase in other revenues was primarily due to ~~increased revenues of $40.2 million from a full period of operations on~~ the ~~lateral~~increase in ~~Northeast Colorado, which began commercial operations during~~ the ~~second quarter of 2015, an $18.7~~Rockies Express operator fee as discussed above. The $1.5 million increase ~~related to the activation of one of our joint tariffs~~ in ~~the second quarter of 2015, lower revenue of $9.7 million due to~~natural gas sales was driven by increased volumes sold and a ~~force majeure at one of our joint tariff partners~~25% increase in natural gas prices during the nine months ended September 30, ~~2015, and a $7.6 million increase in incremental barrels shipped during~~2017 compared to the nine months ended September 30, 2016.

Operating costs and expenses. Operating costs and expenses in the ~~Crude Oil~~Natural Gas Transportation ~~& Logistics~~ segment were ~~$124.2~~$55.7 million for the nine months ended September 30, 2017, compared to $59.9 million for the nine months ended September 30, 2016, ~~compared to $105.0 million for the nine months ended September 30, 2015,~~ which represents ~~an increase~~a decrease of ~~$19.2~~$4.2 million, or ~~18%~~7%. The overall ~~increase~~decrease in operating costs and expenses was primarily ~~driven by~~due to a ~~$8.0~~$1.9 million ~~increase in cost of transportation services, a $4.2 million increase in operations and maintenance costs, a $3.7 million increase~~decrease in depreciation and amortization and a ~~$2.7~~$1.4 million ~~increase~~decrease in ~~taxes, other than income taxes all primarily~~the cost of transportation services. The $1.9 million decrease in depreciation and amortization was driven by changes in depreciation rates at TIGT and the $1.4 million decrease in the cost of transportation services was driven by lower costs associated with fuel reimbursements as a ~~full period~~result of ~~operations on~~changes to TIGT's fuel recovery structure, both as a result of the ~~lateral in Northeast Colorado, which began commercial operations during the second quarter of 2015.~~2016 rate case settlement discussed above.

The following provides a summary of our ~~Natural Gas~~Crude Oil Transportation ~~& Logistics~~ segment results of operations for the periods indicated:


Segment Financial Data - Natural Gas Transportation & Logistics⁽¹⁾	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Segment Financial Data - Crude Oil Transportation ⁽¹⁾									Three Months Ended September 30,				Nine Months Ended September 30,
									2017		2016		2017		2016
	(in thousands)								(in thousands)
Revenues:
Natural gas transportation services	$	32,871	$	30,777	$	93,598	$	94,656
Crude oil transportation services									$	90,113	$	91,387	$	264,299	$	279,281
Sales of natural gas, NGLs, and crude oil	935		2,855		1,331		3,534		2,916		4,439		9,469		4,587
Processing and other revenues	6		4		20		25
Total revenues	33,812		33,636		94,949		98,215		93,029		95,826		273,768		283,868
Operating costs and expenses:
Cost of sales	749		2,565		2,268		2,436		2,819		3,487		8,154		3,487
Cost of transportation services	874		2,808		4,171		8,918		11,957		12,939		39,708		41,586
Operations and maintenance	8,025		7,263		21,711		20,362		2,976		3,203		9,048		10,244
Depreciation and amortization	4,876		5,241		16,233		17,066		13,127		12,836		39,230		38,448
General and administrative	3,872		4,104		12,068		12,789		5,320		4,866		15,318		15,236
Taxes, other than income taxes	1,162		1,156		3,480		3,655		5,352		5,268		16,848		15,248
Total operating costs and expenses	19,558		23,137		59,931		65,226		41,551		42,599		128,306		124,249
Operating income	$	14,254	$	10,499	$	35,018	$	32,989	$	51,478	$	53,227	$	145,462	$	159,619


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 1516 – ~~Reporting~~Reportable Segments to the accompanying condensed consolidated financial statements.

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

Revenues.~~Natural Gas~~ Crude Oil Transportation ~~& Logistics~~ segment revenues were ~~$33.8~~$93.0 million for the three months ended September 30, 2017, compared to $95.8 million for the three months ended September 30, 2016, ~~compared~~which represents a decrease of $2.8 million, or 3%, in segment revenues driven by a $1.5 million decrease in sales of crude oil primarily due to ~~$33.6 million for~~decreased volumes sold during the three months ended September 30, ~~2015, which represents an increase of $0.2~~2017 compared to the three months ended September 30, 2016 and a $1.3 million ~~or 1%. The increase~~decrease in ~~segment revenues was~~crude oil transportation services, primarily due to ana $6.5 million increase ~~of $2.1 million~~ in ~~natural gas transportation services primarily driven by increased tariff rates,~~shipper deficiency payments that are not recognized in revenue, partially offset by a ~~change in the fuel recovery structure, recognized at TIGT beginning May 1, 2016 as a result of the rate case settlement discussed in Note 13 –~~ ~~Regulatory Matters. The~~$3.6 million increase in ~~transportation services revenue was partially offset by~~walk-up barrels shipped and a ~~$1.9~~$1.8 million ~~decrease~~increase in ~~sales of natural gas, NGLs, and crude oil as a result of lower volumes of natural gas sales.~~committed barrels shipped.

Operating costs and expenses. Operating costs and expenses in the ~~Natural Gas~~Crude Oil Transportation ~~& Logistics~~ segment were ~~$19.6~~$41.6 million for the three months ended September 30, 2017 compared to $42.6 million for the three months ended September 30, 2016, ~~compared to $23.1 million for the three months ended September 30, 2015,~~ which represents a decrease of ~~$3.6~~$1.0 million, or ~~15%~~2%. The overall decrease in operating costs and expenses was primarily driven by a ~~$1.9~~$1.0 million decrease in cost of transportation services ~~due to~~driven by lower ~~costs associated with fuel reimbursements~~rent expense as a result of an amendment to the ~~change in the fuel recovery structure discussed above~~Deeprock Terminal lease agreement and a ~~$1.8~~$0.7 million decrease in cost of sales ~~as a result of lower volumes sold. These decreases were partially offset by a $0.8 million increase in operations and maintenance~~primarily due to ~~increased pipeline integrity work~~decreased volumes of crude oil sold during the three months ended September 30, ~~2016.~~2017, partially offset by a $0.5 million increase in general and administrative costs.

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

Revenues. ~~Natural Gas~~Crude Oil Transportation ~~& Logistics~~ segment revenues were ~~$94.9~~$273.8 million for the nine months ended September 30, 2017, compared to $283.9 million for the nine months ended September 30, 2016, ~~compared to $98.2 million for the nine months ended September 30, 2015,~~ which represents a decrease of ~~$3.3~~$10.1 million, or 3%4%, in segment revenues asdriven by a ~~result of a $2.2~~$15.0 million decrease in ~~sales of natural gas, NGLs, and~~ crude oil astransportation services, primarily due to a ~~result of lower volumes of natural gas sold~~$16.8 million increase in shipper deficiency payments that are not recognized in revenue and ~~a 14% decrease in natural gas prices and a $1.1~~an $8.1 million decrease in ~~natural gas transportation services primarily driven by a change in~~ the ~~fuel recovery structure as discussed above and warmer weather conditions that created less demand for short-term transportation capacity~~incremental barrels delivered during the nine months ended September 30, ~~2016~~2017 compared to the nine months ended September 30, ~~2015. These decreases were~~2016, partially offset by a $6.0 million increase in committed barrels shipped and a $3.4 million increase in walk-up barrels shipped. The decrease in crude oil transportation services was partially offset by a $4.9 million increase in sales of crude oil primarily due to increased ~~tariff rates recognized at TIGT subsequent~~volumes of crude oil sold during the nine months ended September 30, 2017 compared to the ~~rate case settlement effective May 1,~~nine months ended September 30, 2016.

