10-Q

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, 2017

or

¨ 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, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer", "accelerated filer", "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨ (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, 2017, the Registrant had 58,075,000 Class A shares and 99,154,440 Class B shares outstanding.

TALLGRASS ENERGY GP, LP

TABLE OF CONTENTS

PART 1—FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
CONDENSED CONSOLIDATED BALANCE SHEETS	1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME	2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	3
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY	4
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3. Quantitative and Qualitative Disclosures About Market Risk	47
Item 4. Controls and Procedures	48
PART II - OTHER INFORMATION	50
Item 1. Legal Proceedings	50
Item 1A. Risk Factors	50
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 3. Defaults Upon Senior Securities	50
Item 4. Mine Safety Disclosures	50
Item 5. Other Information	50
Item 6. Exhibits	50
SIGNATURES	51

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 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 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: an 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: 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 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.

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: 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, 2017		December 31, 2016
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	3,279	$	2,459
Accounts receivable, net	95,629		59,536
Gas imbalances	1,020		1,597
Inventories	10,173		13,093
Derivative assets	—		10,967
Prepayments and other current assets	3,407		7,628
Total Current Assets	113,508		95,280
Property, plant and equipment, net	2,350,830		2,079,232
Goodwill	404,838		343,288
Intangible assets, net	98,876		93,522
Unconsolidated investments	922,280		475,625
Deferred tax asset	496,472		521,454
Deferred financing costs, net	13,326		6,042
Deferred charges and other assets	3,016		11,037
Total Assets	$	4,403,146	$	3,625,480
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	69,620	$	24,449
Accounts payable to related parties	5,955		5,824
Gas imbalances	1,119		1,239
Derivative liabilities	473		556
Accrued taxes	22,890		16,996
Accrued liabilities	11,183		16,755
Deferred revenue	87,979		60,757
Other current liabilities	6,690		6,446
Total Current Liabilities	205,909		133,022
Long-term debt, net	2,261,086		1,555,981
Other long-term liabilities and deferred credits	18,396		7,063
Total Long-term Liabilities	2,279,482		1,563,044
Commitments and Contingencies
Equity:
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	234,241		333,262
Noncontrolling interests	1,683,514		1,596,152
Total Equity	1,917,755		1,929,414
Total Liabilities and Equity	$	4,403,146	$	3,625,480

The accompanying notes are an integral part of these condensed consolidated financial statements.

1

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in thousands, except per unit amounts)
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
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	$	0.27		$	0.15		$	0.63		$	0.38
Diluted net income per Class A share	$	0.27		$	0.15		$	0.63		$	0.38
Basic average number of Class A shares outstanding	58,075			47,725			58,075			47,725
Diluted average number of Class A shares outstanding	58,192			47,775			58,193			47,740

The accompanying notes are an integral part of these condensed consolidated financial statements.

2

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	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		$	—

The accompanying notes are an integral part of these condensed consolidated financial statements.

3

TALLGRASS ENERGY GP, LP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

	Predecessor Equity			Partners' Capital					Noncontrolling Interests			Total Equity
				Class A Shares			Class B Shares
	(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
				Class A Shares			Class B Shares
	(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

The accompanying notes are an integral part of these condensed consolidated financial statements.

4

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 together with its consolidated subsidiaries. TEGP's sole cash-generating asset as of September 30, 2017 is an approximate 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, 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, 2017.

• 20,000,000 TEP common units, representing an approximate 27.02% limited partner interest in TEP at September 30, 2017.

TEP is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. TEP's operations are 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.

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 system; and

• Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering, processing, treating and fractionation facilities; crude oil gathering, storage and terminalling facilities; the provision of 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) its 49.99% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), 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 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 through: (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. TEP also provides crude oil gathering services for customers in Wyoming through a crude oil gathering system in the 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 and Wyoming. TEP performs water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, and 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"). Terminals also owns a 69% membership interest in Deeprock Development, LLC

5

("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 Terminals and the term "NatGas Predecessor" refers to NatGas prior to their acquisition by TEP on January 1, 2017. Terminals Predecessor and 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.

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, 2017 and 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, 2017 and 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, 2017 are not necessarily indicative of the results that may be expected for the full year ending December 31, 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, 2016 ("2016 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 15, 2017.

The condensed consolidated financial statements include the accounts of TEGP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEGP is attributed to TEGP and 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.

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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. TEP is also considered to be a 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.

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 Pronouncement Recently Adopted

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

In January 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. ASU 2017-01 clarifies the definition of a business with 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 screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. The ASU also narrows the definition of the term "output" so that the term is consistent with how outputs are described under the revenue recognition guidance in Topic 606.

The amendments in ASU 2017-01 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2017. Early adoption is permitted in certain circumstances. We elected to adopt the guidance in ASU 2017-01 effective April 1, 2017.

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

In January 2017, the FASB issued ASU No. 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 reporting unit's assets and liabilities. Instead, under the 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 goodwill allocated to that reporting unit.

The amendments in ASU 2017-04 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We elected to adopt the 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 August 31, 2017.

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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 adopted the 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 did not have a material impact on our consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of 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 (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 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the 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 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 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.

We are currently evaluating 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 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

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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 statements for periods prior to January 1, 2018 would not be revised.

ASU No. 2016-02, "Leases (Topic 842)"

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the 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 ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. We are currently evaluating the impact of ASU 2016-02.

3. Variable Interest Entities

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 our controlling interest in Tallgrass Equity and have no contractual commitments or obligations to provide additional financial support to Tallgrass Equity.

Other than TEGP's deferred tax asset of approximately $496.5 million and $521.5 million at September 30, 2017 and December 31, 2016, respectively, the assets and liabilities included in our condensed consolidated balance sheets at September 30, 2017 and December 31, 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 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.

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The following represents the fair value of assets acquired and liabilities assumed at August 3, 2017 (in thousands):

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.

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. Actual revenue and net loss attributable to TEP from TCG of less than $1 million was recognized in the accompanying condensed consolidated statements of income for the period from August 3, 2017 to September 30, 2017.

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.

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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 TEGP for the three and nine months ended September 30, 2017 and 2016 is presented below as if the acquisitions of TCG and Deeprock Development had been completed on January 1, 2016.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Revenue	$	177,022	$	158,642	$	492,625	$	465,232
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 the estimated results of operations of TCG and Deeprock Development for the periods 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 Rockies Express

On 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 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 Rockies Express at September 30, 2017 was allocated as follows:

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	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 Tallgrass NatGas Operator, LLC

Effective January 1, 2017, TEP acquired 100% of the issued and outstanding membership interests in Terminals and 100% of the issued and outstanding membership interests in NatGas from TD for total cash consideration of $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 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 an aggregate additional 49% membership interest in Deeprock Development in July 2017 discussed above. Terminals also owns acreage in Cushing, Oklahoma and Guernsey, Wyoming, which is 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.

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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

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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

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	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.

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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. In connection with the closing of 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 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 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 2017. This amount is periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEGP.

Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows:

	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 and 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, 2017		December 31, 2016
	(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	1,052	$	590
Total receivable from related parties	$	1,052	$	590
Accounts payable to related parties:
Tallgrass Operations, LLC	$	5,955	$	5,811
Deeprock Development, LLC	—		13
Total accounts payable to related parties	$	5,955	$	5,824

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Gas imbalances with affiliated shippers are as follows:

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

6. Inventory

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

	September 30, 2017		December 31, 2016
	(in thousands)
Crude oil	$	2,115	$	5,462
Materials and supplies	5,993		6,383
Natural gas liquids	543		265
Gas in underground storage	1,522		983
Total inventory	$	10,173	$	13,093

7. Property, Plant and Equipment

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

	September 30, 2017			December 31, 2016
	(in thousands)
Crude oil pipelines	$	1,219,913		$	1,202,125
Gathering, processing and terminalling assets (1)	667,379			397,701
Natural gas pipelines	577,343			572,150
General and other	98,860			82,510
Construction work in progress	45,223			20,606
Accumulated depreciation and amortization	(257,888		)	(195,860		)
Total property, plant and equipment, net	$	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.

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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 quantitative impairment test 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, then goodwill is not considered impaired. When goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the reporting unit's fair value, then the reporting unit 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 goodwill allocated to that reporting unit.

We did not elect to apply the qualitative assessment option during our 2017 annual goodwill impairment testing; instead we proceeded directly to the quantitative impairment test. 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

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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 quantitative impairment test indicated no 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, we did not record a goodwill impairment during the 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.

10. Risk Management

We 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, 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 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. As of February 1, 2017, no common units remained subject to the 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 represents the sale of 125,000 barrels of crude oil which settled throughout 2017.

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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 30,2017 and 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
		(in thousands)
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	)	$	1,885	$	5,588

Call Option Derivative

As 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 2016 and October 2016, TEP partially exercised the call option 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 $72.4 million. These common units were deemed canceled upon the exercise of the call option and as of the applicable exercise date were no longer issued and outstanding.

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 was 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, 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, 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, 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 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"). 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 was valued using a Black-Scholes option pricing model. Key inputs to the valuation model 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 was classified within Level 2 of the fair value hierarchy as the value was based on significant observable inputs.

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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:

			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	$	—

11. Long-term Debt

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

	September 30, 2017			December 31, 2016
	(in thousands)
Tallgrass Equity revolving credit facility	$	146,000		$	148,000
TEP revolving credit facility	881,000			1,015,000
TEP 5.50% senior notes due September 15, 2024	750,000			400,000
TEP 5.50% senior notes due January 15, 2028	500,000			—
Less: Deferred financing costs, net (1)	(15,914		)	(7,019		)
Total long-term debt, net	$	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 facilities are presented in noncurrent assets on our condensed consolidated balance sheets.

TEP Senior Unsecured Notes

On September 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.

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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 "2024 Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). On May 16, 2017, the Issuers issued an additional $350 million in aggregate principal amount of the 2024 Notes which are also governed by the 2024 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 issue date, offering price and 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, 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, 2017 and December 31, 2016:

	September 30, 2017			December 31, 2016
	(in thousands)
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

In connection with the 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, 2017, Tallgrass Equity 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, 2017, the weighted average interest rate on outstanding borrowings under the Tallgrass Equity revolving credit facility was 3.74%. During the nine months ended September 30, 2017, Tallgrass Equity's weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 3.88%.

TEP Revolving Credit Facility

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 maturity date of TEP's existing revolving credit facility from May 13, 2018 to 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 addition, the revolving credit facility 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, 2017 and December 31, 2016:

	September 30, 2017			December 31, 2016
	(in thousands)
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

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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 distributions from available cash, if a default or event of default under the credit agreement then exists or would result, 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 5.00 to 1.00 (which will be increased to 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, 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 0.250% to 0.500%, based on TEP's total leverage ratio. As of September 30, 2017, the weighted average interest rate on outstanding borrowings under the TEP revolving credit facility was 3.24%. During the nine months ended September 30, 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 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, 2017 and December 31, 2016, but for which fair value is disclosed:

	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
	(in thousands)
As of September 30, 2017:
Revolving credit facilities	$	—	$	1,027,000	$	—	$	1,027,000	$	1,027,000
2024 Notes	$	—	$	772,028	$	—	$	772,028	$	739,444
2028 Notes	$	—	$	508,660	$	—	$	508,660	$	494,642
As of December 31, 2016:
Revolving credit facilities	$	—	$	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, 2017 and December 31, 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, 2017.

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12. Partnership Equity and Distributions

TEGP Distributions to Holders of Class A Shares

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
		(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	12,528		0.2625
June 30, 2016	August 12, 2016	11,693		0.2450
March 31, 2016	May 13, 2016	10,022		0.2100

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

Subsidiary Distributions

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

		Distributions
		Limited Partner Common Units		General Partner						Distributions per Limited Partner Common Unit
Three Months Ended	Date Paid			Incentive Distribution Rights		General Partner Units		Total
		(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	57,332		26,987		976		85,295		0.7950
June 30, 2016	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

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

As of September 30, 2017, TEP had active equity distribution 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 $100.2 million and $657.5 million. Net cash proceeds from any sale of the TEP common units may be used for general partnership purposes, which 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.

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TEP did not issue common units under the equity distribution agreements during the three months ended September 30, 2017. During the nine months ended September 30, 2017, TEP issued and sold 2,341,061 common units with a weighted average sales price of $48.82 per unit under its equity distribution agreements for net cash proceeds of approximately $112.4 million (net of approximately $1.9 million in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes as described above.

Noncontrolling Interests

As of September 30, 2017, noncontrolling interests in our subsidiaries consisted of a 63.06% interest in Tallgrass Equity held by the Exchange Right Holders, as defined in Note 13 – Net Income per Class A Share, the 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, 2017, we recognized contributions from and distributions to noncontrolling interests of $1.1 million and $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 $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.

During the nine months ended September 30, 2016, we received contributions from and made distributions to noncontrolling interests of $8.7 million and $177.4 million, respectively. Contributions from noncontrolling interests primarily consisted of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $103.7 million, Tallgrass Equity distributions to Exchange Right Holders of $68.7 million and distributions to Pony Express 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 15 – Legal and Environmental Matters.

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 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.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands, except per share data)
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	58,075		47,725		58,075		47,725
Basic net income per Class A share	$	0.27	$	0.15	$	0.63	$	0.38
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	64		3		132		3
Net income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares	$	15,930	$	7,044	$	36,780	$	18,081
Basic weighted average Class A Shares outstanding	58,075		47,725		58,075		47,725
Equity Participation Shares equivalent shares	117		50		118		15
Diluted weighted average Class A Shares outstanding	58,192		47,775		58,193		47,740
Diluted net income per Class A Share	$	0.27	$	0.15	$	0.63	$	0.38

14. Regulatory Matters

There are no regulatory proceedings challenging the rates of Pony Express, Rockies Express, Tallgrass Interstate Gas Transmission, LLC ("TIGT") or Trailblazer Pipeline Company LLC ("Trailblazer"). We have made certain regulatory filings with the FERC, including the following:

Pony Express

On May 22, 2017 and May 31, 2017, Pony Express made tariff filings with the FERC in Docket Nos. IS17-263-000, IS17-464-00, and IS17-465-000 to increase the contract and non-contract rates by an amount reflecting the most recent FERC annual index adjustment of approximately 0.2%, which became effective July 1, 2017.

Rockies Express

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 facilities increased the Rockies Express Zone 3 east-to-west mainline capacity by 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.

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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.

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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, have recorded no reserve for legal claims as of September 30, 2017 or December 31, 2016.

Rockies Express

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, seeking approximately $303 million in damages and other relief. 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, which operated as a stay of the Harris County state court proceeding.

On January 12, 2017, Rockies Express and Ultra entered into an agreement to 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 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 sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due.

On February 2, 2017, Rockies Express and Michels agreed to resolve Michels' claims for a $10 million cash payment by Rockies Express. The cash payment was inclusive of approximately $5.9 million that Rockies Express had been withholding from Michels. Subsequently, Rockies Express and Michels entered into a definitive agreement with respect to the settlement and Rockies Express made the $10 million cash payment to 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 $7.7 million and $4.0 million at September 30, 2017 and December 31, 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.

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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

Trailblazer 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 conducted in 2014, Trailblazer 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 MAOP of 1,000 pounds per square inch across all segments of the Trailblazer Pipeline. Such repair or replacement will likely occur over a period of years, depending upon the remediation and repair plan implemented by Trailblazer. Segments of the Trailblazer 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 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 us.

