Tallgrass Energy 10-K 12 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Feb. 12, 2020	Jun. 28, 2019
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-37365
Entity Registrant Name	Tallgrass Energy, LP
City Area Code	(913)
Local Phone Number	928-6060
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	47-3159268
Entity Address, Address Line One	4200 W. 115th Street, Suite 350
Entity Address, City or Town	Leawood,
Entity Address, State or Province	KS
Entity Address, Postal Zip Code	66211
Title of 12(b) Security	Class A Shares Representing Limited Partner Interests
Trading Symbol	TGE
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 3,204
Entity Central Index Key	0001633651
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	FY
Amendment Flag	false
Common Class A
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		179,632,609
Common Class B
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		102,136,875

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current Assets:
Cash and cash equivalents	$ 9,394	$ 9,596
Accounts receivable, net	324,281	236,097
Inventories	49,081	34,316
Other Assets, Current	12,490	11,816
Total Current Assets	395,246	291,825
Property, plant and equipment, net	2,774,518	2,802,429
Goodwill	441,361	421,983
Intangible assets, net	241,552	227,103
Unconsolidated investments	2,006,219	1,861,686
Deferred tax asset	318,202	273,531
Deferred charges and other assets	36,988	14,952
Total Assets	6,214,086	5,893,509
Current Liabilities:
Accounts payable	246,347	201,512
Accrued taxes	24,921	20,734
Accrued interest	38,603	39,217
Accrued liabilities	50,988	23,287
Deferred revenue	127,932	111,095
Other current liabilities	38,273	42,910
Total Current Liabilities	527,064	438,755
Long-term debt, net	3,441,024	3,205,958
Other long-term liabilities and deferred credits	53,120	31,688
Total Long-term Liabilities	3,494,144	3,237,646
Commitments and Contingencies
Equity:
Total Partners' Equity	1,801,802	1,725,537
Noncontrolling interests	391,076	491,571
Total Equity	2,192,878	2,217,108
Total Liabilities and Equity	6,214,086	5,893,509
Common Class A
Equity:
Total Partners' Equity	1,801,802	1,725,537
Common Class B
Equity:
Total Partners' Equity	$ 0	$ 0

CONSOLIDATED BALANCE SHEETS (UN

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - shares	Dec. 31, 2019	Dec. 31, 2018
Common Class A
Shares, Outstanding	179,583,765	156,311,986
Common Class B
Shares, Outstanding	102,136,875	123,887,893

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Total Revenues	$ 868,548,000	$ 793,259,000	$ 655,898,000
Operating Costs and Expenses:
Operations and maintenance	88,474,000	72,460,000	62,069,000
Depreciation and amortization	128,825,000	110,862,000	90,800,000
General and administrative	104,373,000	70,656,000	65,536,000
Taxes, other than income taxes	35,669,000	31,810,000	28,832,000
Loss (gain) on disposal of assets	(373,000)	11,043,000	599,000
Total Operating Costs and Expenses	515,788,000	442,628,000	384,051,000
Operating Income	352,760,000	350,631,000	271,847,000
Other Income (Expense):
Equity in earnings of unconsolidated investments	325,385,000	306,819,000	237,110,000
Interest expense, net	(161,407,000)	(133,319,000)	(89,348,000)
Other income (expense), net	2,410,000	(751,000)	12,834,000
Total Other Income (Expense)	166,388,000	172,749,000	160,596,000
Net income before tax	519,148,000	523,380,000	432,443,000
Income tax expense	(70,593,000)	(55,709,000)	(208,458,000)
Net income	448,555,000	467,671,000	223,985,000
Net income attributable to noncontrolling interests	(199,746,000)	(330,544,000)	(352,714,000)
Net income (loss) attributable to TGE	$ 248,809,000	$ 137,127,000	$ (128,729,000)
Earnings Per Share, Basic and Diluted [Abstract]
Basic net income (loss) per Class A share	$ 1.42	$ 1.27	$ (2.22)
Diluted net income (loss) per Class A share	$ 1.42	$ 1.27	$ (2.22)
Basic average number of Class A shares outstanding	174,816	107,586	58,076
Diluted average number of Class A shares outstanding	176,500	109,817	58,076
Crude oil transportation services
Revenues:
Total Revenues	$ 417,106,000	$ 398,334,000	$ 345,733,000
Natural gas transportation services
Revenues:
Total Revenues	129,620,000	126,894,000	122,364,000
Sales of natural gas, NGLs, and crude oil
Revenues:
Total Revenues	171,729,000	168,586,000	108,503,000
Processing and other revenues
Revenues:
Total Revenues	150,093,000	99,445,000	79,298,000
Cost of Sales
Operating Costs and Expenses:
Cost of sales and transportation services	94,816,000	114,815,000	91,213,000
Cost of Transportation Services
Operating Costs and Expenses:
Cost of sales and transportation services	$ 63,258,000	$ 53,068,000	$ 46,200,000