Operating costs and expenses. Operating costs and expenses in the ~~Natural Gas~~Crude Oil Transportation ~~& Logistics~~ segment were ~~$59.9~~$128.3 million for the nine months ended September 30, 2017 compared to $124.2 million for the nine months ended September 30, 2016, ~~compared to $65.2 million for the nine months ended September 30, 2015,~~ which represents ~~a decrease~~an increase of ~~$5.3~~$4.1 million, or 8%3%. The overall ~~decrease~~increase in operating costs and expenses was primarily driven by a $4.7 million decrease in cost of transportation services due to lower costs associated with fuel reimbursements as a result of the change in the fuel recovery structure discussed above, a $0.8 million decrease in depreciation and amortization due to lower depreciation rates as of May 1, 2016 as a result of the TIGT rate case settlement, a $0.7 million decrease in general and administrative costs due to a reduction in allocated costs to the segment and a $0.2 million decreaseincrease in cost of sales primarily due to ~~decreased~~increased volumes of ~~natural gas~~crude oil sold ~~partially offset by a reduction in our fuel tracker obligations at Trailblazer driven by the FERC approval of our annual fuel tracker filing~~ during the nine months ended September 30, ~~2015.~~2017 and a $1.6 million increase in taxes, other than income taxes driven by assets placed in service throughout 2016. These ~~decreases~~increases were partially offset by a ~~$1.3~~$1.9 million ~~increase~~decrease in ~~operations~~cost of transportation services driven by lower rent expense as a result of an amendment to the Deeprock Terminal lease agreement and ~~maintenance due~~higher electric costs associated with pressure restrictions during the nine months ended September 30, 2016 and reduced throughput volumes during the nine months ended September 30, 2017 compared to ~~increased pipeline integrity work during~~ the nine months ended September 30, 2016.

The following provides a summary of our Gathering, Processing & ~~Logistics~~Terminalling segment results of operations for the periods indicated:


Segment Financial Data - Processing & Logistics ⁽¹⁾	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016			2015
Segment Financial Data - Gathering, Processing & Terminalling ⁽¹⁾											Three Months Ended September 30,				Nine Months Ended September 30,
											2017		2016		2017			2016
	(in thousands)										(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	15,384	$	16,053		$	45,596		$	56,057	$	28,696	$	15,384	$	58,252		$	45,596
Processing and other revenues	8,530		6,553			24,240			26,705		29,040		11,646		63,163			33,222
Total revenues	23,914		22,606			69,836			82,762		57,736		27,030		121,415			78,818
Operating costs and expenses:
Cost of sales	14,435		14,139			42,516			50,055		24,120		14,435		49,148			42,516
Cost of transportation services	1,061		7			2,204			557		7,531		1,259		15,294			2,802
Operations and maintenance	3,486		4,151			9,100			9,605		7,322		3,918		15,019			10,419
Depreciation and amortization	3,119		3,304			9,418			9,905		5,861		3,465		13,677			10,393
General and administrative	1,406		1,111			4,689			3,331		3,453		1,672		7,061			5,842
Contract termination											—		—		—			8,061
Taxes, other than income taxes	287		106			1,134			318		404		430		1,552			1,565
Loss on disposal of assets	—		—			1,849			4,483
(Gain) loss on disposal of assets											—		—		(1,264		)	1,849
Total operating costs and expenses	23,794		22,818			70,910			78,254		48,691		25,179		100,487			83,447
Operating (loss) income	$	120	$	(212	)	$	(1,074	)	$	4,508
Operating income (loss)											$	9,045	$	1,851	$	20,928		$	(4,629	)


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 1516 – ~~Reporting~~Reportable Segments to the accompanying condensed consolidated financial statements.

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

Revenues. Gathering, Processing & ~~Logistics~~Terminalling segment revenues were ~~$23.9~~$57.7 million for the three months ended September 30, 2017, compared to $27.0 million for the three months ended September 30, 2016, ~~compared to $22.6 million for the three months ended September 30, 2015,~~ which represents a ~~$1.3~~$30.7 million, or 6%114%, increase in segment revenues. The increase in segment revenues was primarily due to a ~~$2.0~~$17.4 million increase in processing and other revenues ~~driven by increased revenue~~and a $13.3 million increase in sales of ~~$2.0 million at Water Solutions primarily attributable to BNN Western, LLC ("Western"), which was acquired on December 16, 2015,~~natural gas, NGLs, and ~~BNN West Texas, LLC ("West Texas"), which commenced operations in March 2016.~~crude oil. The increase in processing and other revenues was ~~partially offset~~driven by increased water business services revenue of $12.7 million as a ~~$0.7~~result of increased fresh water transportation and produced water disposal volumes, increased terminalling services revenue of $2.4 million ~~decrease~~driven by the acquisition of a controlling financial interest in Deeprock Development in July 2017, and increased fee income of $2.0 million driven by the acquisition of the Douglas Gathering System in May 2017. The increase in sales of natural gas, NGLs, and crude oil was primarily driven by ~~lower~~a 40% increase in NGL prices and residue natural gas sales ~~of $0.4 million due to lower volumes processed,~~from the Douglas Gathering System, partially offset by ~~increased NGL prices, and~~ lower ~~natural gas sales of $0.3 million due to decreased~~ volumes of ~~natural gas~~NGLs sold.

Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & ~~Logistics~~Terminalling segment were ~~$23.8~~$48.7 million for the three months ended September 30, 2017 compared to $25.2 million for the three months ended September 30, 2016, ~~compared to $22.8 million for the three months ended September 30, 2015,~~ which represents an increase of ~~$1.0~~$23.5 million, or 4%93%. The increase in operating costs and expenses was ~~driven by~~due to a ~~$1.1~~$9.7 million increase in cost of sales, a $6.3 million increase in cost of transportation services, ~~due to~~a $3.4 million increase in operations and maintenance costs, ~~associated with Western, which was acquired on December 16, 2015,~~ a ~~$0.3~~$2.4 million increase in depreciation and amortization, and a $1.8 million increase in general and administrative ~~costs due to increased costs allocated to Water Solutions as a result of increased operating income related to our acquisitions of Western and West Texas and a $0.3 million~~costs. The increase in cost of sales ~~partially offset~~was primarily driven by ~~a $0.7 million decrease~~higher producer settlements and higher NGL sales driven by prices as discussed above. The increase in cost of transportation services was primarily driven by crude oil transportation fees paid by Stanchion and increased volumes in water business services as discussed above. The increase in operations and maintenance costs, ~~due to less downtime for plant maintenance activities during~~depreciation and amortization, and general and administrative costs were primarily driven by the ~~three months ended September 30, 2016 compared to~~acquisitions of the ~~three months ended September 30, 2015.~~Douglas Gathering System and Deeprock Development.