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. Trailblazer completed additional excavation digs and replaced approximately 8 miles of pipe at an aggregate cost of approximately $19.0 million during 2016, and intends to complete the pipe replacement project in 2017 at an estimated cost of $2.5 million. Trailblazer is currently exploring all possible cost recovery options to recover such out of pocket costs, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.

In connection with our acquisition of the Trailblazer Pipeline, TD agreed to contractually indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions were necessitated by external corrosion caused by the pipeline's disbonded Hi-Melt CTE coating. The contractual indemnity provided by TD was capped at $20 million and was subject to a $1.5 million deductible. 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, 2017.

Terminals

System Failures

In January 2017, approximately 10,000 bbls of 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 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.

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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 reportable segments: (1) Natural Gas Transportation, (2) Crude Oil Transportation, and (3) Gathering, Processing & Terminalling.

Natural Gas Transportation

The Natural Gas Transportation segment is engaged in the ownership and 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

The Crude Oil Transportation 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.

Gathering, Processing & Terminalling

The Gathering, Processing & 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 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, 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

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	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

	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

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	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

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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 TEGP's 36.94% interest in Tallgrass Equity, Tallgrass Equity's 100% membership interest in TEP GP, which owns all of the IDRs, and all of the outstanding general partner units in TEP, and Tallgrass Equity's 20 million TEP common units it acquired at the closing of the TEGP IPO. As used in 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, 2016 (our "2016 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 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 acquisitions of 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 from TD in March 2017 and a 100% membership interest in NatGas and Terminals from TD in January 2017;

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

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

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

• 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, 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; transporting, storing and processing natural 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 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 to effect the TEGP IPO, which was completed on May 12, 2015.

Our sole cash-generating asset is an approximate 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 as well as all of the TEP 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 November 2, 2017.

• 20,000,000 TEP common units, representing an approximate 27.01% limited partner interest in TEP at November 2, 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's operations are 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.

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 system; and

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

Recent Developments

TEGP Distribution Announced

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

TEP Distribution Announced

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

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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.

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

Revenues. Total revenues were $175.9 million for the three months ended September 30, 2017, compared to $153.3 million for the three months ended September 30, 2016, which represents an increase of $22.6 million, or 15%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $30.7 million and $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 segment, as discussed further below.

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

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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. The increase in interest and fees, 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 revolving credit facility.

Unrealized (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 investments. Equity in earnings of unconsolidated investments was $123.6 million and $12.8 million for the three months ended September 30, 2017 and 2016, respectively. Equity in earnings of 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.

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 was $0.5 million for the three months ended September 30, 2017 and 2016.

Deferred income tax expense. Deferred income tax expense for the three months ended September 30, 2017 was $12.6 million, compared to a deferred income tax expense of $3.2 million for the three months ended September 30, 2016, which represents an increase of $9.4 million, or 294%. The increase in deferred income tax expense was driven by the increase in taxable income, primarily attributable to the increased equity in earnings associated with Rockies Express as a result of the Ultra settlement.

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

Revenues. Total revenues were $481.1 million for the nine months ended September 30, 2017, compared to $449.5 million for the nine months ended September 30, 2016, which represents an increase of $31.7 million, or 7%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $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 segment, as discussed further below.

Operating costs and expenses. Operating costs and expenses were $277.0 million for the nine months ended September 30, 2017 compared to $264.3 million for the nine months ended September 30, 2016, which represents an increase of $12.7 million, or 5%. The overall increase in operating costs and expenses is driven by increased operating costs and expenses of $17.0 million and $4.1 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by decreased operating costs and expenses of $4.2 million in the Natural Gas Transportation, as discussed further 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.

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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 our revolving credit facility and the 2024 Notes issued on September 1, 2016. The increase in interest and fees 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 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 investments. Equity in earnings of unconsolidated 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 $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. 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 nine 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.

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, 2017 was $0.8 million compared to $1.3 million for the nine months ended September 30, 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, 2017 was $25.0 million, compared to a deferred income tax expense of $12.8 million for the nine months ended September 30, 2016, which represents an increase of $12.2 million, or 95%. The increase in deferred income tax expense was driven by the increase in taxable income, primarily attributable to the increased equity in earnings associated with Rockies Express as a result of the Ultra settlement.

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The following provides a summary of our Natural Gas Transportation segment results of operations for the periods indicated:

Segment Financial Data - Natural Gas Transportation (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Revenues:
Natural gas transportation services	$	32,139	$	32,871	$	96,140	$	93,598
Sales of natural gas, NGLs, and crude oil	603		935		2,793		1,331
Processing and other revenues	3,342		1,188		6,689		4,875
Total revenues	36,084		34,994		105,622		99,804
Operating costs and expenses:
Cost of sales	586		749		2,177		2,268
Cost of transportation services	1,489		874		2,731		4,171
Operations and maintenance	7,114		8,025		21,502		21,711
Depreciation and amortization	4,794		4,876		14,369		16,233
General and administrative	4,180		3,872		11,534		12,068
Taxes, other than income taxes	905		1,162		3,399		3,480
Total operating costs and expenses	19,068		19,558		55,712		59,931
Operating income	$	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 16 – Reportable Segments to the accompanying condensed consolidated financial statements.

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

Revenues. Natural Gas Transportation segment revenues were $36.1 million for the three months ended September 30, 2017, compared to $35.0 million for the three months ended September 30, 2016, which represents an increase of $1.1 million, or 3%, in segment revenues primarily due to a $2.2 millionincrease in other revenues driven by an increase in the fee that NatGas receives as the operator of the Rockies Express Pipeline attributable to the Ultra settlement recognized during the three months ended September 30, 2017, as discussed in Note 14 – Legal and Environmental Matters. The increase in other revenues was partially offset by a $0.7 milliondecrease in natural gas transportation services driven by lower throughput volumes at TIGT and a $0.3 milliondecrease in natural gas sales.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $19.1 million for the three months ended September 30, 2017, compared to $19.6 million for the three months ended September 30, 2016, which represents a decrease of $0.5 million, or 3%. The overall decrease in operating costs and expenses was primarily due to a $0.9 milliondecrease in operations and maintenance costs due to the timing of pipeline integrity work, partially offset by a $0.6 million increase in cost of transportation services.

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

Revenues. Natural Gas Transportation segment revenues were $105.6 million for the nine months ended September 30, 2017, compared to $99.8 million for the nine months ended September 30, 2016, which represents an increase of $5.8 million, or 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 the increase in the Rockies Express operator fee as discussed above. The $1.5 million increase in natural gas sales was driven by increased volumes sold and a 25% increase in natural gas prices during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016.

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Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $55.7 million for the nine months ended September 30, 2017, compared to $59.9 million for the nine months ended September 30, 2016, which represents a decrease of $4.2 million, or 7%. The overall decrease in operating costs and expenses was primarily due to a $1.9 million decrease in depreciation and amortization and a $1.4 million decrease in 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 result of changes to TIGT's fuel recovery structure, both as a result of the 2016 rate case settlement discussed above.

The following provides a summary of our Crude Oil Transportation segment results of operations for the periods indicated:

Segment Financial Data - Crude Oil Transportation (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Revenues:
Crude oil transportation services	$	90,113	$	91,387	$	264,299	$	279,281
Sales of natural gas, NGLs, and crude oil	2,916		4,439		9,469		4,587
Total revenues	93,029		95,826		273,768		283,868
Operating costs and expenses:
Cost of sales	2,819		3,487		8,154		3,487
Cost of transportation services	11,957		12,939		39,708		41,586
Operations and maintenance	2,976		3,203		9,048		10,244
Depreciation and amortization	13,127		12,836		39,230		38,448
General and administrative	5,320		4,866		15,318		15,236
Taxes, other than income taxes	5,352		5,268		16,848		15,248
Total operating costs and expenses	41,551		42,599		128,306		124,249
Operating income	$	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 16 – Reportable Segments to the accompanying condensed consolidated financial statements.

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

Revenues. Crude Oil Transportation segment revenues were $93.0 million for the three months ended September 30, 2017, compared to $95.8 million for the three months ended September 30, 2016, which represents a decrease of $2.8 million, or 3%, in segment revenues driven by a $1.5 milliondecrease in sales of crude oil primarily due to decreased volumes sold during the three months ended September 30, 2017 compared to the three months ended September 30, 2016 and a $1.3 milliondecrease in crude oil transportation services, primarily due to a $6.5 million increase in shipper deficiency payments that are not recognized in revenue, partially offset by a $3.6 million increase in walk-up barrels shipped and a $1.8 million increase in committed barrels shipped.

Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $41.6 million for the three months ended September 30, 2017 compared to $42.6 million for the three months ended September 30, 2016, which represents a decrease of $1.0 million, or 2%. The overall decrease in operating costs and expenses was primarily driven by a $1.0 milliondecrease in cost of transportation services driven by lower rent expense as a result of an amendment to the Deeprock Terminal lease agreement and a $0.7 milliondecrease in cost of sales primarily due to decreased volumes of crude oil sold during the three months ended September 30, 2017, partially offset by a $0.5 millionincrease in general and administrative costs.

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

Revenues. Crude Oil Transportation segment revenues were $273.8 million for the nine months ended September 30, 2017, compared to $283.9 million for the nine months ended September 30, 2016, which represents a decrease of $10.1 million, or 4%, in segment revenues driven by a $15.0 milliondecrease in crude oil transportation services, primarily due to a $16.8 million increase in shipper deficiency payments that are not recognized in revenue and an $8.1 million decrease in the incremental barrels delivered during the nine months ended September 30, 2017 compared to the nine months ended September 30, 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 volumes of crude oil sold during the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016.

Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $128.3 million for the nine months ended September 30, 2017 compared to $124.2 million for the nine months ended September 30, 2016, which represents an increase of $4.1 million, or 3%. The overall increase in operating costs and expenses was primarily driven by a $4.7 million increase in cost of sales primarily due to increased volumes of crude oil sold during the nine months ended September 30, 2017 and a $1.6 million increase in taxes, other than income taxes driven by assets placed in service throughout 2016. These increases were partially offset by a $1.9 milliondecrease in cost of transportation services driven by lower rent expense as a result of an amendment to the Deeprock Terminal lease agreement and 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 the nine months ended September 30, 2016.

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

Segment Financial Data - Gathering, Processing & Terminalling (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017			2016
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	28,696	$	15,384	$	58,252		$	45,596
Processing and other revenues	29,040		11,646		63,163			33,222
Total revenues	57,736		27,030		121,415			78,818
Operating costs and expenses:
Cost of sales	24,120		14,435		49,148			42,516
Cost of transportation services	7,531		1,259		15,294			2,802
Operations and maintenance	7,322		3,918		15,019			10,419
Depreciation and amortization	5,861		3,465		13,677			10,393
General and administrative	3,453		1,672		7,061			5,842
Contract termination	—		—		—			8,061
Taxes, other than income taxes	404		430		1,552			1,565
(Gain) loss on disposal of assets	—		—		(1,264		)	1,849
Total operating costs and expenses	48,691		25,179		100,487			83,447
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 16 – Reportable Segments to the accompanying condensed consolidated financial statements.

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

Revenues. Gathering, Processing & Terminalling segment revenues were $57.7 million for the three months ended September 30, 2017, compared to $27.0 million for the three months ended September 30, 2016, which represents a $30.7 million, or 114%, increase in segment revenues. The increase in segment revenues was primarily due to a $17.4 million increase in processing and other revenues and a $13.3 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 $12.7 million as a result of increased fresh water transportation and produced water disposal volumes, increased terminalling services revenue of $2.4 million 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 a 40% increase in NGL prices and residue natural gas sales from the Douglas Gathering System, partially offset by lower volumes of NGLs sold.

Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $48.7 million for the three months ended September 30, 2017 compared to $25.2 million for the three months ended September 30, 2016, which represents an increase of $23.5 million, or 93%. The increase in operating costs and expenses was due to a $9.7 million increase in cost of sales, a $6.3 million increase in cost of transportation services, a $3.4 million increase in operations and maintenance costs, a $2.4 million increase in depreciation and amortization, and a $1.8 million increase in general and administrative costs. The increase in cost of sales was primarily driven by 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, depreciation and amortization, and general and administrative costs were primarily driven by the acquisitions of the Douglas Gathering System and Deeprock Development.

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

Revenues. Gathering, Processing & Terminalling segment revenues were $121.4 million for the nine months ended September 30, 2017, compared to $78.8 million for the nine months ended September 30, 2016, which represents a $42.6 million, or 54%, increase in segment revenues. The increase in segment revenues was primarily due to a $29.9 million 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 a 42% increase in NGL prices and four months of residue natural gas sales from the Douglas Gathering System, partially offset by lower volumes of NGLs sold.

Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $100.5 million for the nine months ended September 30, 2017 compared to $83.4 million for the nine months ended September 30, 2016, which represents an increase of $17.0 million, or 20%. The increase in operating costs and expenses was primarily due to a $12.5 million 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, 2016 and a $3.1 million decrease in loss (gain) on disposal of assets primarily driven by a gain on disposal of assets from insurance proceeds received during the nine months ended September 30, 2017 related to assets destroyed by a fire caused by a lightning strike during the nine months ended September 30, 2016.

Liquidity and Capital Resources Overview

Our primary sources of liquidity for the three months ended September 30, 2017 were proceeds from TEP's issuance of long-term debt, borrowings under TEP's revolving credit facility, and cash generated from 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 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, 2017 and December 31, 2016 was as follows:

	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 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 barrels transported, the amount of deficiency payments received, and the volume of prior deficiencies utilized during the period.

As of September 30, 2017, we had a working capital deficit of $92.4 million compared to a working capital deficit of $37.7 million at December 31, 2016, which represents an increase in the working capital deficit of $54.7 million. The overall 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 $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 $5.9 million as a result of increased tax assessments on Pony Express assets placed in service during 2016.

These working capital decreases were partially offset by:

• an increase in accounts receivable of $36.1 million primarily due to crude oil sales at Stanchion; and

• a decrease in accrued liabilities of $5.6 million primarily due to a decrease in interest accrued at September 30, 2017 compared to December 31, 2016 due to the timing of interest payments in 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.

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Cash Flows

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

	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Net cash provided by (used in):
Operating activities	$	450,377		$	306,063
Investing activities	$	(852,941	)	$	(559,774	)
Financing activities	$	403,384		$	252,836

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

Operating Activities. Cash flows provided by operating activities were $450.4 million and $306.1 million for the nine months ended September 30, 2017 and 2016, respectively. The increase in net cash flows provided by operating activities of $144.3 million was primarily driven by a $150.3 million increase in distributions received from Rockies Express as a result of the Ultra settlement received in July 2017 as well as our increased membership interest during the nine months ended September 30, 2017.

Investing Activities. Cash flows used in investing activities were $852.9 million for the nine months ended September 30, 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 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 were primarily driven 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 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, the remainder of which is classified as a financing activity as discussed below; and

• contributions to Rockies Express in the amount of $35.5 million.

These cash outflows were partially offset by $16.1 million of distributions from Rockies Express in excess of cumulative earnings recognized.

Financing Activities. Cash flows provided by financing activities were $403.4 million for the nine months ended September 30, 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 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.

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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 $400.0 million in aggregate principal amount of 5.50% Senior Notes due 2024;

• net cash proceeds of $290.5 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

• net cash proceeds of $90.0 million from TEP's issuance of 2,416,987 common units representing limited partnership interests in a private placement 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, 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 noncontrolling interests of $5.0 million;

• $151.4 million for 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.

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 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 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 2016 Form 10-K.

