Tallgrass Energy 10-K 8 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Feb. 08, 2019	Jun. 30, 2018
Document Information [Line Items]
Entity Registrant Name	TALLGRASS ENERGY, LP
Entity Central Index Key	1,633,651
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	FY
Trading Symbol	TGE
Amendment Flag	false
Emerging Growth Company	false
Entity Small Business	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Shell Company	false
Entity Public Float			$ 1,264.2
Common Class A
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		156,353,761
Common Class B
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		123,887,893

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 9,596	$ 2,593
Accounts receivable, net	236,097	119,955
Inventories	34,316	21,609
Prepayments and other current assets	11,816	13,165
Total Current Assets	291,825	157,322
Property, plant and equipment, net	2,802,429	2,394,337
Goodwill	421,983	404,838
Intangible assets, net	227,103	97,731
Unconsolidated investments	1,861,686	909,531
Deferred financing costs, net	10,990	12,563
Deferred tax asset	273,531	312,997
Deferred charges and other assets	3,962	2,694
Total Assets	5,893,509	4,292,013
Current Liabilities:
Accounts payable	201,512	104,224
Accrued taxes	20,734	19,272
Accrued interest	39,217	25,167
Accrued liabilities	23,287	10,540
Deferred revenue	111,095	88,471
Other current liabilities	42,910	11,202
Total Current Liabilities	438,755	258,876
Long-term debt, net	3,205,958	2,292,993
Other long-term liabilities and deferred credits	31,688	18,965
Total Long-term Liabilities	3,237,646	2,311,958
Commitments and Contingencies
Equity:
Total Partners' Equity	1,725,537	48,613
Noncontrolling interests	491,571	1,672,566
Total Equity	2,217,108	1,721,179
Total Liabilities and Equity	5,893,509	4,292,013
Common Class A
Equity:
Total Partners' Equity	1,725,537	48,613
Common Class B
Equity:
Total Partners' Equity	$ 0	$ 0

CONSOLIDATED BALANCE SHEETS (UN

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - shares	Dec. 31, 2018	Dec. 31, 2017
Common Class A
Shares, Outstanding	156,311,986	58,085,002
Common Class B
Shares, Outstanding	123,887,893	99,154,440

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Total Revenues	$ 220,256,000	$ 200,320,000	$ 193,589,000	$ 179,094,000	$ 174,766,000	$ 175,869,000	$ 160,863,000	$ 144,400,000	$ 793,259,000	$ 655,898,000	$ 611,662,000
Operating Costs and Expenses:
Operations and maintenance									72,460,000	62,069,000	55,070,000
Depreciation and amortization									110,862,000	90,800,000	86,247,000
General and administrative									70,656,000	65,536,000	57,298,000
Taxes, other than income taxes									31,810,000	28,832,000	25,400,000
Contract termination									0	0	8,061,000
(Gain) loss on disposal of assets									11,043,000	599,000	(1,849,000)
Total Operating Costs and Expenses									442,628,000	384,051,000	353,244,000
Operating Income	99,359,000	90,084,000	79,275,000	81,913,000	67,674,000	74,003,000	66,944,000	63,226,000	350,631,000	271,847,000	258,418,000
Other Income (Expense):
Equity in earnings of unconsolidated investments									306,819,000	237,110,000	54,531,000
Interest expense, net									(133,319,000)	(89,348,000)	(45,601,000)
Gain on remeasurement of unconsolidated investment									0	9,728,000	0
Other (expense) income, net									(751,000)	3,106,000	432,000
Total Other Income (Expense)									172,749,000	160,596,000	9,362,000
Net income before tax									523,380,000	432,443,000	267,780,000
Deferred income tax expense									(55,709,000)	(208,458,000)	(17,741,000)
Net income	124,945,000	118,712,000	109,701,000	114,313,000	(93,197,000)	170,777,000	79,167,000	67,238,000	467,671,000	223,985,000	250,039,000
Net income attributable to noncontrolling interests	(65,166,000)	(59,162,000)	(108,638,000)	(97,578,000)	(72,180,000)	(154,911,000)	(70,414,000)	(55,209,000)	(330,544,000)	(352,714,000)	(216,250,000)
Net income (loss) attributable to TGE	$ 59,779,000	$ 59,550,000	$ 1,063,000	$ 16,735,000	$ (165,377,000)	$ 15,866,000	$ 8,753,000	$ 12,029,000	137,127,000	(128,729,000)	33,789,000
Predecessor operations interest in net income									0	0	(6,995,000)
Net income (loss) attributable to TGE, excluding predecessor operations interest									$ 137,127,000	$ (128,729,000)	$ 26,794,000
Earnings Per Share, Basic and Diluted [Abstract]
Basic net income (loss) per Class A share	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ (2.85)	$ 0.27	$ 0.15	$ 0.21	$ 1.27	$ (2.22)	$ 0.55
Diluted net income (loss) per Class A share	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ (2.85)	$ 0.27	$ 0.15	$ 0.21	$ 1.27	$ (2.22)	$ 0.55
Basic average number of Class A shares outstanding									107,586	58,076	48,856
Diluted average number of Class A shares outstanding									109,817	58,076	48,889
Crude oil transportation services
Revenues:
Total Revenues									$ 398,334,000	$ 345,733,000	$ 374,949,000
Natural gas transportation services
Revenues:
Total Revenues									126,894,000	122,364,000	119,962,000
Sales of natural gas, NGLs, and crude oil
Revenues:
Total Revenues									168,586,000	108,503,000	77,123,000
Processing and other revenues
Revenues:
Total Revenues									99,445,000	79,298,000	39,628,000
Cost of Sales
Operating Costs and Expenses:
Cost of sales and transportation services									114,815,000	91,213,000	71,650,000
Cost of Transportation Services
Operating Costs and Expenses:
Cost of sales and transportation services									$ 53,068,000	$ 46,200,000	$ 47,669,000

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flows from Operating Activities:
Net income	$ 467,671	$ 223,985	$ 250,039
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	117,430	98,537	94,038
Equity in earnings of unconsolidated investments	(306,819)	(237,110)	(54,531)
Distributions from unconsolidated investments	306,934	237,192	54,449
Deferred income tax expense	55,709	208,458	17,741
Gain on remeasurement of unconsolidated investment	0	(9,728)	0
Other noncash items, net	(2,382)	9,226	9,711
Accounts receivable and other
Accounts receivable and other	(102,105)	(57,927)	2,835
Accounts payable and accrued liabilities	112,474	84,731	10,684
Deferred revenue	17,547	27,283	33,815
Other current assets and liabilities	(3,079)	(10,542)	(5,578)
Other operating, net	9,145	(2,709)	95
Net Cash Provided by Operating Activities	672,525	571,396	413,298
Cash Flows from Investing Activities:
Contributions to unconsolidated investments	(473,946)	(45,948)	(50,076)
Capital expenditures	(368,873)	(145,144)	(84,491)
Payments to Acquire Businesses, Net of Cash Acquired		(57,202)
Distributions from unconsolidated investments in excess of cumulative earnings	80,213	69,434	24,120
Proceeds from Divestiture of Businesses	50,046
Payments to Acquire Interest in Subsidiaries and Affiliates	0	400,000	436,022
Payments to Acquire Businesses, Gross			0
Payments to Acquire Assets, Investing Activities	(30,704)	(128,526)	0
Acquisition of Pony Express membership interest			49,118
Other investing, net	(7,848)	(15,125)	48
Net Cash Used in Investing Activities	(987,212)	(898,541)	(595,539)
Net Cash Provided by Financing Activities
Proceeds from issuance of long-term debt	500,000	1,103,750	400,000
Borrowings (repayments) under revolving credit facilities, net	417,000	(356,000)	262,000
Distributions to noncontrolling interests	(327,578)	(317,102)	(249,142)
Dividends paid to Class A shareholders	206,431	73,321	42,499
Proceeds from public offering of TEP common units, net of offering costs	0	112,420	337,671
Payments of Debt Issuance Costs	0	22,375	10,380
Proceeds from private placement of TEP common units, net of offering costs	0	0	90,009
Contribution from TD	0	0	17,894
Other financing, net	(11,301)	(12,377)	7,429
Net Cash Provided by Financing Activities	321,690	327,279	182,466
Net Change in Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents	7,003	134	225
Cash and Cash Equivalents, beginning of period	2,593	2,459	2,234
Cash and Cash Equivalents, end of period	9,596	2,593	2,459
Supplemental Disclosures:
Cash payments for interest, net	114,026	72,698	34,367
Shares Issued	644,782	6,617	0
Noncash Acquisition, Contribution of membership interest	(19,500)
Issuance of Noncontrolling Interest in Subsidiary in Exchange for Membership Interest	(31,843)
Increase in Accrual for Property Plant and Equipment	5,755	8,975	0
Capital Unit, Class A
Supplemental Disclosures:
Shares Issued	2,113,758
Rockies Express Pipeline LLC
Cash Flows from Investing Activities:
Payments to Acquire Interest in Subsidiaries and Affiliates		400,000	436,000
Equity Option
Net Cash Provided by Financing Activities
Payments for Repurchase of Common Stock	0	(72,381)	(204,634)
Pawnee Terminal, LLC
Cash Flows from Investing Activities:
Contributions to unconsolidated investments	(30,600)	0	0
BNN North Dakota
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Net of Cash Acquired	(95,000)
NGL Water Solutions Bakken
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Gross	(91,000)
Deeprock North, LLC
Cash Flows from Investing Activities:
Payments to Acquire Assets, Investing Activities	(19,500)
Terminals and NatGas
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Gross		(140,000)	0
Tallgrass Crude Gathering, LLC
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Gross		(36,030)
Pony Express Pipeline
Net Cash Provided by Financing Activities
Distributions to noncontrolling interests	(50,000)	0	(425,882)
Tallgrass Energy Partners
Net Cash Provided by Financing Activities
Payments for Repurchase of Common Stock	0	$ (35,335)	$ 0
Supplemental Disclosures:
Other Significant Noncash Transaction, Value of Consideration Given	(2,365,501)
Rockies Express Pipeline LLC
Supplemental Disclosures:
Other Significant Noncash Transaction, Value of Consideration Given	$ (393,039)

CONSOLIDATED STATEMENTS OF PART

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL - USD ($) shares in Thousands	Total	Tallgrass Energy Partners	Pony Express Pipeline	Terminals and NatGas	Tallgrass Energy, LP (TGE)	Noncontrolling Interest	Noncontrolling InterestTallgrass Energy Partners	Noncontrolling InterestTallgrass Energy PartnersTallgrass Development LP	Noncontrolling InterestPony Express Pipeline	Noncontrolling InterestWater Solutions	Noncontrolling InterestTerminals and NatGas	Noncontrolling InterestRockies Express Pipeline LLC	Noncontrolling InterestDeeprock Development, LLC	Noncontrolling InterestBNN Colorado Water, LLC	Total Partner Equity Including Portion Attributable to Noncontrolling Interest	Total Partner Equity Including Portion Attributable to Noncontrolling InterestTallgrass Energy Partners	Total Partner Equity Including Portion Attributable to Noncontrolling InterestTallgrass Energy PartnersTallgrass Development LP	Total Partner Equity Including Portion Attributable to Noncontrolling InterestPony Express Pipeline	Total Partner Equity Including Portion Attributable to Noncontrolling InterestWater Solutions	Total Partner Equity Including Portion Attributable to Noncontrolling InterestTerminals and NatGas	Total Partner Equity Including Portion Attributable to Noncontrolling InterestTallgrass Energy, LP (TGE)	Total Partner Equity Including Portion Attributable to Noncontrolling InterestRockies Express Pipeline LLC	Total Partner Equity Including Portion Attributable to Noncontrolling InterestDeeprock Development, LLC	Total Partner Equity Including Portion Attributable to Noncontrolling InterestBNN Colorado Water, LLC	Capital Unit, Class A	Capital Unit, Class ATallgrass Energy, LP (TGE)	Capital Unit, Class B	Capital Unit, Class BRockies Express Pipeline LLC	Common Class A	Common Class ATallgrass Energy Partners	Common Class ATallgrass Energy PartnersTallgrass Development LP	Common Class APony Express Pipeline	Common Class AWater Solutions	Common Class ATerminals and NatGas	Common Class ATallgrass Energy, LP (TGE)	Common Class ARockies Express Pipeline LLC	Common Class ADeeprock Development, LLC	Common Class B	Common Class BTallgrass Energy Partners	Common Class BWater Solutions	Common Class BTerminals and NatGas	Common Class BRockies Express Pipeline LLC	Predecessor Equity	Predecessor EquityPony Express Pipeline	Predecessor EquityTerminals and NatGas	Predecessor EquityRockies Express Pipeline LLC
Increase (Decrease) in Partners' Capital [Roll Forward]
Partners' Capital, Including Portion Attributable to Noncontrolling Interest						$ 1,599,188,000									$ 2,093,062,000														$ 422,310,000									$ 0					$ 71,564,000
Shares, Outstanding																									47,725		109,504
Net income	$ 250,039,000				$ 243,044,000	216,250,000									250,039,000														26,794,000									0					6,995,000
Dividends, Common Stock, Cash						0									(42,499,000)														(42,499,000)									0
Noncash compensation expense						7,879,000									9,327,000														1,448,000									0
Acquisitions	280,000,000								$ (173,422,000)									$ (429,039,000)														$ (255,617,000)												$ 0
Contributions from noncontrolling interests						9,304,000									9,304,000														0									0
Distributions to noncontrolling interests	(249,142,000)		$ (425,882,000)			(249,142,000)									(249,142,000)														0									0
Issuance of units to public, net of offering costs		$ 337,700,000					$ 308,909,000									$ 337,671,000														$ 28,762,000									$ 0
LTIP units tendered by employees to satisfy tax withholding obligations							447,000									(498,000)														(51,000)									0
Conversion of Stock, Shares Converted																									10,350		(10,350)
Partners Capital Deferred Tax Asset						0									86,766,000														86,766,000									0
Partial exercise of call option						(211,315,000)									(238,627,000)														(27,312,000)									0
Proceeds from private placement of TEP common units, net of offering costs	90,009,000						82,417,000									90,009,000														7,592,000
Acquisition of additional membership interest	(49,118,000)									$ 5,536,000									$ 6,000,000														$ 464,000							$ 0
Contributions from TD						12,067,000									17,894,000														5,827,000									0
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs						0									986,000														986,000									0
Payments of Capital Distribution						0									1,603,000														1,603,000						$ 1,603,000			0
Contributions from Predecessor															3,736,000																												3,736,000
Payments for Repurchase of Common Stock		0
Partners' Capital, Including Portion Attributable to Noncontrolling Interest						1,596,152,000									1,929,414,000														250,967,000									0					82,295,000
Shares, Outstanding																									58,075		99,154
Net income	223,985,000					352,714,000									223,985,000														(128,729,000)									0					0
Dividends, Common Stock, Cash						0									(73,321,000)														(73,321,000)									0
Noncash compensation expense						10,390,000									11,993,000														1,603,000									0
Acquisitions				$ 57,700,000							$ (36,391,000)	$ 40,159,000	$ 45,869,000							$ (140,000,000)		$ 63,681,000	$ 45,869,000											$ (21,314,000)		$ 23,522,000					$ 0	$ 0			$ (82,295,000)
Contributions from noncontrolling interests						1,589,000									1,589,000														0									0
Distributions to noncontrolling interests	(317,102,000)		0			(317,102,000)									(317,102,000)														0									0
Issuance of units to public, net of offering costs		112,400,000					101,067,000									112,420,000														11,353,000									0
LTIP units tendered by employees to satisfy tax withholding obligations							11,616,000									(12,933,000)														(1,317,000)									0
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures																										10
Partial exercise of call option						(72,890,000)									(84,942,000)														(12,052,000)									0
Proceeds from private placement of TEP common units, net of offering costs	0
Acquisition of additional membership interest													(7,109,000)										(6,440,000)														$ 669,000
Contributions from TD						1,451,000									2,301,000														850,000									0
Payments for Repurchase of Common Stock		35,335,000					(31,717,000)									(35,335,000)														(3,618,000)									0
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	1,721,179,000					1,672,566,000									1,721,179,000														48,613,000									0					0
Shares, Outstanding																									58,085		99,154
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | Accounting Standards Update 2014-09												39,543,000										44,131,000														4,588,000										$ 0
Net income	467,671,000					330,544,000									467,671,000														137,127,000									0					0
Dividends, Common Stock, Cash						0									(206,431,000)														(206,431,000)									0
Noncash compensation expense						3,197,000									9,493,000														6,296,000									0
Other Significant Noncash Transaction, Payments to Acquire Units							(1,762,327,000)	$ (189,520,000)								(2,113,758,000)	$ (251,743,000)													(351,431,000)	$ (62,223,000)
Stock Issued During Period, Shares, Acquisitions																									95,386		10,758	16,797
Proceeds from Issuance or Sale of Equity						644,782,000									644,782,000
Acquisitions			16,200,000						$ (44,732,000)			$ 74,421,000						$ (50,000,000)				$ 108,537,000										$ (5,268,000)				$ 34,116,000
Noncontrolling Interest, Increase from Business Combination													$ 31,843,000	$ 10,138,000									$ 31,843,000	$ 10,138,000													$ 0
Contributions from noncontrolling interests						1,787,000									1,787,000														0									0
Distributions to noncontrolling interests	(327,578,000)		$ (50,000,000)			(327,578,000)									(327,578,000)														0									0
Issuance of units to public, net of offering costs							(279,000)									(377,000)														(98,000)									0
LTIP units tendered by employees to satisfy tax withholding obligations							$ 1,531,000									$ (1,721,000)					$ (30,000)									$ 190,000					$ 30,000				$ 0
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures																										19
Conversion of Stock, Shares Converted																									2,822		(2,822)
Partners' Capital Account, Exchanges and Conversions						8,717,000																							(8,717,000)
Partners Capital Deferred Tax Asset						0									15,427,000														15,427,000									0
Proceeds from private placement of TEP common units, net of offering costs	0
Payments for Repurchase of Common Stock		$ 0
Partners' Capital Account, Public Sale of Units															2,113,758,000														2,113,758,000
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	$ 2,217,108,000					$ 491,571,000									$ 2,217,108,000														$ 1,725,537,000									$ 0					$ 0
Shares, Outstanding																									156,312		123,887

Description of Business

Description of Business	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business	Tallgrass Energy, LP ("TGE") formerly known as Tallgrass Energy GP, LP, is a limited partnership that owns, operates, acquires and develops midstream energy assets in North America and has elected to be treated as a corporation for U.S. federal income tax purposes. "We," "us," "our" and similar terms refer to TGE together with its consolidated subsidiaries. Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity, LLC ("Tallgrass Equity"), in which we directly own an approximate 55.79% membership interest as of December 31, 2018. We 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 an integrated natural gas storage facility; • 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 and processing facilities; crude oil storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs. Natural Gas Transportation. We provide natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) our 75% 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"), and our 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas"), 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. We provide crude oil transportation to customers in Wyoming, Colorado, Kansas, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a FERC-regulated crude oil pipeline commencing in both Guernsey, Wyoming and Weld County, Colorado and terminating in Cushing, Oklahoma (the "Pony Express System"). In the second quarter of 2018, Pony Express placed into service an extension of the system from an additional origin point in Weld County, Colorado located near Platteville, Colorado. Gathering, Processing & Terminalling. We provide 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"), (2) natural gas processing facilities in Casper and Douglas, and (3) a natural gas treating facility at West Frenchie Draw. We also provide NGL transportation services in Northeast Colorado and Wyoming. We perform water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, Wyoming, and North Dakota through BNN Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through our 100% membership interest in Tallgrass Terminals, LLC ("Terminals"), which owns and operates crude oil terminals in Colorado, Oklahoma, and Kansas. The Gathering, Processing & Terminalling segment also includes 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 Tallgrass Energy Partners, LP ("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 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 3 – Acquisitions and Dispositions . Merger Agreement with Tallgrass Energy Partners, LP TGE previously entered into a definitive Agreement and Plan of Merger, dated as of March 26, 2018 (the "Merger Agreement"), with TEP, a Delaware limited partnership, Tallgrass MLP GP, LLC, a Delaware limited liability company and the general partner of TEP ("TEP GP"), and Razor Merger Sub, LLC, a Delaware limited liability company. The merger transaction contemplated by the Merger Agreement (the "TEP Merger") was completed effective June 30, 2018, and as a result, 47,693,097 TEP common units held by the public were converted into the right to receive Class A shares of TGE at an exchange ratio of 2.0 Class A shares for each outstanding TEP common unit, TEP's incentive distribution rights were cancelled, TEP's common units are no longer publicly traded, and 100% of TEP's equity interests are now owned by Tallgrass Equity and its subsidiaries. The TEP Merger was accounted for as an acquisition of noncontrolling interest. Following consummation of the TEP Merger, TGE changed its name from "Tallgrass Energy GP, LP" to "Tallgrass Energy, LP" and began trading on the New York Stock Exchange under the ticker symbol "TGE" on July 2, 2018.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Basis of Presentation The accompanying consolidated financial statements and related notes were prepared in conformity with accounting principles generally accepted in the United States of America ("GAAP"). 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. As further discussed in Note 3 – Acquisitions and Dispositions , we 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 contributions of the Predecessor Entities included in the consolidated financial statements represent transfers of cash as a result of Tallgrass Development's ("TD") 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 consolidated financial statements of TGE include historical cost-basis accounts of the assets of Terminals and NatGas for the periods prior to January 1, 2017, the date we 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. TGE, 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 TGE at historical cost. The consolidated financial statements include the accounts of TGE 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 TGE is attributed to TGE and noncontrolling interests in accordance with the respective ownership interests. 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 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 did not have material assets that could only be used to settle specific obligations of the consolidated VIEs. Prior to June 29, 2018, both Tallgrass Equity and TEP were considered to be VIEs under the applicable authoritative guidance and included in our consolidated results. As a result of the TEP Merger, and changes in ownership and their respective partnership arrangements, Tallgrass Equity and TEP are no longer considered to be VIEs. We continue to consolidate our membership interests in Tallgrass Equity and TEP through the voting interest model. Use of Estimates Certain amounts included in or affecting these 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. Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Net equity contributions of the Predecessor Entities included in the consolidated statements of cash flows represent transfers of cash as a result of TD's centralized cash management systems prior to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are carried at their estimated collectible amounts. We make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and adjustments are recorded as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $7.7 million and $0.5 million at December 31, 2018 and 2017 , respectively. Inventories Inventories primarily consist of crude oil, materials and supplies, gas in underground storage, and natural gas liquids. As discussed further under " Revenue Recognition " below, a loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline loss allowance oil, or PLA, which we can then sell. As PLA oil is accumulated, it is recorded as inventory at the lower of historical cost and net realizable value using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence. Natural gas liquids and gas in underground storage, sometimes referred to as working gas, are recorded at the lower of historical cost and net realizable value using the average cost method. For additional information, see " Gas in Underground Storage " below. Accounting for Regulatory Activities Regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We recorded regulatory assets of approximately $3.2 million and $2.6 million included in "Prepayments and other current assets" and "Deferred charges and other assets" in the consolidated balance sheets at December 31, 2018 and 2017 , respectively. Regulatory assets at December 31, 2018 and December 31, 2017 were primarily attributable to costs associated with fuel tracker assets at our regulated natural gas pipelines as well as both Trailblazer's 2013 and 2018 Rate Case Filings and TIGT's 2015 Rate Case Filing . We recorded regulatory liabilities of approximately $1.9 million and $2.3 million included in "Other current liabilities" in the consolidated balance sheets at December 31, 2018 and 2017 , respectively, related to fuel tracker liabilities at our regulated natural gas pipelines. For further information regarding our rate case filings and fuel tracker balances, see Note 18 – Regulatory Matters . Property, Plant and Equipment Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs related to the construction of assets, including internal labor costs, interest and engineering costs. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation and/or the negative salvage liability discussed under "Depreciation and Amortization" below, as appropriate, with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred. Intangible Assets We establish identifiable intangible assets when they meet either the separability criterion or the contractual-legal criterion. Contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of TIGT's natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years , the period of expected future benefit. During 2018, we recognized additional intangible assets at Plaquemines Liquids Terminal, LLC ("PLT"), a newly formed subsidiary as discussed in Note 3 – Acquisitions and Dispositions , from the acquisition of permits, designs, and other work-product related to the development and construction of a crude oil terminal facility in Louisiana. These intangible assets will be amortized on a straight-line basis over a period of 35 years , the period of expected future benefit. Also, during 2018, we recognized an intangible asset associated with customer relationships as part of our acquisition of NGL Water Solutions Bakken, LLC as discussed in Note 3 – Acquisitions and Dispositions . The customer relationships are amortized on a straight-line basis over a period of 8 years. Other intangible assets include customer contracts amortized on a straight-line basis over a period of 2 - 14 years, based on the remaining term of the contracts at the time of acquisition. Impairment of Long-Lived Assets We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset or asset group's use and its eventual disposition are less than its carrying amount. We assess our long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset or asset group is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Examples of long-lived asset impairment indicators include: • a significant decrease in the market value of a long-lived asset or asset group; • a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition; • a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process; • an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group; • a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and • a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. When an impairment indicator is present, we first assess the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset or asset group to its carrying amount. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the asset or asset group is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized. Gas in Underground Storage Gas in underground storage represents the cost of base gas, which refers to the volumes necessary to maintain pressure and deliverability requirements in our storage facilities. We record base gas as a component of property, plant and equipment. We maintain working gas in our underground storage facilities on behalf of certain third parties. We receive a fee for our storage services but do not reflect the value of third-party gas in the accompanying consolidated financial statements. We occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost and net realizable value. Depreciation and Amortization For non-regulated assets, we have elected to use the straight-line method of depreciation. For our regulated assets, we have elected to compute depreciation using a composite method employed by applying a single depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. The depreciation rates for our regulated natural gas pipeline assets include two components, one based on economic service life (capital recovery) and one based on net costs of removal (negative salvage). The accumulated liability related to negative salvage is classified as "Other long-term liabilities and deferred credits" in our consolidated balance sheets. The rates of depreciation for the various classes of depreciable assets are as follows: Range of Depreciation Rates Crude oil pipelines 2.8% Natural gas pipelines 0.7% - 5.0% Gathering & processing assets 2.2% - 5.0% Water business assets 2.3% - 20.0% Terminal assets 1.8% - 2.8% Replacement Gas Facilities (1) 10.0% General & other 2.9% - 25.0% (1) Represents costs incurred by TIGT, and reimbursed by Pony Express, for the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System after having sold approximately 433 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013. Gas Imbalances Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing and imbalance agreements. Gas imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements. Imbalances are valued at applicable average market index prices. Gas imbalances receivable and payable are included in "Prepayments and other current assets" and "Other current liabilities" in the consolidated balance sheets. Deferred Financing Costs Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method. Deferred financing costs associated with long-term debt are presented as a reduction to the corresponding debt in our consolidated balance sheets. Deferred financing costs associated with our revolving credit facility are presented as noncurrent assets in our consolidated balance sheets. During the year ended December 31, 2018, we recognized a $2.2 million loss on debt retirement, recorded as "Other income, net" in the accompanying consolidated statements of income, associated with the write off of deferred financing costs associated with the Amendment to the TEP revolving credit facility and the termination of the Tallgrass Equity revolving credit facility as discussed further in Note 10 – Long-term Debt . Goodwill 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. 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. 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. See Note 8 – Goodwill and Other Intangible Assets for additional information regarding impairment testing performed during 2018. Investment in Unconsolidated Affiliates We use the equity method to account for investments in 20% or greater owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where we have the ability to exercise significant influence. We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary. See Note 7 – Investments in Unconsolidated Affiliates for additional information regarding our investment in unconsolidated affiliates. Revenue Recognition In May 2014, the FASB issued Accounting Standards Update ("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. Management completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. 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 members' equity. Consolidated revenues presented in the comparative consolidated financial statements for periods prior to January 1, 2018 have not been revised. On January 1, 2018, we recorded a cumulative effect adjustment to equity of $44.1 million , increased the carrying amount of our investment in Rockies Express by $42.8 million , and recognized a receivable from Rockies Express of $1.3 million . These adjustments relate to the cumulative effect adjustment recorded by Rockies Express of $125.2 million upon adoption of ASC 606. The cumulative effect adjustment at Rockies Express arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with rates that vary throughout the term of the contract. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas during the periods prior to implementation. Through our review process, we also identified the following changes to our revenue recognition policies that did not result in a cumulative effect adjustment on January 1, 2018: • Gathering & Processing. We have determined that a number of our gathering & processing contracts at TMID do not represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of raw gas are accounted for as supply arrangements pursuant to ASC 705. As a result, gathering & processing fees previously recognized in revenue are reported as a reduction to cost of sales under ASC 606. • Pipeline Loss Allowance. We have determined that PLA collected under certain crude oil transportation arrangements is a component of the transaction price where the PLA both significantly exceeds actual losses and was negotiated with the intent of providing a revenue stream to Pony Express. Under ASC 606, PLA barrels retained from customers are subject to the guidance for noncash consideration and recognized in revenue at their contract inception fair value. See Note 12 – Revenue from Contracts with Customers for revenue disclosures related to both the implementation and 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. Commitments and Contingencies We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. Environmental Costs We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action. Estimates of environmental liabilities are based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of other factors including our prior experience in remediating contaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information. Fair Value Fair value, as defined in the Codification, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. We apply the fair value measurement guidance to financial assets and liabilities in determining the fair value of derivative assets and liabilities, and to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill. The fair value measurement accounting guidance requires that we make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments' fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity. Fair value, where available, is based on observable market prices. Where observable market prices or inputs are not available, different valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments' complexity. To increase consistency and enhance disclosure of fair value, the Codification creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability's level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows: • Level 1 Inputs-quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date; • Level 2 Inputs-inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and • Level 3 Inputs-unobservable inputs for the asset or liability. These unobservable inputs reflect the entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity's own data). Any transfers between levels within the fair value hierarchy are recognized at the end of the reporting period. For information regarding financial instruments measured at fair value on a recurring basis, see Note 9 – Risk Management . For information regarding the fair value of financial instruments not measured at fair value in the consolidated balance sheets, see Note 10 – Long-term Debt . Risk Management Activities Our operations expose us to a variety of risks including, but not limited to, changes in the prices of commodities that we buy or sell. We manage these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including establishing and monitoring exposure limits. We record derivative contracts at their estimated fair values as of each reporting date and present profit and loss activity on a net basis in "Processing and other revenues" in our consolidated statements of operations. For more information on our risk management activities, see Note 9 – Risk Management . Equity-Based Compensation Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. As discussed in Note 16 – Equity-Based Compensation , prior to February 2018 a portion of the expense recognized relating to equity-based compensation grants was charged to TD. Income Taxes Although TGE is organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U.S. federal and state income taxes. TGE's consolidated subsidiaries consist primarily of entities that are flow-through entities for income tax purposes. We also own certain C corporation subsidiaries which have been formed for the purpose of potential pipeline construction and other investment purposes. In addition, Tallgrass Energy Finance Corp. is a wholly owned subsidiary of TEP that has no material assets and was formed for the sole purpose of being a co-issuer of TEP's senior notes as discussed in Note 10 – Long-term Debt . These C corporation subsidiaries have not commenced operations or generated any material income, and as a result no provision for federal or state income taxes has been recorded in our consolidated financial statements. Deferred income taxes are provided for tempor