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

Revenues. Gathering, Processing & ~~Logistics~~Terminalling segment revenues were ~~$69.8~~$121.4 million for the nine months ended September 30, 2017, compared to $78.8 million for the nine months ended September 30, 2016, ~~compared to $82.8 million for the nine months ended September 30, 2015,~~ which represents a ~~$12.9~~$42.6 million, or ~~16%~~54%, ~~decrease~~increase in segment revenues. The ~~decrease~~increase in segment revenues was primarily due to a ~~$10.5~~$29.9 million ~~decrease~~increase in processing and other revenues and a $12.7 million increase in sales of natural gas, NGLs, and crude oil. The increase in processing and other revenues was driven by increased water business services revenue of $25.1 million as a result of increased fresh water transportation and produced water disposal volumes, increased terminalling services revenue of $2.6 million driven by the acquisition of a controlling interest in Deeprock Development in July 2017, and increased fee income of $2.0 million driven by the acquisition of the Douglas Gathering System in May 2017. The increase in sales of natural gas, NGLs, and crude oil was driven by ~~lower NGL sales of $9.4 million due to lower volumes processed and~~ a ~~7% decrease~~42% increase in NGL prices and ~~a $2.5 million decrease in processing and other revenues driven by lower processing fees at TMID due to decreased volumes processed,~~four months of residue natural gas sales from the Douglas Gathering System, partially offset by ~~a $2.3 million increase in revenue at Water Solutions primarily attributable to the recently acquired Western and West Texas assets.~~lower volumes of NGLs sold.

Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & ~~Logistics~~Terminalling segment were ~~$70.9~~$100.5 million for the nine months ended September 30, 2017 compared to $83.4 million for the nine months ended September 30, 2016, ~~compared~~which represents an increase of $17.0 million, or 20%. The increase in operating costs and expenses was primarily due to ~~$78.3~~a $12.5 million ~~for~~increase in cost of transportation services, a $6.6 million increase in cost of sales, a $4.6 million increase in operations and maintenance costs, a $3.3 million increase in depreciation and amortization, and a $1.2 million increase in general and administrative costs. The increase in cost of sales was primarily driven by higher producer settlements and higher NGL sales attributable to the Douglas Gathering System. The increase in cost of transportation services was primarily driven by crude oil transportation fees paid by Stanchion and increased volumes in water business services as discussed above. The increase in operations and maintenance costs, depreciation and amortization, and general and administrative costs were primarily driven by the acquisitions of the Douglas Gathering System and Deeprock Development. These increases were partially offset by a $8.1 million contract termination as a result of the buyout of an operating agreement at the Sterling Terminal during the nine months ended September 30, ~~2015, which represents~~2016 and a ~~decrease of $7.3~~$3.1 million ~~or 9%. The~~ decrease in operating costs and expenses was driven by a decrease of $7.5 million in cost of sales, primarily due to decreased NGL prices and volumes processed as discussed above, a decrease of $2.6 million in loss (gain) on disposal of assets asprimarily driven by a ~~result~~gain on disposal of assets from insurance proceeds received during the ~~$1.8 million loss on Western~~nine months ended September 30, 2017 related to assets destroyed by a fire ~~as a result of~~caused by a lightning strike during the nine months ended September 30, 2016, compared to a $4.5 million non-cash loss recognized on the sale of compressor assets at TMID in 2015 and a $0.5 million decrease in operations and maintenance costs due to less downtime for plant maintenance activities during the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015. These decreases were partially offset by a $1.6 million increase in cost of transportation services due to costs associated with Western, which was acquired on December 16, 2015, a $1.4 million increase in general and administrative costs due to increased costs allocated to Water Solutions as a result of increased operating income related to our acquisitions of Western and West Texas and a $0.8 million increase in taxes, other than income taxes, due to higher property tax estimates for 2016 as a result of the Western acquisition.2016.

Liquidity and Capital Resources Overview

Our primary sources of liquidity for the three months ended September 30, ~~2016~~2017 were proceeds from TEP's issuance of long-term debt, ~~as discussed further below,~~ borrowings under TEP's revolving credit facility, and cash generated from ~~operations, and proceeds from the issuance of TEP common units.~~operations. We expect our sources of liquidity in the future to include:

cash generated from our operations;

borrowing capacity available under TEP's revolving credit facility; and

future issuances of additional ~~partnership~~TEP common units and/or debt securities.

We believe that cash on hand, cash generated from operations, and availability under TEP's revolving credit facility will be adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements, and our planned cash distributions to shareholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of borrowings under TEP's revolving credit facility and issuances of debt and/or equity securities at TEP. For additional information regarding our revolving credit facilities and senior unsecured notes, see Note 11 – Long-term Debt. For additional information regarding our equity transactions, see Note 12 – Partnership Equity and Distributions.

Our total liquidity as of September 30, ~~2016~~2017 and December 31, ~~2015~~2016 was as follows:

September 30, 2016 December 31, 2015
(in thousands)
Cash on hand
$ 1,359
$ 2,234

Total capacity under the TEP revolving credit facility 1,750,000
1,100,000
Less: Outstanding borrowings under the TEP revolving credit facility⁽¹⁾
(1,005,000 ) (753,000 )
Available capacity under the TEP revolving credit facility 745,000
347,000
Total capacity under the Tallgrass Equity revolving credit facility $ 150,000
$ 150,000
Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility (148,000 ) (148,000 )
Available capacity under the Tallgrass Equity revolving credit facility $ 2,000
$ 2,000
Total Liquidity $ 748,359
$ 351,234


⁽¹⁾	~~As of October 31, 2016, outstanding borrowings under the TEP revolving credit facility were approximately $1.003 billion.~~

~~TEP Revolving Credit Facility~~

Effective January 4, 2016, in connection with the acquisition of an additional 31.3% membership interest in Pony Express, TEP exercised the committed accordion feature to increase the total capacity of the revolving credit facility from $1.1 billion to $1.5 billion. In connection with the acquisition of a 25% membership interest in Rockies Express, TEP amended the revolving credit facility to increase the total capacity to $1.75 billion, which increase became effective May 6, 2016.

The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP's ability (as well as the ability of its restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of its business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of September 30, 2016, TEP was in compliance with the covenants required under the TEP revolving credit facility.

The unused portion of TEP's revolving credit facility is subject to a commitment fee, which ranges from 0.300% to 0.500%, based on TEP's total leverage ratio. As of September 30, 2016, the weighted average interest rate on outstanding borrowings under the TEP revolving credit facility was 2.28%. During the nine months ended September 30, 2016, our weighted average effective interest rate under the TEP revolving credit facility, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 2.72%.

~~Tallgrass Equity Revolving Credit Facility~~

In connection with the Offering, Tallgrass Equity entered into a $150 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on May 12, 2020. Among various other covenants and restrictive provisions, Tallgrass Equity is required to maintain a total leverage ratio of not more than 3.00 to 1.00. As of September 30, 2016, Tallgrass Equity was in compliance with the covenants required under its revolving credit facility.

The unused portion of the Tallgrass Equity revolving credit facility is subject to a commitment fee of 0.50%. As of September 30, 2016, the weighted average interest rate on outstanding borrowings under the Tallgrass Equity revolving credit facility was 3.03%. During the nine months ended September 30, 2016, Tallgrass Equity's weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 3.28%.