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

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We expect to incur approximately $148 million for expansion capital projects and approximately $15 million, net of anticipated reimbursements, for maintenance capital 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,
	2017		2016
	(in thousands)
Maintenance capital expenditures	$	7,746	$	7,085
Expansion capital expenditures	78,448		29,452
Total capital expenditures incurred	$	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 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 is primarily driven by increased expenditures in the Natural Gas Transportation 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 $78.4 million for the nine months ended September 30, 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, 2017 consisted primarily of 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. Expansion capital expenditures of $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 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 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 2016 Form 10-K for the year ended December 31, 2016 and have not changed.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Prior to our acquisition of the Douglas Gathering System on June 5, 2017, approximately 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 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. 

Our Gathering, Processing & Terminalling segment comprised approximately 10% and 3% of our operating income for the 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 prevailing NGL and natural gas prices. Starting in the second half of 2014, the prices of crude oil, natural gas, and NGLs became extremely volatile and declined significantly. Downward pressure and volatility of commodity prices continued in 2015 before recovering somewhat in 2016 and 2017. These declines directly and indirectly resulted in lower realizations and processing volumes on our percent of proceeds and keep whole processing contracts.

Historically, we have 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. Accordingly, we have historically entered into derivative contracts with third parties for a substantial majority of the natural gas we expected to collect for the purpose of hedging our commodity price exposures. In 2016, we also entered into long natural gas swaps covering a portion of the natural gas that TMID expects to purchase in 2017. In addition, 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 and Terminals. During 2016, we began entering into derivative contracts for the sale of crude oil inventory. In 2017, Stanchion began to transact in crude oil and enter into financial derivative contracts in connection with these transactions.

We measure the risk of price changes in our crude oil and natural gas 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 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.

The following table summarizes our commodity derivatives and the change in fair value that would be expected from a 10% price increase or decrease as of September 30, 2017, assuming a parallel shift in the forward curve through the end of 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.

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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 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.

Interest Rate Risk

As described in Note 11 – Long-term Debt, Tallgrass Equity currently has $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 $0.5 million based on our outstanding debt under our revolving credit facilities as of September 30, 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.

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 a majority of our revenues derived from customers who have BB+ or Ba1 and better credit ratings or are part of corporate families with such credit ratings as of September 30, 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.

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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, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Note 15 – 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 herein by reference.

Item 1A. Risk Factors

Item 1A of our 2016 Form 10-K 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, 2017. There have been no material changes to the risk factors contained in our 2016 Form 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 15, 2017, among Tallgrass Energy Partners, LP, Tallgrass Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee. (incorporated by reference to Exhibit 4.1 to Tallgrass Energy Partners, LP’s Current Report on Form 8-K filed on September 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 15, 2017).
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.

50

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, 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)

51

EX-10.1

Exhibit 10.1

TALLGRASS MLP GP, LLC

LONG-TERM INCENTIVE PLAN

EQUITY PARTICIPATION UNIT AGREEMENT

This Equity Participation Unit Agreement ("Agreement") between Tallgrass MLP GP, LLC (the "Company") and [________________] (the "Participant"), regarding an award (this "Award") of [_________] Equity Participation Units (as defined in the Tallgrass MLP GP, LLC Long-Term Incentive Plan (the "Plan")) granted to the Participant on August 2, 2017 (the "Grant Date"), such number of Equity Participation Units subject to adjustment as provided in the Plan, and further subject to the following terms and conditions:

1. Relationship to Plan. This Award is subject to all of the terms, conditions and provisions of the Plan and administrative interpretations thereunder, if any, which have been adopted by the Board or the Committee thereunder and are in effect on the date hereof. Except as otherwise provided herein, capitalized terms shall have the same meanings ascribed to them under the Plan.

2. Vesting Schedule; Settlement.

(a) General. Except as otherwise provided Section 2(b) or the Plan, all of the Equity Participation Units subject to this Award shall vest, if at all, on the Distribution Hurdle Date; provided, however, that (i) the Participant remains in continuous employment with the Company or its Affiliates during the period beginning on the Grant Date and ending on the Distribution Hurdle Date and (ii) such Equity Participation Units have not previously been forfeited prior to such date pursuant to Section 3. If the Distribution Hurdle Date does not occur by the seventh anniversary of the Grant Date, then as of the seventh anniversary of the Grant Date, this Award will expire, terminate and be immediately forfeited by the Participant.

(b) Accelerated Vesting. If prior to the vesting of the Equity Participation Units under Section 2(a) and the seventh anniversary of the Grant Date:

(i) both (A) a Qualifying Transaction occurs and (B) David G. Dehaemers, Jr. ceases to be the Chief Executive Officer of Tallgrass Energy Holdings, LLC, TEGP Management, LLC or the Company, then all unvested Equity Participation Units shall vest as of the later date of (A) or (B) above (the "Qualifying Transaction Acceleration Date"); provided, however, that (x) the Participant remains in continuous employment with the Company or its Affiliates through such Qualifying Transaction Acceleration Date and (y) such Equity Participation Units have not previously been forfeited prior to such Qualifying Transaction Acceleration Date pursuant to Section 3; or

(ii) (A) David G. Dehaemers, Jr. ceases to be the Chief Executive Officer of Tallgrass Energy Holdings, LLC, TEGP Management, LLC or the Company other than in connection with a Qualifying Transaction and (B) after the occurrence of the event in (A), Participant's employment with the Company or its Affiliates is thereafter terminated without Cause, then all unvested Equity Participation Units shall vest as of the date of such termination of Participant’s employment.

For avoidance of doubt, the Equity Participation Units will vest pursuant to this Section 2(b) even if the Distribution Hurdle Date has not occurred.

(c) Settlement of Vested Equity Participation Units. Within 60 days following the Vesting Date of the Equity Participation Units, the Participant shall receive the number of Units equal to the number of vested Equity Participation Units. Units will be evidenced, at the sole option and in the sole discretion of the Committee, either (i) in book-entry form in the Participant's name in the Unit register of the Partnership maintained by the Partnership's transfer agent or (ii) a unit certificate issued in the Participant's name. Upon delivery of a Unit in respect of an Equity Participation Unit, such Equity Participation Unit shall cease to be outstanding in the Participant's notional account described in Section 4.

(d) Definitions. For purposes of this Agreement, the following terms shall have the meanings set forth below:

"Cause" means, as determined by the Board, the Participant's: (i) failure to perform his employment duties that, if curable, is not cured within 30 days after a written notice of such failure is delivered by the Company; (ii) engagement in dishonesty, illegal conduct, or misconduct, which is, in each case, injurious to any member of the Tallgrass Group; (iii) conviction of or plea of guilty or nolo contendere to a crime that constitutes a felony (or state law equivalent) or a crime that constitutes a misdemeanor involving moral turpitude; (iv) violation of a material policy of the Company; (v) breach of his fiduciary duties with respect to any member of the Tallgrass Group as evidenced by a judicial determination of such breach; or (vi) breach of this Agreement or any other written agreement between the Participant and any member of the Tallgrass Group (including the Confidentiality Agreement and the Acceptance Agreement defined in Section 12 below).

"Distribution Hurdle Date" means the earliest date on or after April 1, 2021 on which the average compounded annual distribution growth rate for regular quarterly Partnership distributions, based upon the regular quarterly distribution paid by the Partnership on or immediately prior to such date, is at least 5% over an annualized distribution rate of $3.34 per common unit, as determined by the Committee in its sole discretion with such determination occurring as soon as reasonable practicable after each of the applicable quarterly distribution dates if and until such event has occurred.

"Qualifying Owner" means and includes (i) The Energy & Minerals Group or any of its Affiliates, (ii) Kelso & Company, (iii) any affiliated fund, holding company or investment vehicle of any Person in clause (i) or (ii), (iv) Tallgrass KC, LLC and its subsidiaries or (v) David G. Dehaemers, Jr., any family member, heir or estate of David G. Dehaemers, Jr. or any trust or other Persons controlled by or for the benefit of any of the foregoing.

"Qualifying Transaction" means, any transaction in which (i) a Person other than a Qualifying Owner directly or indirectly acquires Voting Control, (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership, or (iii) the sale or other disposition by the Partnership of all or substantially all of its assets in one or more transactions to any Person other than an Affiliate of a member of the Tallgrass Group.

"Tallgrass Group" means Tallgrass Energy Holdings, LLC, TEGP Management, LLC, Tallgrass Energy GP, LP, Tallgrass Equity, LLC, the Company, the Partnership, Tallgrass Development, LP, and their respective Affiliates and subsidiaries.

"Vesting Date" the date on which the Equity Participation Units vest pursuant to Section 2(a) or 2(b) of this Agreement.

"Voting Control" means the direct or indirect ownership or control of 50% or more of the voting interests in the Company, the ownership of fifty percent 50% or more of the general partner interests in the Partnership, or the ownership of such other rights or interests that grant to the owner or holder thereof the ability to direct the management or policies of the Partnership, whether through the ownership of voting rights, by contract, or otherwise.

3. Forfeiture of Award. Except as set forth in Section 2(b)(ii), upon termination of the Participant's employment with the Company or any of its Affiliates for any reason prior to the Vesting Date, all Equity Participation Units that have not vested in accordance with Section 2 as of such termination date shall be immediately forfeited by the Participant on such termination date.

4. Bookkeeping Account.Until vesting, termination or forfeiture, the Award of Equity Participation Units hereunder shall be evidenced by entry in a bookkeeping account maintained by the Partnership or its transfer agent.

5. Rights as Unitholder; Delivery of Units.Until delivery of Units as described in Section 2(c), the Participant shall have no rights as a unitholder as a result of the grant of Equity Participation Units hereunder, including the right to vote the Equity Participation Units. The Participant shall not be entitled to receive any distributions with respect to the Equity Participation Units unless the Participant receives a separate grant of Distribution Equivalent Rights. The Company shall not be obligated to deliver any Units if counsel to the Company determines that such sale or delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Partnership with, any securities exchange or association upon which the

Units are listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of Units to comply with any such law, rule, regulation or agreement.

6. Assignment of Award. The Participant's rights under this Agreement and the Plan are personal; no assignment or transfer of the Participant's rights under and interest in this Award may be made by the Participant.

7. Withholding. No Units shall be delivered hereunder to or in respect of a Participant unless the amount of all federal, state and other governmental withholding tax requirements imposed upon the Company or an Affiliate with respect to the issuance of such Units has been remitted to the Company or an Affiliate or unless provisions to pay such withholding requirements have been made to the satisfaction of the Committee. The Participant shall satisfy such tax withholding by having the Company or an Affiliate withhold Units otherwise deliverable hereunder, having a Fair Market Value equal to the minimum required tax withholding rate. The Committee may make such provisions as it may deem appropriate for the withholding of any taxes which it determines is required in connection with this Award.

8. Restrictive Covenants.

(a) Definitions. For purposes of this Agreement, the following terms shall have the meanings set forth below:

"Competitive Business" means any business which provides midstream energy services in the United States.

"Prohibited Activity" means Participant’s engagement in any Competitive Business, performance of any service, directly or indirectly, on behalf of a Competitive Business, and/or interest, whether as proprietor, partner, employee, stockholder, principal, agent, consultant, contractor, director, officer, or in any other capacity or manner whatsoever, in any enterprise that engages in a Competitive Business, anywhere within the United States; provided, however, that Participant may have an ownership interest of not more than five percent of the outstanding capital stock of any publicly held entity engaged in a Competitive Business so long as Participant is not otherwise engaged or interested in such entity.

"Prohibited Period" means the period beginning on the Grant Date and ending on the earliest of (A) if a Vesting Date occurs, 18-months following Participant's termination of employment, (B) the date on which the Equity Participation Units are forfeited without vesting under Section 3, and (C) the date on which the Equity Participation Units expire pursuant to Section 2(a).

(b) Noncompetition; Nonsolicitation. The Participant acknowledges and recognizes his status as a key executive and management employee of the Company, his possession of the Company’s trade secret and confidential and/or proprietary information which would be valuable or useful to the Company’s competitors, and the highly competitive nature of the business of the Company and the other members of the Tallgrass Group. Participant further acknowledges that the restrictions contained in this Section are reasonable and necessary for the protection of the immediate interests of the Company and the other members of the Tallgrass Group in that any violation of these restrictions would cause substantial injury to the Company and the other members of the Tallgrass Group. Therefore, in consideration of the Participant’s continued employment with the Company or any Affiliate and the benefits provided to Participant under this Award, and to further protect the proprietary, trade secret, and confidential information of the Tallgrass Group, the Participant agrees that, during the Prohibited Period the Participant will not:

(i) engage in a Prohibited Activity; or

(ii) solicit, entice, induce or in any manner influence any person who has an employee or independent contractor relationship with any member of the Tallgrass Group and with whom the Participant had contact, directly or indirectly, during the term of the Participant's employment, to change or end such relationship or hire, recruit, or attempt to hire or recruit, any such person to provide services for an affiliate of the Participant.

(c) Non-disparagement. So long as the Participant is an employee of the Company or any Affiliate and thereafter (including after the termination of the Participant's employment), the Participant will not make any comments, in any format, whether written, electronic or oral, disparaging of any member of the Tallgrass Group or critical of the business performance, methods, practices, operations, decisions or plans of any member of the Tallgrass Group to any third party.

(d) Protected Disclosures. Notwithstanding any provision to the contrary in this Agreement, nothing in this Agreement prohibits the Participant from reporting possible violations of law or regulation to any

governmental agency or entity, including but not limited to the Department of Justice, the Securities and Exchange Commission, the Congress, and any agency Inspector General, or making other disclosures that are protected under the whistleblower provisions of federal law or regulation. Additionally, the parties acknowledge and agree that the Participant does not need the prior authorization of the Company or any member of the Tallgrass Group to make any such reports or disclosures and the Participant is not required to notify the Company or any member of the Tallgrass Group that the Participant has made such reports or disclosures.

(e) Specific Performance. Recognizing that irreparable damage will result to the Company and the Tallgrass Group in the event of the breach of any of the foregoing covenants and assurances by the Participant contained in Section 8, and that the Company's remedies at law for any such breach or threatened breach will be inadequate, the Company, in addition to such other remedies that may be available to it, will be entitled to an injunction, including a mandatory injunction, to be issued by any court of competent jurisdiction ordering compliance with this Agreement or enjoining and restraining the Participant, and each and every person and entity acting in concert or participation with him, from the continuation of the breach. The Company will not be required to obtain a bond in an amount greater than $1,000. The covenants and obligations of the Participant set forth in Section 8 are in addition to and not in lieu of or exclusive of any other obligations and duties of the Participant to the Company or any member of the Tallgrass Group, whether express or implied in fact or in law.

(f) Reformation. The Company and the Participant agree that the foregoing geographic, duration and other restrictions contained in this Agreement are fair, reasonable, and necessary to protect the Company’s legitimate business interests, given the geographic scope of the Company’s business operations, the competitive and specialized nature of the Company’s business, and the nature of Participant’s position with the Company and that any breach of the covenants contained in this Section 8 would cause irreparable injury to the Tallgrass Group. The Participant expressly represents that enforcement of the restrictive covenants set forth in this Section 8 will not impose an undue hardship upon the Participant or any person or entity affiliated with the Participant. The Participant understands that the foregoing restrictions may limit the Participant’s ability to engage in Prohibited Activities during the Prohibited Period, but acknowledges that the Participant will receive sufficiently high remuneration and other benefits from the Company to justify such restriction. Further, the Participant acknowledges that the Participant’s skills are such that the Participant can be gainfully employed in non-competitive employment, and that the restrictive covenants will not prevent the Participant from earning a living. Nevertheless, if any of the aforesaid restrictions are found by a court of competent jurisdiction to be unreasonable, or overly broad as to geographic area or time, or otherwise unenforceable, the parties intend for the restrictions herein set forth to be modified by the court making such determination so as to be reasonable and enforceable and, as so modified, to be fully enforced.