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Terminals and NatGas	Tallgrass Energy Partners	Tallgrass Energy, LP (TGE)	Rockies Express Pipeline LLC	Deeprock Development, LLC	Pony Express Pipeline	Deeprock North, LLC	BNN Colorado Water, LLC	CES Holding Company, Inc.	Noncontrolling Interest	Noncontrolling InterestTerminals and NatGas	Noncontrolling InterestTallgrass Energy Partners	Noncontrolling InterestRockies Express Pipeline LLC	Noncontrolling InterestDeeprock Development, LLC	Noncontrolling InterestPony Express Pipeline	Noncontrolling InterestDeeprock North, LLC	Noncontrolling InterestBNN Colorado Water, LLC	Noncontrolling InterestCES Holding Company, Inc.	Predecessor Equity	Predecessor EquityTerminals and NatGas	Common Class A	Common Class ATerminals and NatGas	Common Class ATallgrass Energy Partners	Common Class ATallgrass Energy, LP (TGE)	Common Class ARockies Express Pipeline LLC	Common Class ADeeprock Development, LLC	Common Class APony Express Pipeline	Common Class ACES Holding Company, Inc.	Common Class B	Common Class BTallgrass Energy Partners	Common Class BRockies Express Pipeline LLC	Common Class BCES Holding Company, Inc.
Increase (Decrease) in Partners' Capital [Roll Forward]
Shares, Outstanding																						58,075								99,154
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 1,929,414										$ 1,596,152									$ 82,295		$ 250,967								$ 0
Acquisitions		$ (140,000)			$ 63,681	$ 45,869						$ (36,391)		$ 40,159	$ 45,869						$ (82,295)		$ (21,314)			$ 23,522
Net income	223,985										352,714											(128,729)								0
Issuance of units to public, net of offering costs			$ (112,420)										$ (101,067)											$ (11,353)							$ 0
Dividends, Common Stock, Cash	(73,321)										0											(73,321)								0
APIC, Share-based Payment Arrangement, Increase for Cost Recognition	(11,993)										(10,390)											(1,603)								0
Shares Issued, Shares, Share-based Payment Arrangement, after Forfeiture																									10
LTIP units tendered by employees to satisfy tax withholding obligations			(12,933)										11,616											(1,317)							0
Partial exercise of call option	(84,942)										(72,890)											(12,052)								$ 0
Payments for Repurchase of Common Stock			(35,335)										31,717											(3,618)
Acquisition of additional membership interest						$ (6,440)									$ 7,109												$ (669)
Contributions from TD	2,301										1,451											850
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders	1,589										1,589											0
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(317,102)										(317,102)											$ 0
Shares, Outstanding																						58,085								99,154
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	1,721,179										1,672,566											$ 48,613								$ 0
Acquisitions					$ 108,537		$ (50,000)							$ 74,421		$ (44,732)										$ 34,116		$ (5,268)				$ 0
Net income	467,671										330,544											137,127								0
Issuance of units to public, net of offering costs			(377)										(279)											(98)							0
Dividends, Common Stock, Cash	(206,431)										0											(206,431)								0
APIC, Share-based Payment Arrangement, Increase for Cost Recognition	(9,493)										(3,197)											(6,296)								$ 0
Shares Issued, Shares, Share-based Payment Arrangement, after Forfeiture																									19
LTIP units tendered by employees to satisfy tax withholding obligations			(1,721)	$ (30)									(1,531)											(190)	$ (30)						$ 0
Payments for Repurchase of Common Stock			0
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders	1,787										1,787											0
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(327,578)										(327,578)											$ 0
Other Significant Noncash Transaction, Payments to Acquire Units			(251,743)										$ (189,520)											$ (62,223)
Proceeds from Issuance or Sale of Equity	644,782										644,782
Noncontrolling Interest, Increase from Business Combination								$ 31,843	$ 10,138								$ 31,843	$ 10,138
Stock Issued During Period, Shares, Acquisitions																						95,386									10,758	16,797
Conversion of Stock, Shares Converted																						2,822								(2,822)
Partners' Capital Account, Exchanges and Conversions	0										8,717											$ (8,717)
Partners Capital Deferred Tax Asset	15,427																					15,427
Other Significant Noncash Transaction, Value of Consideration Given	(2,113,758)										(1,762,327)											(351,431)
Partners' Capital Account, Public Sale of Units	2,113,758																					$ 2,113,758
Shares, Outstanding																						156,312								123,887
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	2,217,108										491,571											$ 1,725,537								$ 0
Acquisitions										$ 3,400									$ 3,400										$ 0				$ 0
Net income	448,555										199,746											248,809								0
Dividends, Common Stock, Cash	(371,605)										0											(371,605)								0
APIC, Share-based Payment Arrangement, Increase for Cost Recognition	31,293										0											(31,293)								0
Shares Issued, Shares, Share-based Payment Arrangement, after Forfeiture																									1,521
LTIP units tendered by employees to satisfy tax withholding obligations				$ (16,216)																		(16,216)
Payments for Repurchase of Common Stock			$ 0
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders	2,323										2,323											0								0
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(237,350)										(237,350)											$ 0								$ 0
Conversion of Stock, Shares Converted																						21,751								(21,751)
Partners' Capital Account, Exchanges and Conversions											(68,614)											$ 68,614
Partners Capital Deferred Tax Asset	115,370										0											$ 115,370								$ 0
Other Significant Noncash Transaction, Value of Consideration Given	(111,707)
Shares, Outstanding																						179,584								102,136