~~Senior Unsecured Notes~~

On September 1, 2016, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016 (the "Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of the Issuers' 5.50% senior notes due 2024 (the "2024 Notes"). TEP used the net proceeds of the offering to repay outstanding borrowings under its existing senior secured revolving credit facility.

The 2024 Notes are general unsecured senior obligations of the Issuers. The 2024 Notes are unconditionally guaranteed jointly and severally on a senior unsecured basis by TEP's existing direct and indirect wholly owned subsidiaries (other than the Co-Issuer) and certain of TEP's future subsidiaries (the "Guarantors"). The 2024 Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 2024 Notes will mature on September 15, 2024 and interest on the 2024 Notes is payable in cash semi-annually in arrears on each March 15 and September 15, commencing March 15, 2017. TEP may redeem the 2024 Notes prior to their scheduled maturity at the applicable redemption price set forth in the Indenture, plus accrued and unpaid interest.

The Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. As of September 30, 2016, the Issuers and Guarantors are in compliance with the covenants required under the 2024 Notes.

~~TEP Equity Distribution Agreements~~

On October 31, 2014, TEP entered into an equity distribution agreement pursuant to which it may sell from time to time through a group of managers, as its sales agents, common units representing limited partner interests having an aggregate offering price of up to $200 million. On May 13, 2015 the amount was subsequently amended to $100.2 million in order to account for follow-on equity offerings under TEP's S-3 shelf registration statement. On May 17, 2016, TEP entered into a new equity distribution agreement allowing for the sale of common units with an aggregate offering price of up to $657.5 million. Sales of common units, if any, will be made by means of ordinary brokers' transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by TEP and one or more of the managers. TEP intends to use the net cash proceeds from any sale of the units for general partnership purposes, which may include, among other things, TEP's exercise of the call option with respect to the 6,518,000 common units issued to TD in connection with TEP's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to working capital.

During the three months ended September 30, 2016, TEP issued and sold 622,846 common units with a weighted average sales price of $47.39 per unit under its equity distribution agreements for net cash proceeds of approximately $28.7 million (net of approximately $0.8 million in commissions and professional service expenses). During the nine months ended September 30, 2016, TEP issued and sold 6,703,984 common units with a weighted average sales price of $43.98 per unit under its equity distribution agreements for net cash proceeds of approximately $290.5 million (net of approximately $4.4 million in commissions and professional service expenses). During the period from October 1, 2016 to November 2, 2016, TEP issued and sold an additional 628,914 common units with a weighted average sales price of $48.05 per unit under its equity distribution agreement for net cash proceeds of approximately $29.9 million (net of approximately $0.3 million in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes as described above.

~~Private Placement~~



	September 30, 2017			December 31, 2016
	(in thousands)
Cash on hand	$	3,279		$	2,459

Total capacity under the TEP revolving credit facility	1,750,000			1,750,000
Less: Outstanding borrowings under the TEP revolving credit facility	(881,000		)	(1,015,000		)
Less: Letters of credit issued under the TEP revolving credit facility	(3,094		)	—
Available capacity under the TEP revolving credit facility	865,906			735,000
Total capacity under Tallgrass Equity revolving credit facility	$	150,000		$	150,000
Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility	(146,000		)	(148,000		)
Available capacity under the Tallgrass Equity revolving credit facility	$	4,000		$	2,000
Total liquidity	$	873,185		$	739,459

Working Capital

Working capital is the amount by which current assets exceed current liabilities. While various other factors may impact our working capital requirements from period to period, our working capital requirements have typically been, and we expect will continue to be, driven by changes in accounts receivable, accounts payable and deferred revenue. TEP manages its working capital needs through borrowings and repayments of borrowings under its revolving credit facility. Factors impacting changes in accounts receivable and accounts payable could include the timing of collections from customers, payments to suppliers, and the level of spending for capital expenditures. Changes in the market prices of energy commodities ~~primarily NGLs,~~ that we buy and sell in the normal course of business can also impact the timing of changes in accounts receivable and accounts payable. Factors impacting deferred revenue include the volume of ~~crude oil~~barrels transported, the amount of deficiency payments received, and the volume of prior deficiencies utilized during the period.

As of September 30, ~~2016,~~2017, we had a working capital deficit of ~~$16.0~~$92.4 million compared to a working capital deficit of ~~$11.2~~$37.7 million at December 31, ~~2015,~~2016, which represents ~~a decrease~~an increase in the working capital deficit of ~~$4.9~~$54.7 million. The overall ~~decrease~~increase in the working capital deficit was primarily attributable to changes in the following components:

an increase in accounts payable of $45.2 million primarily due to crude oil purchases at Stanchion, as well as increased volumes at TMID and Water Solutions;

an increase in deferred revenue of ~~$25.6~~$27.2 million primarily from deficiency payments collected by Pony Express;

a decrease in derivative assets at fair value of $11.0 million as TEP exercised the remainder of the call option granted by TD; and

an increase in accrued taxes of ~~$6.8~~$5.9 million as a result of increased tax ~~assessments; and~~

~~a decrease of $4.7 million in accounts receivable primarily due to a decrease in incremental barrels shipped at~~assessments on Pony Express assets placed in ~~September 2016 compared to December 2015.~~service during 2016.

These working capital decreases were partially offset by:

an increase in accounts receivable of ~~$25.7~~$36.1 million ~~in derivative assets~~primarily due to crude oil sales at ~~fair value as a result of the reclassification of the call option derivative to current assets as of September 30, 2016;~~Stanchion; and

a decrease in accrued liabilities of ~~$5.2~~$5.6 million primarily due to a decrease in ~~accounts payable, primarily driven by~~interest accrued at September 30, 2017 compared to December 31, 2016 due to the timing of ~~project invoices and payment of contractor retainages related to the construction of the Pony Express lateral~~interest payments in ~~Northeast Colorado.~~September 2017.

A material adverse change in operations, available financing under our revolving credit facility, or available financing from the equity or debt capital markets could impact our ability to fund our requirements for liquidity and capital resources in the future.

Cash Flows

The following table and discussion presents a summary of our cash flow for the periods indicated:


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2017			2016
	(in thousands)						(in thousands)
Net cash provided by (used in):
Operating activities	$	300,971		$	195,447		$	450,377		$	306,063
Investing activities	$	(549,566	)	$	(769,771	)	$	(852,941	)	$	(559,774	)
Financing activities	$	247,720		$	592,466		$	403,384		$	252,836

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

Operating Activities. Cash flows provided by operating activities were ~~$301.0~~$450.4 million and ~~$195.4~~$306.1 million for the nine months ended September 30, ~~2016~~2017 and ~~2015,~~2016, respectively. The increase in net cash flows provided by operating activities of ~~$105.5~~$144.3 million was primarily driven by ~~the~~a $150.3 million increase in ~~operating results as discussed above,~~ distributions received from Rockies Express ~~and~~as a ~~net increase~~result of the Ultra settlement received in ~~cash inflows from changes in working capital, primarily driven by a $19.5 million increase in net cash inflows from accounts receivable due to collection of receivables~~July 2017 as well as our increased membership interest during the nine months ended September 30, 2016 associated primarily with an increase of incremental barrels shipped at Pony Express, and a $11.3 million increase in deferred revenue associated primarily with deficiency payments received by Pony Express.2017.