9. No Employment Guaranteed. No provision of this Agreement shall confer any right upon the Participant to continued employment with the Company or any Affiliate, and Participant acknowledges that Participant's employment with the Company or any Affiliate is on an at-will basis.

10. Governing Law. This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of Delaware, except with respect to Section 8, which shall be governed by, construed, and enforced in accordance with the laws of the State of Kansas.

11. Amendment. This Agreement cannot be modified, altered or amended, except by an agreement, in writing, signed by both the Company and the Participant.

12. Continuing Obligations; Entire Agreement. Participant acknowledges and agrees that Participant continues to remain bound by, and is required to continue to comply with, the (i) Confidentiality Agreement and Assignment of Inventions dated [________] between Participant and the Company (the "Confidentiality Agreement") and (ii) Acceptance Statement dated [________] (the "Acceptance Agreement") and that such agreements remain in full force and effect, unchanged by the execution, delivery and performance of this Agreement.  This Agreement, together with the Confidentiality Agreement and the Acceptance Agreement, constitutes and expresses the entire agreement of the parties with respect to the subject matter hereof, and may be modified only by written agreement signed by the parties.

13. Section 409A. The Equity Participation Units granted pursuant to this Agreement are intended to be exempt from Code Section 409A, as a "short-term deferral," and ambiguous provisions hereof, if any, shall be construed and interpreted in a manner consistent with such intent. No payment, benefit or consideration shall be substituted for the Equity Participation Units if such action would result in the imposition of taxes under Code Section 409A. Notwithstanding anything in this Agreement to the contrary, if any Plan provision or this Agreement results in the imposition of an additional tax under Code Section 409A, that Plan provision or provision of this Agreement shall be reformed, to the extent permissible under Code Section 409A, to avoid imposition of the additional tax, and no such action shall be deemed to adversely affect the Participant's rights to the Equity Participation Units.

[Signature Page Follows]

	TALLGRASS MLP GP, LLC
Date:	By:
	Name:
	Title:

The Participant hereby accepts the foregoing Agreement, subject to the terms and provisions of the Plan and administrative interpretations thereof referred to above.

	PARTICIPANT:
Date:
	[Name]

EX-31.1

Exhibit 31.1

Certification by Chief Executive Officer pursuant to

Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,

as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, David G. Dehaemers, Jr., certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Tallgrass Energy GP, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ David G. Dehaemers, Jr.
	David G. Dehaemers, Jr.
	President and Chief Executive Officer of TEGP Management, LLC (the general partner of Tallgrass Energy GP, LP)

Date: November 2, 2017

EX-31.2

Exhibit 31.2

Certification by Chief Financial Officer pursuant to

Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,

as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Gary J. Brauchle, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Tallgrass Energy GP, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By:	/s/ Gary J. Brauchle
	Gary J. Brauchle
	Executive Vice President and Chief Financial Officer of TEGP Management, LLC (the general partner of Tallgrass Energy GP, LP)

Date: November 2, 2017

EX-32.1

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the quarterly report of Tallgrass Energy GP, LP (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David G. Dehaemers, Jr., President and Chief Executive Officer of TEGP Management, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/ David G. Dehaemers, Jr.
	David G. Dehaemers, Jr.
	President and Chief Executive Officer of TEGP Management, LLC (the general partner of Tallgrass Energy GP, LP)

Date: November 2, 2017

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the quarterly report of Tallgrass Energy GP, LP (the “Partnership”) on Form 10-Q for the quarter ended September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gary J. Brauchle, Executive Vice President and Chief Financial Officer of TEGP Management, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By:	/s/Gary J. Brauchle
	Gary J. Brauchle
	Executive Vice President and Chief Financial Officer of TEGP Management, LLC (the general partner of Tallgrass Energy GP, LP)

Date: November 2, 2017

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 02, 2017
Document Information [Line Items]
Entity Registrant Name	TALLGRASS ENERGY GP, LP
Entity Central Index Key	0001633651
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	Q3
Trading Symbol	TEGP
Amendment Flag	false
Capital Unit, Class A
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		58,075,000
Capital Unit, Class B
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		99,154,440

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 3,279	$ 2,459
Accounts receivable, net	95,629	59,536
Gas imbalances	1,020	1,597
Inventories	10,173	13,093
Derivative assets	0	10,967
Prepayments and other current assets	3,407	7,628
Total Current Assets	113,508	95,280
Property, plant and equipment, net	2,350,830	2,079,232
Goodwill	404,838	343,288
Intangible assets, net	98,876	93,522
Unconsolidated investments	922,280	475,625
Deferred tax asset	496,472	521,454
Deferred financing costs, net	13,326	6,042
Deferred charges and other assets	3,016	11,037
Total Assets	4,403,146	3,625,480
Current Liabilities:
Accounts payable	69,620	24,449
Accounts payable to related parties	5,955	5,824
Gas imbalances	1,119	1,239
Derivative liabilities	473	556
Accrued taxes	22,890	16,996
Accrued liabilities	11,183	16,755
Deferred revenue	87,979	60,757
Other current liabilities	6,690	6,446
Total Current Liabilities	205,909	133,022
Long-term debt, net	2,261,086	1,555,981
Other long-term liabilities and deferred credits	18,396	7,063
Total Long-term Liabilities	2,279,482	1,563,044
Commitments and Contingencies
Equity [Abstract]
Total Partners' Equity	234,241	333,262
Noncontrolling interests	1,683,514	1,596,152
Total Equity	1,917,755	1,929,414
Total Liabilities and Equity	4,403,146	3,625,480
Common Class A
Equity [Abstract]
Total Partners' Equity	234,241	250,967
Common Class B
Equity [Abstract]
Total Partners' Equity	0	0
Predecessor
Equity [Abstract]
Total Partners' Equity	$ 0	$ 82,295

XML

CONDENSED CONSOLIDATED BALANCE SHEETS CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - shares	Sep. 30, 2017	Dec. 31, 2016
Common Class A
Limited Partners' Capital Account, Units Issued	58,075,000	58,075,000
Shares Outstanding	58,075,000	58,075,000
Common Class B
Limited Partners' Capital Account, Units Issued	99,154,440	99,154,440
Shares Outstanding	99,154,440	99,154,440

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
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	0	0	0	8,061
(Gain) loss on disposal of assets	0	0	(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	0	(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	0	9,728	0
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
Predecessor operations interest in net income	0	(3,611)	0	(3,408)
Net income attributable to TEGP, excluding predecessor operations interest	$ 15,866	$ 7,041	$ 36,648	$ 18,078
Earnings Per Share, Basic and Diluted [Abstract]
Basic net income per Class A share	$ (0.27)	$ (0.15)	$ (0.63)	$ (0.38)
Diluted net income per Class A share	$ 0.27	$ 0.15	$ 0.63	$ 0.38
Basic average number of Class A shares outstanding	58,075	47,725	58,075	47,725
Diluted average number of Class A shares outstanding	58,192	47,775	58,193	47,740

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED) - USD ($) $ in Thousands	Total	Pony Express Pipeline	Noncontrolling Interest	Noncontrolling Interest Tallgrass Energy Partners	Noncontrolling Interest Terminals and NatGas	Noncontrolling Interest Rockies Express Pipeline LLC	Noncontrolling Interest Deeprock Development, LLC	Noncontrolling Interest Pony Express Pipeline	Noncontrolling Interest Water Solutions	Total Partner Equity Including Portion Attributable to Noncontrolling Interest	Total Partner Equity Including Portion Attributable to Noncontrolling Interest Tallgrass Energy Partners	Total Partner Equity Including Portion Attributable to Noncontrolling Interest Terminals and NatGas	Total Partner Equity Including Portion Attributable to Noncontrolling Interest Rockies Express Pipeline LLC	Total Partner Equity Including Portion Attributable to Noncontrolling Interest Deeprock Development, LLC	Total Partner Equity Including Portion Attributable to Noncontrolling Interest Pony Express Pipeline	Total Partner Equity Including Portion Attributable to Noncontrolling Interest Water Solutions	Common Class A	Common Class A Tallgrass Energy Partners	Common Class A Terminals and NatGas	Common Class A Rockies Express Pipeline LLC	Common Class A Deeprock Development, LLC	Common Class A Pony Express Pipeline	Common Class A Water Solutions	Common Class B	Common Class B Tallgrass Energy Partners	Common Class B Terminals and NatGas	Common Class B Rockies Express Pipeline LLC	Common Class B Deeprock Development, LLC	Common Class B Pony Express Pipeline	Common Class B Water Solutions	Predecessor Equity	Predecessor Equity Tallgrass Energy Partners	Predecessor Equity Terminals and NatGas	Predecessor Equity Rockies Express Pipeline LLC	Predecessor Equity Deeprock Development, LLC	Predecessor Equity Pony Express Pipeline	Predecessor Equity Water Solutions
Partners' Capital, Including Portion Attributable to Noncontrolling Interest			$ 1,599,188							$ 2,093,062							$ 422,310							$ 0							$ 71,564
Increase (Decrease) in Partners' Capital [Roll Forward]
Acquisitions								$ (173,422)							$ (429,039)							$ (255,617)							$ 0							$ 0
Net income	$ 185,429		163,943							185,429							18,078							0							3,408
Issuance of TEP units to the public, net of offering costs				$ 265,931							$ 290,474							$ 24,543							$ 0							$ 0
Proceeds from private placement of TEP common units, net of offering costs	90,009			82,417							90,009							7,592							0							0
TEGP distributions to Class A shareholders	(29,971)		0							(29,971)							(29,971)							0							0
Noncash compensation expense			5,931							6,991							1,060							0							0
Partial exercise of call option			(156,865)							(177,292)							(20,427)							0							0
Payments for Repurchase of Common Stock	0
Contributions from TD			3,697							5,308							1,611							0							0
Contributions from noncontrolling interest			(8,700)							(8,700)							0							0							0
Distributions to noncontrolling interest	(177,449)	$ (425,882)	(177,400)							(177,449)							0							0							0
Contribution from Predecessor Entities, net			0							5,116							0							0							5,116
Acquisition of noncontrolling interests	49,118								$ 5,536							$ 6,000							$ 464							$ 0							$ 0
Cost associated with equity issuance			0							(657)							(657)							0							0
Partners' Capital, Including Portion Attributable to Noncontrolling Interest			1,616,535							1,864,681							168,058							0							80,088
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	1,929,414		1,596,152							1,929,414							250,967							0							82,295
Acquisitions					$ (36,391)	$ 40,159	$ 45,869					$ (140,000)	$ 63,681	$ 45,869					$ (21,314)	$ 23,522	$ 0					$ 0	$ 0	$ 0					$ (82,295)	$ 0	$ 0
Net income	317,182		280,534							317,182							36,648							0							0
Issuance of TEP units to the public, net of offering costs	112,400			101,043							112,393							11,350							0							0
Proceeds from private placement of TEP common units, net of offering costs	0
TEGP distributions to Class A shareholders	(52,704)		0							(52,704)							52,704							0							0
Noncash compensation expense			6,169							7,355							1,186							0							0
TEP LTIP units tendered by employees to satisfy tax withholding obligations				$ 11,139							$ (12,402)							$ 1,263							$ 0							$ 0
Partial exercise of call option			(72,890)							(84,942)							(12,052)							0							0
Payments for Repurchase of Common Stock	(35,335)		31,717							35,335							3,618							0							0
Contributions from TD			1,451							2,301							850							0							0
Contributions from noncontrolling interest			(1,100)							(1,093)							0							0							0
Distributions to noncontrolling interest	(229,710)	$ 0	229,700							(229,710)							0							0							0
Acquisition of noncontrolling interests	0						$ (7,109)							$ (6,440)							$ 669							$ 0							$ 0
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	$ 1,917,755		$ 1,683,514							$ 1,917,755							$ 234,241							$ 0							$ 0

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
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)	0
Noncash change in the fair value of derivative financial instruments
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 Douglas Gathering System	128,526	0
Capital expenditures	(88,050)	(55,397)
Distributions from unconsolidated investments in excess of cumulative earnings	41,886	16,073
Contributions to unconsolidated investments	(31,570)	(35,515)
Acquisition of noncontrolling interests	0	49,118
Other investing, net	(13,449)	205
Net Cash Used in Investing Activities	(852,941)	(559,774)
Net Cash Provided by Financing Activities
Proceeds from issuance of long-term debt	850,000	400,000
Distributions to noncontrolling interests	(229,710)	(177,449)
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
Payments for Repurchase of Common Stock	(35,335)	0
TEGP distributions to Class A shareholders	(52,704)	(29,971)
Proceeds from private placement of TEP common units, net of offering costs	0	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
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	0
Increase in accrual for payment of property, plant and equipment	1,342	0
Pony Express Pipeline
Net Cash Provided by Financing Activities
Distributions to noncontrolling interests	0	(425,882)
Terminals and NatGas
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Gross	140,000	0
Deeprock Development, LLC
Cash Flows from Investing Activities:
Acquisition of Deeprock Development	57,202	0
Tallgrass Crude Gathering, LLC
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Gross	36,030	0
Equity Option
Net Cash Provided by Financing Activities
Payments for Repurchase of Common Stock	$ (72,381)	$ (151,434)

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Description of Business

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

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 together with its consolidated subsidiaries. TEGP's sole cash-generating asset as of September 30, 2017 is an approximate 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, 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, 2017.

• 20,000,000 TEP common units, representing an approximate 27.02% limited partner interest in TEP at September 30, 2017.

TEP is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. TEP's operations are 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.

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 system; and

• Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering, processing, treating and fractionation facilities; crude oil gathering, storage and terminalling facilities; the provision of 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) its 49.99% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), 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 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 through: (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. TEP also provides crude oil gathering services for customers in Wyoming through a crude oil gathering system in the 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 and Wyoming. TEP performs water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, and 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"). Terminals also owns a 69% membership interest in 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 Terminals and the term "NatGas Predecessor" refers to NatGas prior to their acquisition by TEP on January 1, 2017. Terminals Predecessor and 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.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

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, 2017 and 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, 2017 and 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, 2017 are not necessarily indicative of the results that may be expected for the full year ending December 31, 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, 2016 ("2016 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 15, 2017.

The condensed consolidated financial statements include the accounts of TEGP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEGP is attributed to TEGP and 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. TEP is also considered to be a 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.

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 Pronouncement Recently Adopted

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

In January 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. ASU 2017-01 clarifies the definition of a business with 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 screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. The ASU also narrows the definition of the term "output" so that the term is consistent with how outputs are described under the revenue recognition guidance in Topic 606.

The amendments in ASU 2017-01 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2017. Early adoption is permitted in certain circumstances. We elected to adopt the guidance in ASU 2017-01 effective April 1, 2017.

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

In January 2017, the FASB issued ASU No. 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 reporting unit's assets and liabilities. Instead, under the 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 goodwill allocated to that reporting unit.

The amendments in ASU 2017-04 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We elected to adopt the 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 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 adopted the 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 did not have a material impact on our consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of 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 (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 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the 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 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 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.

We are currently evaluating 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 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 statements for periods prior to January 1, 2018 would not be revised.

ASU No. 2016-02, "Leases (Topic 842)"

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the 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 ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. We are currently evaluating the impact of ASU 2016-02.