Acquisitions & Dispositions

Acquisitions & Dispositions	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Acquisitions & Dispositions	Consolidation of BNN Colorado Effective December 1, 2018, we obtained control of BNN Colorado Water, LLC ("BNN Colorado") through an amendment to the voting rights in BNN Colorado's limited liability company agreement. Prior to the amendment, we accounted for our interest in BNN Colorado under the equity method of accounting. The consolidation was accounted for as a business combination under ASC 805. No gain or loss was recognized on the remeasurement of our 63% membership interest as of December 1, 2018, as the carrying value was determined to approximate the fair value. The 37% equity interest in BNN Colorado held by noncontrolling interests was recorded at its acquisition date fair value of $10.1 million . 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 (in thousands): Accounts receivable $ 4,053 Property, plant and equipment 18,535 Intangible asset 7,922 (1) Accounts payable and accrued liabilities (53 ) Deferred revenue (4,053 ) Net identifiable assets acquired (excluding cash) $ 26,404 (1) The $7.9 million intangible asset acquired represents a customer contract. This intangible asset is amortized on a straight-line basis over a period of approximately 3 years, the remaining term of the underlying contract at the time of acquisition. At December 31, 2018, the assets acquired and liabilities assumed were recorded at provisional amounts based on the preliminary purchase price allocation. We are in the process of identifying and measuring 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 TGE from BNN Colorado of less than $1.0 million was recognized in the accompanying consolidated statements of income for the period from December 1, 2018 to December 31, 2018 . Acquisitions of BNN North Dakota In January 2018, we acquired 100% of the membership interests in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC, which were subsequently merged and renamed BNN North Dakota, LLC ("BNN North Dakota"), for approximately $95.0 million , net of cash acquired. BNN North Dakota owns a produced water gathering and disposal system in the Bakken basin with approximately 133,000 acres under dedication. 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 (in thousands): Accounts receivable $ 2,457 Inventory 67 Property, plant and equipment 48,900 Intangible asset 46,800 (1) Accounts payable and accrued liabilities (3,224 ) Net identifiable assets acquired (excluding cash) $ 95,000 (1) The $46.8 million intangible asset acquired represents three major customer contracts. This intangible asset is amortized on a straight-line basis over a period of 8 - 14 years, the remaining terms of the underlying contracts at the time of acquisition. At March 31, 2018, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2018. Actual revenue and net income attributable to TGE from BNN North Dakota of $18.8 million and $4.7 million , respectively, was recognized in the accompanying consolidated statements of income for the period from January 12, 2018 to December 31, 2018 . In November 2018, we acquired 100% of the membership interests in NGL Water Solutions Bakken, LLC ("NGL Water Solutions Bakken"), a produced water disposal system in the Bakken basin, for cash consideration of approximately $91.0 million , subject to working capital adjustments. NGL Water Solutions Bakken was subsequently merged into BNN North Dakota. 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 (in thousands): Accounts receivable $ 3,599 Prepayments and other current assets 5 Property, plant and equipment 17,200 Intangible asset 54,000 (1) Accounts payable and accrued liabilities (949 ) Net identifiable assets acquired 73,855 Goodwill 17,145 Net assets acquired $ 91,000 (1) The $54.0 million intangible asset acquired represents customer relationships and a customer contract. This intangible asset is amortized on a straight-line basis over a period of 3 - 8 years. At December 31, 2018, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. We are in the process of identifying and measuring 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 $17.1 million is primarily attributed to synergies expected from combining the operations of TGE and NGL Water Solutions Bakken. All the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TGE from NGL Water Solutions Bakken of $1.4 million and $0.5 million , respectively, was recognized in the accompanying consolidated statements of income for the period from November 30, 2018 to December 31, 2018 . Acquisition of Plaquemines Liquids Terminal, LLC In November 2018, we entered into a joint venture agreement with Drexel Hamilton Infrastructure Fund I, L.P. ("DHIF") to jointly-own Plaquemines Liquids Terminal, LLC ("PLT"). PLT was formed with the intention of entering into agreements to develop a storage and terminalling facility. The facility is expected to offer up to 20 million barrels of storage for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers ("VLCC") vessels for international delivery. We made an initial cash contribution to PLT of $30.7 million in exchange for a 100% preferred membership interest and a 80% common membership interest in PLT. DHIF contributed any and all assets and rights related to PLT in exchange for a 20% common membership interest and the right to receive certain special distributions. Our preferred and common membership interests are considered to be a controlling financial interest and PLT was consolidated accordingly. The transaction has been accounted for as an asset acquisition, with substantially all the fair value allocated to the assets and liabilities acquired based on their relative fair values. The intangible assets acquired, valued at approximately $35 million , relate to permits, designs, and other work-product related to the development and construction of a crude oil terminal facility in Louisiana. The liabilities recognized relate to DHIF's right to receive special distributions totaling $35 million . The special distributions are contingent upon PLT reaching certain milestones in the development and construction of the project facilities. Also in November 2018, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT will construct the facilities. Acquisition of Pawnee Terminal In January 2018, we entered into an agreement to acquire a 51% membership interest in the Pawnee, Colorado crude oil terminal ("Pawnee Terminal") from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $30.6 million . The transaction closed on April 1, 2018. As the 51% membership interest does not represent a controlling interest in Pawnee, our investment in Pawnee Terminal is recorded under the equity method of accounting and reported as "Unconsolidated investments" on the consolidated balance sheets. Acquisitions of 75% Membership Interest in Rockies Express and Additional TEP Common Units In May 2016, TD assigned us its right to purchase a 25% membership interest in Rockies Express from a unit of Sempra U.S. Gas and Power ("Sempra") pursuant to the purchase agreement originally entered into between TD's wholly-owned subsidiary and Sempra in March 2016. Subsequently on May 6, 2016, we closed the purchase of a 25% membership interest in Rockies Express from Sempra pursuant to the purchase agreement for cash consideration of approximately $436.0 million , after making the adjustments to the purchase price required by the purchase agreement. In March 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 . The 2017 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. As a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed contribution representing the excess carrying value of the 24.99% membership interest in Rockies Express acquired over the fair value of the consideration paid. For further discussion, see Note 11 - Partnership Equity . In February 2018, TD merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity ("Tallgrass Development Holdings"), and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass Equity issued 27,554,785 unregistered TGE Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of TD. Subsequent to the closing of the transaction, our aggregate membership interest in Rockies Express is 75% . The 2018 transfer of the Rockies Express membership interest between TD and Tallgrass Equity is considered a transaction between entities under common control, but does not represent a change in reporting entity. As a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed contribution representing the excess carrying value of the 25.01% membership interest in Rockies Express acquired over the fair value of the consideration paid. For further discussion, see Note 11 - Partnership Equity . As the aggregate 75% membership interest does not represent a controlling interest in Rockies Express, TGE's investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our consolidated balance sheets. For additional information, see Note 7 - Investments in Unconsolidated Affiliates . The acquisition of an additional 5,619,218 TEP common units is considered an acquisition of noncontrolling interest and resulted in the recognition of a noncash deemed distribution representing the excess purchase price over the $53.8 million carrying value of the 5,619,218 TEP common units acquired as of February 7, 2018. For further discussion, see Note 11 - Partnership Equity . Acquisition and Sale of Outrigger Powder River Operating, LLC In August 2017, we 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 as of the acquisition date and approximately 150,000 acres dedicated on a long-term fee-based contract, for approximately $36 million . 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 (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. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of December 31, 2017. Actual revenue and net loss attributable to TGE from TCG of less than $1 million was recognized in the accompanying consolidated statements of income for the period from August 3, 2017 to December 31, 2017. In February 2018, we entered into an agreement with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to sell our 100% membership interest in TCG, for approximately $50.0 million . The sale of TCG closed on February 23, 2018. During the year ended December 31, 2018 , we recognized a gain of $9.4 million on the sale which is presented in the line item "Gain on disposal of assets" in the consolidated statements of income. Joint Venture with Silver Creek In February 2018, we entered into an agreement with Silver Creek to form Iron Horse Pipeline, LLC ("Iron Horse"), which owns a new 80 -mile crude oil pipeline currently under construction that will transport crude oil from the Powder River Basin to Guernsey, Wyoming ("Iron Horse Pipeline"). During the year ended December 31, 2018 , we contributed an initial $3.5 million and committed to funding our proportionate share of the remaining costs of construction in exchange for a 75% membership interest in Iron Horse. As the 75% membership interest does not represent a controlling interest in Iron Horse, our investment in Iron Horse is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the consolidated balance sheets. In August 2018, we entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the contribution by us and Silver Creek of cash and additional Powder River Basin assets. These additional contributions closed in January 2019. We contributed our 75% membership interest in Iron Horse, $37 million in cash, and various other assets, including terminal facilities currently under construction in Guernsey, Wyoming. Silver Creek contributed the Powder River Express Pipeline ("PRE Pipeline") and their 25% membership interest in Iron Horse. The expanded joint venture operates under the name Powder River Gateway, LLC ("Powder River Gateway"), and owns the Iron Horse Pipeline, the PRE Pipeline, a 70 -mile crude oil pipeline that transports crude oil from the Powder River Basin to Guernsey, Wyoming, and crude oil terminal facilities in Guernsey, Wyoming. Effective January 1, 2019, we own a 51% membership interest in Powder River Gateway and continue to operate the joint venture, while Silver Creek owns a 49% membership interest. Acquisitions of Additional Interests in Deeprock Development, LLC In July 2017, we 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. We 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, we obtained a controlling financial interest in Deeprock Development and accordingly have accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, we remeasured our 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 consolidated statements of income, and consolidated Deeprock Development in our 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 (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. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of December 31, 2017. The goodwill recognized of $61.6 million is primarily attributed to synergies expected from combining our operations with the operations of Deeprock Development. All the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TGE from Deeprock Development of $10.5 million and $0.9 million , respectively, was recognized in the accompanying consolidated statements of income for the period from July 20, 2017 to December 31, 2017. In July 2017, subsequent to the acquisition of an additional 40% membership interest discussed above, we 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% . Acquisition of Deeprock North and Merger with Deeprock Development In January 2018, we acquired an approximate 38% membership interest in Deeprock North, LLC ("Deeprock North") from Kinder Morgan Deeprock North Holdco LLC for cash consideration of $19.5 million . Immediately following the acquisition, Deeprock North was merged into Deeprock Development, and the members of Deeprock North and Deeprock Development received adjusted membership interests in the combined entity. As a result, we recognized additional noncontrolling interests in Deeprock Development of $31.8 million . The acquisition of Deeprock North by Deeprock Development 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. After the acquisition and merger, we own an approximate 60% membership interest in the combined entity. Acquisition of DCP Douglas, LLC In June 2017, we 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 . The acquisition has been accounted for as an asset acquisition, with substantially all the fair value allocated to the long-lived assets acquired based on their relative fair values. Acquisition of Tallgrass Terminals, LLC and Tallgrass NatGas Operator, LLC In January 2017, we 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. As a result of the common control nature of the transaction, the acquisitions resulted in the recognition of a noncash deemed distribution representing the excess fair value of the consideration paid over the carrying value of Terminals and NatGas net assets acquired. For further discussion, see Note 11 - Partnership Equity . Acquisitions of Pony Express In January 2016, we acquired an additional 31.3% membership interest in Pony Express in exchange for cash consideration of $475 million and 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of our common units) issued to TD, for total consideration of approximately $743.6 million . The transaction increased our aggregate membership interest in Pony Express to 98% effective January 1, 2016. As part of the transaction, TD granted us an 18 -month call option covering the newly issued 6,518,000 common units at a price of $42.50 . On the effective date of the acquisition, the call option was valued at $46.0 million . As discussed in Note 9 – Risk Management , in July 2016 and October 2016, we partially exercised the option covering 3,563,146 and 1,251,760 of the common units, respectively. In February 2017, we exercised the remainder of the call option covering an additional 1,703,094 common units, leaving no remaining common units subject to the call option as of such date. As a result of the partial exercises in 2016 and 2017, we derecognized a portion of the derivative asset balance, recognizing approximately $34.0 million and $12.6 million through equity for the years ended December 31, 2016 and 2017, respectively, as discussed further in Note 9 – Risk Management . The acquisition of the additional 31.3% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction has not been recast to reflect the additional 31.3% membership interest. As a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed distribution representing the excess fair value of the consideration paid over the carrying value of the 31.3% membership interest in Pony Express acquired. For further discussion, see Note 11 - Partnership Equity . Cash outflows to acquire an additional noncontrolling interest in Pony Express are classified as an investing activity in the accompanying consolidated statements of cash flows to the extent the consideration paid was used to directly fund the construction of the underlying assets by the noncontrolling member. Cash outflows to acquire an additional noncontrolling interest in excess of the cost to construct the underlying assets are classified as financing activities. For the year ended December 31, 2016, $49.1 million of the $475 million paid to acquire the additional 31.3% membership interest in Pony Express was classified as an investing activity and $425.9 million was classified as a financing activity. In February 2018, we acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from TD for cash consideration of approximately $60 million , bringing our aggregate membership interest in Pony Express to 100% . The acquisition of the remaining 2% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction has not been recast to reflect the additional 2% membership interest. As a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed distribution representing the excess fair value of the consideration paid over the carrying value of the 2% membership interest in Pony Express acquired. For further discussion, see Note 11 – Partnership Equity . Pro Forma Financial Information Unaudited pro forma revenue and net income (loss) attributable to TGE for the years ended December 31, 2018 and 2017 is presented below as if the acquisitions of BNN North Dakota, NGL Water Solutions Bakken, and BNN Colorado had been completed on January 1, 2017. Unaudited pro forma revenue and net (loss) income attributable to TGE for the years ended December 31, 2017 and 2016 is presented below as if the acquisitions of TCG and Deeprock Development had been completed on January 1, 2016. Year Ended December 31, 2018 2017 2016 (in thousands) Revenue $ 813,286 $ 686,803 $ 632,528 Net income (loss) attributable to TGE $ 140,005 $ (129,155 ) $ 34,311 The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TGE 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 TGE 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 (loss) includes adjustments to give effect to the estimated results of operations of BNN North Dakota, NGL Water Solutions Bakken, BNN Colorado, TCG, and Deeprock Development for the periods presented. The pro forma net income (loss) also includes adjustments to eliminate the equity in earnings and gain on remeasurement of unconsolidated investment associated with our previously held 20% membership interest in Deeprock Development and to eliminate the equity in earnings associated with our 63% membership interest in BNN Colorado which was previously accounted for as an equity method investment. Historical Financial Information The results of our acquisitions of Terminals and NatGas are included in the consolidated balance sheets as of December 31, 2018 and December 31, 2017 and in the consolidated statements of income for the years ended December 31, 2018 , 2017 , and 2016 . The following table presents the previously reported consolidated statements of income for the year ended December 31, 2016 adjusted for the acquisitions of Terminals and NatGas: Year Ended December 31, 2016 TGE (As previously reported) Consolidate Terminals Consolidate NatGas Elimination TGE (As currently reported) (in thousands) Revenues: Crude oil transportation services $ 374,949 $ — $ — $ — $ 374,949 Natural gas transportation services 119,962 — — — 119,962 Sales of natural gas, NGLs, and crude oil 77,394 99 — (370 ) (1) 77,123 Processing and other revenues 32,817 12,043 6,228 (11,460 ) (2) 39,628 Total Revenues 605,122 12,142 6,228 (11,830 ) 611,662 Operating Costs and Expenses: Cost of sales 71,920 100 — (370 ) (1) 71,650 Cost of transportation services 58,341 788 — (11,460 ) (2) 47,669 Operations and maintenance 53,386 1,684 — — 55,070 Depreciation and amortization 84,896 1,351 — — 86,247 General and administrative 55,829 1,469 — — 57,298 Taxes, other than income taxes 24,727 673 — — 25,400 Contract termination — 8,061 (3) — — 8,061 Loss on disposal of assets 1,849 — — — 1,849 Total Operating Costs and Expenses 350,948 14,126 — (11,830 ) 353,244 Operating Income (Expense) 254,174 (1,984 ) 6,228 — 258,418 Other Income (Expense): Equity in earnings of unconsolidated investments 51,780 2,751 — — 54,531 Interest expense, net (45,601 ) — — — (45,601 ) Other income, net 432 — — — 432 Total Other Income 6,611 2,751 — — 9,362 Net income before tax 260,785 767 6,228 — 267,780 Deferred income tax expense (17,741 ) — — — (17,741 ) Net income 243,044 767 6,228 — 250,039 Net income attributable to noncontrolling interests (216,250 ) — — — (216,250 ) Net income attributable to TGE $ 26,794 $ 767 $ 6,228 $ — $ 33,789 (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.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	As a result of our relationship with Tallgrass Energy Holdings, LLC ("Tallgrass Energy Holdings") 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 consolidated financial statements. All of our employees are employed by Tallgrass Management, LLC ("Tallgrass Management"). Prior to July 1, 2018, Tallgrass Management was a wholly-owned subsidiary of Tallgrass Energy Holdings. In connection with the closing of the TEP initial public offering on May 17, 2013, TEP and TEP GP entered into an Omnibus Agreement with Tallgrass Energy Holdings and certain of its affiliates (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse Tallgrass Energy Holdings 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 Tallgrass Energy Holdings and its affiliates, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the closing of the TGE initial public offering on May 12, 2015 (the "TGE IPO"), TGE entered into an Omnibus Agreement (the "TGE Omnibus Agreement") with Tallgrass Energy GP, LLC (formerly known as TEGP Management, LLC), Tallgrass Equity and Tallgrass Energy Holdings. Effective July 1, 2018, Tallgrass Management was contributed to Tallgrass Equity in connection with the TEP Merger. As a result, the costs of employer and director compensation and benefits are now incurred directly by Tallgrass Equity. Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows: Year Ended December 31, 2018 2017 2016 (in thousands) Processing and other revenues (1) $ 7,483 $ 8,516 $ 6,228 Cost of transportation services (2) $ — $ 10,476 $ 18,585 Charges to TGE: (3) Property, plant and equipment, net $ — $ 2,679 $ 3,084 Other deferred charges $ — $ 25 $ 44 Operations and maintenance $ — $ 29,881 $ 25,431 General and administrative $ — $ 41,676 $ 40,321 (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 3 – Acquisitions and Dispositions . (3) Charges to TGE, inclusive of Tallgrass Equity and TEP, include indirectly charged wages and salaries, other compensation and benefits, and shared services for periods prior to January 1, 2018. Effective January 1, 2018, these costs are incurred by TEP directly and, in the case of certain employee compensation and benefits, paid on TEP's behalf by its affiliate, Tallgrass Management, LLC, pursuant to the TEP Omnibus Agreement. Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable" in the consolidated balance sheets are as follows: December 31, 2018 December 31, 2017 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 3,447 $ 1,340 Iron Horse Pipeline, LLC 186 — Pawnee Terminal, LLC 115 — Total receivable from related parties $ 3,748 $ 1,340 Accounts payable to related parties: Tallgrass Operations, LLC (1) $ — $ 5,342 Total accounts payable to related parties $ — $ 5,342 (1) Reflects accounts payable for charges to TGE, inclusive of Tallgrass Equity and TEP, including indirectly charged wages and salaries, other compensation and benefits, and shared services prior to January 1, 2018 as discussed above. Gas imbalances with affiliated shippers are as follows: December 31, 2018 December 31, 2017 (in thousands) Affiliate gas imbalance receivables $ 19 $ 18 Affiliate gas imbalance payables $ 742 $ 442

Inventory

Inventory	12 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
Inventory	The components of inventory at December 31, 2018 and 2017 consisted of the following: December 31, 2018 December 31, 2017 (in thousands) Crude oil $ 23,205 $ 12,792 Materials and supplies 8,206 5,891 Gas in underground storage 2,740 1,984 Natural gas liquids 165 942 Total inventory $ 34,316 $ 21,609

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	A summary of net property, plant and equipment by classification is as follows: December 31, 2018 December 31, 2017 (in thousands) Crude oil pipelines $ 1,313,976 $ 1,220,379 Gathering, processing and terminalling assets (1) 889,168 675,092 Natural gas pipelines 607,343 581,400 General and other (2) 180,299 98,680 Construction work in progress 191,994 97,978 Accumulated depreciation and amortization (380,351 ) (279,192 ) Total property, plant and equipment, net (3) $ 2,802,429 $ 2,394,337 (1) Includes approximately $53.6 million and $46.2 million of assets associated with the acquisitions of BNN North Dakota in January and November 2018 and Deeprock North in January 2018, respectively. (2) Includes approximately $30.7 million of land associated with the PLT capital lease as discussed in Note 3 – Acquisitions and Dispositions . (3) Property, plant and equipment, net includes approximately $455.8 million of assets at our regulated natural gas pipelines at December 31, 2018 . Depreciation expense was approximately $102.7 million , $86.9 million , and $83.2 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. Capitalized interest was approximately $5.2 million , $1.1 million , and $0.6 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. Under various lease agreements, TMID, as lessor, leases capacity on NGL pipelines that were constructed for third parties, and Deeprock Development, as lessor, leases capacity on certain of its storage facilities under lease agreements acquired as part of the Deeprock North acquisition on January 2, 2018. Rental income for these arrangements was approximately $10.9 million , $3.8 million , and $3.2 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively, and was recorded as "Processing and other revenues" in the accompanying consolidated statements of income. Under a lease agreement initially effective November 13, 2012, TIGT, as lessor, leases a portion of its office space to a third party. Rental income was approximately $0.8 million for the years ended December 31, 2018 , 2017 , and 2016 and was recorded as "Other income, net" in the accompanying consolidated statements of income. As of December 31, 2018 , future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands): Year Total 2019 $ 7,742 2020 3,952 2021 3,773 2022 3,773 2023 3,773 Thereafter 7,353 Total $ 30,366

Investments in Unconsolidated A

Investments in Unconsolidated Affiliaties - (Notes)	12 Months Ended
	Dec. 31, 2018
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 consolidated balance sheets. As of May 6, 2016, the difference between the fair value of our 25% membership interest in Rockies Express of $436.0 million and the book value of the underlying net assets resulted in a negative basis difference of approximately $404.7 million . As discussed in Note 3 – Acquisitions and Dispositions , we acquired an additional 24.99% and 25.01% membership interest in Rockies Express from TD on March 31, 2017 and February 7, 2018, respectively. As of March 31, 2017, the negative basis difference carried over from TD from the transfer of the 24.99% Rockies Express membership interest was approximately $386.8 million . As of February 7, 2018, the negative basis difference carried over from TD from the transfer of the 25.01% Rockies Express membership interest was approximately $376.5 million . The transfer of the 24.99% Rockies Express membership interest between TD and TEP and the 25.01% Rockies Express membership interest between TD and Tallgrass Equity are considered transactions between entities under common control, but does not represent a change in reporting entity. As a result of the common control nature of the transactions, the 24.99% and 25.01% membership interests in Rockies Express were transferred to TEP and Tallgrass Equity, respectively, at TD's historical carrying amount, including the remaining unamortized basis difference driven by the difference between the fair value of the investments and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD. 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. At December 31, 2018 , the basis difference for our membership interests in Rockies Express was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 47,182 2 - 25 years Property, plant and equipment (1,146,984 ) 35 years Total basis difference $ (1,099,802 ) During the year ended December 31, 2018 , we recognized equity in earnings associated with our aggregate 75% membership interest in Rockies Express of $303.4 million , inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $380.7 million and $432.0 million , respectively. In July 2018, we made a special contribution of approximately $412.5 million to fund our portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018. BNN Colorado Water, LLC As discussed in Note 3 – Acquisitions and Dispositions , we consolidated BNN Colorado effective December 1, 2018 and no longer account for our investment in BNN Colorado under the equity method of accounting. Deeprock Development As discussed in Note 3 – Acquisitions and Dispositions , on July 20, 2017, we acquired an additional 40% membership interest in Deeprock Development. As a result of the acquisition, we consolidated Deeprock Development and effective July 20, 2017 we no longer account for our investment in Deeprock Development under the equity method of accounting. Summarized Financial Information of Unconsolidated Affiliates Combined summarized financial information for all our unconsolidated affiliates is shown in the tables below. Summarized financial information for Deeprock Development is presented from January 1, 2016 to July 20, 2017, the date we acquired a controlling interest in Deeprock Development. Summarized financial information for Rockies Express is presented from the date of the initial acquisition of May 6, 2016 to December 31, 2018. Summarized financial information for BNN Colorado is presented from the date of the acquisition, June 23, 2017 to December 1, 2018, the date we acquired a controlling interest in BNN Colorado. Summarized financial information for Iron Horse is presented from the date of the acquisition, February 23, 2018 to December 31, 2018. Summarized financial information for Pawnee Terminal is presented from the date of the acquisition, April 1, 2018 to December 31, 2018. December 31, 2018 December 31, 2017 (in thousands) Current assets $ 132,213 $ 122,362 Noncurrent assets $ 6,031,066 $ 5,974,926 Current liabilities $ 694,951 $ 714,037 Noncurrent liabilities $ 1,502,906 $ 2,049,189 Members' equity $ 3,965,422 $ 3,334,062 Year Ended December 31, 2018 2017 2016 (in thousands) Revenue $ 930,771 $ 860,115 $ 440,838 Operating income $ 524,607 $ 480,337 $ 203,801 Net income to Members $ 376,934 $ 465,592 $ 184,314

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets Disclosure	Reconciliation of Goodwill The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the reporting period: Year Ended December 31, 2018 Year Ended December 31, 2017 Natural Gas Transportation Gathering, Processing & Terminalling Total Natural Gas Transportation Gathering, Processing & Terminalling Total (in thousands) Balance at beginning of period $ 255,558 $ 149,280 $ 404,838 $ 255,558 $ 87,730 $ 343,288 Goodwill acquired — 17,145 (1) 17,145 — 61,550 (2) 61,550 Balance at end of period $ 255,558 $ 166,425 $ 421,983 $ 255,558 $ 149,280 $ 404,838 (1) The $17.1 million of goodwill was recorded in connection with the acquisition of NGL Water Solutions Bakken on November 30, 2018 as discussed further in Note 3 – Acquisitions and Dispositions . (2) 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 3 – Acquisitions and Dispositions . Annual Goodwill Impairment Analysis In 2018, we elected to apply the qualitative assessment option for four of our five reporting units. In conducting the qualitative assessment we considered relevant factors and circumstances that affect the fair value or carrying amount of the reporting entity. Such factors included changes in discount rates, projected cash flows, macroeconomic considerations, industry and market considerations, overall financial performance, prior quantitative results, and entity and reporting unit specific events. For each of these reporting units, the results of the qualitative assessment indicated that it was more likely than not that the fair value of the reporting units exceeded their respective book values. As such, we did not perform a quantitative impairment analysis, and we concluded that no impairment was indicated as of August 31, 2018. We did not elect to apply the qualitative assessment option for one reporting unit during our 2018 annual goodwill impairment testing; instead we proceeded directly to the quantitative impairment test. We compared the fair value of the reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. The fair value of the 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 revenue, operating expenses, general and administrative expenses, terminal growth rates, maintenance capital expenditures, and the weighted average cost of capital. The fair value of the reporting unit was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For this reporting unit, the results of the quantitative impairment test indicated no impairment as the fair value of the reporting unit was greater than its respective book value. As a result, in accordance with the Codification guidance, we did not record a goodwill impairment during the year ended December 31, 2018 . Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow model 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. Other Intangible Assets A summary of amortized intangible assets is as follows: December 31, 2018 December 31, 2017 (in thousands) Pony Express oil conversion use rights $ 105,973 $ 105,973 Customer contracts 60,348 8,064 Customer relationships 52,100 — Plaquemines Liquids Terminal use rights and permits 35,000 — Accumulated amortization (26,318 ) (16,306 ) Intangible assets, net $ 227,103 $ 97,731 Amortization of intangible assets was approximately $8.1 million , $3.8 million , and $3.0 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. Estimated future amortization for the intangible assets is as follows (in thousands): Year Total 2019 $ 16,528 2020 16,347 2021 16,294 2022 13,144 2023 13,144 Thereafter 116,646 Total (1) $ 192,103 (1) Excludes the $35 million intangible asset at PLT, as discussed in Note 3 – Acquisitions and Dispositions , that will be amortized over 35 years beginning on the in-service date of the project facilities.