Investing Activities. Cash flows used in investing activities were ~~$549.6 million and $769.8~~$852.9 million for the nine months ended September 30, ~~2016~~2017. Investing cash outflows for the nine months ended September 30, 2017 were primarily driven by:

cash outflows of $400.0 million for the acquisition of an additional 24.99% membership interest in Rockies Express;

cash outflows of $140.0 million for the acquisition of Terminals and ~~2015, respectively. During~~NatGas;

cash outflows of $128.5 million for the acquisition of the Douglas Gathering System;

capital expenditures of $88.1 million, primarily due to spending on an additional freshwater connection at Water Solutions and on a connection to a refinery complex on the Pony Express System and remediation digs on the Pony Express System as discussed in Note 15 – Legal and Environmental Matters;

cash outflows of $57.2 million for the acquisition of an additional 40% membership interest in Deeprock Development;

cash outflows of $36.0 million for the acquisition of the PRB Crude System; and

contributions to unconsolidated investments in the amount of $31.6 million, primarily to fund remaining costs associated with the Zone 3 Capacity Enhancement project at Rockies Express.

These cash outflows were partially offset by $41.9 million of distributions received from Rockies Express in excess of cumulative earnings recognized.

Cash flows used in investing activities were $559.8 million for the nine months ended September 30, 2016. Investing cash outflows for the nine months ended September 30, 2016 ~~net cash used in investing activities~~ were primarily driven by by:

•cash outflows of $436.0 million for the acquisition of a 25% membership interest in Rockies Express;

capital expenditures of $55.4 million, primarily due to post in-service spending on Pony Express ~~on May 6, 2016,~~System projects and costs associated with construction of the Buckingham Terminal;

cash outflows of $49.1 million for a portion of the acquisition of an additional 31.3% membership interest in Pony Express, ~~on January 1, 2016,~~ the remainder of which is classified as a financing activity as discussed ~~below, capital expenditures of $45.3 million, primarily due to post in-service spending on Pony Express System projects~~below; and

contributions to Rockies Express in the amount of $35.5 million. ~~During the nine months ended September 30, 2015, net~~

These cash ~~used~~outflows were partially offset by $16.1 million of distributions from Rockies Express in ~~investing activities were driven by the $700.0 million cash outflow for the acquisition~~excess of an additional 33.3% membership interest in Pony Express, which allowed TD to continue funding the pipeline construction at Pony Express, and capital expenditures of $65.1 million, primarily due to construction of the Pony Express System, including the lateral in Northeast Colorado.cumulative earnings recognized.

Financing Activities. Cash flows provided by financing activities were ~~$247.7 million and $592.5~~$403.4 million for the nine months ended September 30, ~~2016~~2017. Financing cash inflows for the nine months ended September 30, 2017 were primarily driven by:

proceeds from TEP's issuance of $850.0 million in aggregate principal amount of 2024 Notes and ~~2015, respectively.~~2028 Notes; and

net cash proceeds of $112.4 million from the issuance of 2,341,061 TEP common units under its Equity Distribution Agreements.

These financing cash inflows were partially offset by cash outflows of:

distributions to noncontrolling interests of $229.7 million, consisting of distributions to TEP unitholders of $135.4 million, Tallgrass Equity distributions to the Exchange Right Holders of $90.0 million, and distributions to Pony Express noncontrolling interests of $4.3 million;

net repayments under the revolving credit facilities of $136.0 million;

$72.4 million for the exercise of the remainder of the call option granted by TD covering 1,703,094 TEP common units;

$35.3 million for 736,262 TEP common units repurchased from TD; and

•distributions to Class A shareholders of $52.7 million.

Cash flows provided by financing activities were $252.8 million for the nine months ended September 30, 2016. Financing cash inflows for the nine months ended September 30, 2016 were primarily driven by:

proceeds from TEP's issuance of ~~$400~~$400.0 million in aggregate principal amount of 5.50% Senior Notes due 2024;

~~TEP's issuance of 6,703,984 common units under the Equity Distribution Agreements for~~ net cash proceeds of $290.5 ~~million;~~million from the issuance of 6,703,984 TEP common units under its Equity Distribution Agreements;

net borrowings under the TEP revolving credit facility of $252.0 million; and

~~the~~net cash proceeds of $90.0 million from TEP's issuance of 2,416,987 ~~TEP~~ common units representing ~~TEP~~ limited partnership interests in a private placement ~~transaction for net cash proceeds of $90.0 million; and~~

~~contributions from noncontrolling interests of $8.7 million, which primarily consisted of contributions from TD to Pony Express.~~transaction.

These financing cash inflows were partially offset by cash outflows of:

$425.9 million for the portion of the acquisition of an additional 31.3% membership interest in Pony Express which exceeds the cumulative capital spending on the underlying assets acquired;

distributions to noncontrolling interests of $177.4 million, ~~consisting~~which consisted of distributions to TEP unitholders of $103.7 million, Tallgrass Equity distributions to the Exchange Right Holders of $68.7 million, and distributions to Pony Express ~~and Water Solutions~~ noncontrolling interests of $5.0 million;

$151.4 million for ~~TEP's~~the partial exercise of the call option granted by TD covering 3,563,146 TEP common units; and

distributions to Class A shareholders of $30.0 ~~million.~~

~~Cash flows provided by financing activities for the nine months ended September 30, 2015 were primarily driven by:~~

~~$1.3 billion of net proceeds from the initial public offering of Class A shares in May 2015;~~

~~$551.2 million of net proceeds from the public offering of TEP common units in February 2015;~~

~~the proceeds from net borrowings under the TEP and Tallgrass Equity revolving credit facilities of $285.0 million; and~~

~~contributions from noncontrolling interests of $19.3 million, primarily driven by contributions from TD to Pony Express.~~

~~These financing cash inflows were partially offset by cash outflows of:~~

~~$953.6 million for the acquisition of 20,000,000 TEP common units by Tallgrass Equity as part of the Offering;~~

~~$334.1 million for the distribution of proceeds from the Offering to the Exchange Right Holders as part of the reorganization of entities effective concurrent with the Offering;~~

~~$171.9 million for the acquisition of additional Tallgrass Equity units as part of the reorganization concurrent with the Offering;~~

~~distributions to TEP unitholders of $74.8 million;~~

~~distributions to the members of the TEGP Predecessor of $13.5 million;~~

~~distributions made by Tallgrass Equity to the Exchange Right Holders of $13.0 million; and~~

~~distributions to TEGP Class A shareholders of $3.5~~ million.

Distributions

Distributions to our Class A shareholders. We distribute 100% of our available cash at the end of each quarter to Class A shareholders of record beginning with the quarter ended June 30, 2015. Our sole cash-generating asset is an approximate ~~30.35%~~36.94% controlling membership interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of direct and indirect partnership interests in TEP, as detailed above in "—"—Overview". Available cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter (including expected distributions from Tallgrass Equity in respect of such quarter) less reserves established at the discretion of our general ~~partner.~~partner as permitted by our partnership agreement. For a discussion of factors and trends impacting TEP's business, which in turn impacts our ability to pay cash distributions to our Class A shareholders, please see "—"—Factors and Trends Impacting Our Business" in our ~~2015~~2016 Form 10-K.