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Variable Interest Entity Variable Interest Entity

9 Months Ended

Sep. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Variable Interest Entity

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 our controlling interest in Tallgrass Equity and have no contractual commitments or obligations to provide additional financial support to Tallgrass Equity.

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

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Acquisitions

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

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 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.

The following represents the fair value of assets acquired and liabilities assumed at August 3, 2017 (in thousands):

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.

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. Actual revenue and net loss attributable to TEP from TCG of less than $1 million was recognized in the accompanying condensed consolidated statements of income for the period from August 3, 2017 to September 30, 2017.

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 TEGP for the three and nine months ended September 30, 2017 and 2016 is presented below as if the acquisitions of TCG and Deeprock Development had been completed on January 1, 2016.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Revenue	$	177,022	$	158,642	$	492,625	$	465,232
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 the estimated results of operations of TCG and Deeprock Development for the periods 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 Rockies Express

On 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 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 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 Tallgrass NatGas Operator, LLC

Effective January 1, 2017, TEP acquired 100% of the issued and outstanding membership interests in Terminals and 100% of the issued and outstanding membership interests in NatGas from TD for total cash consideration of $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 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 an aggregate additional 49% membership interest in Deeprock Development in July 2017 discussed above. Terminals also owns acreage in Cushing, Oklahoma and Guernsey, Wyoming, which is 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.

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Related Party Transactions

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

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. In connection with the closing of 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 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 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 2017. This amount is periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEGP.

Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows:

	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 and 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, 2017		December 31, 2016
	(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	1,052	$	590
Total receivable from related parties	$	1,052	$	590
Accounts payable to related parties:
Tallgrass Operations, LLC	$	5,955	$	5,811
Deeprock Development, LLC	—		13
Total accounts payable to related parties	$	5,955	$	5,824

Gas imbalances with affiliated shippers are as follows:

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

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Inventory

9 Months Ended

Sep. 30, 2017

Inventory Disclosure [Abstract]

Inventory

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

	September 30, 2017		December 31, 2016
	(in thousands)
Crude oil	$	2,115	$	5,462
Materials and supplies	5,993		6,383
Natural gas liquids	543		265
Gas in underground storage	1,522		983
Total inventory	$	10,173	$	13,093

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2017

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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

	September 30, 2017			December 31, 2016
	(in thousands)
Crude oil pipelines	$	1,219,913		$	1,202,125
Gathering, processing and terminalling assets (1)	667,379			397,701
Natural gas pipelines	577,343			572,150
General and other	98,860			82,510
Construction work in progress	45,223			20,606
Accumulated depreciation and amortization	(257,888		)	(195,860		)
Total property, plant and equipment, net	$	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.

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Investments in Unconsolidated Affiliates (Notes)

9 Months Ended

Sep. 30, 2017

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments and Joint Ventures Disclosure

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.

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Goodwill (Notes)

9 Months Ended

Sep. 30, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill Disclosure

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 quantitative impairment test 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, then goodwill is not considered impaired. When goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the reporting unit's fair value, then the reporting unit 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 goodwill allocated to that reporting unit.

We did not elect to apply the qualitative assessment option during our 2017 annual goodwill impairment testing; instead we proceeded directly to the quantitative impairment test. 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 quantitative impairment test indicated no 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, we did not record a goodwill impairment during the 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.

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Risk Management

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management

We 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, 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 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. As of February 1, 2017, no common units remained subject to the 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 represents the sale of 125,000 barrels of crude oil 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 30,2017 and 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
		(in thousands)
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	)	$	1,885	$	5,588

Call Option Derivative

As 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 2016 and October 2016, TEP partially exercised the call option 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 $72.4 million. These common units were deemed canceled upon the exercise of the call option and as of the applicable exercise date were no longer issued and outstanding.

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 was 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, 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, 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, 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 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"). 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 was valued using a Black-Scholes option pricing model. Key inputs to the valuation model 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 was classified within Level 2 of the fair value hierarchy as the value was based on significant observable inputs.

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:

			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	$	—

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Long-term Debt

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Long-term Debt

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

	September 30, 2017			December 31, 2016
	(in thousands)
Tallgrass Equity revolving credit facility	$	146,000		$	148,000
TEP revolving credit facility	881,000			1,015,000
TEP 5.50% senior notes due September 15, 2024	750,000			400,000
TEP 5.50% senior notes due January 15, 2028	500,000			—
Less: Deferred financing costs, net (1)	(15,914		)	(7,019		)
Total long-term debt, net	$	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 facilities are presented in noncurrent assets on our condensed consolidated balance sheets.

TEP Senior Unsecured Notes

On September 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 "2024 Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). On May 16, 2017, the Issuers issued an additional $350 million in aggregate principal amount of the 2024 Notes which are also governed by the 2024 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 issue date, offering price and 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, 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, 2017 and December 31, 2016:

	September 30, 2017			December 31, 2016
	(in thousands)
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

In connection with the 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, 2017, Tallgrass Equity 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, 2017, the weighted average interest rate on outstanding borrowings under the Tallgrass Equity revolving credit facility was 3.74%. During the nine months ended September 30, 2017, Tallgrass Equity's weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 3.88%.

TEP Revolving Credit Facility

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 maturity date of TEP's existing revolving credit facility from May 13, 2018 to 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 addition, the revolving credit facility 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, 2017 and December 31, 2016:

	September 30, 2017			December 31, 2016
	(in thousands)
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

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 distributions from available cash, if a default or event of default under the credit agreement then exists or would result, 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 5.00 to 1.00 (which will be increased to 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, 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 0.250% to 0.500%, based on TEP's total leverage ratio. As of September 30, 2017, the weighted average interest rate on outstanding borrowings under the TEP revolving credit facility was 3.24%. During the nine months ended September 30, 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 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, 2017 and December 31, 2016, but for which fair value is disclosed:

	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
	(in thousands)
As of September 30, 2017:
Revolving credit facilities	$	—	$	1,027,000	$	—	$	1,027,000	$	1,027,000
2024 Notes	$	—	$	772,028	$	—	$	772,028	$	739,444
2028 Notes	$	—	$	508,660	$	—	$	508,660	$	494,642
As of December 31, 2016:
Revolving credit facilities	$	—	$	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, 2017 and December 31, 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, 2017.

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Partnership Equity and Distributions

9 Months Ended

Sep. 30, 2017

Equity [Abstract]

Partnership Equity and Distributions

TEGP Distributions to Holders of Class A Shares

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
		(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	12,528		0.2625
June 30, 2016	August 12, 2016	11,693		0.2450
March 31, 2016	May 13, 2016	10,022		0.2100

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

Subsidiary Distributions

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

		Distributions
		Limited Partner Common Units		General Partner						Distributions per Limited Partner Common Unit
Three Months Ended	Date Paid			Incentive Distribution Rights		General Partner Units		Total
		(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	57,332		26,987		976		85,295		0.7950
June 30, 2016	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

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

As of September 30, 2017, TEP had active equity distribution 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 $100.2 million and $657.5 million. Net cash proceeds from any sale of the TEP common units may be used for general partnership purposes, which 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.

TEP did not issue common units under the equity distribution agreements during the three months ended September 30, 2017. During the nine months ended September 30, 2017, TEP issued and sold 2,341,061 common units with a weighted average sales price of $48.82 per unit under its equity distribution agreements for net cash proceeds of approximately $112.4 million (net of approximately $1.9 million in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes as described above.

Noncontrolling Interests

As of September 30, 2017, noncontrolling interests in our subsidiaries consisted of a 63.06% interest in Tallgrass Equity held by the Exchange Right Holders, as defined in Note 13 – Net Income per Class A Share, the 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, 2017, we recognized contributions from and distributions to noncontrolling interests of $1.1 million and $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 $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.

During the nine months ended September 30, 2016, we received contributions from and made distributions to noncontrolling interests of $8.7 million and $177.4 million, respectively. Contributions from noncontrolling interests primarily consisted of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $103.7 million, Tallgrass Equity distributions to Exchange Right Holders of $68.7 million and distributions to Pony Express 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 15 – Legal and Environmental Matters.

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Net Income per Class A Share Net Income per Class A Share

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

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 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 net income per Class A share for the three and nine months ended September 30, 2017 and 2016:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands, except per share data)
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	58,075		47,725		58,075		47,725
Basic net income per Class A share	$	0.27	$	0.15	$	0.63	$	0.38
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	64		3		132		3
Net income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares	$	15,930	$	7,044	$	36,780	$	18,081
Basic weighted average Class A Shares outstanding	58,075		47,725		58,075		47,725
Equity Participation Shares equivalent shares	117		50		118		15
Diluted weighted average Class A Shares outstanding	58,192		47,775		58,193		47,740
Diluted net income per Class A Share	$	0.27	$	0.15	$	0.63	$	0.38

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Regulatory Matters

9 Months Ended

Sep. 30, 2017

Regulatory Matters [Abstract]

Regulatory Matters

There are no regulatory proceedings challenging the rates of Pony Express, Rockies Express, Tallgrass Interstate Gas Transmission, LLC ("TIGT") or Trailblazer Pipeline Company LLC ("Trailblazer"). We have made certain regulatory filings with the FERC, including the following:

Pony Express

On May 22, 2017 and May 31, 2017, Pony Express made tariff filings with the FERC in Docket Nos. IS17-263-000, IS17-464-00, and IS17-465-000 to increase the contract and non-contract rates by an amount reflecting the most recent FERC annual index adjustment of approximately 0.2%, which became effective July 1, 2017.

Rockies Express

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 facilities increased the Rockies Express Zone 3 east-to-west mainline capacity by 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.

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Legal and Environmental Matters

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

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, have recorded no reserve for legal claims as of September 30, 2017 or December 31, 2016.

Rockies Express

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, seeking approximately $303 million in damages and other relief. 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, which operated as a stay of the Harris County state court proceeding.

On January 12, 2017, Rockies Express and Ultra entered into an agreement to 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 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 sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due.

On February 2, 2017, Rockies Express and Michels agreed to resolve Michels' claims for a $10 million cash payment by Rockies Express. The cash payment was inclusive of approximately $5.9 million that Rockies Express had been withholding from Michels. Subsequently, Rockies Express and Michels entered into a definitive agreement with respect to the settlement and Rockies Express made the $10 million cash payment to 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 $7.7 million and $4.0 million at September 30, 2017 and December 31, 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

Trailblazer 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 conducted in 2014, Trailblazer 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 MAOP of 1,000 pounds per square inch across all segments of the Trailblazer Pipeline. Such repair or replacement will likely occur over a period of years, depending upon the remediation and repair plan implemented by Trailblazer. Segments of the Trailblazer 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 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 us.

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. Trailblazer completed additional excavation digs and replaced approximately 8 miles of pipe at an aggregate cost of approximately $19.0 million during 2016, and intends to complete the pipe replacement project in 2017 at an estimated cost of $2.5 million. Trailblazer is currently exploring all possible cost recovery options to recover such out of pocket costs, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.

In connection with our acquisition of the Trailblazer Pipeline, TD agreed to contractually indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions were necessitated by external corrosion caused by the pipeline's disbonded Hi-Melt CTE coating. The contractual indemnity provided by TD was capped at $20 million and was subject to a $1.5 million deductible. 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, 2017.

Terminals

System Failures

In January 2017, approximately 10,000 bbls of 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 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.

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Reporting Segments

9 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Reporting 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 reportable segments: (1) Natural Gas Transportation, (2) Crude Oil Transportation, and (3) Gathering, Processing & Terminalling.

Natural Gas Transportation

The Natural Gas Transportation segment is engaged in the ownership and 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

The Crude Oil Transportation 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.

Gathering, Processing & Terminalling

The Gathering, Processing & 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 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, 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, 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

	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

	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

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

These condensed consolidated financial statements and related notes for the three and nine months ended September 30, 2017 and 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, 2017 and 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, 2017 are not necessarily indicative of the results that may be expected for the full year ending December 31, 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, 2016 ("2016 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 15, 2017.

Consolidation

The condensed consolidated financial statements include the accounts of TEGP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEGP is attributed to TEGP and 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. TEP is also considered to be a 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.

Use of Estimates

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

Accounting Pronouncement Recently Adopted

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

In January 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. ASU 2017-01 clarifies the definition of a business with 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 screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. The ASU also narrows the definition of the term "output" so that the term is consistent with how outputs are described under the revenue recognition guidance in Topic 606.

The amendments in ASU 2017-01 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2017. Early adoption is permitted in certain circumstances. We elected to adopt the guidance in ASU 2017-01 effective April 1, 2017.

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

In January 2017, the FASB issued ASU No. 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 reporting unit's assets and liabilities. Instead, under the 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 goodwill allocated to that reporting unit.

The amendments in ASU 2017-04 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We elected to adopt the 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 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 adopted the 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 did not have a material impact on our consolidated financial statements.

Accounting Pronouncements Not Yet Adopted

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of 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 (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 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the 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 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 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.

We are currently evaluating 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 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 statements for periods prior to January 1, 2018 would not be revised.

ASU No. 2016-02, "Leases (Topic 842)"

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the 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 ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. We are currently evaluating the impact of ASU 2016-02.

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Acquisitions Equity Method Investments (Policies)

9 Months Ended

Sep. 30, 2017

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments, Policy

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 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.

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Goodwill (Policies)

9 Months Ended

Sep. 30, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets, Goodwill, Policy

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 quantitative impairment test 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, then goodwill is not considered impaired. When goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the reporting unit's fair value, then the reporting unit 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 goodwill allocated to that reporting unit.

We did not elect to apply the qualitative assessment option during our 2017 annual goodwill impairment testing; instead we proceeded directly to the quantitative impairment test. 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 quantitative impairment test indicated no 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, we did not record a goodwill impairment during the 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.

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Acquisitions Business Combinations (Tables)

9 Months Ended

Sep. 30, 2017

Business Acquisition [Line Items]

Business Acquisition, Pro Forma Information

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands)
Revenue	$	177,022	$	158,642	$	492,625	$	465,232
Net income attributable to partners	$	6,083	$	10,787	$	25,951	$	21,896

Equity Method Investments

The basis difference associated with the recently acquired 24.99% membership interest in 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	)

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

Impact of Adjustments Related to Transaction Among Entities Under Common Control, Balance Sheet

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

Impact of Adjustments Related to Transaction Among Entities Under Common Control, Income Statement

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.

Deeprock Development, LLC

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

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

Tallgrass Crude Gathering, LLC

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following represents the fair value of assets acquired and liabilities assumed at August 3, 2017 (in thousands):

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.

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Schedule of Transactions with Affiliated Companies

Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows:

	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 and TEP, include directly charged wages and salaries, other compensation and benefits, and shared services.

Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets

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, 2017		December 31, 2016
	(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	1,052	$	590
Total receivable from related parties	$	1,052	$	590
Accounts payable to related parties:
Tallgrass Operations, LLC	$	5,955	$	5,811
Deeprock Development, LLC	—		13
Total accounts payable to related parties	$	5,955	$	5,824

Schedule of Balances of Gas Imbalance with Affiliated Shippers

Gas imbalances with affiliated shippers are as follows:

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

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Inventory (Tables)

9 Months Ended

Sep. 30, 2017

Inventory Disclosure [Abstract]

Schedule of Components of Inventory

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

	September 30, 2017		December 31, 2016
	(in thousands)
Crude oil	$	2,115	$	5,462
Materials and supplies	5,993		6,383
Natural gas liquids	543		265
Gas in underground storage	1,522		983
Total inventory	$	10,173	$	13,093

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2017

Property, Plant and Equipment [Abstract]

Components of Property Plant and Equipment

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

	September 30, 2017			December 31, 2016
	(in thousands)
Crude oil pipelines	$	1,219,913		$	1,202,125
Gathering, processing and terminalling assets (1)	667,379			397,701
Natural gas pipelines	577,343			572,150
General and other	98,860			82,510
Construction work in progress	45,223			20,606
Accumulated depreciation and amortization	(257,888		)	(195,860		)
Total property, plant and equipment, net	$	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.