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 2,192,878										$ 391,076											$ 1,801,802								$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net income	$ 448,555,000	$ 467,671,000	$ 223,985,000
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	135,495,000	117,430,000	98,537,000
Equity in earnings of unconsolidated investments	(325,385,000)	(306,819,000)	(237,110,000)
Distributions from unconsolidated investments	326,018,000	306,934,000	237,192,000
Deferred Income Tax Expense	69,865,000	55,709,000	208,458,000
Noncash compensation expense	31,293,000	10,665,000	8,898,000
Other noncash items, net	1,897,000	(13,047,000)	(9,400,000)
Accounts receivable and other
Accounts receivable and other	(78,617,000)	(102,105,000)	(57,927,000)
Accounts payable and accrued liabilities	88,490,000	112,474,000	84,731,000
Deferred revenue	16,873,000	17,547,000	27,283,000
Other current assets and liabilities	21,558,000	3,079,000	10,542,000
Other Operating Activities, Cash Flow Statement	(13,920,000)	9,145,000	(2,709,000)
Net Cash Provided by Operating Activities	679,006,000	672,525,000	571,396,000
Cash Flows from Investing Activities:
Capital expenditures	(285,653,000)	(368,873,000)	(145,144,000)
Distributions from unconsolidated investments in excess of cumulative earnings	144,963,000	80,213,000	69,434,000
Contributions to unconsolidated investments	(115,545,000)	(473,946,000)	(45,948,000)
Proceeds from Divestiture of Interest in Consolidated Subsidiaries	59,693,000
Proceeds from Divestiture of Businesses		50,046,000
Payments to Acquire Interest in Subsidiaries and Affiliates		0	400,000,000
Payments to Acquire Assets, Investing Activities		(30,704,000)	(128,526,000)
Other investing, net	(5,326,000)	(7,848,000)	(15,125,000)
Net Cash Provided by (Used in) Investing Activities	(287,284,000)	(987,212,000)	(898,541,000)
Net Cash (Used in) Provided by Financing Activities
Dividends paid to Class A shareholders	371,605,000	206,431,000	73,321,000
Payments of Ordinary Dividends, Noncontrolling Interest	237,350,000	327,578,000	317,102,000
Proceeds from (Repayments of) Debt	232,000,000	417,000,000	(356,000,000)
Payment, Tax Withholding, Share-based Payment Arrangement	(16,216,000)	(30,000)
Proceeds from issuance of long-term debt	0	500,000,000	1,103,750,000
Payments to noncontrolling interests	(7,500,000)	(6,200,000)	(6,200,000)
Proceeds from public offering of TEP common units, net of offering costs	0	0	112,420,000
Payments of Debt Issuance Costs	0	0	22,375,000
Other financing, net	1,247,000	(11,271,000)	(12,377,000)
Net Cash (Used in) Provided by Financing Activities	(391,924,000)	321,690,000	327,279,000
Net Change in Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents	(202,000)	7,003,000	134,000
Cash and Cash Equivalents, beginning of period	9,596,000	2,593,000	2,459,000
Cash and Cash Equivalents, end of period	9,394,000	9,596,000	2,593,000
Supplemental Disclosures:
Cash payments for interest, net	155,945,000	114,026,000	72,698,000
Other Significant Noncash Transaction, Value of Consideration Given	(111,707,000)	(2,113,758,000)
Capital Expenditures Incurred but Not yet Paid	8,143,000	5,755,000	8,975,000
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	11,420,000
Issuance of Noncontrolling Interest in Subsidiary in Exchange for Membership Interest	0	(31,843,000)
Shares Issued	0	644,782,000	6,617,000
Noncash Acquisition, Contribution of membership interest	0	(19,500,000)
Common Class A
Net income	248,809,000	137,127,000	(128,729,000)
Supplemental Disclosures:
Other Significant Noncash Transaction, Value of Consideration Given		(351,431,000)
Shares Issued	0	2,113,758,000
Tallgrass Energy Partners
Supplemental Disclosures:
Other Significant Noncash Transaction, Value of Consideration Given	0	(2,365,501,000)
CES Holding Company, Inc.
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Net of Cash Acquired	(48,416,000)
Terminals and NatGas
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Gross		0	(140,000,000)
Tallgrass Crude Gathering, LLC
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Gross		0	(36,030,000)
NGL Water Solutions Bakken
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Gross		(91,000,000)
Rockies Express Pipeline LLC
Cash Flows from Investing Activities:
Payments to Acquire Interest in Subsidiaries and Affiliates			400,000,000
BNN North Dakota
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Net of Cash Acquired		(95,000,000)
Deeprock Development, LLC
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Net of Cash Acquired		0	(57,202,000)
Pony Express Pipeline
Net Cash (Used in) Provided by Financing Activities
Payments to noncontrolling interests		(50,000,000)
Equity Option
Net Cash (Used in) Provided by Financing Activities
Payments for Repurchase of Common Stock	0	0	(72,381,000)
Powder River Gateway
Cash Flows from Investing Activities:
Contributions to unconsolidated investments	(37,000,000)
Deeprock North, LLC
Cash Flows from Investing Activities:
Contributions to unconsolidated investments		(19,500,000)	0
Pawnee Terminal, LLC
Cash Flows from Investing Activities:
Contributions to unconsolidated investments		(30,600,000)	0
Rockies Express Pipeline LLC
Adjustments to reconcile net income to net cash flows provided by operating activities:
Equity in earnings of unconsolidated investments	(316,400,000)
Cash Flows from Investing Activities:
Contributions to unconsolidated investments	(62,200,000)
Supplemental Disclosures:
Other Significant Noncash Transaction, Value of Consideration Given	0	(393,039,000)
BNN Eastern, LLC
Supplemental Disclosures:
Issuance of Noncontrolling Interest in Subsidiary in Exchange for Membership Interest	(3,400,000)
Tallgrass Energy Partners
Net Cash (Used in) Provided by Financing Activities
Payments for Repurchase of Common Stock	$ 0	$ 0	(35,335,000)
Tallgrass Energy Partners | Common Class A
Net Cash (Used in) Provided by Financing Activities
Payments for Repurchase of Common Stock			$ (3,618,000)