Our distribution for the three months ended September 30, ~~2016,~~2017, in the amount of ~~$0.2625~~$0.3550 per Class A share, or ~~$12.5~~$20.6 million in the aggregate, was announced on October ~~5, 2016~~10, 2017 and will be paid on November 14, ~~2016, 2016~~2017 to Class A shareholders of record on October 31, ~~2016.~~2017.

Capital Requirements

The midstream energy business can be capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of, the following:

maintenance capital expenditures, which are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements; and

expansion capital expenditures, which are cash expenditures towe expect will increase our operating income or operating capacity over the long-term. Expansion capital expenditures include acquisitions or capital improvements (such as additions to or improvements on the capital assets owned, or acquisition or construction of new capital assets).

We expect to incur approximately ~~$46~~$148 million for expansion capital ~~expenditures in 2016, of which approximately $34 million is expected for expansion~~ projects and approximately ~~$12~~$15 million, net of anticipated reimbursements, ~~from affiliates, is expected~~ for maintenance capital ~~expenditures.~~

expenditures in 2017.

The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities:


	Nine Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2017		2016
	(in thousands)				(in thousands)
Maintenance capital expenditures	$	7,085	$	9,237	$	7,746	$	7,085
Expansion capital expenditures	19,308		17,453		78,448		29,452
Total capital expenditures incurred	$	26,393	$	26,690	$	86,194	$	36,537

Capital expenditures incurred represent capital expenditures paid and accrued during the period. Capital expenditures are presented net of noncontrolling interest, and contributions and reimbursements received. The ~~decrease~~increase in maintenance capital expenditures to $7.7 million for the nine months ended September 30, 2017 from $7.1 million for the nine months ended September 30, 2016 ~~from $9.2 million for the nine months ended September 30, 2015~~ is primarily driven by ~~decreased maintenance capital~~increased expenditures in ~~the Processing & Logistics and~~ the Natural Gas Transportation ~~& Logistics segments.~~segment, partially offset by decreased expenditures in the Crude Oil Transportation segment. Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from year to year and from quarter to quarter. The increase in expansion capital expenditures to ~~$19.3~~$78.4 million for the nine months ended September 30, ~~2016 from $17.5 million~~2017 is primarily driven by increased expansion capital expenditures in the Gathering, Processing & Terminalling and Crude Oil Transportation segments. Expansion capital expenditures for the nine months ended September 30, ~~2015 is~~2017 consisted primarily ~~driven by~~of spending on an additional freshwater connection at Water Solutions and on a connection to a refinery complex on the Pony Express System ~~lateral~~and remediation digs on the Pony Express System, as discussed in ~~Northeast Colorado prior to commencement of commercial operations in the second quarter of 2015.~~Note 15 – Legal and Environmental Matters. Expansion capital expenditures of ~~$19.3~~$29.5 million for the nine months ended September 30, 2016 consisted primarily of post in-service spending on Pony Express System projects and costs associated with construction of the Buckingham Terminal.

In addition, we invested cash in unconsolidated affiliates of $31.6 million and $35.5 million during the nine months ended September 30, 2017 and 2016, respectively, to fund our share of capital projects. During the nine months ended September 30, 2017, we invested $9.1 million in a new unconsolidated affiliate, BNN Colorado Water, LLC ("BNN Colorado"). In connection with the investment in BNN Colorado, we have made commitments to fund the remaining construction of the pipeline system, estimated at $8.4 million as of September 30, 2017.

We intend to make cash distributions to our Class A shareholders. Due to our cash distribution policy, we expect that we will distribute available cash to our Class A shareholders on a quarterly basis. We expect TEP to fund future capital expenditures with funds generated from its operations, borrowings under its revolving credit facility, the issuance of additional ~~partnership~~TEP common units and/or the issuance of long-term debt. If these sources are not sufficient, TEP may reduce its discretionary spending.

Contractual Obligations

There have been no material changes in our contractual obligations as reported in our ~~2015~~2016 Form 10-K.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The critical accounting policies and estimates used in the preparation of our condensed consolidated financial statements are set forth in our ~~2015~~2016 Form 10-K for the year ended December 31, ~~2015~~2016 and have not changed. Our disclosure of critical accounting policies and estimates with respect to goodwill is repeated below for the purpose of providing additional information regarding the impairment testing performed as of December 31, 2015.



~~Description~~	~~Judgments and Uncertainties~~	~~Effect if Actual Results Differ from Assumptions~~
~~Impairment of Goodwill~~
We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.	We determine fair value using widely accepted valuation techniques, primarily discounted cash flow and market multiple analyses. These techniques are also used when assigning the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors and the profitability of future business strategies. Our impairment analyses require management to apply judgment in estimating future cash flows as well as asset fair values, including forecasting useful lives of the assets, assessing the probability of different outcomes, including anticipated volumes, contract renewals and changes in our regulated rates, and selecting the discount rate that reflects the risk inherent in future cash flows. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations.	We primarily use a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices. If our assumptions are not appropriate, or future events indicate that our goodwill is impaired, our net income would be impacted by the amount by which the carrying value exceeds the fair value of the reporting unit, to the extent of the balance of goodwill. A prolonged period of lower commodity prices may adversely affect our estimate of future operating results, which could result in future goodwill impairment for reporting units due to the potential impact on our operations and cash flows. We completed our impairment testing of goodwill in the third quarter of 2015 using the methodology described herein, and determined there was no impairment. As a result of a decreased commodity prices in late 2015 and into early 2016, which caused a significant drop in the volumes anticipated from several producers from which TMID receives natural gas for processing, we identified a potential impairment trigger with respect to the $79.2 million of goodwill at the TMID reporting unit, which is a component of our Processing & Logistics segment. We tested TMID's goodwill for impairment as of December 31, 2015 and determined that the fair value of the reporting unit exceeds the carrying value by approximately 21%. As a result, no impairment charge was recorded, however our analysis includes assumptions of a gradual recovery of commodity prices and a corresponding increase in volumes over time. If our outlook for long-term commodity prices is not realized, or our producers further decrease volumes, we could have an impairment in the future. While commodity prices do not have a significant direct exposure to the cash flows projected at TMID, the current commodity price environment has had an indirect impact on TMID's business as certain producers have significantly reduced their anticipated volumes. Keeping all other assumptions constant, as of December 31, 2015 an increase in the discount rate applied of approximately 1.38% or a decrease in overall cash flows by more than 16% would result in a step one failure, however we do not believe that these represent reasonably likely assumptions. If the reporting unit fails step one in the future, we would be required to perform step two of the goodwill impairment test and up to $79.2 million of goodwill at the TMID reporting unit could be written off in the period that the impairment is triggered. During the third quarter of 2016, we completed our annual goodwill impairment testing for all reporting units, and determined that there was no impairment.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