Risk Management

Risk Management	12 Months Ended
	Dec. 31, 2018
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. We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. 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 consolidated balance sheets: Balance Sheet December 31, 2018 December 31, 2017 (in thousands) Crude oil derivative contracts (1) Prepayments and other current assets $ 3,526 $ — Crude oil derivative contracts (2) Other current liabilities $ 1,642 $ 2,368 (1) As of December 31, 2018 , the fair value shown for crude oil derivative contracts represents the forward purchase of 2,105,146 barrels of crude oil, consisting of fixed price and floating price contracts, which will settle throughout 2019. (2) As of December 31, 2018 , the fair value shown for crude oil derivative contracts represents the forward sale of 1,274,500 barrels of crude oil, consisting of fixed price and floating price contracts, which will settle throughout the first quarter of 2019. As of December 31, 2017 , the fair value shown for crude oil derivative contracts represents the forward sale of 356,000 barrels of crude oil, consisting of fixed price and floating price contracts, which settled in the first quarter of 2018. 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 years ended December 31, 2018 , 2017 and 2016 : Location of Amount of gain (loss) recognized in income on derivatives Year Ended December 31, 2018 2017 2016 (in thousands) Crude oil derivative contracts Sales of natural gas, NGLs, and crude oil $ 29,510 $ 39 $ (40 ) Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ — $ 75 $ 74 Call option derivative Other income, net $ — $ 1,885 $ (1,291 ) Call Option Derivative As part of our 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 commodity derivatives consist of market participants and 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 derivative contracts are entered into with counterparties through central trading organizations such as futures, options or stock exchanges or counterparties outside of central trading organizations. While we typically enter into derivative transactions 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. The maximum potential exposure to credit losses on our crude oil derivative contracts at December 31, 2018 was: Asset Position (in thousands) Gross $ 3,526 Netting agreement impact — Cash collateral held — Net exposure $ 3,526 As of December 31, 2018 , we did not have any cash in margin accounts or outstanding letters of credit in support of our commodity derivatives. As of December 31, 2017 , we had $3.0 million of cash in margin accounts and outstanding letters of credit in support of 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 following table summarizes the fair value measurements of our derivative contracts as of December 31, 2018 and 2017 , based on the fair value hierarchy: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2018: Crude oil derivative contracts $ 3,526 $ — $ 3,526 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2018: Crude oil derivative contracts $ 1,642 $ — $ 1,642 $ — As of December 31, 2017: Crude oil derivative contracts $ 2,368 $ — $ 2,368 $ —

Long-term Debt

Long-term Debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-term Debt	Long-term debt consisted of the following at December 31, 2018 and 2017 : December 31, 2018 December 31, 2017 (in thousands) Tallgrass Equity revolving credit facility (1) $ — $ 146,000 TEP revolving credit facility 1,224,000 661,000 TEP 4.75% senior notes due October 1, 2023 500,000 — TEP 5.50% senior notes due September 15, 2024 750,000 750,000 TEP 5.50% senior notes due January 15, 2028 750,000 750,000 Less: Deferred financing costs, net (2) (21,421 ) (17,737 ) Plus: Unamortized premium on 2028 Notes 3,379 3,730 Total long-term debt, net $ 3,205,958 $ 2,292,993 (1) On July 26, 2018, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility. (2) Deferred financing costs, net as presented above relate solely to the Senior Notes (as defined below). Deferred financing costs associated with our revolving credit facilities are presented in noncurrent assets on our consolidated balance sheets. TEP Senior Unsecured Notes On September 26, 2018, 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 26, 2018 (the "2023 Indenture") pursuant to which the Issuers issued $500 million in aggregate principal amount of 4.75% senior notes due 2023 (the "2023 Notes"). The 2023 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 TEP's properties to, another person. The Issuers have also previously issued $500 million in aggregate principal amount of 5.50% senior notes due 2028 (the "2028 Notes") on September 15, 2017 and an additional $250 million in aggregate principal amount of the 2028 Notes on December 11, 2017. The 2028 Notes issued on September 15, 2017 and December 11, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date and offering price. The 2028 Notes are governed by an Indenture dated September 15, 2017 (the "2028 Indenture") which 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 TEP's properties to, another person. In addition, the Issuers have previously issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes") on September 1, 2016 and an additional $350 million in aggregate principal amount of the 2024 Notes on May 16, 2017. The 2024 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 Notes are governed by an Indenture dated September 1, 2016 (the "2024 Indenture") which 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. The 2023 Notes, 2024 Notes, and 2028 Notes are together referred to as the "Senior Notes." As of December 31, 2018 , TEP was in compliance with the covenants required under the 2023 Indenture, the 2024 Indenture, and the 2028 Indenture. TEP Revolving Credit Facility The following table sets forth the available borrowing capacity under the TEP revolving credit facility as of December 31, 2018 and 2017 : December 31, 2018 December 31, 2017 (in thousands) Total capacity under the TEP revolving credit facility $ 2,250,000 $ 1,750,000 Less: Outstanding borrowings under the TEP revolving credit facility (1,224,000 ) (661,000 ) Less: Letters of credit issued under the TEP revolving credit facility (94 ) (94 ) Available capacity under the TEP revolving credit facility $ 1,025,906 $ 1,088,906 On July 26, 2018, TEP and certain of its subsidiaries entered into Amendment No. 1 (the "Amendment") to its existing revolving credit facility with Wells Fargo Bank, National Association, as administrative agent and collateral agent, and a syndicate of lenders (the "Credit Agreement"). The Amendment modified certain provisions of the Credit Agreement to, among other things, (i) increase the available amount of the TEP revolving credit facility to $2.25 billion , (ii) reduce certain applicable margins in the pricing grids used to determine the interest rate and revolving credit commitment fees, (iii) modify the use of proceeds to allow TEP to pay off the Tallgrass Equity revolving credit facility, and (iv) increase the maximum total leverage ratio to 5.50 to 1.00. 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 5.50 to 1.00 ( 5.00 to 1.00 prior to the Amendment), 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 December 31, 2018 , TEP was in compliance with the covenants required under its revolving credit facility. The consummation of the Blackstone Acquisition would constitute an event of default under TEP's revolving credit agreement. The closing conditions of the Blackstone Acquisition include TEP obtaining the consent or waiver of the required lenders under TEP's revolving credit facility in connection with the transactions contemplated by the Blackstone Acquisition. The unused portion of TEP's revolving credit facility is subject to a commitment fee, which ranges from 0.250% to 0.375% ( 0.250% to 0.500% prior to the Amendment), based on TEP's total leverage ratio. As of December 31, 2018 , the weighted average interest rate on outstanding borrowings under the TEP revolving credit facility was 3.96% . During the year ended December 31, 2018 , 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 4.11% . 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 consolidated balance sheets as of December 31, 2018 and 2017 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of December 31, 2018: Revolving credit facility $ — $ 1,224,000 $ — $ 1,224,000 $ 1,224,000 2023 Notes $ — $ 485,285 $ — $ 485,285 $ 494,603 2024 Notes $ — $ 737,745 $ — $ 737,745 $ 741,196 2028 Notes $ — $ 726,503 $ — $ 726,503 $ 746,159 As of December 31, 2017: Revolving credit facilities $ — $ 807,000 $ — $ 807,000 $ 807,000 2024 Notes $ — $ 771,645 $ — $ 771,645 $ 739,824 2028 Notes $ — $ 758,168 $ — $ 758,168 $ 746,169 The long-term debt borrowed under the revolving credit facilities is carried at amortized cost. As of December 31, 2018 and 2017 , the fair value of borrowings under the revolving credit facilities approximates the carrying amount of the borrowings using a discounted cash flow analysis. The Senior Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the Senior 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 December 31, 2018 .

Partnership Equity and Distribu

Partnership Equity and Distributions	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Partnership Equity and Distributions	TGE Dividends to Holders of Class A Shares The following table details the dividends for the periods indicated: Three Months Ended Date Paid Dividends to Class A Shareholders Dividends per Class A Share December 31, 2018 February 14, 2019 (1) $ 81,304 $ 0.5200 September 30, 2018 November 14, 2018 79,717 0.5100 June 30, 2018 August 14, 2018 77,052 0.4975 March 31, 2018 May 15, 2018 28,316 0.4875 December 31, 2017 February 14, 2018 21,346 0.3675 September 30, 2017 November 14, 2017 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 dividend announced on January 15, 2019 for the fourth quarter of 2018 will be paid on February 14, 2019 to Class A shareholders of record at the close of business on January 31, 2019. Subsidiary Distributions TEP Distributions . The following table shows the distributions for the periods indicated: Distributions Distribution per Limited Partner Common Unit Limited Partner General Partner Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) March 31, 2018 May 15, 2018 $ 71,370 $ 39,816 $ 1,267 $ 112,453 $ 0.9750 December 31, 2017 February 14, 2018 70,638 39,125 1,251 111,014 0.9650 September 30, 2017 November 14, 2017 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 As a result of the TEP Merger, Tallgrass Equity and its wholly-owned subsidiary, Tallgrass Equity Investments, LLC, will receive all distributions paid by TEP for the second quarter of 2018 and subsequent periods. Exchange Rights Our current Class B shareholders (collectively, the "Exchange Right Holders") own an equal number of Tallgrass Equity units. The Exchange Right Holders, and any permitted transferees of their Tallgrass Equity units, each have the right to exchange all or a portion of their Tallgrass Equity units for Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us. Upon such exchange, we will cancel the Class B shares received from the exercising party. During the year ended December 31, 2018 , 2,821,332 Class A shares were issued and an equal number of Class B shares were cancelled as a result of the exercise of the Exchange Right. As of February 8, 2019, the Exchange Right Holders primarily consist of Kelso & Company and its affiliated investment funds ("Kelso"), The Energy & Minerals Group and its affiliated investment funds ("EMG"), and Tallgrass KC, LLC ("Tallgrass KC"), which is an entity owned primarily by certain members of TGE's management. As discussed in Note 22 – Subsequent Events , on January 31, 2018, we announced that affiliates of Blackstone Infrastructure Partners (collectively, "BIP") had entered into a definitive purchase agreement with Kelso, EMG, and Tallgrass KC (collectively, the "Sellers"), pursuant to which BIP will acquire from the Sellers 100% of the membership interests in our general partner and an approximately 44% economic interest in us (the "Blackstone Acquisition"). One or more affiliates of GIC Special Investment Pte. Ltd., the infrastructure and private equity arm of GIC Pte. Ltd., Singapore's sovereign wealth fund, will be a minority investor in the Blackstone Acquisition. Following consummation of the Blackstone Acquisition, the Exchange Rights Holders are expected to consist of BIP and certain members of TGE's management. Equity Distribution Agreements Neither TGE or TEP currently have equity distribution agreements in place. TEP was previously a party to equity distribution agreements pursuant to which it sold from time to time through a group of managers, as its sales agents, TEP common units representing limited partner interests. Following the TEP Merger, these agreements were terminated effective July 2, 2018. During the year ended December 31, 2018 , TEP did not issue any common units under its equity distribution agreements. During the year ended December 31, 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 agreement 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. During the year ended December 31, 2016 , TEP issued and sold 7,696,708 common units with a weighted average sales price of $44.46 per unit under its equity distribution agreements for net cash proceeds of approximately $337.7 million (net of approximately $4.5 million in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes as described above. 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. Secondary Offering On November 17, 2016, TGE entered into an Underwriting Agreement (the "Underwriting Agreement"), by and among TGE and certain selling shareholders named in the Underwriting Agreement (the "Selling Shareholders"), on one hand, and Goldman, Sachs & Co., as the sole underwriter (the "Underwriter"), on the other hand, providing for the offer and sale by the Selling Shareholders (the "Secondary Offering"), and purchase by the Underwriter, of 9,000,000 Class A shares at a price to the public of $22.00 per share. Pursuant to the Underwriting Agreement, the Selling Shareholders also granted the Underwriter an option for a period of 30 days to purchase up to an additional 1,350,000 Class A shares, on the same terms, which the Underwriter exercised in full. In connection with the Secondary Offering, Class A shares were issued to the Selling Shareholders upon the exercise by each Selling Shareholder of its right to exchange all or a portion of its Tallgrass Equity units into Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged (the "Exchange Right"). Pursuant to the terms of the Exchange Right, simultaneously therewith, the exercising Selling Shareholder transferred to TGE Class B shares in an amount equal to the number of Tallgrass Equity units exchanged by such exercising Selling Shareholder. Upon each such exchange, TGE cancelled the Class B shares received from the exercising Selling Shareholder. Immediately prior to the Secondary Offering, we and the Exchange Right Holders owned approximately 30.35% and 69.65% of the Tallgrass Equity units, respectively. At the completion of the Secondary Offering, we and the Exchange Right Holders owned 36.94% and 63.06% of the Tallgrass Equity units, respectively. Private Placement On April 28, 2016, TEP issued an aggregate of 2,416,987 common units for net cash proceeds of $90 million in a private placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C. The units were subsequently registered pursuant to our Form S-3/A (File No. 333-210976) filed with the SEC on May 6, 2016, which became effective May 17, 2016. Noncontrolling Interests As of December 31, 2018 , noncontrolling interests in our subsidiaries consisted of a 44.21% interest in Tallgrass Equity held by the Exchange Right Holders, an approximate 40% membership interest in Deeprock Development, and a 37% membership interest in BNN Colorado. During the year ended December 31, 2018 , we recognized contributions from and distributions to noncontrolling interests of $1.8 million and $327.6 million , respectively. Contributions from noncontrolling interests consisted primarily of contributions from DER to Deeprock Development. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $223.7 million , distributions to TEP unitholders of $97.7 million , and distributions to Deeprock Development and Pony Express noncontrolling interests of $6.2 million . During the year ended December 31, 2017 , we recognized contributions from and made distributions to noncontrolling interests of $1.6 million and $317.1 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 $185.7 million , Tallgrass Equity distributions to the Exchange Right Holders of $125.2 million , and distributions to Pony Express and Deeprock Development noncontrolling interests of $6.2 million . During the year ended December 31, 2016 , we recognized contributions from and made distributions to noncontrolling interests of $9.3 million and $249.1 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 $145.1 million , Tallgrass Equity distributions to the Exchange Right Holders of $97.5 million , and distributions to Pony Express and Water Solutions noncontrolling interests of $6.5 million . Other Contributions and Distributions During the year ended December 31, 2018 , TGE recognized the following other contributions and distributions: • TGE was deemed to have made a noncash capital distribution of $198.0 million , which represents the excess purchase price over the $53.8 million carrying value of the 5,619,218 TEP common units acquired as of February 7, 2018; • TGE was deemed to have received a noncash capital contribution of $108.5 million , which represents the excess carrying value of the 25.01% membership interest in Rockies Express acquired as of February 7, 2018 over the fair value of the consideration paid; and • TEP was deemed to have made a noncash capital distribution of $16.2 million , which represents the excess purchase price over the $33.8 million carrying value of the additional 2% membership interest in Pony Express acquired as of February 1, 2018. During the year ended December 31, 2017 , TGE recognized the following other contributions and distributions: • TEP was deemed to have made a noncash capital distribution of $57.7 million , which represents the excess purchase price over the $82.3 million carrying value of the Terminals and NatGas net assets acquired January 1, 2017; • TEP was deemed to have received a noncash capital contribution of $63.7 million , which represents the excess carrying value of the additional 24.99% membership interest in Rockies Express acquired March 31, 2017 over the fair value of the consideration paid; and • TEP received contributions from TD of $2.3 million primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 19 – Legal and Environmental Matters . During the year ended December 31, 2016 , TGE recognized the following other contributions and distributions: • TEP was deemed to have made noncash capital distributions of $280.0 million , which represent the excess purchase price over the $417.7 million carrying value of the additional 31.3% membership interest in Pony Express acquired effective January 1, 2016, partially offset by the 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of our common units) issued to TD; • TEP received contributions from TD of $17.9 million primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed above. • TGE distributed the remaining $1.6 million in remaining proceeds from the TGE IPO to the Exchange Right Holders that had been retained for short-term working capital needs.

Revenue from Contracts with Cus

Revenue from Contracts with Customers (Notes)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	As discussed in Note 2 – Summary of Significant Accounting Policies , we adopted the guidance in ASC Topic 606 effective January 1, 2018 using the modified retrospective method of adoption. As a result, revenue reported for the years ended December 31, 2017 and 2016 have not been revised. The following tables provide the impact of ASC Topic 606 on our consolidated balance sheet as of December 31, 2018 and the consolidated statements of income for the year ended December 31, 2018 : December 31, 2018 As currently reported Under previous guidance Impact of ASC Topic 606 (in thousands) Unconsolidated investments $ 1,861,686 $ 1,773,849 $ 87,837 (1) Year Ended December 31, 2018 As currently reported Under previous guidance Impact of ASC Topic 606 (in thousands) Crude oil transportation services $ 398,334 $ 398,329 $ 5 (2) Sales of natural gas, NGLs, and crude oil $ 168,586 $ 173,055 $ (4,469 ) (3) Processing and other revenues $ 99,445 $ 104,117 $ (4,672 ) (1)(3) Cost of sales $ 114,815 $ 123,458 $ (8,643 ) (2)(3) Equity in earnings of unconsolidated investments $ 306,819 $ 261,848 $ 44,971 (1) Net income attributable to TGE $ 137,127 $ 121,402 $ 15,725 Basic net income per Class A share $ 1.27 $ 1.13 $ 0.14 Diluted net income per Class A share $ 1.27 $ 1.13 $ 0.14 (1) Reflects the impact on our investment in Rockies Express and the management fee collected by NatGas of the cumulative effect adjustment at Rockies Express, which arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with rates that vary throughout the term of the contract. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas. (2) Reflects the impact to revenue and cost of sales to value PLA barrels collected under certain crude oil transportation arrangements at their contract inception fair value in revenue and record an associated lower of cost or net realizable value adjustment in cost of sales. (3) Reflects the reclassification of certain gathering and processing fees collected under arrangements determined to be supply arrangements, rather than customer arrangements under ASC 606, to cost of sales and the reclassification of certain commodities retained as consideration for processing services to processing fee revenue. Disaggregated Revenue A summary of our revenue by line of business is as follows: Year Ended December 31, 2018 Natural Gas Transportation segment Crude Oil Transportation segment Gathering, Processing, & Terminalling segment Corporate and Other Total Revenue (in thousands) Crude oil transportation - committed shipper revenue $ — $ 392,276 $ — $ — $ 392,276 Natural gas transportation - firm service 128,041 — — (4,585 ) 123,456 Water business services — — 52,333 — 52,333 Natural gas gathering & processing fees — — 24,109 — 24,109 All other (1) 11,223 45,888 18,444 (53,950 ) 21,605 Total service revenue 139,264 438,164 94,886 (58,535 ) 613,779 Natural gas liquids sales — — 101,382 — 101,382 Natural gas sales 1,195 — 29,558 — 30,753 Crude oil sales — 6,290 652 — 6,942 Total commodity sales revenue 1,195 6,290 131,592 — 139,077 Total revenue from contracts with customers 140,459 444,454 226,478 (58,535 ) 752,856 Other revenue (2) — — 53,187 (12,784 ) 40,403 Total revenue (3) $ 140,459 $ 444,454 $ 279,665 $ (71,319 ) $ 793,259 (1) Includes revenue from crude oil transportation walk up shippers, crude oil terminal services, interruptible natural gas transportation and storage, and natural gas park and loan service. (2) Includes lease and derivative revenue not subject to ASC 606. (3) Excludes $930.8 million of revenue recognized at Rockies Express, BNN Colorado, and Pawnee Terminal for the year ended December 31, 2018 . See Note 7 – Investments in Unconsolidated Affiliates for additional information. Performance Obligations A performance obligation is a promise in a contract to transfer a distinct good or service to the customer, and is the unit of account in ASC Topic 606. A contract's transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. The majority of our contracts have a single performance obligation and are billed and collected monthly. All of our segments engage in commodity sales, in which our performance obligations include an obligation to deliver the specified volume of a commodity to the designated receipt point. Revenue from commodity sales is recognized at a point in time when the customer obtains control of the commodity, typically upon delivery to the designated delivery point when the customer accepts and takes possession of the commodity. In the Natural Gas Transportation segment, our performance obligations typically include an obligation to stand ready to provide natural gas transportation, storage, or an integrated transportation and storage service over the life of the contract, which is a series. These performance obligations are satisfied over time using each day of service to measure progress toward satisfaction of the performance obligation. In the Crude Oil Transportation segment, our performance obligations typically include an obligation to provide crude oil transportation services over the life of the contract, which is a series. These performance obligations are satisfied over time using barrels delivered to measure progress toward satisfaction of the performance obligation. In the Gathering, Processing & Terminalling segment, the performance obligations vary based on the operating asset and type of contract. In our natural gas gathering and processing arrangements, performance obligations typically include an obligation to provide an integrated processing service over the life of the contract, which is a series. These performance obligations are satisfied over time using each unit of gas processed to measure progress toward satisfaction of the performance obligation. In our freshwater supply arrangements, performance obligations typically include an obligation to deliver a specified volume of water to the designated receipt point. These performance obligations are satisfied at a point in time when the customer obtains control of the water. In our produced water gathering and disposal arrangements, performance obligations typically include an obligation to provide an integrated produced water gathering and disposal service over the life of the contract, which is a series. These performance obligations are satisfied over time using barrels disposed to measure progress toward satisfaction of the performance obligation. On December 31, 2018 , we had $1.6 billion of remaining performance obligations at our consolidated subsidiaries, which we refer to as total backlog. Total backlog includes performance obligations under long-term crude oil transportation contracts with committed shippers, natural gas firm transportation and firm storage contracts, and certain water business service contracts with minimum volume commitments, and excludes variable consideration that is not estimated at contract inception, as discussed further below. We expect to recognize the total backlog during future periods as follows (in thousands): Year Estimated Revenue 2019 $ 532,549 2020 357,226 2021 170,713 2022 163,852 2023 140,101 Thereafter 210,625 Total $ 1,575,066 Contract Estimates Accounting for long-term contracts involves the use of various techniques to estimate total contract revenue. Contract estimates are based on various assumptions to project the outcome of future events that often span several years. These assumptions include the anticipated volumes of crude oil expected to be delivered by our customers for transport in future periods. The nature of our contracts gives rise to several types of variable consideration, including PLA, volumetric charges for actual volumes delivered, overrun charges, and other fees that are contingent on the actual volumes delivered by our customers. As the amount of variable consideration is allocable to each distinct performance obligation within the series of performance obligations that comprise the single performance obligation and the uncertainty related to the consideration is resolved each month as the distinct service is provided, we do not estimate the total variable consideration for the single overall performance obligation. Consequently, we are able to include in the transaction price each month the actual amount of variable consideration because no uncertainty exists surrounding the services provided that month. Certain of our contracts include provisions in which a portion of the consideration is noncash. In our Crude Oil Transportation segment, we collect PLA from our customers. As crude oil is transported, we earn, and take title to, a portion of the oil transported for our services. Any PLA that remains after replacing losses in transit can be sold. Where PLA is determined to be a component of compensation for the transportation services provided, crude oil retained is recognized in revenue at its contract inception fair value. In our Gathering, Processing & Terminalling segment, we retain commodity products as consideration under certain of our gathering and processing arrangements. Processing fee revenue is recorded when the performance obligation is completed based on the value of the product received at the time services are performed. At this time, the variability of the non-cash consideration related to both form (price) and other-than-form (volume and product mix), which are interrelated, is resolved. As a significant change in one or more of these estimates could affect the amount and timing of revenue recognized under our customer contracts, we review and update our contract-related estimates regularly. Contract Balances The timing of revenue recognition, billings, and cash collections may result in billed accounts receivable, unbilled receivables (contract assets), and deferred revenue (contract liabilities) on our consolidated balance sheets. Revenue is generally billed and collected monthly based on services provided or commodity volumes sold. In our Crude Oil Transportation segment, we recognize shipper deficiencies, or deferred revenue, for barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers' agreed upon destination point. These shipper deficiencies are charged at the committed tariff rate per barrel and recorded as a contract liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes remote. We also recognize contract liabilities, in the form of deferred revenue, under certain water business services contracts in the Gathering, Processing & Terminalling segment. Contract balances as of December 31, 2018 were as follows: December 31, 2018 January 1, 2018 (in thousands) Accounts receivable from contracts with customers $ 80,935 $ 61,888 Other accounts receivable 151,414 56,727 Receivable from related parties 3,748 1,340 Accounts receivable, net $ 236,097 $ 119,955 Deferred revenue from contracts with customers (1) $ 111,095 $ 88,471 (1) Revenue recognized during the year ended December 31, 2018 that was included in the deferred revenue balance at the beginning of the period was $12.0 million . This revenue primarily represented the utilization of shipper deficiencies at Pony Express.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure	Leases and Right of Way Agreements Rent expense under operating leases and right of way agreements totaled approximately $1.4 million , $9.5 million , and $16.5 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. At December 31, 2018 , future minimum rental commitments under major, non-cancelable leases and right of way ("ROW") agreements were as follows (in thousands): Year Operating Lease and ROW Obligations Capital Lease Obligations 2019 $ 1,818 $ 449 2020 1,757 449 2021 1,056 449 2022 796 449 2023 679 449 Thereafter 3,153 17,770 Total $ 9,259 $ 20,015 Operating leases consist of leases for office space and equipment. Prior to the acquisition of a controlling interest in Deeprock Development in July 2017, as discussed in Note 3 - Acquisitions and Dispositions , rent expense included payments made by Pony Express to Deeprock Development for the use by Pony Express of storage capacity at the Deeprock tank storage facility near Cushing, Oklahoma. Capital lease obligations consist of the PLT land site lease, as discussed in Note 3 - Acquisitions and Dispositions . The PLT land site lease includes a bargain purchase option exercisable after the initial lease term. PLT satisfied the capital lease obligation of $30.7 million at lease inception, and as a result has no imputed interest on the future minimum rental commitments in the table above. These future commitments represent certain administrative fees and estimated payments to the Plaquemines Port & Harbor Terminal District which approximate the ad valorem taxes that would be assessed if PLT acquired the land directly. Capital Expenditures We had committed approximately $39.6 million for the future purchase of property, plant and equipment at December 31, 2018 . Other Purchase Obligations At December 31, 2018 , future minimum commitments under long-term, non-cancelable contracts for other purchase obligations were as follows (in thousands): Year Total 2019 $ 13,467 2020 11,198 2021 6,677 2022 5,604 2023 5,614 Thereafter 13,231 Total $ 55,791

Net Income per Class A Share

Net Income per Class A Share	12 Months Ended
	Dec. 31, 2018
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 TGE by the weighted average number of outstanding Class A shares during the period. Class B shares do not share in the earnings of TGE. 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 TGE 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 TGE 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 TGE'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 TGE Class B shares) for TGE Class A shares at an exchange ratio of one TGE Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. As of February 8, 2019, the Exchange Right Holders primarily consist of Kelso, EMG and Tallgrass KC. Following consummation of the Blackstone Acquisition, the Exchange Right Holders will primarily consist of BIP and certain members of TGE's management. Pursuant to the TGE 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 years ended December 31, 2018 and 2016, the potential issuance of TGE Equity Participation Shares would have had a dilutive effect on basic net income per Class A share. The potential issuance of TGE Equity Participation Shares would not have had a dilutive effect on the basic net loss per Class A share for the year ended December 31, 2017. 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 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 consolidated statements of income. The following table illustrates the calculation of net income per Class A share for the years ended December 31, 2018 , 2017 , and 2016 : Year Ended December 31, 2018 2017 2016 (in thousands, except per unit amounts) Basic Net Income per Class A Share: Net income (loss) attributable to TGE, excluding predecessor operations interest $ 137,127 $ (128,729 ) $ 26,794 Basic weighted average Class A Shares outstanding 107,586 58,076 48,856 Basic net income (loss) per Class A share $ 1.27 $ (2.22 ) $ 0.55 Diluted Net Income per Class A Share: Net income (loss) attributable to TGE, excluding predecessor operations interest $ 137,127 $ (128,729 ) $ 26,794 Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares 2,108 — 9 Net income (loss) attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares $ 139,235 $ (128,729 ) $ 26,803 Basic weighted average Class A Shares outstanding 107,586 58,076 48,856 Equity Participation Shares equivalent shares 2,231 — 33 Diluted weighted average Class A Shares outstanding 109,817 58,076 48,889 Diluted net income (loss) per Class A Share $ 1.27 $ (2.22 ) $ 0.55