Description of Business

Description of Business	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business	Tallgrass Energy, LP ("TGE") 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 63.75% membership interest as of December 31, 2019 , and Tallgrass Energy Partners, LP ("TEP"), a wholly-owned subsidiary of Tallgrass Equity and its subsidiaries. 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 FERC-regulated crude oil pipeline systems; 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 (1) 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") and (2) our 51% membership interest in Powder River Gateway, LLC ("Powder River Gateway"), which owns the Powder River Express Pipeline ("PRE Pipeline"), a 70 -mile FERC-regulated crude oil pipeline that transports crude oil from the Powder River Basin to Guernsey, Wyoming, the Iron Horse Pipeline ("Iron Horse Pipeline"), a 80 -mile FERC-regulated crude oil pipeline placed into service in May 2019 that transports crude oil from the Powder River Basin to Guernsey, Wyoming, and crude oil terminal facilities in Guernsey, Wyoming. Gathering, Processing & Terminalling. We provide natural gas gathering and processing services for customers in Wyoming through (collectively, the "Midstream Facilities"): (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, North Dakota, and Ohio 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. 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 "TEP Merger Agreement"), with TEP, 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 TEP 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. March 2019 Blackstone Acquisition On March 11, 2019, pursuant to the terms of a previously announced definitive purchase agreement (the "Purchase Agreement"), dated January 30, 2019, entered into among acquisition vehicles controlled by affiliates of Blackstone Infrastructure Partners ("BIP" and, such acquisition vehicles controlled by BIP, collectively, the "March 2019 Acquirors"), affiliates of Kelso & Co., affiliates of The Energy & Minerals Group, Tallgrass KC, LLC, an entity owned by certain members of our management, and the other sellers named therein (collectively, the "Sellers"), the March 2019 Acquirors acquired from the Sellers (i) 100% of the membership interests in our general partner, (ii) 21,751,018 Class A shares representing limited partner interests ("Class A shares") in us, (iii) 100,655,121 units representing limited liability company interests ("TE Units") in Tallgrass Equity, and (iv) 100,655,121 Class B shares representing limited partner interests ("Class B shares") in us, in exchange for aggregate consideration of approximately $3.2 billion in cash, which was paid to the Sellers (the "March 2019 Blackstone Acquisition"). As a result of the March 2019 Blackstone Acquisition, BIP effectively controls our business and affairs through the exercise of the rights of the sole member of our general partner. Additionally, the March 2019 Acquirors, Prairie Secondary Acquiror LP, a Delaware limited partnership ("Prairie Secondary Acquiror 1"), and Prairie Secondary Acquiror E LP, a Delaware limited partnership ("Prairie Secondary Acquiror 2" and, together with Prairie Secondary Acquiror 1 and the March 2019 Acquirors, the "Sponsor Entities"), each of which are also controlled by BIP, collectively held an approximate 44.1% economic interest in us as of December 31, 2019 . Take-Private Merger On December 16, 2019, we and our general partner entered into a definitive Agreement and Plan of Merger (the "Take-Private Merger Agreement") with Prairie Private Acquiror LP, a Delaware limited partnership ("Buyer"), and Prairie Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of Buyer ("Buyer Sub"). Buyer is an affiliate of the Sponsor Entities. Pursuant to the Take-Private Merger Agreement and subject to the satisfaction or waiver of certain conditions therein, Buyer will merge with and into TGE, with TGE surviving the merger and continuing to exist as a Delaware limited partnership (the "Take-Private Merger"). At the effective time of the Take-Private Merger (the "Effective Time"), each issued and outstanding Class A share other than the Class A shares owned by the Sponsor Entities and certain of their permitted transferees, will be converted into the right to receive $22.45 per Class A share in cash without any interest thereon. Through the Take-Private Merger, the Sponsor Entities and the limited partners of Buyer immediately prior to the Effective Time will become the owners of all of the outstanding Class A shares and the Class A shares will cease to be publicly traded upon closing of the Take-Private Merger. The Take-Private Merger Agreement is subject to the satisfaction of customary conditions, including approval of the merger by holders of a majority of the outstanding Class A and Class B shares of TGE, voting together as a single class, inclusive of the approximately 44.1% of the total Class A and Class B shares held by the Sponsors Entities as of December 31, 2019. As discussed in Note 11 – Partnership Equity , pursuant to the Take-Private Merger Agreement, TGE has agreed not to pay dividends during the pendency of the transactions contemplated by the Take-Private Merger Agreement.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