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Investments in Unconsolidated Affiliates (Tables)

9 Months Ended

Sep. 30, 2017

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

The basis difference associated with the recently acquired 24.99% membership interest in 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	)

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

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Goodwill (Tables)

9 Months Ended

Sep. 30, 2017

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of 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.

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Risk Management (Tables)

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of 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, 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 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. As of February 1, 2017, no common units remained subject to the 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 represents the sale of 125,000 barrels of crude oil which settled throughout 2017.

Derivative Contracts Included in Consolidated 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 30,2017 and 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
		(in thousands)
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	)	$	1,885	$	5,588

Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification

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:

			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	$	—

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Long-term Debt (Tables)

9 Months Ended

Sep. 30, 2017

Line of Credit Facility [Line Items]

Schedule of Debt

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

	September 30, 2017			December 31, 2016
	(in thousands)
Tallgrass Equity revolving credit facility	$	146,000		$	148,000
TEP revolving credit facility	881,000			1,015,000
TEP 5.50% senior notes due September 15, 2024	750,000			400,000
TEP 5.50% senior notes due January 15, 2028	500,000			—
Less: Deferred financing costs, net (1)	(15,914		)	(7,019		)
Total long-term debt, net	$	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 facilities are presented in noncurrent assets on our condensed consolidated balance sheets.

Carrying Amount and Fair value of Long-term Debt

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, 2017 and December 31, 2016, but for which fair value is disclosed:

	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
	(in thousands)
As of September 30, 2017:
Revolving credit facilities	$	—	$	1,027,000	$	—	$	1,027,000	$	1,027,000
2024 Notes	$	—	$	772,028	$	—	$	772,028	$	739,444
2028 Notes	$	—	$	508,660	$	—	$	508,660	$	494,642
As of December 31, 2016:
Revolving credit facilities	$	—	$	1,163,000	$	—	$	1,163,000	$	1,163,000
2024 Notes	$	—	$	398,000	$	—	$	398,000	$	392,981

Tallgrass Equity, LLC

Line of Credit Facility [Line Items]

Schedule of Line of Credit Facilities

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

	September 30, 2017			December 31, 2016
	(in thousands)
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

Tallgrass Energy Partners

Line of Credit Facility [Line Items]

Schedule of Line of Credit Facilities

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

	September 30, 2017			December 31, 2016
	(in thousands)
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

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Partnership Equity and Distributions Partnership and Equity and Distributions (Tables)

9 Months Ended

Sep. 30, 2017

Tallgrass Energy GP, LP

Summary of Distributions

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
		(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	12,528		0.2625
June 30, 2016	August 12, 2016	11,693		0.2450
March 31, 2016	May 13, 2016	10,022		0.2100

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

Tallgrass Energy Partners

Summary of Distributions

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

		Distributions
		Limited Partner Common Units		General Partner						Distributions per Limited Partner Common Unit
Three Months Ended	Date Paid			Incentive Distribution Rights		General Partner Units		Total
		(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	57,332		26,987		976		85,295		0.7950
June 30, 2016	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

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

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Net Income per Class A Share Net Income per Class A Share (Tables)

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

Summary of Net Income per Class A Share

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
	(in thousands, except per share data)
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	58,075		47,725		58,075		47,725
Basic net income per Class A share	$	0.27	$	0.15	$	0.63	$	0.38
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	64		3		132		3
Net income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares	$	15,930	$	7,044	$	36,780	$	18,081
Basic weighted average Class A Shares outstanding	58,075		47,725		58,075		47,725
Equity Participation Shares equivalent shares	117		50		118		15
Diluted weighted average Class A Shares outstanding	58,192		47,775		58,193		47,740
Diluted net income per Class A Share	$	0.27	$	0.15	$	0.63	$	0.38

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Reporting Segments (Tables)

9 Months Ended

Sep. 30, 2017

Segment Reporting [Abstract]

Summary of TEGP's Segment Information of Revenue

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

	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, 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

Summary of TEGP's Segment Information of Earnings

	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

	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

Summary of TEGP's Segment Capital Expenditures

	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

Summary of TEGP's Segment Information of Assets

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

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Description of Business - Additional Information (Detail) - shares	9 Months Ended
	Sep. 30, 2017	Jul. 21, 2017	Mar. 31, 2017	Jan. 01, 2017
Rockies Express Pipeline LLC
Organization [Line Items]
Equity Method Investment, Ownership Percentage	49.99%
Rockies Express Pipeline LLC | Tallgrass Development LP
Organization [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			24.99%
Tallgrass NatGas Operator, LLC
Organization [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				100.00%
Tallgrass Terminals, LLC
Organization [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				100.00%
Deeprock Development, LLC
Organization [Line Items]
Ownership Percentage in Subsidiary	69.00%
Business Acquisition, Percentage of Voting Interests Acquired		49.00%
Tallgrass Equity, LLC
Organization [Line Items]
Variable Interest Entity, Ownership Percentage	36.94%
Tallgrass MLP GP, LLC
Organization [Line Items]
Limited Liability Company (LLC) or General Partner, Ownership Interest	100.00%
Tallgrass Energy Partners
Organization [Line Items]
Limited Liability Company (LLC) or General Partner, Ownership Interest	1.13%
General partner units issued	834,391
Subsidiary Of Limited Liability Company Or Limited Partnership Ownership Interest Units	20,000,000
Ownership Percentage in Subsidiary	27.02%

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Variable Interest Entity VIE Assets and Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Deferred tax asset	$ 496,472	$ 521,454

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Acquisitions Outrigger Acquisition, Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Aug. 03, 2017	Sep. 30, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Property, plant and equipment, net		$ 2,350,830	$ 2,079,232
Intangible assets, net		$ 98,876	$ 93,522
Net identifiable assets acquired	$ 36,030
Finite-Lived Intangible Assets, Remaining Amortization Period	8 years
Tallgrass Crude Gathering, LLC
Business Acquisition [Line Items]
Accounts receivable	$ 117
Property, plant and equipment, net	29,306
Intangible assets, net	6,694
Accounts payable and accrued liabilities	$ 87

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Acquisitions DRD Acquisition, Assets Acquired & Liabilities Assumed (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Aug. 03, 2017	Jul. 20, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Property, plant and equipment, net	$ 2,350,830			$ 2,079,232
Net identifiable assets acquired		$ 36,030
Goodwill	$ 404,838			$ 343,288	$ 343,288	$ 343,288
Deeprock Development, LLC
Business Acquisition [Line Items]
Accounts receivable			$ 968
Other current assets			598
Property, plant and equipment, net			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

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Acquisitions Pro Forma Revenue & Net Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Business Combinations [Abstract]
Revenue	$ 177,022	$ 158,642	$ 492,625	$ 465,232
Net income attributable to partners	$ 6,083	$ 10,787	$ 25,951	$ 21,896

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Acquisitions Equity Method Investments (Details) - Rockies Express Pipeline LLC $ in Thousands	9 Months Ended
	Sep. 30, 2017 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ (380,589)
Basis Difference, Amortization Period	35 years
Long-term Debt
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 19,078
Property, Plant and Equipment
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ (399,667)
Basis Difference, Amortization Period	35 years
Minimum | Long-term Debt
Schedule of Equity Method Investments [Line Items]
Basis Difference, Amortization Period	2 years
Maximum | Long-term Debt
Schedule of Equity Method Investments [Line Items]
Basis Difference, Amortization Period	25 years

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Acquisitions Impact of Acquisition, Balance Sheet (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Cash and cash equivalents	$ 3,279	$ 2,459	$ 1,359	$ 2,234
Accounts receivable, net	95,629	59,536
Gas imbalances	1,020	1,597
Inventories	10,173	13,093
Derivative assets	0	10,967
Prepayments and other current assets	3,407	7,628
Total Current Assets	113,508	95,280
Property, plant and equipment, net	2,350,830	2,079,232
Goodwill	404,838	343,288	$ 343,288	$ 343,288
Intangible assets, net	98,876	93,522
Unconsolidated investments	922,280	475,625
Deferred tax asset	496,472	521,454
Deferred financing costs, net	13,326	6,042
Deferred charges and other assets	3,016	11,037
Total Assets	4,403,146	3,625,480
Accounts payable	69,620	24,449
Accounts payable to related parties	5,955	5,824
Gas imbalances	1,119	1,239
Derivative liabilities	473	556
Accrued taxes	22,890	16,996
Accrued liabilities	11,183	16,755
Deferred revenue	87,979	60,757
Other current liabilities	6,690	6,446
Total Current Liabilities	205,909	133,022
Long-term debt, net	2,261,086	1,555,981
Other long-term liabilities and deferred credits	18,396	7,063
Total Long-term Liabilities	2,279,482	1,563,044
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	1,917,755	1,929,414
Total Liabilities and Equity	$ 4,403,146	3,625,480
Tallgrass Energy GP, LP
Business Acquisition [Line Items]
Cash and cash equivalents		2,459
Accounts receivable, net		59,469
Gas imbalances		1,597
Inventories		12,805
Derivative assets		10,967
Prepayments and other current assets		6,820
Total Current Assets		94,117
Property, plant and equipment, net		2,012,263
Goodwill		343,288
Intangible assets, net		93,522
Unconsolidated investments		461,915
Deferred tax asset		521,454
Deferred financing costs, net		6,042
Deferred charges and other assets		9,637
Total Assets		3,542,238
Accounts payable		24,403
Accounts payable to related parties		5,768
Gas imbalances		1,239
Derivative liabilities		556
Accrued taxes		16,328
Accrued liabilities		16,578
Deferred revenue		60,757
Other current liabilities		6,446
Total Current Liabilities		132,075
Long-term debt, net		1,555,981
Other long-term liabilities and deferred credits		7,063
Total Long-term Liabilities		1,563,044
Partners' Capital, Including Portion Attributable to Noncontrolling Interest		1,847,119
Total Liabilities and Equity		3,542,238
Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Cash and cash equivalents		0
Accounts receivable, net		38
Gas imbalances		0
Inventories		288
Derivative assets		0
Prepayments and other current assets		808
Total Current Assets		1,134
Property, plant and equipment, net		66,969
Goodwill		0
Intangible assets, net		0
Unconsolidated investments		13,710
Deferred tax asset		0
Deferred financing costs, net		0
Deferred charges and other assets		1,400
Total Assets		83,213
Accounts payable		46
Accounts payable to related parties		56
Gas imbalances		0
Derivative liabilities		0
Accrued taxes		668
Accrued liabilities		177
Deferred revenue		0
Other current liabilities		0
Total Current Liabilities		947
Long-term debt, net		0
Other long-term liabilities and deferred credits		0
Total Long-term Liabilities		0
Partners' Capital, Including Portion Attributable to Noncontrolling Interest		82,266
Total Liabilities and Equity		83,213
Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Cash and cash equivalents		0
Accounts receivable, net		29
Gas imbalances		0
Inventories		0
Derivative assets		0
Prepayments and other current assets		0
Total Current Assets		29
Property, plant and equipment, net		0
Goodwill		0
Intangible assets, net		0
Unconsolidated investments		0
Deferred tax asset		0
Deferred financing costs, net		0
Deferred charges and other assets		0
Total Assets		29
Accounts payable		0
Accounts payable to related parties		0
Gas imbalances		0
Derivative liabilities		0
Accrued taxes		0
Accrued liabilities		0
Deferred revenue		0
Other current liabilities		0
Total Current Liabilities		0
Long-term debt, net		0
Other long-term liabilities and deferred credits		0
Total Long-term Liabilities		0
Partners' Capital, Including Portion Attributable to Noncontrolling Interest		29
Total Liabilities and Equity		$ 29

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Acquisitions Impact of Acquisition, Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Business Acquisition [Line Items]
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
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	0	0	0	8,061
(Gain) loss on disposal of assets	0	0	(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
Interest expense, net	(24,408)	(12,157)	(61,539)	(31,275)
Unrealized (loss) gain on derivative instrument	0	(4,419)	1,885	5,588
Equity in earnings of unconsolidated investments	123,642	12,764	187,121	37,495
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		(3,209)		(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 (Loss) Attributable to Parent	$ 15,866	10,652	$ 36,648	21,486
Consolidation, Eliminations
Business Acquisition [Line Items]
Crude oil transportation services		0		0
Natural gas transportation services		0		0
Sales of natural gas, NGLs, and crude oil		(271)		(271)
Processing and other revenues		(2,884)		(8,576)
Total Revenues		(3,155)		(8,847)
Cost of sales (exclusive of depreciation and amortization shown below)		(271)		(271)
Cost of transportation services (exclusive of depreciation and amortization shown below)		(2,884)		(8,576)
Operations and maintenance		0		0
Depreciation and amortization		0		0
General and administrative		0		0
Taxes, other than income taxes		0		0
Contract termination				0
(Gain) loss on disposal of assets				0
Total Operating Costs and Expenses		(3,155)		(8,847)
Operating Income		0		0
Interest expense, net		0		0
Unrealized (loss) gain on derivative instrument		0		0
Equity in earnings of unconsolidated investments		0		0
Other income, net		0		0
Total Other Income (Expense)		0		0
Net income before tax		0		0
Deferred income tax expense		0		0
Net income		0		0
Net income attributable to noncontrolling interests		0		0
Net Income (Loss) Attributable to Parent		0		0
Tallgrass Energy GP, LP
Business Acquisition [Line Items]
Crude oil transportation services		91,387		279,281
Natural gas transportation services		31,444		89,406
Sales of natural gas, NGLs, and crude oil		20,758		51,514
Processing and other revenues		8,536		24,260
Total Revenues		152,125		444,461
Cost of sales (exclusive of depreciation and amortization shown below)		18,590		48,116
Cost of transportation services (exclusive of depreciation and amortization shown below)		13,528		43,924
Operations and maintenance		14,714		41,055
Depreciation and amortization		20,831		64,099
General and administrative		13,715		41,710
Taxes, other than income taxes		6,717		19,862
Contract termination				0
(Gain) loss on disposal of assets				1,849
Total Operating Costs and Expenses		88,095		260,615
Operating Income		64,030		183,846
Interest expense, net		(12,157)		(31,275)
Unrealized (loss) gain on derivative instrument		(4,419)		5,588
Equity in earnings of unconsolidated investments		12,066		35,387
Other income, net		480		1,267
Total Other Income (Expense)		(4,030)		10,967
Net income before tax		60,000		194,813
Deferred income tax expense		(3,209)		(12,792)
Net income		56,791		182,021
Net income attributable to noncontrolling interests		(49,750)		(163,943)
Net Income (Loss) Attributable to Parent		7,041		18,078
Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Crude oil transportation services		0		0
Natural gas transportation services		0		0
Sales of natural gas, NGLs, and crude oil		0		0
Processing and other revenues		3,116		8,982
Total Revenues		3,116		8,982
Cost of sales (exclusive of depreciation and amortization shown below)		0		0
Cost of transportation services (exclusive of depreciation and amortization shown below)		198		598
Operations and maintenance		432		1,319
Depreciation and amortization		346		975
General and administrative		266		1,153
Taxes, other than income taxes		143		431
Contract termination				8,061
(Gain) loss on disposal of assets				0
Total Operating Costs and Expenses		1,385		12,537
Operating Income		1,731		(3,555)
Interest expense, net		0		0
Unrealized (loss) gain on derivative instrument		0		0
Equity in earnings of unconsolidated investments		698		2,108
Other income, net		0		0
Total Other Income (Expense)		698		2,108
Net income before tax		2,429		(1,447)
Deferred income tax expense		0		0
Net income		2,429		(1,447)
Net income attributable to noncontrolling interests		0		0
Net Income (Loss) Attributable to Parent		2,429		(1,447)
Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Crude oil transportation services		0		0
Natural gas transportation services		0		0
Sales of natural gas, NGLs, and crude oil		0		0
Processing and other revenues		1,182		4,855
Total Revenues		1,182		4,855
Cost of sales (exclusive of depreciation and amortization shown below)		0		0
Cost of transportation services (exclusive of depreciation and amortization shown below)		0		0
Operations and maintenance		0		0
Depreciation and amortization		0		0
General and administrative		0		0
Taxes, other than income taxes		0		0
Contract termination				0
(Gain) loss on disposal of assets				0
Total Operating Costs and Expenses		0		0
Operating Income		1,182		4,855
Interest expense, net		0		0
Unrealized (loss) gain on derivative instrument		0		0
Equity in earnings of unconsolidated investments		0		0
Other income, net		0		0
Total Other Income (Expense)		0		0
Net income before tax		1,182		4,855
Deferred income tax expense		0		0
Net income		1,182		4,855
Net income attributable to noncontrolling interests		0		0
Net Income (Loss) Attributable to Parent		$ 1,182		$ 4,855