Major Customers and Concentrati

Major Customers and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2018
Risks and Uncertainties [Abstract]
Major Customers and Concentration of Credit Risk	During the years ended December 31, 2018 and 2017, one non-affiliated customer, Continental Resources, Inc. ("Continental Resources"), accounted for $81.9 million ( 10% ) and $100.2 million ( 15% ), of our total operating revenues, respectively. During the year ended December 31, 2016 , two non-affiliated customers, Continental Resources and Shell Trading (US) Company ("Shell"), accounted for $97.8 million ( 16% ) and $76.2 million ( 12% ) of our total operating revenues, respectively. Revenues from Continental Resources for the year ended December 31, 2018 were earned in our Crude Oil Transportation and Gathering, Processing & Terminalling segments. Revenues from Continental Resources for the years ended December 31, 2017 and 2016 were earned in our Crude Oil Transportation segment. Revenues from Shell for the year ended December 31, 2016 were earned in our Natural Gas Transportation, Crude Oil Transportation, and Gathering, Processing & Terminalling segments. For the year ended December 31, 2018 , the percentage of segment revenues from the top ten non-affiliated customers for each segment was as follows: Percentage of Segment Revenue Natural Gas Transportation 58% Crude Oil Transportation 84% Gathering, Processing & Terminalling 60% We attempt to mitigate credit risk by seeking credit support, such as letters of credit, prepayments or other financial guarantees from customers with specific credit concerns.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Based Compensation	Long-term Incentive Plan We have two long-term incentive plans. The Tallgrass Energy GP, LLC Long-Term Incentive Plan (f/k/a the TEGP Management, LLC Long-Term Incentive Plan), was originally adopted by our general partner effective as of May 1, 2015, and was amended and restated effective August 2, 2018 (as amended, the "TGE LTIP"). In addition, the Tallgrass MLP GP, LLC Long-Term Incentive Plan was originally adopted by TEP GP effective as of May 13, 2013, and was amended and restated effective August 2, 2018 (as amended, the "Legacy LTIP" and together with the TGE LTIP, the "Plans"). In connection with the completion of the TEP Merger effective June 30, 2018, the Legacy LTIP was assumed by our general partner. Awards under the Plans may consist of, among others, unrestricted shares, restricted shares, equity participation shares, options and share appreciation rights which may be granted to (i) the employees of our general partner and its affiliates who perform services for us, (ii) the non-employee directors of our general partner and (iii) the consultants who perform services for us. The TGE LTIP limits the number of shares that may be delivered pursuant to awards to 3,144,589 Class A shares, and the Legacy LTIP limits the number of shares that may be delivered pursuant to awards under such plan to 20,000,000 Class A shares, subject in each case to any adjustment due to recapitalization, reorganization or a similar event permitted under the applicable Plan. Shares that are forfeited or withheld to satisfy exercise price or tax withholding obligations are available for delivery pursuant to other awards under the applicable Plan. The Plans are administered by the board of directors of our general partner or a committee thereof, which is referred to as the plan administrator. Equity Participation Shares Vesting of the Equity Participation Shares granted to date is contingent on certain service and performance conditions. The Equity Participation Shares are non-participating; as such participants are not entitled to receive any dividends with respect to the Equity Participation Shares unless the participant receives a separate grant of Distribution Equivalent Rights. At this time, no grants of Distribution Equivalent Rights have been made. The Equity Participation Share grants under the Plans are measured at their grant date fair value. The Equity Participation Shares are non-participating; therefore, the grant date fair value is discounted from the grant date fair value of TGE's Class A shares for the present value of the expected future dividends during the vesting period. Effective June 30, 2018 with the completion of the TEP Merger, as discussed in Note 1 – Description of Business , TEP's outstanding Equity Participation Units were converted to Equity Participation Shares at a ratio of 2.0 Equity Participation Shares for each outstanding TEP Equity Participation Unit. Total equity-based compensation cost related to the Equity Participation Share grants was approximately $7.6 million , $1.6 million , and $1.4 million for the years ended December 31, 2018 , 2017 , and 2016 respectively, excluding costs associated with TEP's Equity Participation Units prior to the TEP Merger. Of the total compensation cost, $7.6 million , $0.2 million , and $0.2 million for the years ended December 31, 2018 , 2017 , and 2016 respectively, were recognized as compensation expense at TGE and the remainder was allocated to TEP and TD. As of December 31, 2018 , $34.3 million of total compensation cost related to non-vested Equity Participation Shares is expected to be recognized over a weighted-average period of 3.2 years . The following table summarizes the changes in the Equity Participation Shares outstanding for the years ended December 31, 2018 , 2017 and 2016 : Equity Participation Shares Weighted Average Outstanding at January 1, 2016 160,000 $ 27.97 Granted 45,000 18.22 Outstanding at December 31, 2016 205,000 25.83 Granted 30,000 23.66 Vested (10,002 ) (14.26 ) Outstanding at December 31, 2017 224,998 25.91 Granted 1,138,200 17.01 Converted (1) 1,786,310 18.20 Vested (20,664 ) (19.19 ) Forfeited (79,200 ) (20.62 ) Outstanding at December 31, 2018 3,049,644 $ 18.25 (1) Reflects TEP's outstanding Equity Participation Units that were converted to Equity Participation Shares at a ratio of 2.0 Equity Participation Shares for each outstanding TEP Equity Participation Unit upon completion of the TEP Merger as discussed above.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. We record a valuation allowance to reduce our deferred tax assets to the amount we believe is more likely than not to be realized. In making these determinations we consider historical and projected taxable income, and ongoing prudent and feasible tax planning strategies, in assessing the appropriateness of a valuation allowance. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective. U.S. Federal and State Taxes Although we are organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U.S. federal and state income taxes. We are projecting a loss for both U.S. federal and state income taxes for the tax year ended December 31, 2018 . As a result, there is no current provision for income taxes for the year ended December 31, 2018 . Tax Components Components of the deferred income tax expense are as follows: Year Ended December 31, 2018 2017 2016 (in thousands) Deferred income tax expense: Federal income tax $ 41,585 $ 200,787 $ 15,587 State income tax 14,124 7,671 2,154 Total deferred income tax expense $ 55,709 $ 208,458 $ 17,741 The difference between tax expense based on the statuary federal income tax rate and our effective tax expense is summarized as follows: Year Ended December 31, 2018 2017 2016 (in thousands) Net income before tax $ 523,380 $ 432,443 $ 267,780 Less: Predecessor operations interest in net income — — (6,995 ) Net income before tax, excluding predecessor operations interest 523,380 432,443 260,785 Less: Net income attributable to noncontrolling interests (330,544 ) (352,714 ) (216,250 ) Net income subject to tax $ 192,836 $ 79,729 $ 44,535 Federal statutory income tax rate 21 % 35 % 35 % Income tax at statutory rate $ 40,496 $ 27,905 $ 15,587 State income taxes, net of federal benefit 5,419 2,392 1,592 Change in state tax rate 8,705 1,353 562 Other 1,089 — — Valuation allowance — 3,926 — Total income tax expense before change in tax legislation $ 55,709 $ 35,576 $ 17,741 Impact of federal tax legislation on deferred tax asset — 172,037 — Impact of federal tax legislation on valuation allowance — 845 — Total income tax expense $ 55,709 $ 208,458 $ 17,741 Effective tax rate 10.6 % 48.2 % 6.8 % Deferred tax assets result from the following: December 31, 2018 December 31, 2017 (in thousands) Deferred tax assets: Investment in partnerships $ 198,290 $ 269,136 Net operating losses 80,012 48,632 Deferred tax assets before valuation allowance $ 278,302 $ 317,768 Valuation allowance (4,771 ) (4,771 ) Total deferred tax assets $ 273,531 $ 312,997 Deferred tax liability: Equity earnings adjustment pursuant to ASC 606 $ 817 $ — On May 12, 2015, as a result of the transfer of the ownership interest in Tallgrass Equity as part of the Reorganization Transactions in connection with the TGE IPO, we recognized a deferred tax asset of $445.2 million . In November 2016, we completed the Secondary Offering as discussed in Note 11 – Partnership Equity . In connection with the resulting transfer of Tallgrass Equity Units, we recognized an additional deferred tax asset of $86.8 million . During 2018, a portion of the Exchange Right Holders exercised their Exchange Right as discussed in Note 11 – Partnership Equity . In connection with the resulting transfer of Tallgrass Equity Units, we recognized an additional deferred tax asset of $15.4 million . These transfers of ownership were accounted for at the historical carrying basis for GAAP accounting purposes, but recorded at the value of the consideration paid for U.S. federal income tax purposes. The tax rates that apply when the deferred tax balances ultimately reverse are inherent in the realization of the deferred tax balances. State tax rates can change from year to year based upon changes in both state apportionment percentages and state tax laws. As of December 31, 2018 , we had a federal net operating loss carry forward of $328.2 million and various state net operating loss carry forwards. The determination of the state net operating loss carry forwards is dependent upon apportionment percentages and state laws that can change from year to year and impact the amount of such carry forwards. If not utilized, the federal net operating loss carry forward will expire between 2035 and 2037 and the state operating loss carry forwards will expire between 2025 and 2037. We believe that it is more likely than not that the benefit from certain state operating loss carryforwards will not be realized. In recognition of this risk, we have provided a valuation allowance on the deferred tax assets relating to these carryforwards. On December 22, 2017, legislation referred to as the "Tax Cuts and Jobs Act" ("TCJA") was signed into law. Substantially all provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes amendments to the Internal Revenue Code of 1986 that significantly change the taxation of individuals and business entities. Pursuant to ASC Topic 740, Income Taxes (ASC 740), we recognized the tax effect of the TCJA changes during the year ended December 31, 2017, the period in which the law was enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Accordingly, we remeasured our deferred tax asset based on the new tax rates, resulting in an increase to our tax provision of $172.9 million for the year ended December 31, 2017. The 2015 through 2018 tax years are open to examination for federal and state tax.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2018
Regulated Operations [Abstract]
Regulatory Matters	There are no regulatory proceedings challenging the rates of Pony Express, Rockies Express, or TIGT. On June 29, 2018, Trailblazer Pipeline Company LLC ("Trailblazer") filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act ("NGA"), as further described below. We have also made certain regulatory filings with the FERC, including the following: Rockies Express Petition for Declaratory Order – FERC Docket No. RP13-969-000 In June 2013, in Docket No. RP13-969-000, Rockies Express filed with the FERC a Petition for Declaratory Order which sought a ruling that the "most favored nations" or "MFN" provisions contained in Rockies Express' negotiated rate agreements ("NRAs") with its Foundation and Anchor Shippers would not prevent Rockies Express from providing firm transportation service at rates lower than Foundation and Anchor Shippers' rates that (1) have an east-to-west primary path; (2) are for a term of one year or longer; and (3) are limited to service in one rate zone and therefore do not utilize all of the same facilities or rate zones as the service provided pursuant to the Foundation and Anchor Shipper NRAs. In November 2013, the FERC issued a declaratory order finding that the potential transactions would not trigger the MFN rights of Rockies Express' Foundation and Anchor Shippers. Various parties filed requests for rehearing of the FERC's declaratory order. In September 2014 and December 2015, the FERC accepted amended contracts with the shippers holding MFN rights on Rockies Express, which reflect the terms of settlements between these shippers and Rockies Express. The settlements provide additional clarity with respect to the applicability of the settling shippers' MFN rights, sharing by Rockies Express of certain transportation revenues, and the withdrawal of the settling shippers from the Petition for Declaratory Order proceeding. On September 27, 2017, FERC issued an order denying the requests for rehearing of the declaratory order issued in November 2013, and no party sought judicial appeal of the FERC order denying rehearing within the statutory deadline. Seneca Lateral Facilities Conversion – FERC Docket No. CP15-102-000 On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with the FERC an application for (1) authorization to convert certain existing and operating pipeline and compression facilities located in Noble and Monroe Counties, Ohio (Seneca Lateral Facilities described in Docket Nos. CP13-539-000 and CP14-194-000) from Natural Gas Policy Act of 1978 Section 311 authority to NGA Section 7 jurisdiction, and (2) issuance of a certificate of public convenience and necessity authorizing Rockies Express to operate and maintain the Seneca Lateral Facilities. On April 7, 2016, the FERC issued a Certificate to Rockies Express granting its requested authorizations and on June 1, 2016 Rockies Express commenced NGA service on the Seneca Lateral. 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. RP16-702-000 and RP17-240-000 On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702-000. 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. RP17-240-000. The FERC issued an order accepting the filing on December 29, 2016. Electric Power Charge Clarification - FERC Docket No. RP17-285-000 On December 21, 2016, in Docket No. RP17-285-000, 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. RP17-401-000 and RP17-1064-000 On February 13, 2017, in Docket No. RP17-401-000, 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. RP17-1064-000 with a proposed effective date of November 1, 2017. The FERC issued an order accepting the filing on October 18, 2017. Increased Frequency of FL&U and PCT Adjustments - FERC Docket No. RP18-228-000 On December 1, 2017, in Docket No. RP18-228-000, Rockies Express made a filing with the FERC to increase the frequency in which it may adjust fixed fuel and lost and unaccounted for retainages and power cost tracker charges during the year so that its recovery of fixed fuel and lost and unaccounted for charges and power costs more closely track usage. Rockies Express proposed an effective date of April 1, 2018. The comment period ended on December 13, 2017, and no parties opposed Rockies Express' filing. On April 4, 2018, the FERC issued a letter order accepting Rockies Express' proposal, subject to certain modifications. Rockies Express submitted a compliance filing reflecting the approved tariff provisions and requested modifications on April 10, 2018. No comments on the compliance filing were submitted by the comment deadline of April 16, 2018. On April 18, 2018, the FERC issued an order accepting Rockies Express' compliance filing effective April 19, 2018. 2018 Annual FERC Fuel Tracking Filing - FERC Docket No. RP18-453-000 On February 20, 2018, in Docket No. RP18-453-000, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2018. The FERC issued an order accepting the filing on March 19, 2018. Cheyenne Hub Enhancement Project - FERC Docket No. CP18-103-000 On March 2, 2018, Rockies Express submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub. Rockies Express filed this certificate application in conjunction with a concurrently filed certificate application by Cheyenne Connector, LLC ("Cheyenne Connector") for the Cheyenne Connector Pipeline Project further described below. The comment period for the Cheyenne Hub Enhancement Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Rockies Express has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment. Rockies Express Form No. 501-G Filing - FERC Docket No. RP19-412-000 On December 6, 2018, Rockies Express submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. The filing remains pending before the FERC. Cheyenne Connector Cheyenne Connector Pipeline Project - FERC Docket No. CP18-102-000 On March 2, 2018, Cheyenne Connector, an indirect subsidiary of TGE, submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity to construct and operate a 70 -mile, 36 -inch pipeline to transport natural gas from multiple gas processing plants in Weld County, Colorado to Rockies Express' Cheyenne Hub. The comment period for the Cheyenne Connector Pipeline Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Cheyenne Connector has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment. TIGT General Rate Case Filing - FERC Docket No. RP16-137-000, et seq. On October 30, 2015, in Docket No. RP16-137-000, et seq. , TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA. The general rate case was ultimately resolved via settlement, which the FERC approved on November 2, 2016, and a compliance filing that modernized TIGT's FERC Gas Tariff, consistent with prior FERC orders, which the FERC accepted on March 16, 2017. Per the terms of the 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). 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. RP17-1051-000 On September 15, 2017, in Docket No. RP17-1051-000, TIGT proposed certain revisions to 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. 2018 Annual Fuel Tracker Filing - FERC Docket No. RP18-533-000 On March 1, 2018, in Docket No. RP18-533-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2018. The FERC accepted the filing on March 22, 2018. TIGT Form No. 501-G Filing - FERC Docket No. RP19-423-000 On December 6, 2018, TIGT submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. On December 18, 2018, one protest and one set of comments were filed by intervenors in the docket. The filing remains pending before the FERC. Trailblazer 2016 Annual Fuel Tracker Filing – FERC Docket Nos. RP16-814-000 and RP16-814-001 On April 1, 2016, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2016 in Docket No. RP16-814-000. The FERC accepted this filing on April 18, 2016. On May 19, 2016, Trailblazer filed its refund report associated with the April 1, 2016 annual fuel tracker filing, which the FERC accepted on July 11, 2016. On September 7, 2016, Trailblazer filed an adjustment to its April 1, 2016 filing in Docket No. RP16-814-001, which the FERC accepted on October 3, 2016. Trailblazer filed a corresponding refund report on October 14, 2016, which the FERC accepted on November 16, 2016. 2017 Annual and Interim Fuel Tracker Filings - FERC Docket Nos. RP17-549-000 and RP17-1052-000 On March 22, 2017, in Docket No. RP17-549-000, 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. RP17-1052-000 with a proposed effective date of November 1, 2017. The FERC accepted the filing on October 13, 2017. 2018 Annual Fuel Tracker Filing - FERC Docket No. RP18-580-000 On March 22, 2018, in Docket No. RP18-580-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2018. The FERC accepted the filing on April 20, 2018. General Rate Case Filing - FERC Docket No. RP18-922-000, et seq. On June 29, 2018, Trailblazer filed a general rate case with the FERC, which satisfies the requirement set forth in the settlement resolving Trailblazer's previous general rate case that Trailblazer file a new general rate case with rates to be effective no later than January 1, 2019. The June 29, 2018 filing reflects an overall increase to Trailblazer's cost of service. In the filing, Trailblazer is proposing to maintain its existing bifurcated firm transportation service rate design as well as its current tracking methodologies for the treatment of Fuel and Lost and Unaccounted For ("FL&U") gas and electric power costs. The proposed rates include an increase in rates on Trailblazer's Existing System Firm Transportation Service. The overall rate increase would be partially offset by a proposed decrease in rates for Expansion System Firm Transportation Service and interruptible services. Trailblazer is also proposing to include a cost recovery mechanism in its tariff to recover future eligible costs related to system safety, integrity, reliability, environmental and cybersecurity issues. Under the NGA and the FERC's regulations, Trailblazer's shippers and other interested parties, including the FERC's Trial Staff, have the right to challenge any aspect of Trailblazer's rate case filing. On July 11, 2018, four protests were filed that challenge various aspects of Trailblazer's rate case filing. FERC action remains pending. On July 31, 2018, the FERC issued an Order accepting and suspending the rate case filing, and establishing hearing and settlement procedures. In the Order, the FERC approved the as-filed rate decreases for Expansion System Firm Transportation Service, as well as Trailblazer's interruptible services, effective August 1, 2018. The Commission also established a paper hearing to examine the extent to which Trailblazer is entitled to an income tax allowance. All remaining issues, including the proposed rate increases to Existing System Firm Transportation Service have been set for hearing and are accepted effective January 1, 2019, subject to refund. On August 30, 2018, Trailblazer and certain of Trailblazer's shippers filed a request for rehearing of the July 31, 2018 Order, which remains pending before the FERC. Consistent with the July 31, 2018 Order, on August 30, 2018, certain of Trailblazer's shippers and other interested parties filed initial briefs regarding the Income Tax Allowance issue. Trailblazer filed its reply brief regarding the same on September 14, 2018. On November 1, 2018, Trailblazer filed a supplement to its reply brief addressing a recent FERC order regarding the appropriate methodology used to calculate return on equity and discussing the impact of such order on Trailblazer's proposed Income Tax Allowance. The briefs remain pending before the FERC. On August 28, 2018, the participants attended an initial settlement conference. On September 12, 2018, the Chief Administrative Law Judge issued an order continuing settlement judge procedures. On November 15, 2018, the participants attended a second settlement conference. On December 31, 2018, Trailblazer filed a motion with the FERC to move the suspended tariff records into effect as of January 1, 2019. In January 2019, the participants attended a third settlement conference. A fourth settlement conference is scheduled in late February 2019. Pony Express On May 25, 2016, Pony Express made a tariff filing with the FERC in Docket No. IS16-326-000 to update its non-contract rates under its Local Pipeline Tariff for local non-contract rates from all origins, by an amount reflecting the most recent FERC annual index adjustment of approximately 0.9799 effective July 1, 2016, which resulted in a reduction of the Pony Express non-contract rates of 2.01% . On May 22, 2017 and May 31, 2017, Pony Express made tariff filings with the FERC in Docket Nos. IS17-263-000, IS17-464-000, and IS17-465-000 to increase the contract and non-contract rates by an amount reflecting the FERC annual index adjustment of approximately 0.2% , which became effective July 1, 2017. On November 30, 2017, Pony Express filed with the FERC in Docket No. IS18-60-000 certain changes to its tariffs to reflect the addition of two new destination points, which became effective January 1, 2018. On December 29, 2017, Pony Express filed with the FERC in Docket No. IS18-113-000 certain changes to its tariffs to reflect a new origin point in Rooks County, Kansas, which became effective on February 1, 2018. On February 28, 2018, Pony Express filed with the FERC in Docket No. IS18-199-000 certain changes to its tariffs to reflect a new origin point in Platteville, Colorado, which became effective on April 1, 2018. On March 1, 2018, Pony Express submitted proposed revisions to its Rules and Regulations Tariff in Docket No. IS18-204-000 to establish the right to accept "Specialty Batches" of oil that do not conform to the Quality Specifications reflected in the tariff, provided that the acceptance is operationally feasible. These tariff changes became effective on April 1, 2018. On April 11, 2018, Pony Express filed with the FERC in Docket No. IS18–267–000 certain changes to its tariffs to reflect additional contract rates from a new origin point in Platteville, Colorado, which became effective May 1, 2018. On May 2, 2018, Pony Express filed with the FERC in Docket No. IS18-297-000 certain changes to its rules and regulations applicable to new intermediate off-system storage points, which became effective May 15, 2018. On May 31, 2018, Pony Express made tariff filings with the FERC in Docket No. IS18-570-000 to increase the contract and non-contract rates by an amount reflecting the FERC annual index adjustment of approximately 4.4% which became effective July 1, 2018. On January 11, 2019, Pony Express filed with the FERC in Docket No. IS19-145-000 certain changes to its tariffs to incorporate the Sterling origin point in Logan County, Colorado in the published rate schedules, to establish a line fill return rate from the Natoma origin point, and to make minor clarifying edits. Iron Horse Petition for Declaratory Order - FERC Docket No. OR19-9-000 On November 9, 2018, Iron Horse filed a Petition for Declaratory Order with the FERC, requesting approval of Iron Horse's proposed rate structures, Committed Shipper rights, and prorationing provisions for shippers and various other aspects of the Transportation Service Agreement for service on the pipeline. The Petition is pending before the FERC.

Legal and Environmental Matters

Legal and Environmental Matters	12 Months Ended
	Dec. 31, 2018
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 matters 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 December 31, 2018 and 2017 . Rockies Express Ohio Public Utility Excise Tax The Ohio Tax Commissioner has assessed Rockies Express a public utility excise tax on transactions concerning product that entered and exited Rockies Express within the state of Ohio. This tax applies to gross receipts from all business conducted within the state, but exempts all receipts derived wholly from interstate business. Rockies Express has disputed any obligation to pay Ohio's public utility excise tax, but has paid the taxes as assessed in order to preserve its right to appeal. The dispute is currently pending before the Ohio Supreme Court, with a final decision possible by the end of 2019. It is Rockies Express' position that the relevant statute exempts receipts derived wholly from interstate business from the public utility excise tax. The Ohio Supreme Court and the United States Supreme Court have both held that, once it enters an interstate pipeline, natural gas is moving in "interstate commerce" for the duration of its journey until it is delivered to a local distribution system. While it is difficult to accurately predict how the Ohio Supreme Court will decide the case, Rockies Express is optimistic about the ultimate outcome. As of December 31, 2018, Rockies Express has paid public utility excise taxes to the state of Ohio totaling $7.1 million , accrued an additional $3.3 million for amounts expected to be assessed through the year ended December 31, 2018, and has recognized a $10.4 million deposit representing the anticipated refund of the public utility excise taxes paid. Mineral Management Service Lawsuit On June 30, 2009, Rockies Express filed claims against Mineral Management Service, a former unit of the U.S. Department of Interior (collectively "Interior") for breach of its contractual obligation to sign transportation service agreements for pipeline capacity that it had agreed to take on Rockies Express. The Civilian Board of Contract Appeals ("CBCA") conducted a trial and ruled that Interior was liable for breach of contract, but limited the damages Interior was required to pay. On September 13, 2013, the United States Court of Appeals for the Federal Circuit issued a decision affirming that Interior was liable for its breach of contract, but reversing the CBCA's decision to limit damages. The case was remanded to the CBCA for the purpose of calculating damages at a hearing. On May 20, 2016, Rockies Express and Interior agreed to resolve the claims in this matter in exchange for a $65 million cash payment to Rockies Express. Interior paid the amount due Rockies Express on June 23, 2016. Ultra Resources In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, 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. We received our 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 currently 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 $7.4 million and $7.7 million at December 31, 2018 and 2017 , respectively. Rockies Express Seneca Lateral On January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations. The release required Rockies Express to shut off the flow through the segment until February 27, 2018, when temporary repairs were completed allowing the segment to be placed back into service. Total cost of remediation was approximately $6.1 million prior to any insurance recoveries. Permanent repairs were completed in September 2018. As of February 8, 2019 , Rockies Express has recovered a significant majority of these costs from insurance. 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. 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. TMG Archibald Booster Station Tallgrass Midstream Gathering, LLC ("TMG") is currently a party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Archibald Booster Station located in Campbell County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling, and quarterly recovery activities at monitoring wells. The facility is currently in compliance with the WDEQ under the remedy agreement. Irwin Booster Station TMG is also party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Irwin Booster Station located in Converse County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling. The facility is currently in compliance with the WDEQ under the remedy agreement. Trailblazer Pipeline Integrity Management Program Starting in 2014 Trailblazer's operating capacity was decreased as a result of smart tool surveys that identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing subscription levels or had a material adverse financial impact on us. However, Trailblazer continued performing remediation to increase and maximize its operating capacity over the long-term and spent approximately $21 million during 2018 for this pipe replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable operating capacity. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms. In connection with TEP's acquisition of Trailblazer in April 2014, TD agreed to indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline. The contractual indemnity was capped at $20 million and subject to a $1.5 million deductible. TEP received the entirety of the $20 million from TD pursuant to the contractual indemnity as of December 31, 2017. Pony Express Pipeline Integrity In connection with certain crack tool runs on the Pony Express System completed in 2015, 2016, and 2017, Pony Express completed approximately $18 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. Remediation work was substantially complete as of March 31, 2018. 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 .

Reporting Segments

Reporting Segments	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Reporting Segments	Our operations are located in the United States. We are organized into three reportable segments: (1) Natural Gas Transportation, (2) Crude Oil Transportation, and (3) Gathering, Processing & Terminalling. Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with our revolving credit facility and the Senior Notes, public company costs, and equity-based compensation expense. 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 aggregate 75% membership interest in Rockies Express, inclusive of the additional 25.01% membership interest acquired effective February 7, 2018. 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. Gathering, Processing & Terminalling The Gathering, Processing & Terminalling segment is engaged in the ownership and operation of natural gas gathering and processing facilities that produce NGLs and residue gas sold in local wholesale markets or delivered into pipelines for transportation to additional end markets; our crude oil terminal services; water business services provided primarily to the oil and gas exploration and production industry; the transportation of NGLs; and Stanchion. 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. During the second quarter of 2018, upon completion of the TEP Merger, management updated TGE's internal reporting. Beginning in the second quarter of 2018, we consider Adjusted EBITDA, as described below, to be our primary segment performance measure. We consider Adjusted EBITDA to be our primary segment performance measure as we believe it is the most meaningful measure to assess our financial condition and results of operations as a public entity. We define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments and deficiency payments received from or utilized by our customers. Adjusted EBITDA is calculated and presented at the Tallgrass Equity level, before consideration of noncontrolling interest associated with the Exchange Right Holders, which we believe provides investors the most complete picture of our overall financial and operational results. The following tables set forth our segment information for the periods indicated: Year Ended December 31, 2018 2017 2016 Revenue: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 140,459 $ (4,661 ) $ 135,798 $ 141,021 $ (6,694 ) $ 134,327 $ 135,097 $ (5,641 ) $ 129,456 Crude Oil Transportation 444,454 (39,319 ) 405,135 364,574 (10,676 ) 353,898 380,503 (370 ) 380,133 Gathering, Processing & Terminalling 279,665 (27,339 ) 252,326 186,211 (18,538 ) 167,673 113,533 (11,460 ) 102,073 Total revenue $ 864,578 $ (71,319 ) $ 793,259 $ 691,806 $ (35,908 ) $ 655,898 $ 629,133 $ (17,471 ) $ 611,662 Year Ended December 31, 2018 2017 2016 Tallgrass Equity Adjusted EBITDA: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 377,224 $ (4,251 ) $ 372,973 $ 180,978 $ (2,176 ) $ 178,802 $ 75,029 $ (1,633 ) $ 73,396 Crude Oil Transportation 239,330 (8,147 ) 231,183 140,785 4,878 145,663 132,154 4,881 137,035 Gathering, Processing & Terminalling 59,203 12,398 71,601 16,083 (2,702 ) 13,381 4,078 (3,248 ) 830 Corporate and Other (21,321 ) — (21,321 ) (37,591 ) — (37,591 ) (2,142 ) — (2,142 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investments (1) 237,197 66,922 15,287 Gain (loss) on disposal of assets (1) 4,630 189 (526 ) Non-cash gain (loss) related to derivative instruments (1) 3,340 (64 ) (650 ) Gain on remeasurement of unconsolidated investment (1) — 2,744 — Less: Interest expense, net (1) (95,465 ) (29,403 ) (16,632 ) Depreciation and amortization expense (1) (74,998 ) (26,131 ) (25,567 ) Distributions from unconsolidated investments (1) (302,364 ) (86,551 ) (22,085 ) Non-cash compensation expense (1) (8,634 ) (2,682 ) (1,862 ) Deficiency payments, net (1) (14,443 ) (7,701 ) (9,672 ) Loss on debt retirement (2,245 ) — — Deferred income tax expense (55,709 ) (208,458 ) (17,741 ) Net income attributable to Exchange Right Holders (208,618 ) (137,849 ) (95,882 ) Net income (loss) attributable to TGE $ 137,127 $ (128,729 ) $ 33,789 (1) Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity. Year Ended December 31, Capital Expenditures: 2018 2017 2016 (in thousands) Natural Gas Transportation $ 112,529 $ 16,705 $ 28,475 Crude Oil Transportation 65,745 57,022 29,893 Gathering, Processing & Terminalling 185,732 71,417 26,123 Corporate and Other 4,867 — — Total capital expenditures $ 368,873 $ 145,144 $ 84,491 Unconsolidated Investments: December 31, 2018 December 31, 2017 (in thousands) Natural Gas Transportation $ 1,794,987 $ 895,873 Crude Oil Transportation 35,467 — Gathering, Processing & Terminalling 31,232 13,658 Total unconsolidated investments $ 1,861,686 $ 909,531 Assets: December 31, 2018 December 31, 2017 (in thousands) Natural Gas Transportation $ 2,606,696 $ 1,606,666 Crude Oil Transportation 1,423,740 1,407,758 Gathering, Processing & Terminalling 1,522,559 943,340 Corporate and Other 340,514 334,249 Total assets $ 5,893,509 $ 4,292,013

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2018
Selected Quarterly Financial Data (Unaudited) [Abstract]
Quarterly Financial Information	The following tables summarize our unaudited quarterly financial data for 2018 and 2017 : Quarter Ended 2018 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 179,094 $ 193,589 $ 200,320 $ 220,256 Operating income $ 81,913 $ 79,275 $ 90,084 $ 99,359 Net income $ 114,313 $ 109,701 $ 118,712 $ 124,945 Net income allocable to noncontrolling interests $ (97,578 ) $ (108,638 ) $ (59,162 ) $ (65,166 ) Net income attributable to TGE $ 16,735 $ 1,063 $ 59,550 $ 59,779 Basic net income per Class A Share $ 0.29 $ 0.02 $ 0.38 $ 0.38 Diluted net income per Class A Share $ 0.29 $ 0.02 $ 0.38 $ 0.38 During the second quarter of 2018, we recognized increased deferred income tax expense as a result of our increased ownership in TEP due to the TEP Merger and the resulting increase in income allocated to TGE. Quarter Ended 2017 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 144,400 $ 160,863 $ 175,869 $ 174,766 Operating income $ 63,226 $ 66,944 $ 74,003 $ 67,674 Net income $ 67,238 $ 79,167 $ 170,777 $ (93,197 ) Net income allocable to noncontrolling interests $ (55,209 ) $ (70,414 ) $ (154,911 ) $ (72,180 ) Net income (loss) attributable to TGE $ 12,029 $ 8,753 $ 15,866 $ (165,377 ) Basic net income (loss) per Class A Share $ 0.21 $ 0.15 $ 0.27 $ (2.85 ) Diluted net income (loss) per Class A Share $ 0.21 $ 0.15 $ 0.27 $ (2.85 ) During the third quarter of 2017, we recognized equity in earnings relating to our proportionate share of the Ultra settlement discussed in Note 19 – Legal and Environmental Matters . During the fourth quarter of 2017, we remeasured our deferred tax asset based on the new tax rates as a result of the federal rate change under the TCJA signed into law on December 22, 2017, resulting in an increase to our tax provision. For additional information, see Note 17 – Income Taxes .