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 contained in the Financial Accounting Standards Board's Accounting Standards Codification ("ASC"), the single source of 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. The term "Predecessor Entities" refers to Terminals and NatGas prior to their acquisition by TEP on January 1, 2017. Predecessor Equity as presented in the consolidated financial statements represents the capital account activity of the Predecessor Entities prior to January 1, 2017. For additional information regarding these acquisitions, see Note 3 – Acquisitions and Dispositions . The consolidated financial statements include the accounts of TGE and its subsidiaries and controlled affiliates. 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. We have no elements of other comprehensive income for the periods presented. 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. 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 $0.7 million and $7.7 million at December 31, 2019 and 2018 , respectively. Inventories Inventories primarily consist of crude oil, materials and supplies, gas in underground storage, and natural gas liquids. 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 existence, 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 $2.6 million and $3.2 million included in "Prepayments and other current assets" and "Deferred charges and other assets" in the consolidated balance sheets at December 31, 2019 and 2018 , respectively. Regulatory assets at December 31, 2019 and December 31, 2018 were primarily attributable to costs associated with rate case filings and fuel tracker assets at our regulated natural gas pipelines. We recorded regulatory liabilities of approximately $3.0 million and $1.9 million included in "Other current liabilities" in the consolidated balance sheets at December 31, 2019 and 2018 , 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 19 – 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. We recognized intangible assets associated with customer relationships as part of our acquisitions of NGL Water Solutions Bakken, LLC ("NGL Water Solutions Bakken") and BNN Eastern, LLC ("BNN Eastern") in 2018 and 2019, respectively, 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 not be recoverable. 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% - 4.0% 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 (expense), 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 according to the benefit received by the 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 2019 . 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 We adopted Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers" on January 1, 2018, using the modified retrospective method. For periods subsequent to adoption, we account for revenue from contracts with customers in accordance with the five-step model outlined in ASC Topic 606, "Revenue from Contracts with Customers ("ASC 606"). Under the five-step model, we identify the contract, identify the performance obligations, determine the transaction price, allocate the transaction price, and recognize revenue. Revenue is recognized when (or as) the performance obligations are satisfied. For additional information see Note 12 – Revenue from Contracts with Customers . 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 the adequacy of, and compliance with, 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 "Sales of natural gas, NGLs, and crude oil" 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 17 – Equity-Based Compensation , prior to February 2018 a portion of the expense recognized relating to equity-based compensation grants was charged to Tallgrass Development, LP (" 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 for these entities has been recorded in our consolidated financial statements. As discussed in Note 3 – Acquisitions and Dispositions , in April 2019, BNN Eastern, a newly formed indirect subsidiary of TGE, entered into a Stock Purchase Agreement to acquire all of the outstanding stock of CES Holding Company, Inc., which owns all of the issued and outstanding membership interests of K & H Partners LLC. CES Holding Company, Inc. is a C corporation for U.S. federal income tax purposes and is considered a taxable entity for such purposes. 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, 2019 , we had not recognized any material amounts in connection with uncertainty in income taxes. 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 Pronouncement Recently 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 within GAAP 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. Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2019. This 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 the previous guidance. Accordingly, we will not recast comparative periods