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Acquisitions Additional Information (Details) $ in Thousands							2 Months Ended		3 Months Ended		9 Months Ended
	Aug. 03, 2017 USD ($) a mi	Jul. 21, 2017 USD ($) shares	Jul. 20, 2017 USD ($)	Jun. 05, 2017 USD ($) mi	Mar. 31, 2017 USD ($)	Jan. 01, 2017 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Jul. 19, 2017	Dec. 31, 2016 USD ($)	May 06, 2016	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Gain on remeasurement of unconsolidated investment									$ 9,728	$ 0	$ 9,728	$ 0
Goodwill							$ 404,838	$ 404,838	$ 404,838	$ 343,288	404,838	343,288		$ 343,288		$ 343,288
Acquisition of Douglas Gathering System											128,526	0
Payments to Acquire Interest in Subsidiaries and Affiliates											$ 400,000	436,022
Tallgrass Energy Partners
Business Acquisition [Line Items]
Equity interest held by noncontrolling interests							72.67%	72.67%	72.67%		72.67%
Ownership Percentage in Subsidiary											27.02%
Tallgrass Crude Gathering, LLC
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual							$ 1,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual							$ 1,000
Deeprock Development, LLC
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual								$ 2,400
Equity interest held by noncontrolling interests							31.00%	31.00%	31.00%		31.00%
Goodwill			$ 61,550
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual								$ 1,100
Tallgrass Midstream Gathering LLC
Business Acquisition [Line Items]
Miles of gathering pipeline | mi				1,500
Tallgrass Midstream Gathering LLC | Tallgrass Energy Partners
Business Acquisition [Line Items]
Acquisition of Douglas Gathering System				$ 128,500
Tallgrass Crude Gathering, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	100.00%
Miles of gathering pipeline | mi	34
Acres for Crude Oil gathering system | a	150,000
Payments to Acquire Businesses, Gross											$ 36,030	0
Tallgrass Crude Gathering, LLC | Tallgrass Energy Partners
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 36,000
Rockies Express Pipeline LLC | Tallgrass Energy Partners
Business Acquisition [Line Items]
Payments to Acquire Interest in Subsidiaries and Affiliates					$ 400,000
Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired						100.00%
Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired						100.00%
Terminals and NatGas
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross											140,000	0
Terminals and NatGas | Tallgrass Energy Partners
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross						$ 140,000
Deeprock Development, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		49.00%
Acquisition of Deeprock Development											$ 57,202	$ 0
Fair Value of Previously Held Equity Interest			22,900
Gain on remeasurement of unconsolidated investment			$ 9,700
Equity interest held by noncontrolling interests			40.00%
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value			$ 45,900
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares		128,790
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned		$ 6,700
Ownership Percentage in Subsidiary											69.00%
Deeprock Development, LLC | Tallgrass Energy Partners
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		6,400
Acquisition of Deeprock Development			$ 57,200
Business Combination, Consideration Transferred		$ 13,100
Kinder Morgan Cushing, LLC | Deeprock Development, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			40.00%
Deeprock Energy Resources, LLC | Deeprock Development, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		9.00%
DCP Assets Holding, LP | Tallgrass Midstream Gathering LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				100.00%
Tallgrass Development LP | Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					24.99%
Sempra U.S. Gas and Power | Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired															25.00%
Deeprock Development, LLC
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage													20.00%
Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage							49.99%	49.99%	49.99%		49.99%
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity							$ (380,589)	$ (380,589)	$ (380,589)		$ (380,589)
Basis Difference, Amortization Period											35 years
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service											2.86%
Rockies Express Pipeline LLC | Tallgrass Energy Partners
Business Acquisition [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity					$ 386,800

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Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Related Party Transaction [Line Items]
Revenue from related parties	$ 3,338	$ 1,182	$ 6,662	$ 4,855
Cost of transportation services from related parties	1,062	4,630	10,476	13,888
Operations and maintenance
Related Party Transaction [Line Items]
Expenses related to transactions with related companies	7,973	6,560	21,680	19,117
General and administrative expense
Related Party Transaction [Line Items]
Expenses related to transactions with related companies	11,960	10,423	32,628	30,066
Property, Plant and Equipment
Related Party Transaction [Line Items]
Costs capitalized from transactions with related parties	$ 765	$ 688	$ 1,568	$ 2,255

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Related Party Transactions - Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Receivable from related parties	$ 1,052	$ 590
Accounts payable to related parties	5,955	5,824
Rockies Express Pipeline LLC
Related Party Transaction [Line Items]
Receivable from related parties	1,052	590
Tallgrass Operations, LLC
Related Party Transaction [Line Items]
Accounts payable to related parties	5,955	5,811
Deeprock Development, LLC
Related Party Transaction [Line Items]
Accounts payable to related parties	$ 0	$ 13

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Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Affiliate gas imbalance receivables	$ 17	$ 177
Affiliate gas imbalance payables	$ 43	$ 0

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Related Party Transactions - Additional Information (Detail)	3 Months Ended
	Sep. 30, 2017 USD ($)
Public Company Expense | Tallgrass Development LP
Related Party Transaction [Line Items]
Public company cost reimbursement	$ 500,000

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Inventory Inventory (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Crude oil	$ 2,115	$ 5,462
Materials and supplies	5,993	6,383
Natural gas liquids	543	265
Gas in underground storage	1,522	983
Inventory, Net	$ 10,173	$ 13,093

XML

Property Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Jul. 21, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Accumulated depreciation and amortization	$ (257,888)		$ (195,860)
Property, plant and equipment	2,350,830		2,079,232
Crude oil pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,219,913		1,202,125
Gathering, Processing & Terminalling Assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	667,379		397,701
Natural gas pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	577,343		572,150
General and other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	98,860		82,510
Construction work in progress
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	45,223		$ 20,606
Tallgrass Midstream Gathering LLC | Gathering, Processing & Terminalling Assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	138,200
Deeprock Development, LLC
Property, Plant and Equipment [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		49.00%
Deeprock Development, LLC | Gathering, Processing & Terminalling Assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	68,400
Outrigger Energy, LLC | Gathering, Processing & Terminalling Assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 29,300

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Investments in Unconsolidated Affiliates Equity Method Investments (Details) - Rockies Express Pipeline LLC - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Revenue	$ 216,756	$ 159,421	$ 625,243	$ 551,323
Equity Method Investment Summarized Financial Information Operating Income	123,965	66,436	344,037	267,847
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	$ 233,990	$ 34,184	$ 371,185	$ 226,847

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Investments in Unconsolidated Affiliates Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Jul. 21, 2017	Jul. 20, 2017	Mar. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated investments	$ 123,642	$ 12,764	$ 187,121	$ 37,495
Payments to Acquire Equity Method Investments			$ 31,570	$ 35,515
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	49.99%		49.99%
Equity in earnings of unconsolidated investments			$ 185,660
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries			227,500
Payments to Acquire Equity Method Investments			$ 29,500
Deeprock Development, LLC
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					49.00%
Deeprock Development, LLC | Kinder Morgan Cushing, LLC
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired						40.00%
Rockies Express Pipeline LLC | Tallgrass Development LP
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired							24.99%

XML

Goodwill (Details) - USD ($) $ in Thousands		3 Months Ended
	Jul. 20, 2017	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Goodwill		$ 404,838	$ 343,288	$ 343,288	$ 343,288
Goodwill, Acquired During Period		61,550	0
Natural Gas Transportation
Goodwill [Line Items]
Goodwill		255,558	255,558	255,558	255,558
Goodwill, Acquired During Period		0	0
Gathering, Processing & Terminalling
Goodwill [Line Items]
Goodwill		149,280	87,730	$ 87,730	$ 87,730
Goodwill, Acquired During Period		$ 61,550	$ 0
Deeprock Development, LLC
Goodwill [Line Items]
Goodwill, Acquired During Period	$ 61,600

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Risk Management - Schedule of Fair Value of Derivative Contracts (Detail) $ in Thousands	Jan. 01, 2016 shares	Sep. 30, 2017 USD ($) Bcf bbl	Dec. 31, 2016 USD ($) Bcf bbl
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative asset at fair value			$ 291
Derivative liability at fair value		$ 1	116
Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value			10,676
Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative liability at fair value		472	440
Other Current Assets | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		0	291
Other Current Assets | Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		0	10,676
Other Current Liabilities | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative liability at fair value		1	116
Other Current Liabilities | Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative liability at fair value		$ 472	$ 440
Commodity | Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		323,620	125,000
Pony Express Pipeline
Derivatives, Fair Value [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	31.30%
Pony Express Pipeline | Equity Option
Derivatives, Fair Value [Line Items]
Derivative, Term of Contract	18 months
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	6,518,000
Long | Commodity | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf		0.1	0.4
Short | Commodity | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf			0.3

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Risk Management - Derivative Contracts Included in Consolidated Statement of Income (Detail) - Derivatives not designated as hedging contracts - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Energy Related Derivative
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 175	$ 318	$ 1,065	$ 466
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	(22)	161	84	(190)
Equity Option
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 0	$ (4,419)	$ 1,885	$ 5,588

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Risk Management - Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative liability at fair value	$ 472	$ 440
Energy Related Derivative | Quoted prices in active markets for identical assets (Level 1)
Derivatives, Fair Value [Line Items]
Derivative liability at fair value	0	0
Energy Related Derivative | Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative liability at fair value	472	440
Energy Related Derivative | Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative liability at fair value	0	0
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		291
Derivative liability at fair value	1	116
Energy commodity derivative contracts | Quoted prices in active markets for identical assets (Level 1)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		0
Derivative liability at fair value	0	0
Energy commodity derivative contracts | Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		291
Derivative liability at fair value	1	116
Energy commodity derivative contracts | Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		0
Derivative liability at fair value	$ 0	0
Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		10,676
Equity Option | Quoted prices in active markets for identical assets (Level 1)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		0
Equity Option | Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		10,676
Equity Option | Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		$ 0

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Risk Management Risk Management - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands					9 Months Ended
	Feb. 01, 2017	Oct. 31, 2016	Jul. 21, 2016	Jan. 01, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased	736,262
Partial exercise of call option	$ 35,300				$ 35,335	$ 0
Margin Deposit Assets					800
Letters of Credit Outstanding, Amount					3,000
Pony Express Pipeline
Derivative [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				31.30%
Equity Option
Derivative [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased	1,703,094	1,251,760	3,563,146
Partial exercise of call option	$ 72,400	$ 53,200	$ 151,400		$ 72,381	$ 151,434
Equity Option | Pony Express Pipeline
Derivative [Line Items]
Derivative, Term of Contract				18 months
Option Indexed to Issuer's Equity, Strike Price				$ 42.50
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares				6,518,000

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Long-term Debt Schedule of Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Total long-term debt, net	$ 2,261,086	$ 1,555,981
Revolving Credit Facility
Debt Instrument [Line Items]
Total long-term debt, net	1,027,000	1,163,000
Tallgrass Equity, LLC | Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Debt, Gross	146,000	148,000
Total long-term debt, net	146,000	148,000
Tallgrass Energy Partners
Debt Instrument [Line Items]
Less: Deferred financing costs, net	(15,914)	(7,019)
Tallgrass Energy Partners | Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Debt, Gross	881,000	1,015,000
Total long-term debt, net	881,000	1,015,000
2024 Senior Notes
Debt Instrument [Line Items]
Total long-term debt, net	739,444	392,981
2024 Senior Notes | Tallgrass Energy Partners | Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Gross	750,000	400,000
2028 Senior Notes
Debt Instrument [Line Items]
Total long-term debt, net	494,642
2028 Senior Notes | Tallgrass Energy Partners | Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 500,000	$ 0

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Long-term Debt Capacity under Revolving Credit Facility - Tallgrass Equity (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Long-term Debt	$ (2,261,086)	$ (1,555,981)
Letters of Credit Outstanding, Amount	(3,000)
Revolving Credit Facility
Line of Credit Facility [Line Items]
Long-term Debt	(1,027,000)	(1,163,000)
Tallgrass Equity, LLC | Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	150,000	150,000
Long-term Debt	(146,000)	(148,000)
Line of Credit Facility, Remaining Borrowing Capacity	4,000	2,000
Tallgrass Energy Partners | Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,750,000	1,750,000
Long-term Debt	(881,000)	(1,015,000)
Letters of Credit Outstanding, Amount	(3,094)	0
Line of Credit Facility, Remaining Borrowing Capacity	$ 865,906	$ 735,000

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Long-term Debt - Carrying Amount and Fair Value of Long-term Debt (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt	$ 2,261,086	$ 1,555,981
2024 Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Fair Value	772,028	398,000
Long-term Debt	739,444	392,981
2024 Senior Notes | Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Long-term Debt, Fair Value	0	0
2024 Senior Notes | Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Long-term Debt, Fair Value	772,028	398,000
2024 Senior Notes | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Long-term Debt, Fair Value	0	0
2028 Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Fair Value	508,660
Long-term Debt	494,642
2028 Senior Notes | Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Long-term Debt, Fair Value	0
2028 Senior Notes | Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Long-term Debt, Fair Value	508,660
2028 Senior Notes | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Long-term Debt, Fair Value	0
Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Debt, Fair Value	1,027,000	1,163,000
Long-term Debt	1,027,000	1,163,000
Revolving Credit Facility | Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Long-term Debt, Fair Value	0	0
Revolving Credit Facility | Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Long-term Debt, Fair Value	1,027,000	1,163,000
Revolving Credit Facility | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Long-term Debt, Fair Value	$ 0	$ 0