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Powder River Gateway In January 2019, we closed on an expansion of our joint venture with Silver Creek. Effective January 1, 2019, we own a 51% membership interest in Powder River Gateway, which owns the Iron Horse Pipeline, the PRE Pipeline, and crude oil terminal facilities in Guernsey, Wyoming. For additional information, see Note 3 – Acquisitions and Dispositions . Blackstone Acquisition On January 31, 2019, we announced that BIP had entered into a definitive purchase agreement with Kelso, EMG, and Tallgrass KC pursuant to which BIP will acquire 100% of the membership interests in our general partner and an approximate 44% economic interest in us. Subject to customary closing conditions, the Blackstone Acquisition is expected to close within the first quarter of 2019.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements and related notes were prepared in conformity with accounting principles generally accepted in the United States of America ("GAAP"). 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.
Consolidation	As further discussed in Note 3 – Acquisitions and Dispositions , we 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 contributions of the Predecessor Entities included in the consolidated financial statements represent transfers of cash as a result of Tallgrass Development's ("TD") 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 consolidated financial statements of TGE include historical cost-basis accounts of the assets of Terminals and NatGas for the periods prior to January 1, 2017, the date we 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. TGE, 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 TGE at historical cost. The consolidated financial statements include the accounts of TGE 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 TGE is attributed to TGE and noncontrolling interests in accordance with the respective ownership interests. 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 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 did not have material assets that could only be used to settle specific obligations of the consolidated VIEs. Prior to June 29, 2018, both Tallgrass Equity and TEP were considered to be VIEs under the applicable authoritative guidance and included in our consolidated results. As a result of the TEP Merger, and changes in ownership and their respective partnership arrangements, Tallgrass Equity and TEP are no longer considered to be VIEs. We continue to consolidate our membership interests in Tallgrass Equity and TEP through the voting interest model.
Use of Estimates	Use of Estimates Certain amounts included in or affecting these 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.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Net equity contributions of the Predecessor Entities included in the consolidated statements of cash flows represent transfers of cash as a result of TD's centralized cash management systems prior to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions.
Accounts Receivable and Allowance for Doubtful Accounts Accounts Receivable and Allowance for Doubtful Accounts Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are carried at their estimated collectible amounts. We make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and adjustments are recorded as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $7.7 million and $0.5 million at December 31, 2018 and 2017 , respectively.
Inventories	Inventories Inventories primarily consist of crude oil, materials and supplies, gas in underground storage, and natural gas liquids. As discussed further under " Revenue Recognition " below, a loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline loss allowance oil, or PLA, which we can then sell. As PLA oil is accumulated, it is recorded as inventory at the lower of historical cost and net realizable value using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence. Natural gas liquids and gas in underground storage, sometimes referred to as working gas, are recorded at the lower of historical cost and net realizable value using the average cost method. For additional information, see " Gas in Underground Storage " below.
Accounting for Regulatory Activities	Accounting for Regulatory Activities Regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We recorded regulatory assets of approximately $3.2 million and $2.6 million included in "Prepayments and other current assets" and "Deferred charges and other assets" in the consolidated balance sheets at December 31, 2018 and 2017 , respectively. Regulatory assets at December 31, 2018 and December 31, 2017 were primarily attributable to costs associated with fuel tracker assets at our regulated natural gas pipelines as well as both Trailblazer's 2013 and 2018 Rate Case Filings and TIGT's 2015 Rate Case Filing . We recorded regulatory liabilities of approximately $1.9 million and $2.3 million included in "Other current liabilities" in the consolidated balance sheets at December 31, 2018 and 2017 , respectively, related to fuel tracker liabilities at our regulated natural gas pipelines. For further information regarding our rate case filings and fuel tracker balances, see Note 18 – Regulatory Matters .
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs related to the construction of assets, including internal labor costs, interest and engineering costs. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation and/or the negative salvage liability discussed under "Depreciation and Amortization" below, as appropriate, with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred.
Intangible Assets	Intangible Assets We establish identifiable intangible assets when they meet either the separability criterion or the contractual-legal criterion. Contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of TIGT's natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years , the period of expected future benefit. During 2018, we recognized additional intangible assets at Plaquemines Liquids Terminal, LLC ("PLT"), a newly formed subsidiary as discussed in Note 3 – Acquisitions and Dispositions , from the acquisition of permits, designs, and other work-product related to the development and construction of a crude oil terminal facility in Louisiana. These intangible assets will be amortized on a straight-line basis over a period of 35 years , the period of expected future benefit. Also, during 2018, we recognized an intangible asset associated with customer relationships as part of our acquisition of NGL Water Solutions Bakken, LLC as discussed in Note 3 – Acquisitions and Dispositions . The customer relationships are amortized on a straight-line basis over a period of 8 years. Other intangible assets include customer contracts amortized on a straight-line basis over a period of 2 - 14 years, based on the remaining term of the contracts at the time of acquisition.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset or asset group's use and its eventual disposition are less than its carrying amount. We assess our long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset or asset group is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Examples of long-lived asset impairment indicators include: • a significant decrease in the market value of a long-lived asset or asset group; • a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition; • a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process; • an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group; • a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and • a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. When an impairment indicator is present, we first assess the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset or asset group to its carrying amount. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the asset or asset group is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized.
Gas in Underground Storage	Gas in Underground Storage Gas in underground storage represents the cost of base gas, which refers to the volumes necessary to maintain pressure and deliverability requirements in our storage facilities. We record base gas as a component of property, plant and equipment. We maintain working gas in our underground storage facilities on behalf of certain third parties. We receive a fee for our storage services but do not reflect the value of third-party gas in the accompanying consolidated financial statements. We occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost and net realizable value.
Depreciation and Amortization	Depreciation and Amortization For non-regulated assets, we have elected to use the straight-line method of depreciation. For our regulated assets, we have elected to compute depreciation using a composite method employed by applying a single depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. The depreciation rates for our regulated natural gas pipeline assets include two components, one based on economic service life (capital recovery) and one based on net costs of removal (negative salvage). The accumulated liability related to negative salvage is classified as "Other long-term liabilities and deferred credits" in our consolidated balance sheets. The rates of depreciation for the various classes of depreciable assets are as follows: Range of Depreciation Rates Crude oil pipelines 2.8% Natural gas pipelines 0.7% - 5.0% Gathering & processing assets 2.2% - 5.0% Water business assets 2.3% - 20.0% Terminal assets 1.8% - 2.8% Replacement Gas Facilities (1) 10.0% General & other 2.9% - 25.0% (1) Represents costs incurred by TIGT, and reimbursed by Pony Express, for the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System after having sold approximately 433 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013.
Gas Imbalances	Gas Imbalances Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing and imbalance agreements. Gas imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements. Imbalances are valued at applicable average market index prices. Gas imbalances receivable and payable are included in "Prepayments and other current assets" and "Other current liabilities" in the consolidated balance sheets.
Deferred Financing Costs	Deferred Financing Costs Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method. Deferred financing costs associated with long-term debt are presented as a reduction to the corresponding debt in our consolidated balance sheets. Deferred financing costs associated with our revolving credit facility are presented as noncurrent assets in our consolidated balance sheets. During the year ended December 31, 2018, we recognized a $2.2 million loss on debt retirement, recorded as "Other income, net" in the accompanying consolidated statements of income, associated with the write off of deferred financing costs associated with the Amendment to the TEP revolving credit facility and the termination of the Tallgrass Equity revolving credit facility as discussed further in Note 10 – Long-term Debt .
Goodwill	Goodwill 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. 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. 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. See Note 8 – Goodwill and Other Intangible Assets for additional information regarding impairment testing performed during 2018.
Investment in Unconsolidated Affiliates	Investment in Unconsolidated Affiliates We use the equity method to account for investments in 20% or greater owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where we have the ability to exercise significant influence. We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary. See Note 7 – Investments in Unconsolidated Affiliates for additional information regarding our investment in unconsolidated affiliates.
Revenue Recognition	Revenue Recognition In May 2014, the FASB issued Accounting Standards Update ("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. Management completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. 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 members' equity. Consolidated revenues presented in the comparative consolidated financial statements for periods prior to January 1, 2018 have not been revised. On January 1, 2018, we recorded a cumulative effect adjustment to equity of $44.1 million , increased the carrying amount of our investment in Rockies Express by $42.8 million , and recognized a receivable from Rockies Express of $1.3 million . These adjustments relate to the cumulative effect adjustment recorded by Rockies Express of $125.2 million upon adoption of ASC 606. The cumulative effect adjustment at Rockies Express arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with rates that vary throughout the term of the contract. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas during the periods prior to implementation. Through our review process, we also identified the following changes to our revenue recognition policies that did not result in a cumulative effect adjustment on January 1, 2018: • Gathering & Processing. We have determined that a number of our gathering & processing contracts at TMID do not represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of raw gas are accounted for as supply arrangements pursuant to ASC 705. As a result, gathering & processing fees previously recognized in revenue are reported as a reduction to cost of sales under ASC 606. • Pipeline Loss Allowance. We have determined that PLA collected under certain crude oil transportation arrangements is a component of the transaction price where the PLA both significantly exceeds actual losses and was negotiated with the intent of providing a revenue stream to Pony Express. Under ASC 606, PLA barrels retained from customers are subject to the guidance for noncash consideration and recognized in revenue at their contract inception fair value. See Note 12 – Revenue from Contracts with Customers for revenue disclosures related to both the implementation and 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.
Commitments and Contingencies	Commitments and Contingencies We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss.
Environmental Costs	Environmental Costs We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action. Estimates of environmental liabilities are based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of other factors including our prior experience in remediating contaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information.
Fair Value	Fair Value Fair value, as defined in the Codification, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. We apply the fair value measurement guidance to financial assets and liabilities in determining the fair value of derivative assets and liabilities, and to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill. The fair value measurement accounting guidance requires that we make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments' fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity. Fair value, where available, is based on observable market prices. Where observable market prices or inputs are not available, different valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments' complexity. To increase consistency and enhance disclosure of fair value, the Codification creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability's level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows: • Level 1 Inputs-quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date; • Level 2 Inputs-inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and • Level 3 Inputs-unobservable inputs for the asset or liability. These unobservable inputs reflect the entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity's own data). Any transfers between levels within the fair value hierarchy are recognized at the end of the reporting period. For information regarding financial instruments measured at fair value on a recurring basis, see Note 9 – Risk Management . For information regarding the fair value of financial instruments not measured at fair value in the consolidated balance sheets, see Note 10 – Long-term Debt .
Risk Management Activities	Risk Management Activities Our operations expose us to a variety of risks including, but not limited to, changes in the prices of commodities that we buy or sell. We manage these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including establishing and monitoring exposure limits. We record derivative contracts at their estimated fair values as of each reporting date and present profit and loss activity on a net basis in "Processing and other revenues" in our consolidated statements of operations. For more information on our risk management activities, see Note 9 – Risk Management .
Equity-Based Compensation	Equity-Based Compensation Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. As discussed in Note 16 – Equity-Based Compensation , prior to February 2018 a portion of the expense recognized relating to equity-based compensation grants was charged to TD.
Income Taxes	Income Taxes Although TGE is organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U.S. federal and state income taxes. TGE's consolidated subsidiaries consist primarily of entities that are flow-through entities for income tax purposes. We also own certain C corporation subsidiaries which have been formed for the purpose of potential pipeline construction and other investment purposes. In addition, Tallgrass Energy Finance Corp. is a wholly owned subsidiary of TEP that has no material assets and was formed for the sole purpose of being a co-issuer of TEP's senior notes as discussed in Note 10 – Long-term Debt . These C corporation subsidiaries have not commenced operations or generated any material income, and as a result no provision for federal or state income taxes has been recorded in our consolidated financial statements. Deferred income taxes are provided for temporary differences arising from differences between the consolidated financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates expected to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not that a deferred tax asset will not be realized. In determining the appropriate valuation allowance, we consider projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies, and our overall deferred tax position. Pursuant to the applicable guidance related to accounting for uncertainty in income taxes, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2018 , we had not recognized any material amounts in connection with uncertainty in income taxes.
Business Combinations	Business Combinations We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill or gain from a bargain purchase. For material or complex acquisitions, management typically engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, noncontrolling interest, if any, and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, we will record any material adjustments to the initial estimate based on new information obtained about facts and circumstances that existed as of the acquisition date. An income, market or cost valuation approach may be utilized to estimate the fair value of the assets acquired, liabilities assumed, and noncontrolling interest, if any, in a business combination. We typically use an income approach, such as the multi-period excess earnings method, to value intangible assets. The income approach requires management to estimate future cash flows: (i) discrete financial forecasts, which rely on management's estimates of gross margin and operating expenses; (ii) terminal growth rates; and (iii) appropriate discount rates. We typically use a cost approach to value property, plant and equipment. The cost approach is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. See Note 3 – Acquisitions and Dispositions for additional information regarding our business combinations.
Accounting Pronouncements Issued But Not Yet Effective	Accounting Pronouncements Not Yet Adopted 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 right-of-use ("ROU") 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. Subsequent to issuing ASU 2016-02, the FASB has issued a series of subsequent updates to the lease guidance in Topic 842, including ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, ASU No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, and ASU 2018-20, Leases (Topic 842): Narrow-Scope Improvements for Lessors. The amendments in ASU 2016-02, ASU 2018-01, ASU 2018-10, ASU 2018-11, and ASU 2018-20 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2019. The approach allows us to (i) initially apply ASC 842 at the adoption date, January 1, 2019 and (ii) continue reporting comparative periods presented in the financial statements in the period of adoption under ASC 840. We will not recast comparative periods in the consolidated financial statements. We have elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements as property, plant and equipment. Adoption of the new standard resulted in the recognition of ROU assets and lease liabilities for operating leases as of January 1, 2019. Excluding ROU assets and lease liabilities relating to agreements between consolidated subsidiaries, the ROU assets and liabilities recognized as of January 1, 2019 are not expected to be material. Our accounting for finance leases remained substantially unchanged.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Schedule Of Estimated Useful Life	The rates of depreciation for the various classes of depreciable assets are as follows: Range of Depreciation Rates Crude oil pipelines 2.8% Natural gas pipelines 0.7% - 5.0% Gathering & processing assets 2.2% - 5.0% Water business assets 2.3% - 20.0% Terminal assets 1.8% - 2.8% Replacement Gas Facilities (1) 10.0% General & other 2.9% - 25.0% (1) Represents costs incurred by TIGT, and reimbursed by Pony Express, for the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System after having sold approximately 433 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013.

Acquisitions & Dispositions - B

Acquisitions & Dispositions - Business Combinations (Tables)	12 Months Ended
	Dec. 31, 2018
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	Unaudited pro forma revenue and net income (loss) attributable to TGE for the years ended December 31, 2018 and 2017 is presented below as if the acquisitions of BNN North Dakota, NGL Water Solutions Bakken, and BNN Colorado had been completed on January 1, 2017. Unaudited pro forma revenue and net (loss) income attributable to TGE for the years ended December 31, 2017 and 2016 is presented below as if the acquisitions of TCG and Deeprock Development had been completed on January 1, 2016. Year Ended December 31, 2018 2017 2016 (in thousands) Revenue $ 813,286 $ 686,803 $ 632,528 Net income (loss) attributable to TGE $ 140,005 $ (129,155 ) $ 34,311
Impact of Adjustments Related to Transaction Among Entities Under Common Control, Income Statement	The following table presents the previously reported consolidated statements of income for the year ended December 31, 2016 adjusted for the acquisitions of Terminals and NatGas: Year Ended December 31, 2016 TGE (As previously reported) Consolidate Terminals Consolidate NatGas Elimination TGE (As currently reported) (in thousands) Revenues: Crude oil transportation services $ 374,949 $ — $ — $ — $ 374,949 Natural gas transportation services 119,962 — — — 119,962 Sales of natural gas, NGLs, and crude oil 77,394 99 — (370 ) (1) 77,123 Processing and other revenues 32,817 12,043 6,228 (11,460 ) (2) 39,628 Total Revenues 605,122 12,142 6,228 (11,830 ) 611,662 Operating Costs and Expenses: Cost of sales 71,920 100 — (370 ) (1) 71,650 Cost of transportation services 58,341 788 — (11,460 ) (2) 47,669 Operations and maintenance 53,386 1,684 — — 55,070 Depreciation and amortization 84,896 1,351 — — 86,247 General and administrative 55,829 1,469 — — 57,298 Taxes, other than income taxes 24,727 673 — — 25,400 Contract termination — 8,061 (3) — — 8,061 Loss on disposal of assets 1,849 — — — 1,849 Total Operating Costs and Expenses 350,948 14,126 — (11,830 ) 353,244 Operating Income (Expense) 254,174 (1,984 ) 6,228 — 258,418 Other Income (Expense): Equity in earnings of unconsolidated investments 51,780 2,751 — — 54,531 Interest expense, net (45,601 ) — — — (45,601 ) Other income, net 432 — — — 432 Total Other Income 6,611 2,751 — — 9,362 Net income before tax 260,785 767 6,228 — 267,780 Deferred income tax expense (17,741 ) — — — (17,741 ) Net income 243,044 767 6,228 — 250,039 Net income attributable to noncontrolling interests (216,250 ) — — — (216,250 ) Net income attributable to TGE $ 26,794 $ 767 $ 6,228 $ — $ 33,789 (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.
BNN Colorado Water, 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 (in thousands): Accounts receivable $ 4,053 Property, plant and equipment 18,535 Intangible asset 7,922 (1) Accounts payable and accrued liabilities (53 ) Deferred revenue (4,053 ) Net identifiable assets acquired (excluding cash) $ 26,404 (1) The $7.9 million intangible asset acquired represents a customer contract. This intangible asset is amortized on a straight-line basis over a period of approximately 3 years, the remaining term of the underlying contract at the time of acquisition.
BNN North Dakota
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 (in thousands): Accounts receivable $ 2,457 Inventory 67 Property, plant and equipment 48,900 Intangible asset 46,800 (1) Accounts payable and accrued liabilities (3,224 ) Net identifiable assets acquired (excluding cash) $ 95,000 (1) The $46.8 million intangible asset acquired represents three major customer contracts. This intangible asset is amortized on a straight-line basis over a period of 8 - 14 years, the remaining terms of the underlying contracts at the time of acquisition.
NGL Water Solutions Bakken
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 (in thousands): Accounts receivable $ 3,599 Prepayments and other current assets 5 Property, plant and equipment 17,200 Intangible asset 54,000 (1) Accounts payable and accrued liabilities (949 ) Net identifiable assets acquired 73,855 Goodwill 17,145 Net assets acquired $ 91,000 (1) The $54.0 million intangible asset acquired represents customer relationships and a customer contract. This intangible asset is amortized on a straight-line basis over a period of 3 - 8 years.
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 (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.
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 (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

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2018
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: Year Ended December 31, 2018 2017 2016 (in thousands) Processing and other revenues (1) $ 7,483 $ 8,516 $ 6,228 Cost of transportation services (2) $ — $ 10,476 $ 18,585 Charges to TGE: (3) Property, plant and equipment, net $ — $ 2,679 $ 3,084 Other deferred charges $ — $ 25 $ 44 Operations and maintenance $ — $ 29,881 $ 25,431 General and administrative $ — $ 41,676 $ 40,321 (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 3 – Acquisitions and Dispositions . (3) Charges to TGE, inclusive of Tallgrass Equity and TEP, include indirectly charged wages and salaries, other compensation and benefits, and shared services for periods prior to January 1, 2018. Effective January 1, 2018, these costs are incurred by TEP directly and, in the case of certain employee compensation and benefits, paid on TEP's behalf by its affiliate, Tallgrass Management, LLC, pursuant to the TEP Omnibus Agreement.
Schedule of Balances with Affiliates Included in Consolidated Balance Sheets	Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable" in the consolidated balance sheets are as follows: December 31, 2018 December 31, 2017 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 3,447 $ 1,340 Iron Horse Pipeline, LLC 186 — Pawnee Terminal, LLC 115 — Total receivable from related parties $ 3,748 $ 1,340 Accounts payable to related parties: Tallgrass Operations, LLC (1) $ — $ 5,342 Total accounts payable to related parties $ — $ 5,342 (1) Reflects accounts payable for charges to TGE, inclusive of Tallgrass Equity and TEP, including indirectly charged wages and salaries, other compensation and benefits, and shared services prior to January 1, 2018 as discussed above.
Schedule of Balances of Gas Imbalance with Affiliated Shippers	Gas imbalances with affiliated shippers are as follows: December 31, 2018 December 31, 2017 (in thousands) Affiliate gas imbalance receivables $ 19 $ 18 Affiliate gas imbalance payables $ 742 $ 442

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
Schedule of Components of Inventory	The components of inventory at December 31, 2018 and 2017 consisted of the following: December 31, 2018 December 31, 2017 (in thousands) Crude oil $ 23,205 $ 12,792 Materials and supplies 8,206 5,891 Gas in underground storage 2,740 1,984 Natural gas liquids 165 942 Total inventory $ 34,316 $ 21,609

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Components of Property Plant and Equipment	A summary of net property, plant and equipment by classification is as follows: December 31, 2018 December 31, 2017 (in thousands) Crude oil pipelines $ 1,313,976 $ 1,220,379 Gathering, processing and terminalling assets (1) 889,168 675,092 Natural gas pipelines 607,343 581,400 General and other (2) 180,299 98,680 Construction work in progress 191,994 97,978 Accumulated depreciation and amortization (380,351 ) (279,192 ) Total property, plant and equipment, net (3) $ 2,802,429 $ 2,394,337 (1) Includes approximately $53.6 million and $46.2 million of assets associated with the acquisitions of BNN North Dakota in January and November 2018 and Deeprock North in January 2018, respectively. (2) Includes approximately $30.7 million of land associated with the PLT capital lease as discussed in Note 3 – Acquisitions and Dispositions . (3) Property, plant and equipment, net includes approximately $455.8 million of assets at our regulated natural gas pipelines at December 31, 2018 .
Schedule of Future Minimum Rental Payments for Operating Leases	As of December 31, 2018 , future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands): Year Total 2019 $ 7,742 2020 3,952 2021 3,773 2022 3,773 2023 3,773 Thereafter 7,353 Total $ 30,366

Investments in Unconsolidated_2

Investments in Unconsolidated Affiliaties - (Tables)	12 Months Ended
	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	Combined summarized financial information for all our unconsolidated affiliates is shown in the tables below. Summarized financial information for Deeprock Development is presented from January 1, 2016 to July 20, 2017, the date we acquired a controlling interest in Deeprock Development. Summarized financial information for Rockies Express is presented from the date of the initial acquisition of May 6, 2016 to December 31, 2018. Summarized financial information for BNN Colorado is presented from the date of the acquisition, June 23, 2017 to December 1, 2018, the date we acquired a controlling interest in BNN Colorado. Summarized financial information for Iron Horse is presented from the date of the acquisition, February 23, 2018 to December 31, 2018. Summarized financial information for Pawnee Terminal is presented from the date of the acquisition, April 1, 2018 to December 31, 2018. December 31, 2018 December 31, 2017 (in thousands) Current assets $ 132,213 $ 122,362 Noncurrent assets $ 6,031,066 $ 5,974,926 Current liabilities $ 694,951 $ 714,037 Noncurrent liabilities $ 1,502,906 $ 2,049,189 Members' equity $ 3,965,422 $ 3,334,062 Year Ended December 31, 2018 2017 2016 (in thousands) Revenue $ 930,771 $ 860,115 $ 440,838 Operating income $ 524,607 $ 480,337 $ 203,801 Net income to Members $ 376,934 $ 465,592 $ 184,314
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	At December 31, 2018 , the basis difference for our membership interests in Rockies Express was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 47,182 2 - 25 years Property, plant and equipment (1,146,984 ) 35 years Total basis difference $ (1,099,802 )

Goodwill and Intangible Assets

Goodwill and Intangible Assets - (Tables)	12 Months Ended
	Dec. 31, 2018
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: Year Ended December 31, 2018 Year Ended December 31, 2017 Natural Gas Transportation Gathering, Processing & Terminalling Total Natural Gas Transportation Gathering, Processing & Terminalling Total (in thousands) Balance at beginning of period $ 255,558 $ 149,280 $ 404,838 $ 255,558 $ 87,730 $ 343,288 Goodwill acquired — 17,145 (1) 17,145 — 61,550 (2) 61,550 Balance at end of period $ 255,558 $ 166,425 $ 421,983 $ 255,558 $ 149,280 $ 404,838 (1) The $17.1 million of goodwill was recorded in connection with the acquisition of NGL Water Solutions Bakken on November 30, 2018 as discussed further in Note 3 – Acquisitions and Dispositions . (2) 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 3 – Acquisitions and Dispositions .
Schedule of Finite-Lived Intangible Assets	A summary of amortized intangible assets is as follows: December 31, 2018 December 31, 2017 (in thousands) Pony Express oil conversion use rights $ 105,973 $ 105,973 Customer contracts 60,348 8,064 Customer relationships 52,100 — Plaquemines Liquids Terminal use rights and permits 35,000 — Accumulated amortization (26,318 ) (16,306 ) Intangible assets, net $ 227,103 $ 97,731
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense	Estimated future amortization for the intangible assets is as follows (in thousands): Year Total 2019 $ 16,528 2020 16,347 2021 16,294 2022 13,144 2023 13,144 Thereafter 116,646 Total (1) $ 192,103 (1) Excludes the $35 million intangible asset at PLT, as discussed in Note 3 – Acquisitions and Dispositions , that will be amortized over 35 years beginning on the in-service date of the project facilities.