Acquisitions & Dispositions

Acquisitions & Dispositions	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions & Dispositions	Cheyenne Connector In October 2019, a subsidiary of DCP Midstream, LP ("DCP") exercised its option to purchase a 50% membership interest in Cheyenne Connector, LLC ("Cheyenne Connector"), which is currently developing and constructing the Cheyenne Connector Pipeline as discussed in Note 19 – Regulatory Matters . Effective November 4, 2019, we entered into a limited liability company agreement with DCP under which DCP made initial contributions of $59.7 million to Cheyenne Connector and entered into natural gas transportation agreements, in exchange for a 50% membership interest in Cheyenne Connector. Upon closing of the transaction, we derecognized the assets and liabilities of Cheyenne Connector, which primarily consisted of construction work in progress of $134.4 million . No gain or loss was recognized on the deconsolidation as the carrying value was determined to approximate the fair value. We will account for our remaining 50% membership interest in Cheyenne Connector under the equity method of accounting and will continue to operate the Cheyenne Connector joint venture. Acquisition of Central Environmental Services In April 2019, BNN Eastern, a newly formed indirect subsidiary of TGE, entered into a Stock Purchase Agreement to acquire all of the outstanding stock of CES Holding Company, Inc., which owns all of the issued and outstanding membership interests of K & H Partners LLC, a company doing business as Central Environmental Services ("CES"). CES Holding Company, Inc. is a C corporation for U.S. federal income tax purposes and is considered a taxable entity for such purposes. CES owns and operates a salt water disposal facility located in the Utica and Marcellus area of Ohio. On May 1, 2019, the acquisition closed for cash consideration of approximately $52 million paid at closing, and the issuance of a 7.65% membership interest in BNN Eastern to one of the sellers in the transaction. In addition, the transaction included a potential earn out payment to the sellers of approximately $3 million based on the achievement of certain milestones during 2019, which was payable in cash or in additional membership interests in BNN Eastern. Because the milestones were not achieved, there will not be an earn out payment in connection with the transaction. 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: Preliminary Adjustments Final (in thousands) Accounts receivable $ 1,391 $ — $ 1,391 Prepayments 67 — 67 Property, plant and equipment 6,900 4,400 11,300 Intangible asset 35,800 (2,900 ) 32,900 (1) Accounts payable and accrued liabilities (1,518 ) — (1,518 ) (2) Deferred tax liability (8,557 ) (189 ) (8,746 ) Net identifiable assets acquired 34,083 1,311 35,394 Goodwill 17,734 (1,311 ) 16,423 Net assets acquired (excluding cash) $ 51,817 $ — $ 51,817 (1) The $32.9 million intangible asset acquired represents customer relationships and is amortized on a straight-line basis over a period of 8 years. (2) Includes the estimated fair value of the liability for contingent consideration of $0.7 million . At June 30, 2019, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. During the three months ended September 30, 2019, the preliminary purchase price allocation was adjusted to reflect additional information obtained with respect to the property, plant and equipment acquired. The purchase price allocation was considered final as of September 30, 2019. The 7.65% equity interest in BNN Eastern held by noncontrolling interests was recorded at its acquisition date fair value of $3.4 million . The fair value of the noncontrolling interests 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 goodwill recognized of $16.4 million is primarily attributed to synergies expected from combining the operations of TGE and CES. All the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TGE from CES of $6.4 million and $0.8 million , respectively, was recognized in the accompanying consolidated statements of income for the period from May 1, 2019 to December 31, 2019 . 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. 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, 2019. 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 . Acquisition 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. 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 . Acquisition of NGL Water Solutions Bakken In November 2018, we acquired 100% of the membership interests in NGL Water Solutions Bakken, a produced water disposal system in the Bakken basin, for cash consideration of approximately $91.0 million . 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: Preliminary Adjustments Final (in thousands) Accounts receivable $ 3,599 $ (3,599 ) $ — Prepayments and other current assets 5 — 5 Property, plant and equipment 17,200 — 17,200 Intangible asset 54,000 — 54,000 (1) Accounts payable and accrued liabilities (949 ) 644 (305 ) Net identifiable assets acquired 73,855 (2,955 ) 70,900 Goodwill 17,145 2,955 20,100 Net assets acquired $ 91,000 $ — $ 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. During the six months ended June 30, 2019, the preliminary purchase price allocation was adjusted for certain immaterial items related to working capital adjustments and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2019. The goodwill recognized of $20.1 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 developing storage and terminalling facilities for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers vessels for international delivery on a site located on the Mississippi River in Plaquemines Parish, Louisiana. 