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Long-term Debt - Additional Information (Detail)				9 Months Ended
	Sep. 15, 2017 USD ($)	May 16, 2017 USD ($)	Sep. 01, 2016 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Jun. 02, 2017 USD ($)	Dec. 31, 2016 USD ($)	May 12, 2015 USD ($)
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt				$ 850,000,000	$ 400,000,000
Tallgrass Energy Partners
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.24%
Debt Instrument, Interest Rate, Effective Percentage				3.25%
Line of Credit Facility, Maximum Potential Accordion Feature						$ 250,000,000
Sublimit for Swing Line Loans						60,000,000
Sublimit for Letters of Credit						75,000,000
Tallgrass Energy Partners | Revolving Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 1,750,000,000			$ 1,750,000,000
Tallgrass Energy Partners | Revolving Credit Facility | Wells Fargo Bank, National Association
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity						$ 1,750,000,000
Tallgrass Energy Partners | Maximum | Revolving Credit Facility | Wells Fargo Bank, National Association
Debt Instrument [Line Items]
Consolidated leverage ratio				5.0
Credit facility commitment fee				0.50%
Contingent Consolidated Leverage Ratio				5.50
Consolidated Senior Secured Leverage Ratio One				3.75
Tallgrass Energy Partners | Minimum | Revolving Credit Facility | Wells Fargo Bank, National Association
Debt Instrument [Line Items]
Credit facility commitment fee				0.25%
Consolidated Interest Coverage Ratio One				2.50
Tallgrass Equity, LLC
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate				3.74%
Debt Instrument, Interest Rate, Effective Percentage				3.88%
Tallgrass Equity, LLC | Revolving Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 150,000,000			$ 150,000,000
Tallgrass Equity, LLC | Revolving Credit Facility | Barclays Bank
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity								$ 150,000,000
Credit facility commitment fee				0.50%
Tallgrass Equity, LLC | Maximum | Revolving Credit Facility | Barclays Bank
Debt Instrument [Line Items]
Consolidated leverage ratio				3.00
2028 Senior Notes | Senior Notes | Tallgrass Energy Partners
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt	$ 500,000,000
Debt Instrument, Interest Rate, Stated Percentage				5.50%
2024 Senior Notes | Senior Notes | Tallgrass Energy Partners
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt		$ 350,000,000	$ 400,000,000
Debt Instrument, Interest Rate, Stated Percentage				5.50%

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Partnership Equity and Distributions Partnership and Equity Distributions - TEGP Summary of Distributions (Details) - Tallgrass Energy GP, LP - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016
Distribution Made to Limited Partner [Line Items]
Partners' Capital Account, Distributions	$ 20,617	$ 19,891	$ 16,697	$ 16,116	$ 12,528	$ 11,693	$ 10,022
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.3550	$ 0.3425	$ 0.2875	$ 0.2775	$ 0.2625	$ 0.2450	$ 0.2100

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Partnership Equity and Distributions Partnership Equity and Distributions - TEP Summary of Distributions (Details) - Tallgrass Energy Partners - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016
Distribution Made to Limited Partner [Line Items]
Limited Partner Common Units	$ 69,174	$ 67,671	$ 60,486	$ 58,793	$ 57,332	$ 54,442	$ 48,238
Incentive Distribution Rights	37,744	36,342	29,840	28,358	26,987	24,262	19,816
General Partner Units	1,219	1,186	1,040	1,008	976	911	830
Partners' Capital Account, Distributions	$ 108,137	$ 105,199	$ 91,366	$ 88,159	$ 85,295	$ 79,615	$ 68,884
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.9450	$ 0.9250	$ 0.8350	$ 0.8150	$ 0.7950	$ 0.7550	$ 0.7050

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Partnership Equity and Distributions - Additional Information (Detail) - USD ($)					3 Months Ended							9 Months Ended
	Feb. 01, 2017	Oct. 31, 2016	Jul. 21, 2016	Jan. 01, 2016	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2017	Sep. 30, 2016	May 17, 2016	May 13, 2015
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased	736,262
Payments for Repurchase of Common Stock	$ (35,300,000)											$ (35,335,000)	$ 0
Treasury Stock Acquired, Average Cost Per Share	$ 47.99
Partners' Capital Account, Authorized Amount														$ 657,500,000	$ 100,200,000
Partners' Capital Account, Units, Sold in Public Offering												2,341,061
SharesIssuedPricePerShareQTD												$ 48.82
Issuance of TEP units to the public, net of offering costs												$ 112,400,000
LimitedPartnerOfferingCosts												1,900,000
Distributions to noncontrolling interests												$ 229,710,000	177,449,000
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests					2.00%							2.00%
Distributions to noncontrolling interests												$ 0	425,882,000
Tallgrass Energy Partners
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests					72.67%							72.67%
Partners' Capital Account, Distributions					$ (108,137,000)	$ (105,199,000)	$ (91,366,000)	$ (88,159,000)	$ (85,295,000)	$ (79,615,000)	$ (68,884,000)
Tallgrass Equity, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests					63.06%							63.06%
Deeprock Development, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests					31.00%							31.00%
Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Payments for Repurchase of Common Stock												$ 31,717,000
Contributions from noncontrolling interest												1,100,000	8,700,000
Distributions to noncontrolling interests												(229,700,000)	177,400,000
Tallgrass Equity distributions to noncontrolling interests												90,000,000	68,700,000
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders												4,300,000.0	5,000,000.0
Contributions from TD												1,451,000	3,697,000
Noncontrolling Interest | Tallgrass Energy Partners
Limited Partners' Capital Account [Line Items]
Issuance of TEP units to the public, net of offering costs												101,043,000	265,931,000
Partners' Capital Account, Distributions												135,400,000	103,700,000
Total Partner Equity Including Portion Attributable to Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Payments for Repurchase of Common Stock												35,335,000
Contributions from noncontrolling interest												1,093,000	8,700,000
Distributions to noncontrolling interests												229,710,000	177,449,000
Contributions from TD												2,301,000	5,308,000
Total Partner Equity Including Portion Attributable to Noncontrolling Interest | Tallgrass Energy Partners
Limited Partners' Capital Account [Line Items]
Issuance of TEP units to the public, net of offering costs												112,393,000	290,474,000
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				31.30%
Equity Option
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased	1,703,094	1,251,760	3,563,146
Payments for Repurchase of Common Stock	$ (72,400,000)	$ (53,200,000)	$ (151,400,000)									$ (72,381,000)	$ (151,434,000)
Equity Option | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares				6,518,000

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Net Income per Class A Share Net Income per Class A Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share [Abstract]
Net income attributable to TEGP, excluding predecessor operations interest	$ 15,866	$ 7,041	$ 36,648	$ 18,078
Basic average number of Class A shares outstanding	58,075	47,725	58,075	47,725
Basic net income per Class A share	$ 0.27	$ 0.15	$ 0.63	$ 0.38
Incremental net income attributable to TEGP including the effect of the assumed issuance of Equity Participation Shares	$ 64	$ 3	$ 132	$ 3
Net income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares	$ 15,930	$ 7,044	$ 36,780	$ 18,081
Equity Participation Shares equivalent shares	117	50	118	15
Diluted weighted average Class A Shares outstanding	58,192	47,775	58,193	47,740
Diluted net income per Class A Share	$ 0.27	$ 0.15	$ 0.63	$ 0.38

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Regulatory Matters Regulatory Matters (Details) - MMBTU / d MMBTU / d in Thousands	Jan. 06, 2017	Jul. 01, 2017
Public Utilities, General Disclosures [Line Items]
Capacity Enhancement	0
Pony Express Pipeline
Public Utilities, General Disclosures [Line Items]
FERC Annual Index Adjustment		0.20%

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Legal and Environmental Matters - Additional Information (Detail)						1 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended			15 Months Ended	24 Months Ended
	Jul. 12, 2017 USD ($)	Feb. 16, 2017 USD ($)	Feb. 02, 2017 USD ($)	Jan. 12, 2017 USD ($) Bcf / d	Jun. 17, 2014 USD ($)	Jan. 31, 2017 bbl	Jun. 30, 2017 USD ($)	Sep. 30, 2017 USD ($) ft-lb	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) Bcf / d mi	Dec. 31, 2015 USD ($) mi	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Apr. 14, 2016 USD ($)
Loss Contingencies [Line Items]
Environmental accruals								$ 7,700,000		$ 4,000,000			$ 4,000,000
Aggregate cost of crack tool runs								$ 9,000,000					$ 9,800,000
Crude Oil Spilled or Leaked | bbl						10,000
Crude oil recovered | bbl						9,000
Total Remediation costs							$ 600,000
General Partner
Loss Contingencies [Line Items]
Contributions from TD												$ 20,000,000
Trailblazer
Loss Contingencies [Line Items]
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi										8
Maximum Allowable Operating Pressure | ft-lb								144,000
Excavation Digs											32
Aggregate Cost of Excavation Digs											$ 1,300,000
Estimated pipeline replacement costs										$ 19,000,000
Trailblazer | Subsequent Event
Loss Contingencies [Line Items]
Estimated remediation and cleanup costs									$ 2,500,000
Trailblazer | Minimum
Loss Contingencies [Line Items]
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi											25
Trailblazer | Maximum
Loss Contingencies [Line Items]
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi											35
Pipeline replacement costs								$ 2,700,000
Tallgrass Development LP
Loss Contingencies [Line Items]
Contractual indemnity provided to TEP by TD								20,000,000
Annual deductible								$ 1,500,000
Ultra Resources Complaint
Loss Contingencies [Line Items]
Firm transportation service agreement | Bcf / d				0.2						0.2
Gain Contingency, Unrecorded Amount														$ 303,000,000
Litigation Settlement, Amount	$ 150,000,000
Firm Transportation Rate				$ 0.37
Anticipated Annual Revenue				$ 26,800,000
Michels Corporation Complaint
Loss Contingencies [Line Items]
Litigation Settlement, Amount		$ 10,000,000	$ 10,000,000
Loss Contingency, Damages Sought, Value					$ 24,200,000
Withholding for Liquidated Delay Damages and Excess Completion Costs		$ 5,900,000

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Reporting Segments - Summary of TEGP's Segment Information of Revenue (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Total Revenues	$ 175,869	$ 153,268	$ 481,132	$ 449,451
TEGP
Segment Reporting Information [Line Items]
Total Revenues	175,869	153,268	481,132	449,451
TEGP | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues	34,201	33,567	100,852	95,612
TEGP | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues	86,082	95,555	266,821	283,597
TEGP | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues	55,586	24,146	113,459	70,242
TEGP | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	0
TEGP | Operating Segments
Segment Reporting Information [Line Items]
Total Revenues	186,849	157,850	500,805	462,490
TEGP | Operating Segments | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues	36,084	34,994	105,622	99,804
TEGP | Operating Segments | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues	93,029	95,826	273,768	283,868
TEGP | Operating Segments | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues	57,736	27,030	121,415	78,818
TEGP | Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	0
TEGP | Inter-Segment
Segment Reporting Information [Line Items]
Total Revenues	(10,980)	(4,582)	(19,673)	(13,039)
TEGP | Inter-Segment | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues	(1,883)	(1,427)	(4,770)	(4,192)
TEGP | Inter-Segment | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues	(6,947)	(271)	(6,947)	(271)
TEGP | Inter-Segment | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues	(2,150)	(2,884)	(7,956)	(8,576)
TEGP | Inter-Segment | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues	$ 0	$ 0	$ 0	$ 0

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Reporting Segments - Summary of TEGP's Segment Information of Earnings (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Operating Income	$ 74,003	$ 66,943	$ 204,173	$ 185,146
Reconciliation to Net Income:
Interest expense, net	24,408	12,157	61,539	31,275
Unrealized (loss) gain on derivative instrument	0	(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	0	9,728	0
Other income, net	454	480	796	1,267
Net income before tax	183,419	63,611	342,164	198,221
TEGP
Segment Reporting Information [Line Items]
Operating Income	74,003	66,943	204,173	185,146
Reconciliation to Net Income:
Net income before tax	183,419	63,611	342,164	198,221
TEGP | Natural Gas Transportation
Segment Reporting Information [Line Items]
Operating Income	15,133	14,009	45,140	35,681
TEGP | Crude Oil Transportation
Segment Reporting Information [Line Items]
Operating Income	51,037	57,457	153,516	172,232
TEGP | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Operating Income	11,369	(952)	17,644	(13,050)
TEGP | Corporate and Other
Segment Reporting Information [Line Items]
Operating Income	(3,536)	(3,571)	(12,127)	(9,717)
TEGP | Operating Segments
Segment Reporting Information [Line Items]
Operating Income	74,003	66,943	204,173	185,146
TEGP | Operating Segments | Natural Gas Transportation
Segment Reporting Information [Line Items]
Operating Income	17,016	15,436	49,910	39,873
TEGP | Operating Segments | Crude Oil Transportation
Segment Reporting Information [Line Items]
Operating Income	51,478	53,227	145,462	159,619
TEGP | Operating Segments | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Operating Income	9,045	1,851	20,928	(4,629)
TEGP | Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Operating Income	(3,536)	(3,571)	(12,127)	(9,717)
TEGP | Inter-Segment
Segment Reporting Information [Line Items]
Operating Income	0	0	0	0
TEGP | Inter-Segment | Natural Gas Transportation
Segment Reporting Information [Line Items]
Operating Income	(1,883)	(1,427)	(4,770)	(4,192)
TEGP | Inter-Segment | Crude Oil Transportation
Segment Reporting Information [Line Items]
Operating Income	(441)	4,230	8,054	12,613
TEGP | Inter-Segment | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Operating Income	2,324	(2,803)	(3,284)	(8,421)
TEGP | Inter-Segment | Corporate and Other
Segment Reporting Information [Line Items]
Operating Income	0	0	0	0
TEGP | Segment Reconciling Items
Reconciliation to Net Income:
Interest expense, net	24,408	12,157	61,539	31,275
Unrealized (loss) gain on derivative instrument	0	(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	0	9,728	0
Other income, net	$ 454	$ 480	$ 796	$ 1,267

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Reporting Segments Reporting Segments - Summary of TEP's Segment Information for Payments to Acquire Plant, Property and Equipment (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Capital expenditures	$ 88,050	$ 55,397
TEGP
Segment Reporting Information [Line Items]
Capital expenditures	88,050	55,397
TEGP | Natural Gas Transportation
Segment Reporting Information [Line Items]
Capital expenditures	9,829	11,146
TEGP | Crude Oil Transportation
Segment Reporting Information [Line Items]
Capital expenditures	28,785	25,985
TEGP | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Capital expenditures	49,436	18,266
TEGP | Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 0	$ 0

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Reporting Segments - Summary of TEGP's Segment Information of Assets (Detail) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Segment assets	$ 4,403,146	$ 3,625,480
TEGP
Segment Reporting Information [Line Items]
Segment assets	4,403,146	3,625,480
TEGP | Natural Gas Transportation
Segment Reporting Information [Line Items]
Segment assets	1,618,828	1,176,147
TEGP | Crude Oil Transportation
Segment Reporting Information [Line Items]
Segment assets	1,384,981	1,410,695
TEGP | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Segment assets	887,089	495,170
TEGP | Corporate and Other
Segment Reporting Information [Line Items]
Segment assets	$ 512,248	$ 543,468

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Reporting Segments - Additional Information (Detail) - Segment	9 Months Ended
	Sep. 30, 2017	Mar. 31, 2017	Jan. 01, 2017
Segment Reporting Information [Line Items]
Number of reportable segments	3
Tallgrass Terminals, LLC
Segment Reporting Information [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			100.00%
Tallgrass NatGas Operator, LLC
Segment Reporting Information [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			100.00%
Rockies Express Pipeline LLC | Tallgrass Development LP
Segment Reporting Information [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		24.99%
Rockies Express Pipeline LLC
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	49.99%