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2018
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 consolidated balance sheets: Balance Sheet December 31, 2018 December 31, 2017 (in thousands) Crude oil derivative contracts (1) Prepayments and other current assets $ 3,526 $ — Crude oil derivative contracts (2) Other current liabilities $ 1,642 $ 2,368 (1) As of December 31, 2018 , the fair value shown for crude oil derivative contracts represents the forward purchase of 2,105,146 barrels of crude oil, consisting of fixed price and floating price contracts, which will settle throughout 2019. (2) As of December 31, 2018 , the fair value shown for crude oil derivative contracts represents the forward sale of 1,274,500 barrels of crude oil, consisting of fixed price and floating price contracts, which will settle throughout the first quarter of 2019. As of December 31, 2017 , the fair value shown for crude oil derivative contracts represents the forward sale of 356,000 barrels of crude oil, consisting of fixed price and floating price contracts, which settled in the first quarter of 2018.
Derivative Contracts Included in Consolidated Statements of Income	The following table summarizes the impact of derivative contracts not designated as hedging contracts for the years ended December 31, 2018 , 2017 and 2016 : Location of Amount of gain (loss) recognized in income on derivatives Year Ended December 31, 2018 2017 2016 (in thousands) Crude oil derivative contracts Sales of natural gas, NGLs, and crude oil $ 29,510 $ 39 $ (40 ) Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ — $ 75 $ 74 Call option derivative Other income, net $ — $ 1,885 $ (1,291 )
Derivative Instruments Maximum Potential Exposure to Credit Loss [Table Text Block]	The maximum potential exposure to credit losses on our crude oil derivative contracts at December 31, 2018 was: Asset Position (in thousands) Gross $ 3,526 Netting agreement impact — Cash collateral held — Net exposure $ 3,526
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 December 31, 2018 and 2017 , based on the fair value hierarchy: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2018: Crude oil derivative contracts $ 3,526 $ — $ 3,526 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2018: Crude oil derivative contracts $ 1,642 $ — $ 1,642 $ — As of December 31, 2017: Crude oil derivative contracts $ 2,368 $ — $ 2,368 $ —

Long-term Debt (Tables)

Long-term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of Debt	Long-term debt consisted of the following at December 31, 2018 and 2017 : December 31, 2018 December 31, 2017 (in thousands) Tallgrass Equity revolving credit facility (1) $ — $ 146,000 TEP revolving credit facility 1,224,000 661,000 TEP 4.75% senior notes due October 1, 2023 500,000 — TEP 5.50% senior notes due September 15, 2024 750,000 750,000 TEP 5.50% senior notes due January 15, 2028 750,000 750,000 Less: Deferred financing costs, net (2) (21,421 ) (17,737 ) Plus: Unamortized premium on 2028 Notes 3,379 3,730 Total long-term debt, net $ 3,205,958 $ 2,292,993 (1) On July 26, 2018, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility. (2) Deferred financing costs, net as presented above relate solely to the Senior Notes (as defined below). Deferred financing costs associated with our revolving credit facilities are presented in noncurrent assets on our consolidated balance sheets.
Schedule of Line of Credit Facilities	The following table sets forth the available borrowing capacity under the TEP revolving credit facility as of December 31, 2018 and 2017 : December 31, 2018 December 31, 2017 (in thousands) Total capacity under the TEP revolving credit facility $ 2,250,000 $ 1,750,000 Less: Outstanding borrowings under the TEP revolving credit facility (1,224,000 ) (661,000 ) Less: Letters of credit issued under the TEP revolving credit facility (94 ) (94 ) Available capacity under the TEP revolving credit facility $ 1,025,906 $ 1,088,906
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 consolidated balance sheets as of December 31, 2018 and 2017 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of December 31, 2018: Revolving credit facility $ — $ 1,224,000 $ — $ 1,224,000 $ 1,224,000 2023 Notes $ — $ 485,285 $ — $ 485,285 $ 494,603 2024 Notes $ — $ 737,745 $ — $ 737,745 $ 741,196 2028 Notes $ — $ 726,503 $ — $ 726,503 $ 746,159 As of December 31, 2017: Revolving credit facilities $ — $ 807,000 $ — $ 807,000 $ 807,000 2024 Notes $ — $ 771,645 $ — $ 771,645 $ 739,824 2028 Notes $ — $ 758,168 $ — $ 758,168 $ 746,169

Partnership Equity and Distri_2

Partnership Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2018
Tallgrass Energy, LP (TGE)
Dividends Declared	The following table details the dividends for the periods indicated: Three Months Ended Date Paid Dividends to Class A Shareholders Dividends per Class A Share December 31, 2018 February 14, 2019 (1) $ 81,304 $ 0.5200 September 30, 2018 November 14, 2018 79,717 0.5100 June 30, 2018 August 14, 2018 77,052 0.4975 March 31, 2018 May 15, 2018 28,316 0.4875 December 31, 2017 February 14, 2018 21,346 0.3675 September 30, 2017 November 14, 2017 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 dividend announced on January 15, 2019 for the fourth quarter of 2018 will be paid on February 14, 2019 to Class A shareholders of record at the close of business on January 31, 2019.
Tallgrass Energy Partners
Dividends Declared	TEP Distributions . The following table shows the distributions for the periods indicated: Distributions Distribution per Limited Partner Common Unit Limited Partner General Partner Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) March 31, 2018 May 15, 2018 $ 71,370 $ 39,816 $ 1,267 $ 112,453 $ 0.9750 December 31, 2017 February 14, 2018 70,638 39,125 1,251 111,014 0.9650 September 30, 2017 November 14, 2017 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 As a result of the TEP Merger, Tallgrass Equity and its wholly-owned subsidiary, Tallgrass Equity Investments, LLC, will receive all distributions paid by TEP for the second quarter of 2018 and subsequent periods.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	The following tables provide the impact of ASC Topic 606 on our consolidated balance sheet as of December 31, 2018 and the consolidated statements of income for the year ended December 31, 2018 : December 31, 2018 As currently reported Under previous guidance Impact of ASC Topic 606 (in thousands) Unconsolidated investments $ 1,861,686 $ 1,773,849 $ 87,837 (1) Year Ended December 31, 2018 As currently reported Under previous guidance Impact of ASC Topic 606 (in thousands) Crude oil transportation services $ 398,334 $ 398,329 $ 5 (2) Sales of natural gas, NGLs, and crude oil $ 168,586 $ 173,055 $ (4,469 ) (3) Processing and other revenues $ 99,445 $ 104,117 $ (4,672 ) (1)(3) Cost of sales $ 114,815 $ 123,458 $ (8,643 ) (2)(3) Equity in earnings of unconsolidated investments $ 306,819 $ 261,848 $ 44,971 (1) Net income attributable to TGE $ 137,127 $ 121,402 $ 15,725 Basic net income per Class A share $ 1.27 $ 1.13 $ 0.14 Diluted net income per Class A share $ 1.27 $ 1.13 $ 0.14 (1) Reflects the impact on our investment in Rockies Express and the management fee collected by NatGas of the cumulative effect adjustment at Rockies Express, which arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with rates that vary throughout the term of the contract. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas. (2) Reflects the impact to revenue and cost of sales to value PLA barrels collected under certain crude oil transportation arrangements at their contract inception fair value in revenue and record an associated lower of cost or net realizable value adjustment in cost of sales. (3) Reflects the reclassification of certain gathering and processing fees collected under arrangements determined to be supply arrangements, rather than customer arrangements under ASC 606, to cost of sales and the reclassification of certain commodities retained as consideration for processing services to processing fee revenue.
Disaggregation of Revenue	A summary of our revenue by line of business is as follows: Year Ended December 31, 2018 Natural Gas Transportation segment Crude Oil Transportation segment Gathering, Processing, & Terminalling segment Corporate and Other Total Revenue (in thousands) Crude oil transportation - committed shipper revenue $ — $ 392,276 $ — $ — $ 392,276 Natural gas transportation - firm service 128,041 — — (4,585 ) 123,456 Water business services — — 52,333 — 52,333 Natural gas gathering & processing fees — — 24,109 — 24,109 All other (1) 11,223 45,888 18,444 (53,950 ) 21,605 Total service revenue 139,264 438,164 94,886 (58,535 ) 613,779 Natural gas liquids sales — — 101,382 — 101,382 Natural gas sales 1,195 — 29,558 — 30,753 Crude oil sales — 6,290 652 — 6,942 Total commodity sales revenue 1,195 6,290 131,592 — 139,077 Total revenue from contracts with customers 140,459 444,454 226,478 (58,535 ) 752,856 Other revenue (2) — — 53,187 (12,784 ) 40,403 Total revenue (3) $ 140,459 $ 444,454 $ 279,665 $ (71,319 ) $ 793,259 (1) Includes revenue from crude oil transportation walk up shippers, crude oil terminal services, interruptible natural gas transportation and storage, and natural gas park and loan service. (2) Includes lease and derivative revenue not subject to ASC 606. (3) Excludes $930.8 million of revenue recognized at Rockies Express, BNN Colorado, and Pawnee Terminal for the year ended December 31, 2018 . See Note 7 – Investments in Unconsolidated Affiliates for additional information.
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]	We expect to recognize the total backlog during future periods as follows (in thousands): Year Estimated Revenue 2019 $ 532,549 2020 357,226 2021 170,713 2022 163,852 2023 140,101 Thereafter 210,625 Total $ 1,575,066
Contract with Customer, Asset and Liability	Contract balances as of December 31, 2018 were as follows: December 31, 2018 January 1, 2018 (in thousands) Accounts receivable from contracts with customers $ 80,935 $ 61,888 Other accounts receivable 151,414 56,727 Receivable from related parties 3,748 1,340 Accounts receivable, net $ 236,097 $ 119,955 Deferred revenue from contracts with customers (1) $ 111,095 $ 88,471 (1) Revenue recognized during the year ended December 31, 2018 that was included in the deferred revenue balance at the beginning of the period was $12.0 million . This revenue primarily represented the utilization of shipper deficiencies at Pony Express.

Commitments and Contingencies -

Commitments and Contingencies - (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	At December 31, 2018 , future minimum rental commitments under major, non-cancelable leases and right of way ("ROW") agreements were as follows (in thousands): Year Operating Lease and ROW Obligations Capital Lease Obligations 2019 $ 1,818 $ 449 2020 1,757 449 2021 1,056 449 2022 796 449 2023 679 449 Thereafter 3,153 17,770 Total $ 9,259 $ 20,015
Other Commitments	At December 31, 2018 , future minimum commitments under long-term, non-cancelable contracts for other purchase obligations were as follows (in thousands): Year Total 2019 $ 13,467 2020 11,198 2021 6,677 2022 5,604 2023 5,614 Thereafter 13,231 Total $ 55,791

Net Income per Class A Share (T

Net Income per Class A Share (Tables)	12 Months Ended
	Dec. 31, 2018
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 years ended December 31, 2018 , 2017 , and 2016 : Year Ended December 31, 2018 2017 2016 (in thousands, except per unit amounts) Basic Net Income per Class A Share: Net income (loss) attributable to TGE, excluding predecessor operations interest $ 137,127 $ (128,729 ) $ 26,794 Basic weighted average Class A Shares outstanding 107,586 58,076 48,856 Basic net income (loss) per Class A share $ 1.27 $ (2.22 ) $ 0.55 Diluted Net Income per Class A Share: Net income (loss) attributable to TGE, excluding predecessor operations interest $ 137,127 $ (128,729 ) $ 26,794 Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares 2,108 — 9 Net income (loss) attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares $ 139,235 $ (128,729 ) $ 26,803 Basic weighted average Class A Shares outstanding 107,586 58,076 48,856 Equity Participation Shares equivalent shares 2,231 — 33 Diluted weighted average Class A Shares outstanding 109,817 58,076 48,889 Diluted net income (loss) per Class A Share $ 1.27 $ (2.22 ) $ 0.55

Major Customers and Concentra_2

Major Customers and Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2018
Risks and Uncertainties [Abstract]
Schedules of Concentration of Risk	For the year ended December 31, 2018 , the percentage of segment revenues from the top ten non-affiliated customers for each segment was as follows: Percentage of Segment Revenue Natural Gas Transportation 58% Crude Oil Transportation 84% Gathering, Processing & Terminalling 60%

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-based Compensation, Activity	The following table summarizes the changes in the Equity Participation Shares outstanding for the years ended December 31, 2018 , 2017 and 2016 : Equity Participation Shares Weighted Average Outstanding at January 1, 2016 160,000 $ 27.97 Granted 45,000 18.22 Outstanding at December 31, 2016 205,000 25.83 Granted 30,000 23.66 Vested (10,002 ) (14.26 ) Outstanding at December 31, 2017 224,998 25.91 Granted 1,138,200 17.01 Converted (1) 1,786,310 18.20 Vested (20,664 ) (19.19 ) Forfeited (79,200 ) (20.62 ) Outstanding at December 31, 2018 3,049,644 $ 18.25 (1) Reflects TEP's outstanding Equity Participation Units that were converted to Equity Participation Shares at a ratio of 2.0 Equity Participation Shares for each outstanding TEP Equity Participation Unit upon completion of the TEP Merger as discussed above.

Income Taxes - (Tables)

Income Taxes - (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense	Components of the deferred income tax expense are as follows: Year Ended December 31, 2018 2017 2016 (in thousands) Deferred income tax expense: Federal income tax $ 41,585 $ 200,787 $ 15,587 State income tax 14,124 7,671 2,154 Total deferred income tax expense $ 55,709 $ 208,458 $ 17,741
Schedule of Effective Income Tax Rate Reconciliation	The difference between tax expense based on the statuary federal income tax rate and our effective tax expense is summarized as follows: Year Ended December 31, 2018 2017 2016 (in thousands) Net income before tax $ 523,380 $ 432,443 $ 267,780 Less: Predecessor operations interest in net income — — (6,995 ) Net income before tax, excluding predecessor operations interest 523,380 432,443 260,785 Less: Net income attributable to noncontrolling interests (330,544 ) (352,714 ) (216,250 ) Net income subject to tax $ 192,836 $ 79,729 $ 44,535 Federal statutory income tax rate 21 % 35 % 35 % Income tax at statutory rate $ 40,496 $ 27,905 $ 15,587 State income taxes, net of federal benefit 5,419 2,392 1,592 Change in state tax rate 8,705 1,353 562 Other 1,089 — — Valuation allowance — 3,926 — Total income tax expense before change in tax legislation $ 55,709 $ 35,576 $ 17,741 Impact of federal tax legislation on deferred tax asset — 172,037 — Impact of federal tax legislation on valuation allowance — 845 — Total income tax expense $ 55,709 $ 208,458 $ 17,741 Effective tax rate 10.6 % 48.2 % 6.8 %
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets result from the following: December 31, 2018 December 31, 2017 (in thousands) Deferred tax assets: Investment in partnerships $ 198,290 $ 269,136 Net operating losses 80,012 48,632 Deferred tax assets before valuation allowance $ 278,302 $ 317,768 Valuation allowance (4,771 ) (4,771 ) Total deferred tax assets $ 273,531 $ 312,997 Deferred tax liability: Equity earnings adjustment pursuant to ASC 606 $ 817 $ —

Reporting Segments (Tables)

Reporting Segments (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Summary of TGE's Segment Information of Revenue	The following tables set forth our segment information for the periods indicated: Year Ended December 31, 2018 2017 2016 Revenue: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 140,459 $ (4,661 ) $ 135,798 $ 141,021 $ (6,694 ) $ 134,327 $ 135,097 $ (5,641 ) $ 129,456 Crude Oil Transportation 444,454 (39,319 ) 405,135 364,574 (10,676 ) 353,898 380,503 (370 ) 380,133 Gathering, Processing & Terminalling 279,665 (27,339 ) 252,326 186,211 (18,538 ) 167,673 113,533 (11,460 ) 102,073 Total revenue $ 864,578 $ (71,319 ) $ 793,259 $ 691,806 $ (35,908 ) $ 655,898 $ 629,133 $ (17,471 ) $ 611,662
Summary of TGE's Segment Information of Earnings	Year Ended December 31, 2018 2017 2016 Tallgrass Equity Adjusted EBITDA: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 377,224 $ (4,251 ) $ 372,973 $ 180,978 $ (2,176 ) $ 178,802 $ 75,029 $ (1,633 ) $ 73,396 Crude Oil Transportation 239,330 (8,147 ) 231,183 140,785 4,878 145,663 132,154 4,881 137,035 Gathering, Processing & Terminalling 59,203 12,398 71,601 16,083 (2,702 ) 13,381 4,078 (3,248 ) 830 Corporate and Other (21,321 ) — (21,321 ) (37,591 ) — (37,591 ) (2,142 ) — (2,142 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investments (1) 237,197 66,922 15,287 Gain (loss) on disposal of assets (1) 4,630 189 (526 ) Non-cash gain (loss) related to derivative instruments (1) 3,340 (64 ) (650 ) Gain on remeasurement of unconsolidated investment (1) — 2,744 — Less: Interest expense, net (1) (95,465 ) (29,403 ) (16,632 ) Depreciation and amortization expense (1) (74,998 ) (26,131 ) (25,567 ) Distributions from unconsolidated investments (1) (302,364 ) (86,551 ) (22,085 ) Non-cash compensation expense (1) (8,634 ) (2,682 ) (1,862 ) Deficiency payments, net (1) (14,443 ) (7,701 ) (9,672 ) Loss on debt retirement (2,245 ) — — Deferred income tax expense (55,709 ) (208,458 ) (17,741 ) Net income attributable to Exchange Right Holders (208,618 ) (137,849 ) (95,882 ) Net income (loss) attributable to TGE $ 137,127 $ (128,729 ) $ 33,789 (1) Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.
Summary of TGE's Segment Information for Payments to Acquire Plant, Property and Equipment	Year Ended December 31, Capital Expenditures: 2018 2017 2016 (in thousands) Natural Gas Transportation $ 112,529 $ 16,705 $ 28,475 Crude Oil Transportation 65,745 57,022 29,893 Gathering, Processing & Terminalling 185,732 71,417 26,123 Corporate and Other 4,867 — — Total capital expenditures $ 368,873 $ 145,144 $ 84,491
Summary of TGE's Segment Information of Unconsolidated Investments	Unconsolidated Investments: December 31, 2018 December 31, 2017 (in thousands) Natural Gas Transportation $ 1,794,987 $ 895,873 Crude Oil Transportation 35,467 — Gathering, Processing & Terminalling 31,232 13,658 Total unconsolidated investments $ 1,861,686 $ 909,531
Summary of TGE's Segment Information of Assets	Assets: December 31, 2018 December 31, 2017 (in thousands) Natural Gas Transportation $ 2,606,696 $ 1,606,666 Crude Oil Transportation 1,423,740 1,407,758 Gathering, Processing & Terminalling 1,522,559 943,340 Corporate and Other 340,514 334,249 Total assets $ 5,893,509 $ 4,292,013

Selected Quarterly Financial _2

Selected Quarterly Financial Data (Unaudited) - (Tables)	12 Months Ended
	Dec. 31, 2018
Selected Quarterly Financial Data (Unaudited) [Abstract]
Schedule of Quarterly Financial Information	The following tables summarize our unaudited quarterly financial data for 2018 and 2017 : Quarter Ended 2018 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 179,094 $ 193,589 $ 200,320 $ 220,256 Operating income $ 81,913 $ 79,275 $ 90,084 $ 99,359 Net income $ 114,313 $ 109,701 $ 118,712 $ 124,945 Net income allocable to noncontrolling interests $ (97,578 ) $ (108,638 ) $ (59,162 ) $ (65,166 ) Net income attributable to TGE $ 16,735 $ 1,063 $ 59,550 $ 59,779 Basic net income per Class A Share $ 0.29 $ 0.02 $ 0.38 $ 0.38 Diluted net income per Class A Share $ 0.29 $ 0.02 $ 0.38 $ 0.38 During the second quarter of 2018, we recognized increased deferred income tax expense as a result of our increased ownership in TEP due to the TEP Merger and the resulting increase in income allocated to TGE. Quarter Ended 2017 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 144,400 $ 160,863 $ 175,869 $ 174,766 Operating income $ 63,226 $ 66,944 $ 74,003 $ 67,674 Net income $ 67,238 $ 79,167 $ 170,777 $ (93,197 ) Net income allocable to noncontrolling interests $ (55,209 ) $ (70,414 ) $ (154,911 ) $ (72,180 ) Net income (loss) attributable to TGE $ 12,029 $ 8,753 $ 15,866 $ (165,377 ) Basic net income (loss) per Class A Share $ 0.21 $ 0.15 $ 0.27 $ (2.85 ) Diluted net income (loss) per Class A Share $ 0.21 $ 0.15 $ 0.27 $ (2.85 ) During the third quarter of 2017, we recognized equity in earnings relating to our proportionate share of the Ultra settlement discussed in Note 19 – Legal and Environmental Matters . During the fourth quarter of 2017, we remeasured our deferred tax asset based on the new tax rates as a result of the federal rate change under the TCJA signed into law on December 22, 2017, resulting in an increase to our tax provision. For additional information, see Note 17 – Income Taxes .

Description of Business - Addit

Description of Business - Additional Information (Detail)	Jun. 30, 2018shares	Dec. 31, 2018	Dec. 31, 2018
Organization [Line Items]
Equity interest ownership percentage		20.00%	20.00%
Exchange Ratio	2
Rockies Express Pipeline LLC
Organization [Line Items]
Equity interest ownership percentage		75.00%	75.00%
Tallgrass Equity, LLC
Organization [Line Items]
Ownership Interest			55.79%
Tallgrass NatGas Operator, LLC
Organization [Line Items]
Ownership Interest			100.00%
Tallgrass Terminals, LLC
Organization [Line Items]
Ownership Interest			100.00%
Tallgrass Energy Partners
Organization [Line Items]
Ownership Interest		100.00%
Limited Partner Common Units	47,693,097

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) $ in Thousands	Dec. 01, 2018	Nov. 30, 2018	Jan. 12, 2018	Aug. 03, 2017	Dec. 31, 2018USD ($)	Jan. 01, 2018USD ($)	Dec. 31, 2017USD ($)	May 06, 2016USD ($)	Aug. 06, 2012mi
Business Acquisition [Line Items]
Allowance for Doubtful Accounts Receivable					$ 7,700		$ 500
Regulatory Assets					3,200		2,600
Regulatory Liabilities					1,900		2,300
Finite-Lived Intangible Assets, Remaining Amortization Period	3 years			8 years
Loss on debt retirement					$ 2,200
Equity interest ownership percentage					20.00%
Cumulative Effect of New Accounting Principle in Period of Adoption						$ 44,100
Unconsolidated investments					$ 1,861,686		909,531
Accounts receivable, net					$ 236,097		$ 119,955
Crude oil pipelines
Business Acquisition [Line Items]
Depreciation Rate					2.80%
Replacement Gas Facilities
Business Acquisition [Line Items]
Depreciation Rate					10.00%
Minimum
Business Acquisition [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period		3 years	8 years
Minimum | Natural gas pipelines
Business Acquisition [Line Items]
Depreciation Rate					0.70%
Minimum | Gathering & processing assets
Business Acquisition [Line Items]
Depreciation Rate					2.20%
Minimum | Water business assets
Business Acquisition [Line Items]
Depreciation Rate					2.30%
Minimum | Terminal business assets
Business Acquisition [Line Items]
Depreciation Rate					1.80%
Minimum | General and other
Business Acquisition [Line Items]
Depreciation Rate					2.90%
Maximum
Business Acquisition [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period		8 years	14 years
Maximum | Natural gas pipelines
Business Acquisition [Line Items]
Depreciation Rate					5.00%
Maximum | Gathering & processing assets
Business Acquisition [Line Items]
Depreciation Rate					5.00%
Maximum | Water business assets
Business Acquisition [Line Items]
Depreciation Rate					20.00%
Maximum | Terminal business assets
Business Acquisition [Line Items]
Depreciation Rate					2.80%
Maximum | General and other
Business Acquisition [Line Items]
Depreciation Rate					25.00%
Tallgrass Interstate Gas Transmission, LLC (TIGT)
Business Acquisition [Line Items]
Miles of Natural Gas Pipeline | mi									433
Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Cumulative Effect of New Accounting Principle in Period of Adoption						125,200
Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Accounts receivable, net						1,300
Use Rights | Pony Express Pipeline
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life					35 years
Use Rights | Plaquemines Liquids Terminal, LLC
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life					35 years
Customer Contracts | Minimum
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life					2 years
Customer Contracts | Maximum
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life					14 years
Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Depreciation Rate					2.86%
Equity interest ownership percentage					75.00%
Unconsolidated investments						$ 42,800		$ 436,000

Acquisitions & Dispositions -_2

Acquisitions & Dispositions - BNN Colorado, Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Dec. 01, 2018	Aug. 03, 2017	Nov. 05, 2018
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill			$ 35,000
Finite-Lived Intangible Assets, Remaining Amortization Period	3 years	8 years
BNN Colorado Water, LLC
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables	$ 4,053
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	18,535
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	7,922
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable	(53)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Deferred Revenue	(4,053)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 26,404

Acquisitions & Dispositions -_3

Acquisitions & Dispositions - BNN North Dakota Acquisitions, Assets Acquired & Liabilities Assumed (Details) - USD ($) $ in Thousands	Dec. 01, 2018	Nov. 30, 2018	Jan. 12, 2018	Aug. 03, 2017	Dec. 31, 2018	Nov. 05, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill						$ 35,000
Goodwill					$ 421,983		$ 404,838	$ 343,288
Finite-Lived Intangible Assets, Remaining Amortization Period	3 years			8 years
BNN North Dakota
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables			$ 2,457
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory			67
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			48,900
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill			46,800
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable			(3,224)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net			$ 95,000
NGL Water Solutions Bakken
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables		$ 3,599
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets		5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		17,200
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill		54,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable		(949)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		73,855
Goodwill		17,145
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net		$ 91,000
Minimum
Business Acquisition [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period		3 years	8 years
Maximum
Business Acquisition [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period		8 years	14 years

Acquisitions & Dispositions - T

Acquisitions & Dispositions - TCG Acquisition, Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Dec. 01, 2018	Aug. 03, 2017	Nov. 05, 2018
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill			$ 35,000
Finite-Lived Intangible Assets, Remaining Amortization Period	3 years	8 years
Tallgrass Crude Gathering, LLC
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables		$ 117
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment		29,306
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill		6,694
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable		(87)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		$ 36,030

Acquisitions & Dispositions - D

Acquisitions & Dispositions - DRD Acquisition, Assets Acquired & Liabilities Assumed (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Jul. 20, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Goodwill	$ 421,983	$ 404,838		$ 343,288
Deeprock Development, LLC
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables			$ 968
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other			598
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			70,148
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable			(712)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Deferred Revenue			6,546
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net			64,456
Goodwill			61,550
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net			$ 126,006

Acquisitions & Dispositions - P

Acquisitions & Dispositions - Pro Forma Revenue & Net Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Combinations [Abstract]
Pro Forma Revenue	$ 813,286	$ 686,803	$ 632,528
Pro Forma Net income (loss) attributable to TGE	$ 140,005	$ (129,155)	$ 34,311

Acquisitions & Dispositions - I

Acquisitions & Dispositions - Impact of Acquisition, Income Statement (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Total Revenues	$ 220,256,000	$ 200,320,000	$ 193,589,000	$ 179,094,000	$ 174,766,000	$ 175,869,000	$ 160,863,000	$ 144,400,000	$ 793,259,000	$ 655,898,000	$ 611,662,000
Operations and maintenance									72,460,000	62,069,000	55,070,000
Depreciation and amortization									110,862,000	90,800,000	86,247,000
General and administrative									70,656,000	65,536,000	57,298,000
Taxes, other than income taxes									31,810,000	28,832,000	25,400,000
Contract termination									0	0	8,061,000
(Gain) loss on disposal of assets									11,043,000	599,000	(1,849,000)
Total Operating Costs and Expenses									442,628,000	384,051,000	353,244,000
Operating income	99,359,000	90,084,000	79,275,000	81,913,000	67,674,000	74,003,000	66,944,000	63,226,000	350,631,000	271,847,000	258,418,000
Equity in earnings of unconsolidated investments									306,819,000	237,110,000	54,531,000
Interest expense, net									(133,319,000)	(89,348,000)	(45,601,000)
Other (expense) income, net									(751,000)	3,106,000	432,000
Nonoperating Income (Expense)									172,749,000	160,596,000	9,362,000
Net income before tax									523,380,000	432,443,000	267,780,000
Deferred income tax expense									(55,709,000)	(208,458,000)	(17,741,000)
Net income	124,945,000	118,712,000	109,701,000	114,313,000	(93,197,000)	170,777,000	79,167,000	67,238,000	467,671,000	223,985,000	250,039,000
Net income attributable to noncontrolling interests	(65,166,000)	(59,162,000)	(108,638,000)	(97,578,000)	(72,180,000)	(154,911,000)	(70,414,000)	(55,209,000)	(330,544,000)	(352,714,000)	(216,250,000)
Net income attributable to TGE	$ 59,779,000	$ 59,550,000	$ 1,063,000	$ 16,735,000	$ (165,377,000)	$ 15,866,000	$ 8,753,000	$ 12,029,000	137,127,000	(128,729,000)	33,789,000
Tallgrass Energy, LP (TGE)
Business Acquisition [Line Items]
Total Revenues											605,122,000
Operations and maintenance											53,386,000
Depreciation and amortization											84,896,000
General and administrative											55,829,000
Taxes, other than income taxes											24,727,000
Contract termination											0
(Gain) loss on disposal of assets											(1,849,000)
Total Operating Costs and Expenses											350,948,000
Operating income											254,174,000
Equity in earnings of unconsolidated investments											51,780,000
Interest expense, net											(45,601,000)
Other (expense) income, net											432,000
Nonoperating Income (Expense)											6,611,000
Net income before tax											260,785,000
Deferred income tax expense											(17,741,000)
Net income											243,044,000
Net income attributable to noncontrolling interests											(216,250,000)
Net income attributable to TGE											26,794,000
Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Total Revenues											12,142,000
Operations and maintenance											1,684,000
Depreciation and amortization											1,351,000
General and administrative											1,469,000
Taxes, other than income taxes											673,000
Contract termination											8,061,000
(Gain) loss on disposal of assets											0
Total Operating Costs and Expenses											14,126,000
Operating income											(1,984,000)
Equity in earnings of unconsolidated investments											2,751,000
Interest expense, net											0
Other (expense) income, net											0
Nonoperating Income (Expense)											2,751,000
Net income before tax											767,000
Deferred income tax expense											0
Net income											767,000
Net income attributable to noncontrolling interests											0
Net income attributable to TGE											767,000
Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Total Revenues											6,228,000
Operations and maintenance											0
Depreciation and amortization											0
General and administrative											0
Taxes, other than income taxes											0
Contract termination											0
(Gain) loss on disposal of assets											0
Total Operating Costs and Expenses											0
Operating income											6,228,000
Equity in earnings of unconsolidated investments											0
Interest expense, net											0
Other (expense) income, net											0
Nonoperating Income (Expense)											0
Net income before tax											6,228,000
Deferred income tax expense											0
Net income											6,228,000
Net income attributable to noncontrolling interests											0
Net income attributable to TGE											6,228,000
Consolidation, Eliminations
Business Acquisition [Line Items]
Total Revenues											(11,830,000)
Operations and maintenance											0
Depreciation and amortization											0
General and administrative											0
Taxes, other than income taxes											0
Contract termination											0
(Gain) loss on disposal of assets											0
Total Operating Costs and Expenses											(11,830,000)
Operating income											0
Equity in earnings of unconsolidated investments											0
Interest expense, net											0
Other (expense) income, net											0
Nonoperating Income (Expense)											0
Net income before tax											0
Deferred income tax expense											0
Net income											0
Net income attributable to noncontrolling interests											0
Net income attributable to TGE											0
Crude oil transportation services
Business Acquisition [Line Items]
Total Revenues									398,334,000	345,733,000	374,949,000
Crude oil transportation services | Tallgrass Energy, LP (TGE)
Business Acquisition [Line Items]
Total Revenues											374,949,000
Crude oil transportation services | Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Total Revenues											0
Crude oil transportation services | Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Total Revenues											0
Crude oil transportation services | Consolidation, Eliminations
Business Acquisition [Line Items]
Total Revenues											0
Natural gas transportation services
Business Acquisition [Line Items]
Total Revenues									126,894,000	122,364,000	119,962,000
Natural gas transportation services | Tallgrass Energy, LP (TGE)
Business Acquisition [Line Items]
Total Revenues											119,962,000
Natural gas transportation services | Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Total Revenues											0
Natural gas transportation services | Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Total Revenues											0
Natural gas transportation services | Consolidation, Eliminations
Business Acquisition [Line Items]
Total Revenues											0
Sales of natural gas, NGLs, and crude oil
Business Acquisition [Line Items]
Total Revenues									168,586,000	108,503,000	77,123,000
Sales of natural gas, NGLs, and crude oil | Tallgrass Energy, LP (TGE)
Business Acquisition [Line Items]
Total Revenues											77,394,000
Sales of natural gas, NGLs, and crude oil | Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Total Revenues											99,000
Sales of natural gas, NGLs, and crude oil | Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Total Revenues											0
Sales of natural gas, NGLs, and crude oil | Consolidation, Eliminations
Business Acquisition [Line Items]
Total Revenues											(370,000)
Processing and other revenues
Business Acquisition [Line Items]
Total Revenues									99,445,000	79,298,000	39,628,000
Processing and other revenues | Tallgrass Energy, LP (TGE)
Business Acquisition [Line Items]
Total Revenues											32,817,000
Processing and other revenues | Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Total Revenues											12,043,000
Processing and other revenues | Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Total Revenues											6,228,000
Processing and other revenues | Consolidation, Eliminations
Business Acquisition [Line Items]
Total Revenues											(11,460,000)
Cost of Sales
Business Acquisition [Line Items]
Cost of sales and transportation services									114,815,000	91,213,000	71,650,000
Cost of Sales | Tallgrass Energy, LP (TGE)
Business Acquisition [Line Items]
Cost of sales and transportation services											71,920,000
Cost of Sales | Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Cost of sales and transportation services											100,000
Cost of Sales | Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Cost of sales and transportation services											0
Cost of Sales | Consolidation, Eliminations
Business Acquisition [Line Items]
Cost of sales and transportation services											(370,000)
Cost of Transportation Services
Business Acquisition [Line Items]
Cost of sales and transportation services									$ 53,068,000	$ 46,200,000	47,669,000
Cost of Transportation Services | Tallgrass Energy, LP (TGE)
Business Acquisition [Line Items]
Cost of sales and transportation services											58,341,000
Cost of Transportation Services | Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Cost of sales and transportation services											788,000
Cost of Transportation Services | Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Cost of sales and transportation services											0
Cost of Transportation Services | Consolidation, Eliminations
Business Acquisition [Line Items]
Cost of sales and transportation services											$ (11,460,000)