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 , of which $25 million is included in "Other current liabilities" and the remaining $10 million is included in "Other long-term liabilities and deferred credits" in the consolidated balance sheets. 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 expects to construct the facilities. The project is currently under development. Acquisition of Pawnee Terminal In January 2018, we entered into an agreement to acquire a 51% membership interest in a crude oil terminal located in Pawnee, Colorado ("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 in Rockies Express and Additional TEP Common Units 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 ("Tallgrass Development Holdings"), a wholly-owned subsidiary of Tallgrass Equity (the "TD Merger"). As a result of the TD 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 Class B shares and TE 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, "Tallgrass Crude Gathering"), which owns 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 (the "PRB Crude System"), 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 Tallgrass Crude Gathering 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 Tallgrass Crude Gathering, for approximately $50.0 million . The sale of Tallgrass Crude Gathering 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 "Loss (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"), to construct and own the 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 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. As Silver Creek retained certain participating rights with respect to Powder River Gateway, the 51% membership interest does not represent a controlling interest in Powder River Gateway. Accordingly, our investment in Powder River Gateway is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the consolidated balance sheets. Acquisitions of Additional Interests in Deeprock Development, LLC In July 2017, we acquired an additional 40% membership interest in Deeprock Development, LLC ("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 "Other income (expense), net" 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 was 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 . Acquisition of Additional Interest in Pony Express 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 attributable to TGE for the years ended December 31, 2019 and 2018 is presented below as if the acquisition of CES had been completed on January 1, 2018. 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 attributable to TGE for the year ended December 31, 2017 is presented below as if the acquisitions of Tallgrass Crude Gathering and Deeprock Development had been completed on January 1, 2016. Year Ended December 31, 2019 2018 2017 (in thousands) Revenue $ 873,340 $ 827,998 $ 686,803 Net income (loss) attributable to TGE $ 249,644 $ 141,988 $ (129,155 ) 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 CES, BNN North Dakota, NGL Water Solutions Bakken, BNN Colorado, Tallgrass Crude Gathering, 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.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows: Year Ended December 31, 2019 2018 2017 (in thousands) Processing and other revenues (1) $ 7,394 $ 7,483 $ 8,516 Cost of transportation services (2) $ 940 $ — $ 10,476 Charges to TGE: (3) Property, plant and equipment, net $ — $ — $ 2,679 Other deferred charges $ — $ — $ 25 Operations and maintenance $ — $ — $ 29,881 General and administrative $ — $ — $ 41,676 (1) Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline. (2) Reflects rent expense for crude oil storage and terminalling services provided by Powder River Gateway and 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 pursuant to an Omnibus Agreement entered into by TEP and TEP GP with Tallgrass Energy Holdings, LLC and certain of its affiliates in connection with the closing of our initial public offering on May 17, 2013. Effective January 1, 2018, these costs are incurred by TGE directly. Details of balances with affiliates included in "Accounts receivable, net" in the consolidated balance sheets are as follows: December 31, 2019 December 31, 2018 (in thousands) Receivable from related parties: Powder River Gateway, LLC $ 12,071 $ — Rockies Express Pipeline LLC 3,998 3,447 Cheyenne Connector, LLC 575 — Pawnee Terminal, LLC 125 115 Iron Horse Pipeline, LLC — 186 Total receivable from related parties $ 16,769 $ 3,748 Details of gas imbalances with affiliated shippers included in "Prepayments and other current assets" and "Other current liabilities" in the consolidated balance sheets are as follows: December 31, 2019 December 31, 2018 (in thousands) Affiliate gas imbalance receivables $ 74 $ 19 Affiliate gas imbalance payables $ 991 $ 742

Inventory

Inventory	12 Months Ended
	Dec. 31, 2019
Inventory Disclosure [Abstract]
Inventory	The components of inventory at December 31, 2019 and 2018 consisted of the following: December 31, 2019 December 31, 2018 (in thousands) Crude oil $ 46,164 $ 23,205 Gas in underground storage 1,772 2,740 Materials and supplies 650 8,206 Natural gas liquids 495 165 Total inventory $ 49,081 $ 34,316