AsPrior to our acquisition of ~~September 30, 2016~~the Douglas Gathering System on June 5, 2017, approximately ~~91%~~99% of our reserved processing capacity was subject to firm or volumetric fee contracts, with the majority of fee revenue based on the volumes actually processed. With our acquisition of the Douglas Gathering System, the largest existing firm fee contract was terminated because the counterparty to this contract, DCP Douglas, LLC, became our indirect wholly-owned subsidiary. In addition, we acquired a number of commodity sensitive gathering and processing contracts such as percent of proceeds or keep whole processing contracts in the acquisition. For the three months ended September 30, 2017, approximately 81% of our gathering and processing volumes were subject to firm or volumetric fee contracts, with the majority of fee revenue based on the volumes actually processed. The remaining 9%19% was subject to commodity sensitive contracts such as percent of proceeds or keep whole processing contracts. The profitability of our commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. ~~We do not currently hedge~~

Our Gathering, Processing & Terminalling segment comprised approximately 10% and 3% of our operating income for the ~~commodity exposure in~~nine months ended September 30, 2017 and 2016, respectively. The profitability of our commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility in ~~our Processing & Logistics segment~~prevailing NGL and ~~we do not expect to~~natural gas prices. Starting in the ~~foreseeable future. Starting in~~second half of 2014, the prices of crude oil, natural gas, and NGLs ~~were~~became extremely volatile and declined significantly. Downward pressure and volatility onof commodity prices continued in 2015 ~~and the first half of~~before recovering somewhat in 2016 and ~~may continue for the foreseeable future.~~2017. These declines directly and indirectly resulted in lower realizations and processing volumes on our percent of proceeds and keep whole processing contracts. ~~Our Processing & Logistics segment comprised less than 1% of our operating income for both the three and nine months ended September 30, 2016.~~

We have a limited amount of direct commodity price exposure related to crude oil collected as part of our contractual pipeline loss allowance at Pony Express. During the third quarter of 2016, we entered into a derivative contract for the sale of 30,000 barrels of crude oil, which settled in October 2016. The fair value of this swap was a liability of approximately $7,000 at September 30, 2016.

Historically, we have ~~also~~ had a limited amount of direct commodity price exposure related to natural gas collected for electrical compression costs and lost and unaccounted for gas on the TIGT System. WeAccordingly, we have historically entered into derivative contracts with third parties for a substantial majority of the natural gas we ~~expect~~expected to collect ~~during the current year~~ for the purpose of hedging our commodity price exposures. ~~As of September 30,~~In 2016, we ~~had short~~also entered into long natural gas swaps ~~outstanding with a notional volume of approximately 0.8 Bcf, representing~~covering a portion of the natural gas that ~~is expected~~TMID expects to ~~be sold by~~purchase in 2017. In addition, we have a limited amount of direct commodity price exposure related to crude oil collected as part of our ~~Natural Gas Transportation & Logistics segment through~~contractual pipeline loss allowance at Pony Express and Terminals. During 2016, we began entering into derivative contracts for the ~~first quarter~~sale of ~~2017. The fair value of~~crude oil inventory. In 2017, Stanchion began to transact in crude oil and enter into financial derivative contracts in connection with these ~~swaps was a liability of approximately $0.2 million at September 30, 2016.~~transactions.

We measure the risk of price changes in our crude oil and natural gas ~~swaps~~derivatives utilizing a sensitivity analysis model. The sensitivity analysis measures the potential income or loss (i.e., the change in fair value of the derivative instruments) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. We enter into derivative contracts ~~solely~~primarily for the purpose of mitigating the risks that accompany certain of our business activities and, therefore, both the sensitivity analysis model and the change in the market value of our outstanding derivative contracts are offset largely by changes in the value of the underlying physical commodity prices. ~~A hypothetical 10% increase in the crude oil price forward curve would result in a decrease of approximately $0.1 million in the net fair value of~~

The following table summarizes our crude oil derivative instruments as of September 30, 2016. A hypothetical 10% increase in the natural gas price forward curve would result in a decrease of approximately $0.2 million in the fair value of our natural gas derivative instruments as of September 30, 2016 as a result of our hedging program. For the purpose of determiningcommodity derivatives and the change in fair value ~~associated with the hypothetical natural gas~~that would be expected from a 10% price increase ~~scenario, we have assumed~~or decrease as of September 30, 2017, assuming a parallel shift in the forward curve through the end of ~~2016.~~2017:



	Fair Value		Effect of 10% Price Increase			Effect of 10% Price Decrease
	(in thousands)
Natural gas derivative contracts⁽¹⁾	$	1	$	29		$	(29	)
Crude oil derivative contracts ⁽²⁾	$	472	$	(875	)	$	875


⁽¹⁾	Represents long natural gas swaps outstanding with a notional volume of approximately 0.1 Bcf covering a portion of the natural gas that is expected to be purchased by our Gathering, Processing & Terminalling segment throughout 2017.


⁽²⁾	Represents the purchase and sale of 323,620 barrels of crude oil by our Gathering, Processing & Terminalling segment which will settle throughout 2017 and the first quarter of 2018.

The Commodity Futures Trading Commission ("CFTC") has promulgated regulations to implement the Dodd-Frank Wall Street Reform and Consumer Protection Act's changes to the Commodity Exchange Act, including the definition of commodity-based swaps subject to those regulations. The CFTC regulations ~~are intended to implement~~implemented new reporting and record keeping requirements related to those swap transactions and a mandatory clearing and exchange-execution regime for various types, categories or classes of swaps, subject to certain exemptions, including the trade-option and end-user exemptions. Although we anticipate that most, if not all, of our swap transactions should continue to qualify for an exemption to the clearing and exchange-execution requirements, we will still be subject to record keeping and reporting requirements. Other changes to the Commodity Exchange Act made as a result of the Dodd-Frank Wall Street Reform and Consumer Protection Act and the CFTC's implementing regulations could significantly increase the cost of entering into new swaps.

Interest Rate Risk

As described in "Note 11 – ~~Liquidity and Capital Resources Overview~~Long-term Debt" above, on September 1, 2016 TEP issued $400 million in 5.50% senior notes due 2024. In addition, TEP currently has a $1.75 billion revolving credit facility with borrowings of approximately $1.0 billion as of September 30, 2016. Borrowings under the revolving credit facility will bear interest, at TEP's option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin was initially 1.00%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin was initially 2.00%. After June 25, 2014, the applicable margin ranges from 0.75% to 2.75%, based upon TEP's total leverage ratio and whether it has elected the base rate or the reserve adjusted Eurodollar rate. Tallgrass Equity currently has ~~an additional $148~~$146 million in outstanding borrowings under its revolving credit facility. Borrowings under the credit facility bear interest, at Tallgrass Equity's option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin is 1.50%, and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is 2.50%.

As of September 30, 2017, TEP has issued $750 million of 2024 Notes and $500 million of 2028 Notes. In addition, TEP currently has a $1.75 billion revolving credit facility with borrowings of approximately $881.0 million as of September 30, 2017. Borrowings under the revolving credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. During the three months ended September 30, 2017, for borrowings bearing interest based on the base rate, the applicable margin was 0.75%, and for borrowings bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin was 1.75%. For periods after September 30, 2017, the applicable margin will range from 0.50% to 1.50% for base rate borrowings and 1.50% to 2.50% for reserve adjusted Eurodollar rate borrowings, based upon our total leverage ratio.

We do not currently hedge the interest rate risk on our borrowings under the revolving credit facilities. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the fair value of the debt by ~~$0.6~~$0.5 million based on our outstanding debt ~~obligations~~under our revolving credit facilities as of September 30, ~~2016.~~2017.