Acquisitions & Dispositions - A

Acquisitions & Dispositions - Additional Information (Details)	Jan. 31, 2019USD ($)	Nov. 30, 2018USD ($)	Nov. 05, 2018USD ($)	Jul. 12, 2018USD ($)	Apr. 01, 2018USD ($)	Feb. 23, 2018USD ($)	Feb. 07, 2018USD ($)shares	Feb. 06, 2018USD ($)	Feb. 01, 2018USD ($)	Jan. 12, 2018USD ($)a	Jan. 02, 2018USD ($)	Jan. 01, 2018	Aug. 03, 2017USD ($)ami	Jul. 21, 2017USD ($)shares	Jul. 20, 2017USD ($)	Jun. 05, 2017USD ($)mi	Feb. 01, 2017shares	Jan. 01, 2017USD ($)	Oct. 31, 2016shares	Jul. 21, 2016shares	Jan. 01, 2016USD ($)$ / sharesshares	Dec. 31, 2018USD ($)mi	Dec. 31, 2018USD ($)mi	Dec. 31, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2018USD ($)mi	Dec. 31, 2018USD ($)mi	Dec. 31, 2018USD ($)mi	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jan. 01, 2019	Dec. 01, 2018USD ($)	Mar. 31, 2017	Sep. 01, 2016USD ($)	May 06, 2016
Business Acquisition [Line Items]
Payments to Acquire Businesses, Net of Cash Acquired																													$ 57,202,000
Payments to Acquire Businesses, Gross																														$ 0
Goodwill																						$ 421,983,000	$ 421,983,000	$ 404,838,000	$ 404,838,000	$ 421,983,000	$ 421,983,000	$ 421,983,000	404,838,000	343,288,000
Facility storage capacity			$ 20,000,000
Payments to Acquire Assets, Investing Activities			$ 30,700,000																							$ 30,704,000			128,526,000	0
Preferred Membership Interest, Ownership Percentage			100.00%
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill			$ 35,000,000
Equity interest ownership percentage																						20.00%	20.00%			20.00%	20.00%	20.00%
Contributions to unconsolidated investments																										$ (473,946,000)			(45,948,000)	(50,076,000)
Payments to Acquire Interest in Subsidiaries and Affiliates																										0			400,000,000	436,022,000
Issuance of Noncontrolling Interest in Subsidiary in Exchange for Membership Interest																										31,843,000
Proceeds from Divestiture of Businesses																										$ 50,046,000
Miles of Pipeline | mi																						70	70			70	70	70
Gain on remeasurement of unconsolidated investment																										$ 0			9,728,000	0
Distributions to noncontrolling interests																										$ (327,578,000)			(317,102,000)	(249,142,000)
Derivative Asset, Noncurrent																																		$ 46,000,000
Partners' Capital Account, Units, Treasury Units Purchased | shares																	736,262
Acquisition of Pony Express membership interest																														(49,118,000)
Equity Option
Business Acquisition [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased | shares																	1,703,094		1,251,760	3,563,146
General Partner
Business Acquisition [Line Items]
Partial exercise of call option																													12,600,000	34,000,000
Tallgrass Development LP
Business Acquisition [Line Items]
Units Acquired | shares							5,619,218
Deeprock North, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired											38.00%
Contributions to unconsolidated investments											$ (19,500,000)
BNN Colorado Water, LLC
Business Acquisition [Line Items]
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage																																63.00%
Iron Horse Pipeline, LLC
Business Acquisition [Line Items]
Equity interest ownership percentage						75.00%
Contributions to unconsolidated investments						$ (3,500,000)
Pawnee Terminal
Business Acquisition [Line Items]
Equity interest ownership percentage					51.00%
Contributions to unconsolidated investments					$ (30,600,000)
Deeprock Development, LLC
Business Acquisition [Line Items]
Business Combination, Step Acquisition, Equity Interest in Acquiree, Percentage															20.00%
Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Equity interest ownership percentage																						75.00%	75.00%			75.00%	75.00%	75.00%
Contributions to unconsolidated investments				$ (412,500,000)																						$ (432,000,000)
PRE Pipeline
Business Acquisition [Line Items]
Miles of Pipeline | mi																						70	70			70	70	70
Iron Horse Pipeline, LLC
Business Acquisition [Line Items]
Miles of Pipeline | mi																						80	80			80	80	80
NGL Water Solutions Bakken
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual																							$ 1,400,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual																							$ 500,000
Payments to Acquire Businesses, Gross																										$ 91,000,000
Goodwill		$ 17,145,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill		$ 54,000,000
BNN Colorado Water, LLC
Business Acquisition [Line Items]
Equity interest held by noncontrolling interests																						37.00%	37.00%			37.00%	37.00%	37.00%
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual																						$ 1,000,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual																						$ (1,000,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill																																$ 7,922,000
Plaquemines Liquids Terminal, LLC
Business Acquisition [Line Items]
Equity interest held by noncontrolling interests			20.00%
Business Acquisition, Percentage of Voting Interests Acquired			80.00%
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill			$ 35,000,000
BNN North Dakota
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual																												$ 18,800,000
Payments to Acquire Businesses, Net of Cash Acquired																										$ 95,000,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual																												$ 4,700,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill										$ 46,800,000
Deeprock Development, LLC
Business Acquisition [Line Items]
Equity interest held by noncontrolling interests																						40.00%	40.00%			40.00%	40.00%	40.00%
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual																								10,500,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual																								$ 900,000
Goodwill															$ 61,550,000
Tallgrass Crude Gathering, LLC
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual																									1,000,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual																									$ (1,000,000)
Payments to Acquire Businesses, Gross																													36,030,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill													$ 6,694,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest								100.00%
Proceeds from Divestiture of Businesses								$ 50,000,000
Gain (Loss) on Disposition of Business								$ 9,400,000
Pony Express Pipeline
Business Acquisition [Line Items]
Distributions to noncontrolling interests																										$ (50,000,000)			0	(425,882,000)
Drexel Hamilton Infrastructure Fund I, L.P. (DHIF)
Business Acquisition [Line Items]
Right to receive special distributions			$ 35,000,000
NGL Water Solutions Bakken
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		100.00%
Payments to Acquire Businesses, Gross		$ 91,000,000
BNN Colorado Water, LLC
Business Acquisition [Line Items]
Equity interest held by noncontrolling interests																																37.00%
Acquisition, noncontrolling interest, fair value																																$ 10,100,000
BNN North Dakota
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired										100.00%
Payments to Acquire Businesses, Net of Cash Acquired										$ 95,000,000
Acres for Water Gathering and Disposal System | a										133,000
Terminals and NatGas
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross																		$ 140,000,000
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%
Tallgrass Midstream Gathering LLC
Business Acquisition [Line Items]
Payments to Acquire Assets, Investing Activities																$ 128,500,000
Miles of gathering pipeline | mi																1,500
Tallgrass Midstream Gathering LLC | DCP Assets Holding, LP
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired																100.00%
Deeprock Development, LLC
Business Acquisition [Line Items]
Equity interest held by noncontrolling interests															40.00%
Acquisition, noncontrolling interest, fair value															$ 45,900,000
Payments to Acquire Businesses, Net of Cash Acquired															57,200,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares														128,790
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned														$ 6,700,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest												69.00%															60.00%
Acquisition fair value															22,900,000
Gain on remeasurement of unconsolidated investment															$ 9,700,000
Deeprock Development, LLC | Kinder Morgan Cushing, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired															40.00%
Deeprock Development, LLC | Deeprock Energy Resources, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired														9.00%
Deeprock Development, LLC | Tallgrass Energy Partners
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross														$ 6,400,000
Business Combination, Consideration Transferred														$ 13,100,000
Tallgrass Crude Gathering, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired													100.00%
Payments to Acquire Businesses, Gross													$ 36,000,000
Miles of gathering pipeline | mi													34
Acres for Crude Oil gathering system | a													150,000
Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired																																			25.00%
Payments to Acquire Interest in Subsidiaries and Affiliates																													400,000,000	436,000,000
Rockies Express Pipeline LLC | Sempra U.S. Gas and Power
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired																																			25.00%
Rockies Express Pipeline LLC | Tallgrass Development LP
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired							25.01%																										24.99%
Pony Express Pipeline
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired									2.00%												31.30%
Payments to Acquire Interest in Subsidiaries and Affiliates									$ 60,000,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest									100.00%												98.00%
Distributions to noncontrolling interests																					$ (475,000,000)
Common Unit, Issuance Value																					268,600,000
Total consideration																					$ 743,600,000
Option Indexed to Issuer's Equity, Strike Price | $ / shares																					$ 42.50
Pony Express Pipeline | Equity Option
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares																					6,518,000
Derivative, Term of Contract																					18 months
Capital Unit, Class B | TGE and Tallgrass Equity, LLC
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares							27,554,785
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned							$ 644,800,000
Noncontrolling Interest
Business Acquisition [Line Items]
Carrying Value of Common Units							53.8
Distributions to noncontrolling interests																										$ (327,578,000)			(317,102,000)	(249,142,000)
Partial exercise of call option																													(72,890,000)	$ (211,315,000)
Noncontrolling Interest | Deeprock Development, LLC
Business Acquisition [Line Items]
Acquisition of Pony Express membership interest																													$ (7,109,000)
Subsequent Event | Powder River Gateway
Business Acquisition [Line Items]
Equity interest ownership percentage																															51.00%
Subsequent Event | Iron Horse Pipeline, LLC
Business Acquisition [Line Items]
Contributions to unconsolidated investments	$ (37,000,000)
Subsequent Event | Silver Creek Midstream, LLC | Powder River Gateway
Business Acquisition [Line Items]
Equity interest ownership percentage																															49.00%
Subsequent Event | Silver Creek Midstream, LLC | Iron Horse Pipeline, LLC
Business Acquisition [Line Items]
Equity interest ownership percentage	25.00%

Related Party Transactions - Sc

Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Revenue from affiliated companies	$ 7,483	$ 8,516	$ 6,228
Costs of transportation services from affiliated companies	0	10,476	18,585
Other Deferred Charges
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	0	25	44
Operation and maintenance
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	0	29,881	25,431
General and administrative expense
Related Party Transaction [Line Items]
General and administrative costs from transactions with affiliated companies	0	41,676	40,321
Property, Plant and Equipment
Related Party Transaction [Line Items]
Property, plant and equipment, net	$ 0	$ 2,679	$ 3,084

Related Party Transactions - _2

Related Party Transactions - Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Receivable from related parties	$ 3,748	$ 1,340
Accounts payable to related parties	0	5,342
Rockies Express Pipeline LLC
Related Party Transaction [Line Items]
Receivable from related parties	3,447	1,340
Iron Horse Pipeline, LLC
Related Party Transaction [Line Items]
Receivable from related parties	186	0
Pawnee Terminal, LLC
Related Party Transaction [Line Items]
Receivable from related parties	115	0
Tallgrass Operations LLC
Related Party Transaction [Line Items]
Accounts payable to related parties	$ 0	$ 5,342

Related Party Transactions - _3

Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Affiliate gas imbalance receivables	$ 19	$ 18
Affiliate gas imbalance payables	$ 742	$ 442

Inventory (Details)

Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Crude oil	$ 23,205	$ 12,792
Materials and supplies	8,206	5,891
Gas in underground storage	2,740	1,984
Natural gas liquids	165	942
Total Inventory	$ 34,316	$ 21,609

Property, Plant and Equipment -

Property, Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Accumulated depreciation and amortization	$ (380,351,000)	$ (279,192,000)
Property, plant and equipment, net	2,802,429,000	2,394,337,000
Crude oil pipelines
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,313,976,000	1,220,379,000
Gathering, processing and terminalling assets (1)
Property, Plant and Equipment [Line Items]
Property, plant and equipment	889,168,000	675,092,000
Natural gas pipelines
Property, Plant and Equipment [Line Items]
Property, plant and equipment	607,343,000	581,400,000
Property, plant and equipment, net	455,800,000
General and other
Property, Plant and Equipment [Line Items]
Property, plant and equipment	180,299,000	98,680,000
Construction work in progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment	191,994,000	$ 97,978,000
Plaquemines Liquids Terminal, LLC | General and other
Property, Plant and Equipment [Line Items]
Property, plant and equipment	30,700,000
BNN North Dakota | Gathering, processing and terminalling assets (1)
Property, Plant and Equipment [Line Items]
Property, plant and equipment	53,600,000
Deeprock North, LLC | Gathering, processing and terminalling assets (1)
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 46,200,000

Property, Plant and Equipment_2

Property, Plant and Equipment - Future Minimum Rental Income (Details) $ in Thousands	Dec. 31, 2018USD ($)
Property, Plant and Equipment [Abstract]
2,019	$ 7,742
2,020	3,952
2,021	3,773
2,022	3,773
2,023	3,773
Thereafter	7,353
Total	$ 30,366

Property, Plant and Equipment_3

Property, Plant and Equipment - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 102,700	$ 86,900	$ 83,200
Capitalized interest	5,200	1,100	600
Rental Income, Operating	10,900	3,800	3,200
Rental Income, Nonoperating	$ 800	$ 800	$ 800

Investments in Unconsolidated_3

Investments in Unconsolidated Affiliates - Equity Method Investments (Details) - Rockies Express Pipeline LLC - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Feb. 07, 2018	Mar. 31, 2017	May 06, 2016
Schedule of Equity Method Investments [Line Items]
Basis Difference, Amortization Period	35 years
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ (1,099,802)	$ 376,500	$ 386,800	$ 404,700
Long-term Debt
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 47,182
Property, Plant and Equipment
Schedule of Equity Method Investments [Line Items]
Basis Difference, Amortization Period	35 years
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ (1,146,984)
Maximum | Long-term Debt
Schedule of Equity Method Investments [Line Items]
Basis Difference, Amortization Period	25 years
Minimum | Long-term Debt
Schedule of Equity Method Investments [Line Items]
Basis Difference, Amortization Period	2 years

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliates - Summarized Financial Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets	$ 132,213	$ 122,362
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	6,031,066	5,974,926
Equity Method Investment, Summarized Financial Information, Current Liabilities	694,951	714,037
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	1,502,906	2,049,189
Equity Method Investment Summarized Financial Information, Equity	3,965,422	3,334,062
Equity Method Investment, Summarized Financial Information, Revenue	930,771	860,115	$ 440,838
Equity Method Investment Summarized Financial Information Operating Income	524,607	480,337	203,801
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	$ 376,934	$ 465,592	$ 184,314

Investments in Unconsolidated_4

Investments in Unconsolidated Affiliaties - (Details) - USD ($) $ in Thousands	Jul. 13, 2018	Jul. 12, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Feb. 07, 2018	Jan. 01, 2018	Jul. 20, 2017	Mar. 31, 2017	May 06, 2016
Schedule of Equity Method Investments [Line Items]
Unconsolidated investments			$ 1,861,686	$ 909,531
Equity interest ownership percentage			20.00%
Equity in earnings of unconsolidated investments			$ 306,819	237,110	$ 54,531
Contributions to unconsolidated investments			(473,946)	$ (45,948)	$ (50,076)
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Unconsolidated investments							$ 42,800			$ 436,000
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity			$ (1,099,802)			$ 376,500			$ 386,800	$ 404,700
Basis Difference, Amortization Period			35 years
Depreciation Rate			2.86%
Equity interest ownership percentage			75.00%
Equity in earnings of unconsolidated investments			$ 303,400
Distributions to unconsolidated affiliates			380,700
Contributions to unconsolidated investments		$ (412,500)	$ (432,000)
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired										(25.00%)
Tallgrass Development LP | Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired						(25.01%)			(24.99%)
Kinder Morgan Cushing, LLC | Deeprock Development, LLC
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired								(40.00%)
Senior Notes | Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Repayments of Senior Debt	$ 550,000
Debt Instrument, Interest Rate, Stated Percentage			6.85%

Goodwill and Intangible Asset_2

Goodwill and Intangible Assets - Schedule of Goodwill by Segment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Goodwill	$ 421,983	$ 404,838	$ 343,288
Goodwill, Acquired During Period	17,145	61,550
Natural Gas Transportation
Goodwill [Line Items]
Goodwill	255,558	255,558	255,558
Goodwill, Acquired During Period	0	0
Gathering, Processing & Terminalling
Goodwill [Line Items]
Goodwill	166,425	149,280	$ 87,730
NGL Water Solutions Bakken | Gathering, Processing & Terminalling
Goodwill [Line Items]
Goodwill, Acquired During Period	$ 17,145
Deeprock Development, LLC | Gathering, Processing & Terminalling
Goodwill [Line Items]
Goodwill, Acquired During Period		$ 61,550

Goodwill and Intangible Asset_3

Goodwill and Intangible Assets - Intangible Assets (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Acquired Finite-Lived Intangible Assets [Line Items]
Accumulated amortization	$ 26,318,000	$ 16,306,000
Intangible assets, net	227,103,000	97,731,000
Use Rights
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-lived Intangible Assets Acquired	105,973,000	105,973,000
Customer Contracts
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-lived Intangible Assets Acquired	60,348,000	8,064,000
Customer Relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-lived Intangible Assets Acquired	52,100,000	0
Plaquemines Liquids Terminal, LLC | Use Rights
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-lived Intangible Assets Acquired	$ 35,000,000	$ 0

Goodwill and Intangible Asset_4

Goodwill and Intangible Assets - Future Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Nov. 05, 2018
Finite-Lived Intangible Assets [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill		$ 35,000
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
2,019	$ 16,528
2,020	16,347
2,021	16,294
2,022	13,144
2,023	13,144
Thereafter	116,646
Total (1)	$ 192,103
Plaquemines Liquids Terminal, LLC
Finite-Lived Intangible Assets [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill		$ 35,000
Plaquemines Liquids Terminal, LLC | Use Rights
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life	35 years

Goodwill and Intangible Asset_5

Goodwill and Intangible Assets - Additional Detail (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization of Intangible Assets	$ 8.1	$ 3.8	$ 3

Risk Management - Schedule of F

Risk Management - Schedule of Fair Value of Derivative Contracts (Details) - Energy Related Derivative $ in Thousands	Dec. 31, 2018USD ($)bbl	Dec. 31, 2017USD ($)bbl
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 3,526
Derivative liability at fair value	1,642	$ 2,368
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	3,526	0
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability at fair value	$ 1,642	$ 2,368
Commodity | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,105,146
Commodity | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	1,274,500	356,000

Risk Management - Derivative Co

Risk Management - Derivative Contracts Included in Consolidated Statement of Income (Detail) - Not Designated as Hedging Instrument - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Energy Related Derivative
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 29,510	$ 39	$ (40)
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	0	75	74
Equity Option
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 0	$ 1,885	$ (1,291)

Risk Management - Derivative In

Risk Management - Derivative Instruments Maximum Potential Exposure to Credit Loss (Details) - Energy Related Derivative $ in Thousands	Dec. 31, 2018USD ($)
Concentration Risk [Line Items]
Gross	$ 3,526
Netting agreement impact	0
Cash collateral held	0
Net exposure	$ 3,526

Risk Management - Schedule of E

Risk Management - Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established (Details) - Energy Related Derivative - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 3,526
Derivative liability at fair value	1,642	$ 2,368
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
Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	3,526
Derivative liability at fair value	1,642	2,368
Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	0
Derivative liability at fair value	$ 0	$ 0

Risk Management - Additional In

Risk Management - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Dec. 31, 2017	Feb. 01, 2017	Oct. 31, 2016	Jul. 21, 2016	Jan. 01, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Feb. 01, 2018
Derivative [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased		736,262
Partial exercise of call option		$ 35,300
Cash in Margin Accounts and Outstanding Letters of Credit	3
Pony Express Pipeline
Derivative [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					31.30%				2.00%
Option Indexed to Issuer's Equity, Strike Price					$ 42.50
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		$ 0	$ 72,381	$ 204,634
Equity Option | Pony Express Pipeline
Derivative [Line Items]
Derivative, Term of Contract					18 months
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares					6,518,000

Long-term Debt - Schedule of De

Long-term Debt - Schedule of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total long-term debt, net	$ 3,205,958	$ 2,292,993
Revolving Credit Facility
Debt Instrument [Line Items]
Total long-term debt, net	1,224,000	807,000
Tallgrass Equity, LLC | Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross	0	146,000
Tallgrass Energy Partners
Debt Instrument [Line Items]
Less: Deferred financing costs, net	(21,421)	(17,737)
Plus: Unamortized premium on 2028 Notes	3,379	3,730
Tallgrass Energy Partners | Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross	1,224,000	661,000
Total long-term debt, net	1,224,000	661,000
2023 Senior Notes
Debt Instrument [Line Items]
Total long-term debt, net	494,603
2023 Senior Notes | Tallgrass Energy Partners | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	500,000	0
2024 Senior Notes
Debt Instrument [Line Items]
Total long-term debt, net	741,196	739,824
2024 Senior Notes | Tallgrass Energy Partners | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	750,000	750,000
2028 Senior Notes
Debt Instrument [Line Items]
Total long-term debt, net	746,159	746,169
2028 Senior Notes | Tallgrass Energy Partners | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	$ 750,000	$ 750,000

Long-term Debt - Capacity under

Long-term Debt - Capacity under Revolving Credit Facility - TEP (Details) - USD ($)	Dec. 31, 2018	Jul. 26, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Long-term Debt	$ (3,205,958,000)		$ (2,292,993,000)
Revolving Credit Facility
Line of Credit Facility [Line Items]
Long-term Debt	(1,224,000,000)		(807,000,000)
Tallgrass Energy Partners | Revolving Credit Facility
Line of Credit Facility [Line Items]
Long-term Debt	(1,224,000,000)		(661,000,000)
Letters of Credit Outstanding, Amount	(94,000)		(94,000)
Line of Credit Facility, Remaining Borrowing Capacity	1,025,906,000		1,088,906,000
Wells Fargo Bank, National Association | Tallgrass Energy Partners | Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,250,000,000	$ 2,250,000,000	$ 1,750,000,000

Long-term Debt - Carrying Amoun

Long-term Debt - Carrying Amount and Fair Value of Long-term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term Debt	$ 3,205,958	$ 2,292,993
2023 Senior Notes
Debt Instrument [Line Items]
Fair Value	485,285
Long-term Debt	494,603
2023 Senior Notes | Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Fair Value	0
2023 Senior Notes | Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Fair Value	485,285
2023 Senior Notes | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Fair Value	0
2024 Senior Notes
Debt Instrument [Line Items]
Fair Value	737,745	771,645
Long-term Debt	741,196	739,824
2024 Senior Notes | Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Fair Value	0	0
2024 Senior Notes | Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Fair Value	737,745	771,645
2024 Senior Notes | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Fair Value	0	0
2028 Senior Notes
Debt Instrument [Line Items]
Fair Value	726,503	758,168
Long-term Debt	746,159	746,169
2028 Senior Notes | Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Fair Value	0	0
2028 Senior Notes | Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Fair Value	726,503	758,168
2028 Senior Notes | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Fair Value	0	0
Revolving Credit Facility
Debt Instrument [Line Items]
Fair Value	1,224,000	807,000
Long-term Debt	1,224,000	807,000
Revolving Credit Facility | Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Fair Value	0	0
Revolving Credit Facility | Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Fair Value	1,224,000	807,000
Revolving Credit Facility | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Fair Value	$ 0	$ 0

Long-term Debt - Additional Inf

Long-term Debt - Additional Information (Detail)	Sep. 26, 2018USD ($)	Jul. 26, 2018USD ($)	Dec. 11, 2017USD ($)	Sep. 15, 2017USD ($)	May 16, 2017USD ($)	Sep. 01, 2016USD ($)	Jul. 25, 2018	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt								$ 500,000,000	$ 1,103,750,000	$ 400,000,000
Tallgrass Energy Partners | Revolving Credit Facility
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate								3.96%
Debt Instrument, Interest Rate, Effective Percentage								4.11%
Tallgrass Energy Partners | Revolving Credit Facility | Wells Fargo Bank, National Association
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 2,250,000,000						$ 2,250,000,000	$ 1,750,000,000
Tallgrass Energy Partners | Maximum | Revolving Credit Facility
Debt Instrument [Line Items]
Consolidated leverage ratio		5.50					5
Consolidated Senior Secured Leverage Ratio One								3.75
Credit facility commitment fee		0.375%					0.50%
Tallgrass Energy Partners | Minimum | Revolving Credit Facility
Debt Instrument [Line Items]
Consolidated Interest Coverage Ratio One								2.50
Credit facility commitment fee		0.25%					0.25%
2023 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								4.75%
2028 Senior Notes | Senior Notes | Tallgrass Energy Partners
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt			$ 250,000,000	$ 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%

Partnership Equity and Distri_3

Partnership Equity and Distributions - TGE Summary of Distributions (Details) - Tallgrass Energy, LP (TGE) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	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]
Dividends	$ 81,304	$ 79,717	$ 77,052	$ 28,316	$ 21,346	$ 20,617	$ 19,891	$ 16,697	$ 16,116	$ 12,528	$ 11,693	$ 10,022
Dividends Payable, Amount Per Share	$ 0.5200	$ 0.5100	$ 0.4975	$ 0.4875	$ 0.3675	$ 0.3550	$ 0.3425	$ 0.2875	$ 0.2775	$ 0.2625	$ 0.2450	$ 0.2100

Partnership Equity and Distri_4

Partnership Equity and Distributions - TEP Summary of Distributions (Details) - Tallgrass Energy Partners - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	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 Distributions	$ 71,370	$ 70,638	$ 69,174	$ 67,671	$ 60,486	$ 58,793	$ 57,332	$ 54,442	$ 48,238
Incentive Distribution Rights, Distribution	39,816	39,125	37,744	36,342	29,840	28,358	26,987	24,262	19,816
General Partner Distributions	1,267	1,251	1,219	1,186	1,040	1,008	976	911	830
Total Distributions	$ (112,453)	$ (111,014)	$ (108,137)	$ (105,199)	$ (91,366)	$ (88,159)	$ (85,295)	$ (79,615)	$ (68,884)
Distribution per Limited Partner Unit	$ 0.9750	$ 0.9650	$ 0.9450	$ 0.9250	$ 0.8350	$ 0.8150	$ 0.7950	$ 0.7550	$ 0.7050

Partnership Equity and Distri_5

Partnership Equity and Distributions - Additional Information (Detail) - USD ($)	Feb. 07, 2018	Feb. 01, 2017	Nov. 17, 2016	Nov. 16, 2016	Apr. 28, 2016	Jan. 01, 2016	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Feb. 01, 2018	May 06, 2016
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased		736,262
Payments for Repurchase of Common Stock		$ 35,300,000
Treasury Stock Acquired, Average Cost Per Share		$ 47.99
Partners' Capital Account, Units, Private Placement of Units					2,416,987
Proceeds from private placement of TEP common units, net of offering costs					$ 90,000,000												$ 0	$ 0	$ 90,009,000
Distributions to noncontrolling interests																	(327,578,000)	(317,102,000)	(249,142,000)
Payments for Purchase of Common Stock																	(198,000,000)
Acquisitions																			280,000,000
Terminals and NatGas
Limited Partners' Capital Account [Line Items]
Acquisitions																		$ 57,700,000
Carrying Value of Assets Acquired																		82.3
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Distributions to noncontrolling interests																	(50,000,000)	$ 0	$ (425,882,000)
Acquisitions																	$ 16,200,000
Carrying Value of Assets Acquired																	33.8		417.7
Tallgrass Energy Partners
Limited Partners' Capital Account [Line Items]
Ownership Interest																100.00%
Partners' Capital Account, Units, Sold in Public Offering																		2,341,061	7,696,708
Shares Issued, Price Per Share								$ 48.82				$ 44.46						$ 48.82	$ 44.46
Issuance of units to public, net of offering costs																		$ 112,400,000	$ 337,700,000
Limited Partners' Offering Costs								$ 1,900,000				$ 4,500,000						1,900,000	4,500,000
Payments for Repurchase of Common Stock																	$ 0	35,335,000	0
Partners' Capital Account, Distributions							$ 112,453,000	$ 111,014,000	$ 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]
Ownership Interest																	55.79%
Variable Interest Entity Ownership Percentage			36.94%	30.35%
Equity interest held by noncontrolling interests			63.06%	69.65%												44.21%	44.21%
Deeprock Development, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests																40.00%	40.00%
BNN Colorado Water, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests																37.00%	37.00%
Common Class A
Limited Partners' Capital Account [Line Items]
Conversion of Stock, Shares Issued																	2,821,332
Partners' Capital Account, Units, Sold in Public Offering			9,000,000
Shares Issued, Price Per Share			$ 22
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired						31.30%														2.00%
Distributions to noncontrolling interests						$ (475,000,000)
Common Unit, Issuance Value						$ 268,600,000
Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired																					25.00%
Over-Allotment Option | Common Class A
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Units, Sold in Public Offering			1,350,000
Tallgrass Development LP
Limited Partners' Capital Account [Line Items]
Units Acquired	5,619,218
Tallgrass Development LP | Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	25.01%										24.99%
Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Contributions from noncontrolling interests																	$ 1,787,000	1,589,000	9,304,000
Distributions to noncontrolling interests																	(327,578,000)	(317,102,000)	(249,142,000)
Tallgrass Equity distributions to noncontrolling interest																	223,700,000	125,200,000	97,500,000
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders																	6,200,000	6,200,000	6,500,000
Carrying Value of Common Units	53.8
Contributions from TD																		1,451,000	12,067,000
Distribution of Excess Proceeds to Exchange Right Holders																			0
Noncontrolling Interest | Terminals and NatGas
Limited Partners' Capital Account [Line Items]
Acquisitions																		(36,391,000)
Noncontrolling Interest | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Acquisitions																	(44,732,000)		(173,422,000)
Noncontrolling Interest | Tallgrass Energy Partners
Limited Partners' Capital Account [Line Items]
Issuance of units to public, net of offering costs																	(279,000)	101,067,000	308,909,000
Payments for Repurchase of Common Stock																		(31,717,000)
Proceeds from private placement of TEP common units, net of offering costs																			82,417,000
Partners' Capital Account, Distributions																	(97,700,000)	(185,700,000)	(145,100,000)
Noncontrolling Interest | Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Acquisitions																	74,421,000	40,159,000
Noncontrolling Interest | Deeprock Development, LLC
Limited Partners' Capital Account [Line Items]
Acquisitions																		45,869,000
Total Partner Equity Including Portion Attributable to Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Contributions from noncontrolling interests																	1,787,000	1,589,000	9,304,000
Distributions to noncontrolling interests																	(327,578,000)	(317,102,000)	(249,142,000)
Contributions from TD																		2,301,000	17,894,000
Distribution of Excess Proceeds to Exchange Right Holders																			1,603,000
Total Partner Equity Including Portion Attributable to Noncontrolling Interest | Terminals and NatGas
Limited Partners' Capital Account [Line Items]
Acquisitions																		(140,000,000)
Total Partner Equity Including Portion Attributable to Noncontrolling Interest | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Acquisitions																	(50,000,000)		(429,039,000)
Total Partner Equity Including Portion Attributable to Noncontrolling Interest | Tallgrass Energy Partners
Limited Partners' Capital Account [Line Items]
Issuance of units to public, net of offering costs																	(377,000)	112,420,000	337,671,000
Payments for Repurchase of Common Stock																		(35,335,000)
Proceeds from private placement of TEP common units, net of offering costs																			90,009,000
Total Partner Equity Including Portion Attributable to Noncontrolling Interest | Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Acquisitions																	108,537,000	63,681,000
Total Partner Equity Including Portion Attributable to Noncontrolling Interest | Deeprock Development, LLC
Limited Partners' Capital Account [Line Items]
Acquisitions																		45,869,000
Common Class A
Limited Partners' Capital Account [Line Items]
Contributions from noncontrolling interests																	0	0	0
Distributions to noncontrolling interests																	0	0	0
Contributions from TD																		850,000	5,827,000
Distribution of Excess Proceeds to Exchange Right Holders																			1,603,000
Common Class A | Terminals and NatGas
Limited Partners' Capital Account [Line Items]
Acquisitions																		(21,314,000)
Common Class A | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Acquisitions																	(5,268,000)		(255,617,000)
Common Class A | Tallgrass Energy Partners
Limited Partners' Capital Account [Line Items]
Issuance of units to public, net of offering costs																	(98,000)	11,353,000	28,762,000
Payments for Repurchase of Common Stock																		(3,618,000)
Proceeds from private placement of TEP common units, net of offering costs																			7,592,000
Common Class A | Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Acquisitions																	$ 34,116,000	$ 23,522,000
Common Class A | Tallgrass Energy, LP (TGE)
Limited Partners' Capital Account [Line Items]
Distribution of Excess Proceeds to Exchange Right Holders																			$ 1,603,000

Revenue from Contracts with C_3

Revenue from Contracts with Customers - Impact of Adoption (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Unconsolidated investments	$ 1,861,686				$ 909,531				$ 1,861,686	$ 909,531
Total revenues	(220,256)	$ (200,320)	$ (193,589)	$ (179,094)	(174,766)	$ (175,869)	$ (160,863)	$ (144,400)	(793,259)	(655,898)	$ (611,662)
Equity in earnings of unconsolidated investments									306,819	237,110	54,531
Net income attributable to TGE	$ 59,779	$ 59,550	$ 1,063	$ 16,735	$ (165,377)	$ 15,866	$ 8,753	$ 12,029	$ 137,127	$ (128,729)	$ 33,789
Basic net income per Class A share	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ (2.85)	$ 0.27	$ 0.15	$ 0.21	$ 1.27	$ (2.22)	$ 0.55
Diluted net income per Class A share	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ (2.85)	$ 0.27	$ 0.15	$ 0.21	$ 1.27	$ (2.22)	$ 0.55
Accounting Standards Update 2014-09 | Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Unconsolidated investments	$ 1,773,849								$ 1,773,849
Equity in earnings of unconsolidated investments									261,848
Net income attributable to TGE									$ 121,402
Basic net income per Class A share									$ 1.13
Diluted net income per Class A share									$ 1.13
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Unconsolidated investments	$ 87,837								$ 87,837
Equity in earnings of unconsolidated investments									44,971
Net income attributable to TGE									$ 15,725
Basic net income per Class A share									$ 0.14
Diluted net income per Class A share									$ 0.14
Crude oil transportation services
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total revenues									$ (398,334)	$ (345,733)	$ (374,949)
Crude oil transportation services | Accounting Standards Update 2014-09 | Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total revenues									(398,329)
Crude oil transportation services | Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total revenues									(5)
Sales of natural gas, NGLs, and crude oil
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total revenues									(168,586)	(108,503)	(77,123)
Sales of natural gas, NGLs, and crude oil | Accounting Standards Update 2014-09 | Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total revenues									(173,055)
Sales of natural gas, NGLs, and crude oil | Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total revenues									(4,469)
Processing and other revenues
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total revenues									(99,445)	(79,298)	(39,628)
Processing and other revenues | Accounting Standards Update 2014-09 | Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total revenues									(104,117)
Processing and other revenues | Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Total revenues									(4,672)
Cost of Sales
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of sales and transportation services									114,815	$ 91,213	$ 71,650
Cost of Sales | Accounting Standards Update 2014-09 | Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of sales and transportation services									123,458
Cost of Sales | Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Cost of sales and transportation services									$ (8,643)

Revenue from Contracts with C_4

Revenue from Contracts with Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 793,259
Equity Method Investment, Summarized Financial Information, Revenue	930,771	$ 860,115	$ 440,838
Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	392,276
Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	123,456
Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	52,333
Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	24,109
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	21,605
Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	613,779
Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	101,382
Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	30,753
Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6,942
Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	139,077
Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	752,856
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	40,403
Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	140,459
Natural Gas Transportation | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Natural Gas Transportation | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	128,041
Natural Gas Transportation | Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Natural Gas Transportation | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Natural Gas Transportation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	11,223
Natural Gas Transportation | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	139,264
Natural Gas Transportation | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Natural Gas Transportation | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,195
Natural Gas Transportation | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Natural Gas Transportation | Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	1,195
Natural Gas Transportation | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	140,459
Natural Gas Transportation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	444,454
Crude Oil Transportation | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	392,276
Crude Oil Transportation | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Crude Oil Transportation | Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Crude Oil Transportation | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Crude Oil Transportation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	45,888
Crude Oil Transportation | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	438,164
Crude Oil Transportation | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Crude Oil Transportation | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Crude Oil Transportation | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6,290
Crude Oil Transportation | Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6,290
Crude Oil Transportation | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	444,454
Crude Oil Transportation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Gathering, Processing & Terminalling
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	279,665
Gathering, Processing & Terminalling | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Gathering, Processing & Terminalling | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Gathering, Processing & Terminalling | Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	52,333
Gathering, Processing & Terminalling | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	24,109
Gathering, Processing & Terminalling | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	18,444
Gathering, Processing & Terminalling | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	94,886
Gathering, Processing & Terminalling | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	101,382
Gathering, Processing & Terminalling | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	29,558
Gathering, Processing & Terminalling | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	652
Gathering, Processing & Terminalling | Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	131,592
Gathering, Processing & Terminalling | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	226,478
Gathering, Processing & Terminalling | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	53,187
Corporate and Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(71,319)
Corporate and Other | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Corporate and Other | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(4,585)
Corporate and Other | Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Corporate and Other | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Corporate and Other | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(53,950)
Corporate and Other | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(58,535)
Corporate and Other | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Corporate and Other | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Corporate and Other | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Corporate and Other | Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0
Corporate and Other | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(58,535)
Corporate and Other | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ (12,784)

Revenue from Contracts with C_5

Revenue from Contracts with Customers - Remaining Performance Obligation (Details) $ in Thousands	Dec. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 532,549
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 357,226
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 170,713
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 163,852
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Amount	$ 140,101
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	111 years 3 months
Revenue, Remaining Performance Obligation, Amount	$ 1,575,066

Revenue from Contracts with C_6

Revenue from Contracts with Customers - Contract with Customer, Asset and Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Contract with Customer, Asset, Net	$ 80,935	$ 61,888
Accounts and Other Receivables, Net, Current	151,414	56,727
Accounts Receivable, Related Parties, Current	3,748	1,340
Accounts receivable, net	236,097	119,955
Deferred revenue	111,095	$ 88,471
Contract with Customer, Liability, Revenue Recognized	$ 12,000

Commitments and Contingencies_2

Commitments and Contingencies - Schedule of Future Minimum Rental Payments for Operating Leases (Details) $ in Thousands	Dec. 31, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 1,818
Operating Leases, Future Minimum Payments, Due in Two Years	1,757
Operating Leases, Future Minimum Payments, Due in Three Years	1,056
Operating Leases, Future Minimum Payments, Due in Four Years	796
Operating Leases, Future Minimum Payments, Due in Five Years	679
Operating Leases, Future Minimum Payments, Due Thereafter	3,153
Operating Leases, Future Minimum Payments Due	9,259
Capital Leases, Future Minimum Payments Due, Next Twelve Months	449
Capital Leases, Future Minimum Payments Due in Two Years	449
Capital Leases, Future Minimum Payments Due in Three Years	449
Capital Leases, Future Minimum Payments Due in Four Years	449
Capital Leases, Future Minimum Payments Due in Five Years	449
Capital Leases, Future Minimum Payments Due Thereafter	17,770
Capital Leases, Future Minimum Payments Due	$ 20,015

Commitments and Contingencies_3

Commitments and Contingencies - Other Commitments (Details) $ in Thousands	Dec. 31, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,019	$ 13,467
2,020	11,198
2,021	6,677
2,022	5,604
2,023	5,614
Thereafter	13,231
Total Other Purchase Obligations	$ 55,791

Commitments and Contingencies_4

Commitments and Contingencies - Additional Information - (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Rent Expense	$ 1.4	$ 9.5	$ 16.5
Commitments for Future Capital Expenditures	39.6
Capital Lease Obligations	$ 30.7

Net Income per Class A Share -

Net Income per Class A Share - Schedule of Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Net income (loss) attributable to TGE, excluding predecessor operations interest									$ 137,127	$ (128,729)	$ 26,794
Basic weighted average Class A Shares outstanding									107,586	58,076	48,856
Basic net income (loss) per Class A share	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ (2.85)	$ 0.27	$ 0.15	$ 0.21	$ 1.27	$ (2.22)	$ 0.55
Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares									$ 2,108	$ 0	$ 9
Net income (loss) attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares									$ 139,235	$ (128,729)	$ 26,803
Equity Participation Shares equivalent shares									2,231	0	33
Diluted weighted average Class A Shares outstanding									109,817	58,076	48,889
Diluted net income (loss) per Class A share	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ (2.85)	$ 0.27	$ 0.15	$ 0.21	$ 1.27	$ (2.22)	$ 0.55

Major Customers and Concentra_3

Major Customers and Concentration of Credit Risk (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Concentration Risk [Line Items]
Total Revenues	$ 220,256	$ 200,320	$ 193,589	$ 179,094	$ 174,766	$ 175,869	$ 160,863	$ 144,400	$ 793,259	$ 655,898	$ 611,662
Continental Resources
Concentration Risk [Line Items]
Total Revenues									$ 81,900	$ 100,200	$ 97,800
Concentration Risk, Percentage									10.00%	15.00%	16.00%
Shell Trading (US) Company
Concentration Risk [Line Items]
Total Revenues											$ 76,200
Concentration Risk, Percentage											12.00%
Natural Gas Transportation
Concentration Risk [Line Items]
Concentration Risk, Percentage									58.00%
Crude Oil Transportation
Concentration Risk [Line Items]
Concentration Risk, Percentage									84.00%
Gathering, Processing & Terminalling
Concentration Risk [Line Items]
Concentration Risk, Percentage									60.00%

Equity- Based Compensation - Sc

Equity- Based Compensation - Schedule of Share-based Compensation (Details)	Jun. 30, 2018	Dec. 31, 2018$ / sharesshares	Dec. 31, 2017$ / sharesshares	Dec. 31, 2016$ / sharesshares	Dec. 31, 2015$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exchange Ratio	2
Shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | shares		3,049,644	224,998	205,000	160,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | shares		1,138,200	30,000	45,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | shares		(20,664)	(10,002)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period | shares		(79,200)
Weighted Average Grant Date Fair Value
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ / shares		$ 18.25	$ 25.91	$ 25.83	$ 27.97
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares		17.01	23.66	$ 18.22
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ / shares		(19.19)	$ (14.26)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ / shares		$ (20.62)
Tallgrass Energy Partners
Shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | shares		1,786,310
Weighted Average Grant Date Fair Value
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares		$ 18.20

Equity Based Compensation - Add

Equity Based Compensation - Additional Information (Detail) $ in Millions	Jun. 30, 2018	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Aug. 02, 2018shares	May 12, 2015shares
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Exchange Ratio	2
Allocated Share-based Compensation Expense		$ 7.6	$ 1.6	$ 1.4
Share-based compensation expense related to the EPU grants recognized		(7.6)	$ (0.2)	$ (0.2)
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized		$ 34.3
Weighted average period in which compensation cost related to nonvested EPUs expected to be recognized		3 years 2 months
Maximum
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | shares						3,144,589
Legacy LTIP | Maximum
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | shares					20,000,000

Income Taxes - Schedule of Comp

Income Taxes - Schedule of Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Federal income tax	$ 41,585	$ 200,787	$ 15,587
State income tax	14,124	7,671	2,154
Deferred income tax expense	$ 55,709	$ 208,458	$ 17,741

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Contingency [Line Items]
Net income before tax									$ 523,380	$ 432,443	$ 267,780
Predecessor operations interest in net income									0	0	(6,995)
Net Income Attributable to Parent before tax, Excluding Predecessor Share of Income									523,380	432,443	260,785
Net income attributable to noncontrolling interests	$ (65,166)	$ (59,162)	$ (108,638)	$ (97,578)	$ (72,180)	$ (154,911)	$ (70,414)	$ (55,209)	(330,544)	(352,714)	(216,250)
Income Loss From Continuing Operations Before Income Taxes Extraordinary Items But After Deducting Income And Taxes Attributable To Noncontrolling Interest									$ 192,836	$ 79,729	$ 44,535
Federal statutory income tax rate									21.00%	35.00%	35.00%
Income tax at statutory rate									$ 40,496	$ 27,905	$ 15,587
State income taxes, net of federal benefit									5,419	2,392	1,592
Change in tax rate										172,900
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount									1,089
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount									0	3,926	0
Total income tax expense before change in tax legislation									55,709	35,576	17,741
Deferred income tax expense									$ 55,709	$ 208,458	$ 17,741
Effective tax rate									10.60%	48.20%	6.80%
State and Local Jurisdiction
Income Tax Contingency [Line Items]
Change in tax rate									$ 8,705	$ 1,353	$ 562
US Treasury and Government
Income Tax Contingency [Line Items]
Change in tax rate									0	172,037	0
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount									$ 0	$ 845	$ 0

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	May 12, 2015
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Investment in Subsidiaries	$ 198,290	$ 269,136
Deferred Tax Assets, Operating Loss Carryforwards	80,012	48,632
Deferred Tax Assets, Gross	278,302	317,768
Deferred Tax Assets, Valuation Allowance	(4,771)	(4,771)
Deferred Tax Assets, Net	273,531	$ 312,997	$ 445,200
Deferred Tax Liabilities, Investment in Noncontrolled Affiliates	$ 817

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Nov. 17, 2016	May 12, 2015
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Net	$ 312,997	$ 273,531		$ 445,200
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	$ 172,900
US Treasury and Government
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards		328,000
Exchange Right Holders
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Net		$ 15,400	$ 86,800

Regulatory Matters (Details)

Regulatory Matters (Details)	12 Months Ended
	Dec. 31, 2018Bcf / dmi	Jul. 01, 2018	Jul. 01, 2017	Jul. 01, 2016
Public Utilities, General Disclosures [Line Items]
Capacity Enhancement | Bcf / d	0.8
Miles of Pipeline | mi	70
Size of Pipeline	36
Pony Express Pipeline
Public Utilities, General Disclosures [Line Items]
FERC Annual Index Adjustment		4.40%	0.20%	2.01%
Pony Express Pipeline | Local Non-Contract Rates
Public Utilities, General Disclosures [Line Items]
FERC Annual Index Adjustment				97.99%

Legal and Environmental Matte_2

Legal and Environmental Matters - Additional Information (Detail)

Jul. 12, 2017USD ($)

Feb. 16, 2017USD ($)

Feb. 02, 2017USD ($)

Jan. 12, 2017USD ($)Bcf / d

May 20, 2016USD ($)

Jun. 17, 2014USD ($)

Jan. 31, 2017bbl

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)mi

Dec. 31, 2016Bcf / d

Dec. 31, 2015mi

Dec. 31, 2017USD ($)

Dec. 31, 2017USD ($)

Apr. 14, 2016USD ($)

Loss Contingencies [Line Items]

Accrued taxes

$ 20,734,000

$ 19,272,000

$ 19,272,000

$ 19,272,000

Environmental accruals

7,400,000

7,700,000

7,700,000

7,700,000

Environmental Remediation Expense

21,000,000

$ 21,800,000

Aggregate cost of crack tool runs

$ 18,000,000

Crude Oil Spilled or Leaked | bbl

10,000

Crude oil recovered | bbl

9,000

General Partner

Loss Contingencies [Line Items]

Contributions from TD

$ 20,000,000

Rockies Express Pipeline LLC

Loss Contingencies [Line Items]

Excise and Sales Taxes

7,100,000

Accrued taxes

3,300,000

Income Taxes Receivable

10,400,000

Total Remediation costs

6,100,000

Trailblazer

Loss Contingencies [Line Items]

Miles of Natural Gas Pipeline Needing Repair or Replacement | mi

8

Tallgrass Development LP

Loss Contingencies [Line Items]

Contractual indemnity provided to TEP by TD

20,000,000

Annual deductible

$ 1,500,000

Tallgrass Terminals, LLC

Loss Contingencies [Line Items]

Total Remediation costs

$ 600,000

Minimum | Trailblazer

Loss Contingencies [Line Items]

Miles of Natural Gas Pipeline Needing Repair or Replacement | mi

25

Maximum | Trailblazer

Loss Contingencies [Line Items]

Miles of Natural Gas Pipeline Needing Repair or Replacement | mi

35

Mineral Management Service Lawsuit

Loss Contingencies [Line Items]

Litigation Settlement, Amount Awarded from Other Party

$ 65,000,000

Ultra Resources Complaint

Loss Contingencies [Line Items]

Litigation Settlement, Amount Awarded from Other Party

$ 150,000,000

Firm transportation service agreement | Bcf / d

0.2

0.2

Gain Contingency, Unrecorded Amount

$ 303,000,000

Firm Transportation Rate

$ 0.37

Anticipated Annual Revenue

$ 26,800,000

Michels Corporation Complaint

Loss Contingencies [Line Items]

Loss Contingency, Damages Sought, Value

$ 24,200,000

Litigation Settlement, Amount Awarded to Other Party

$ 10,000,000

$ 10,000,000

Withholding for Liquidated Delay Damages and Excess Completion Costs

$ 5,900,000

Reporting Segments - Summary of

Reporting Segments - Summary of TGE's Segment Information of Revenue (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total Revenues	$ 220,256	$ 200,320	$ 193,589	$ 179,094	$ 174,766	$ 175,869	$ 160,863	$ 144,400	$ 793,259	$ 655,898	$ 611,662
TGE
Segment Reporting Information [Line Items]
Total Revenues									793,259	655,898	611,662
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues									135,798	134,327	129,456
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues									405,135	353,898	380,133
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues									252,326	167,673	102,073
TGE | Operating Segments
Segment Reporting Information [Line Items]
Total Revenues									864,578	691,806	629,133
TGE | Operating Segments | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues									140,459	141,021	135,097
TGE | Operating Segments | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues									444,454	364,574	380,503
TGE | Operating Segments | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues									279,665	186,211	113,533
TGE | Inter-Segment
Segment Reporting Information [Line Items]
Total Revenues									(71,319)	(35,908)	(17,471)
TGE | Inter-Segment | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues									(4,661)	(6,694)	(5,641)
TGE | Inter-Segment | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues									(39,319)	(10,676)	(370)
TGE | Inter-Segment | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues									$ (27,339)	$ (18,538)	$ (11,460)

Reporting Segments - Summary _2

Reporting Segments - Summary of TGE's Segment Information of Earnings (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Equity in earnings of unconsolidated investments									$ 306,819	$ 237,110	$ 54,531
(Gain) loss on disposal of assets									11,043	599	(1,849)
Gain on remeasurement of unconsolidated investment									0	9,728	0
Interest expense, net									133,319	89,348	45,601
Depreciation, Depletion and Amortization, Nonproduction									(110,862)	(90,800)	(86,247)
Proceeds from Equity Method Investment, Distribution									(306,934)	(237,192)	(54,449)
Loss on debt retirement									2,200
Deferred income tax expense									(55,709)	(208,458)	(17,741)
Net income attributable to noncontrolling interests	$ 65,166	$ 59,162	$ 108,638	$ 97,578	$ 72,180	$ 154,911	$ 70,414	$ 55,209	330,544	352,714	216,250
Net income (loss) attributable to TGE	$ 59,779	$ 59,550	$ 1,063	$ 16,735	$ (165,377)	$ 15,866	$ 8,753	$ 12,029	137,127	(128,729)	33,789
TGE
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Net income (loss) attributable to TGE									137,127	(128,729)	33,789
TGE | Natural Gas Transportation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									372,973	178,802	73,396
TGE | Crude Oil Transportation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									231,183	145,663	137,035
TGE | Gathering, Processing & Terminalling
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									71,601	13,381	830
TGE | Corporate and Other
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									(21,321)	(37,591)	(2,142)
TGE | Operating Segments | Natural Gas Transportation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									377,224	180,978	75,029
TGE | Operating Segments | Crude Oil Transportation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									239,330	140,785	132,154
TGE | Operating Segments | Gathering, Processing & Terminalling
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									59,203	16,083	4,078
TGE | Operating Segments | Corporate and Other
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									(21,321)	(37,591)	(2,142)
TGE | Inter-Segment | Natural Gas Transportation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									(4,251)	(2,176)	(1,633)
TGE | Inter-Segment | Crude Oil Transportation
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									(8,147)	4,878	4,881
TGE | Inter-Segment | Gathering, Processing & Terminalling
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									12,398	(2,702)	(3,248)
TGE | Inter-Segment | Corporate and Other
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization									0	0	0
TGE | Segment Reconciling Items
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Equity in earnings of unconsolidated investments									237,197	66,922	15,287
(Gain) loss on disposal of assets									4,630	189	(526)
Unrealized gain (loss) on derivative instrument									3,340	(64)	(650)
Gain on remeasurement of unconsolidated investment									0	2,744	0
Interest expense, net									(95,465)	(29,403)	(16,632)
Depreciation, Depletion and Amortization, Nonproduction									(74,998)	(26,131)	(25,567)
Proceeds from Equity Method Investment, Distribution									(302,364)	(86,551)	(22,085)
Share-based Compensation									(8,634)	(2,682)	(1,862)
Deficiency Payments									(14,443)	(7,701)	(9,672)
Loss on debt retirement									2,245	0	0
Deferred income tax expense									(55,709)	(208,458)	(17,741)
Exchange Right Holders | TGE | Segment Reconciling Items
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Net income attributable to noncontrolling interests									$ (208,618)	$ (137,849)	$ (95,882)

Reporting Segments - Summary _3

Reporting Segments - Summary of TGE's Segment Information for Payments to Acquire Plant, Property and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Capital expenditures	$ 368,873	$ 145,144	$ 84,491
TGE
Segment Reporting Information [Line Items]
Capital expenditures	368,873	145,144	84,491
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Capital expenditures	112,529	16,705	28,475
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Capital expenditures	65,745	57,022	29,893
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Capital expenditures	185,732	71,417	26,123
TGE | Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 4,867	$ 0	$ 0

Reporting Segments - Summary _4

Reporting Segments - Summary of TGE's Segment Information of Unconsolidated Investments (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Unconsolidated investments	$ 1,861,686	$ 909,531
TGE
Segment Reporting Information [Line Items]
Unconsolidated investments	1,861,686	909,531
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Unconsolidated investments	1,794,987	895,873
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Unconsolidated investments	35,467	0
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Unconsolidated investments	$ 31,232	$ 13,658

Reporting Segments - Summary _5

Reporting Segments - Summary of TGE's Segment Information of Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Assets	$ 5,893,509	$ 4,292,013
TGE
Segment Reporting Information [Line Items]
Assets	5,893,509	4,292,013
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Assets	2,606,696	1,606,666
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Assets	1,423,740	1,407,758
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Assets	1,522,559	943,340
TGE | Corporate and Other
Segment Reporting Information [Line Items]
Assets	$ 340,514	$ 334,249

Reporting Segments - Additional

Reporting Segments - Additional Information (Details) - Segment	12 Months Ended
	Dec. 31, 2018	Feb. 07, 2018	Mar. 31, 2017	May 06, 2016
Segment Reporting Information [Line Items]
Number of Reportable Segments	3
Equity interest ownership percentage	20.00%
Rockies Express Pipeline LLC
Segment Reporting Information [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				25.00%
Rockies Express Pipeline LLC | Tallgrass Development LP
Segment Reporting Information [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		25.01%	24.99%
Rockies Express Pipeline LLC
Segment Reporting Information [Line Items]
Equity interest ownership percentage	75.00%

Selected Quarterly Financial _3

Selected Quarterly Financial Data (Unaudited) - (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Selected Quarterly Financial Data (Unaudited) [Abstract]
Total revenues	$ 220,256	$ 200,320	$ 193,589	$ 179,094	$ 174,766	$ 175,869	$ 160,863	$ 144,400	$ 793,259	$ 655,898	$ 611,662
Operating income	99,359	90,084	79,275	81,913	67,674	74,003	66,944	63,226	350,631	271,847	258,418
Net income	124,945	118,712	109,701	114,313	(93,197)	170,777	79,167	67,238	467,671	223,985	250,039
Net income attributable to noncontrolling interests	65,166	59,162	108,638	97,578	72,180	154,911	70,414	55,209	330,544	352,714	216,250
Net income (loss) attributable to TGE	$ 59,779	$ 59,550	$ 1,063	$ 16,735	$ (165,377)	$ 15,866	$ 8,753	$ 12,029	$ 137,127	$ (128,729)	$ 33,789
Basic net income (loss) per Class A share	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ (2.85)	$ 0.27	$ 0.15	$ 0.21	$ 1.27	$ (2.22)	$ 0.55
Diluted net income (loss) per Class A share	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ (2.85)	$ 0.27	$ 0.15	$ 0.21	$ 1.27	$ (2.22)	$ 0.55

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail)	Jan. 31, 2019	Jan. 01, 2019	Dec. 31, 2018
Subsequent Event [Line Items]
Equity interest ownership percentage			20.00%
Powder River Gateway | Subsequent Event
Subsequent Event [Line Items]
Equity interest ownership percentage		51.00%
Tallgrass Energy GP, LLC | Blackstone Infrastructure Partners | Subsequent Event
Subsequent Event [Line Items]
Ownership Interest	100.00%
Tallgrass Energy, LP (TGE) | Blackstone Infrastructure Partners | Subsequent Event
Subsequent Event [Line Items]
Ownership Interest	44.00%