Credit Risk

We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We manage our exposure to credit risk associated with customers to whom we extend credit through a credit approval process which includes credit analysis, the establishment of credit limits and ongoing monitoring procedures. We may request letters of credit, cash collateral, prepayments or guarantees as forms of credit support. ~~We have historically experienced only minimal credit losses in connection with our receivables.~~

A substantial majority of our revenue is produced under long-term firm fee contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with ~~slightly under 50%~~a majority of our revenues derived from customers who have ~~an investment grade~~BB+ or Ba1 and better credit ~~rating~~ratings or are part of corporate families with ~~investment grade~~such credit ratings as of September 30, 2016. This represents a decrease in the portion of our revenues derived from customers with an investment grade credit rating from 2015, primarily as a result of credit downgrades at several of our customers and throughout the industry due to the current commodity price environment.2017.

We also have indirect credit risk exposure with respect to our investment in Rockies Express. See Item 1A.—Risk Factors in our 2016 Form 10-K for additional information.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a- 15(e) or Rule 15d- 15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms including, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, ~~2016~~2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Note 1415 – Legal and Environmental Matters to the condensed consolidated financial statements included in Part I—Item 1.—Financial Statements of this Quarterly Report, which is incorporated ~~here~~herein by reference.

Item 1A. Risk Factors

Item 1A of our ~~2015~~2016 Form 10-K ~~for the year ended December 31, 2015 and Item 1A of our Form 10-Qs for the three months ended March 31, 2016 and June 30, 2016 set~~sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition or operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results for the quarter ended September 30, ~~2016.~~2017. There have been no material changes to the risk factors contained in our ~~2015~~2016 Form ~~10-K for the year ended December 31, 2015 and our Form 10-Qs for the quarters ended March 31, 2016 and June 30, 2016.~~10-K.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits



Exhibit No.		Description

4.1		Indenture, dated September ~~1, 2016,~~15, 2017, among Tallgrass Energy Partners, LP, Tallgrass Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as ~~trustee~~trustee. (incorporated by reference to Exhibit 4.1 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed on September ~~1, 2016)~~15, 2017).

4.2		Form of 5.50% Senior Note (included as Exhibit A in Exhibit 4.1 which is incorporated by reference to Exhibit 4.1 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed on September ~~1, 2016)~~15, 2017).

31.1* 10.1†*		Form of Employee Equity Participation Unit Agreement.

31.1*		Rule 13a-14(a)/15d-14(a) Certification of David G. Dehaemers, Jr.

31.2*		Rule 13a-14(a)/15d-14(a) Certification of Gary J. Brauchle.

32.1*		Section 1350 Certification of David G. Dehaemers, Jr.

32.2*		Section 1350 Certification of Gary J. Brauchle.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.


* -	filed herewith

† - Management contract of compensatory plan or arrangement required to be filed as an exhibit to this Form 10-Q pursuant to Item 6.

SIGNATURES

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



		Tallgrass Energy GP, LP
		(registrant)
		By:	TEGP Management, LLC, its general partner

Date:	November 2, ~~2016~~2017	By:	/s/ Gary J. Brauchle
			Name:	Gary J. Brauchle
			Title:	Executive Vice President and Chief Financial Officer
				(Duly Authorized Officer and Principal Financial Officer)

4751



Schedule of Noncash Investing and Financing Activities:
Property, plant and equipment acquired via the cash management agreement with Tallgrass Development, LP	$	—	$	120,254
Contributions from noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP	$	—	$	43,401
Distribution to noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP	$	—	$	44,142



	TEGP Predecessor			Partners' Equity (excluding noncontrolling interests)					Noncontrolling Interests			Total Equity
	TEGP Predecessor			Class A Shares			Class B Shares		Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2016	$	—		$	422,310		$	—	$	1,599,188		$	2,021,498
Net income	—			18,078			—		163,943			182,021
Acquisition of additional 31.3% membership interest in Pony Express	—			(255,617		)	—		(173,422		)	(429,039		)
Issuance of TEP common units to public, net of offering costs	—			24,543			—		265,931			290,474
Distributions to noncontrolling interests	—			—			—		(177,449		)	(177,449		)
Partial exercise of call option	—			(20,427		)	—		(156,865		)	(177,292		)
Issuance of TEP common units in a private placement, net of offering costs	—			7,592			—		82,417			90,009
TEGP distributions to Class A shareholders	—			(29,971		)	—		—			(29,971		)
Contributions from noncontrolling interests	—			—			—		8,700			8,700
Noncash compensation expense	—			1,060			—		5,931			6,991
Acquisition of membership interest in BNN	—			(464		)	—		(5,536		)	(6,000		)
Contributions from TD	—			1,611			—		3,697			5,308
Costs associated with equity issuance	—			(657		)	—		—			(657		)
Balance at September 30, 2016	$	—		$	168,058		$	—	$	1,616,535		$	1,784,593

	TEGP Predecessor			Partners' Equity (excluding noncontrolling interests)					Noncontrolling Interests			Total Equity
	TEGP Predecessor			Class A Shares			Class B Shares		Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2015	$	146,866		$	—		$	—	$	1,648,285		$	1,795,151
Net income for the period from January 1, 2015 to May 11, 2015	7,393			—			—		32,196			$	39,589
Issuance of TEP common units to the public, net of offering costs	63,477			—			—		487,766			$	551,243
Acquisition of additional 33.3% Pony Express membership interest	(98,446		)	—			—		(601,554		)	$	(700,000	)
Distributions to TEGP Predecessor	(4,108		)	—			—		(9,425		)	$	(13,533	)
Consolidation of TEGP Predecessor assets	(115,182		)	115,182			—		—			$	—
Issuance of Class A shares to the public, net of offering costs	—			1,314,741			—		—			$	1,314,741
Acquisition of Acquired TEP Units from TD	—			(953,600		)	—		—			$	(953,600	)
Distribution of excess Offering proceeds to Exchange Right Holders	—			(334,068		)	—		—			$	(334,068	)
Acquisition of Tallgrass Equity units from Exchange Right Holders	—			(171,948		)	—		—			$	(171,948	)
Deferred tax asset	—			445,128			—		—			$	445,128
Net income for the period from May 12, 2015 to September 30, 2015	—			6,886			—		73,235			$	80,121
Issuance of common units under TEP LTIP plan	—			(661		)	—		(5,901		)	$	(6,562	)
TEGP distributions to Class A Shareholders	—			(3,484		)	—		—			$	(3,484	)
Noncash compensation expense	—			195			—		7,325			$	7,520
Contributions from noncontrolling interests	—			—			—		110,553			$	110,553
Distributions to noncontrolling interests	—			—			—		(132,355		)	$	(132,355	)
Distributions to TEP GP Members	—			(7,465		)	—		—			$	(7,465	)
Acquisition of noncontrolling interests	—			—			—		(600		)	$	(600	)
Balance at September 30, 2015	$	—		$	410,906		$	—	$	1,609,525		$	2,020,431



	Three Months Ended September 30, 2016		Period from May 6, 2016 to September 30, 2016
	(in thousands)
Revenue	$	159,421	$	257,582
Operating income	$	66,436	$	110,268
Net income to Members	$	34,184	$	118,925