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	A summary of net property, plant and equipment by classification is as follows: December 31, 2019 December 31, 2018 (in thousands) Crude oil pipelines $ 1,375,036 $ 1,313,976 Gathering, processing and terminalling assets 1,007,648 889,168 Natural gas pipelines 625,631 607,343 General and other (1) 175,537 180,299 Construction work in progress 72,842 191,994 Accumulated depreciation and amortization (482,176 ) (380,351 ) Total property, plant and equipment, net (2) $ 2,774,518 $ 2,802,429 (1) Includes approximately $30.7 million of land associated with the PLT capital lease as discussed in Note 13 – Leases . (2) Property, plant and equipment, net includes approximately $464.8 million of assets at our regulated natural gas pipelines at December 31, 2019 . Depreciation expense was approximately $109.4 million , $102.7 million , and $86.9 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. Capitalized interest was approximately $7.5 million , $5.2 million , and $1.1 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively.

Investments in Unconsolidated A

Investments in Unconsolidated Affiliaties - (Notes)	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments and Joint Ventures Disclosure	The following table summarizes our investments in unconsolidated affiliates: Percentage Ownership at December 31, 2019 Carrying Value as of December 31, 2019 2018 (in thousands) Rockies Express Pipeline LLC 75 % $ 1,714,857 $ 1,794,987 Cheyenne Connector, LLC 50 % 96,194 — Powder River Gateway, LLC 51 % 164,773 — Pawnee Terminal, LLC 51 % 30,395 31,232 Iron Horse Pipeline, LLC Not applicable — 35,467 Total investments in unconsolidated affiliates $ 2,006,219 $ 1,861,686 Cheyenne Connector As discussed in Note 3 – Acquisitions and Dispositions , DCP exercised its option to purchase a 50% membership interest in Cheyenne Connector. The transaction closed effective November 4, 2019 and we subsequently deconsolidated Cheyenne Connector's assets and liabilities and began accounting for our remaining 50% membership interest under the equity method of accounting. Powder River Gateway and Iron Horse Pipeline As discussed in Note 3 – Acquisitions and Dispositions , effective January 1, 2019 we contributed our membership interest in Iron Horse along with cash and other assets under construction to Powder River Gateway, a joint venture with Silver Creek, in exchange for a 51% membership interest in the joint venture. 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. Rockies Express Basis Difference Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our consolidated balance sheets. On May 6, 2016, TEP acquired a 25% membership interest in Rockies Express. On that date, the difference between the fair value of our investment 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, 2019 , the basis difference for our membership interests in Rockies Express was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 42,845 2 - 25 years Property, plant and equipment (1,108,670 ) 35 years Total basis difference $ (1,065,825 ) During the year ended December 31, 2019 , we recognized equity in earnings associated with our 75% membership interest in Rockies Express of $316.4 million , inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $458.7 million and $62.2 million , respectively. Rockies Express Senior Notes Offerings On January 31, 2020, Rockies Express issued $750 million in aggregate principal amount of senior notes. The issuance was composed of two tranches, $400 million of 3.60% senior notes due 2025 and $350 million of 4.80% senior notes due 2030. The proceeds of the issuance will be used to redeem the 5.625% senior notes due April 15, 2020 in March 2020. On April 12, 2019, Rockies Express and U.S. Bank, National Association, as trustee, entered into an Indenture pursuant to which Rockies Express issued $550 million in aggregate principal amount of 4.95% senior notes due 2029. Substantially all of the net proceeds received by Rockies Express from the senior notes offering were used to repay Rockies Express' $525 million term loan facility. Summarized Financial Information of Unconsolidated Affiliates The following tables summarize the combined financial information of our investments in unconsolidated affiliates during the periods in which we held a membership interest for the periods indicated: December 31, 2019 2018 (in thousands) Current assets $ 201,621 $ 132,213 Noncurrent assets $ 6,430,144 $ 6,031,066 Current liabilities $ 216,596 $ 694,951 Noncurrent liabilities $ 2,211,448 $ 1,502,906 Members' equity $ 4,203,721 $ 3,965,422 Year Ended December 31, 2019 2018 2017 (in thousands) Revenue $ 931,025 $ 930,771 $ 860,115 Operating income $ 499,493 $ 524,607 $ 480,337 Net income $ 394,725 $ 376,934 $ 465,592

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2019
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: Natural Gas Transportation Gathering, Processing & Terminalling Total (in thousands) Balance at December 31, 2017 $ 255,558 $ 149,280 $ 404,838 Goodwill acquired — 17,145 (1) 17,145 Balance at December 31, 2018 255,558 166,425 421,983 Goodwill acquired — 16,423 (2) 16,423 Other adjustments — 2,955 (3) 2,955 Balance at December 31, 2019 $ 255,558 $ 185,803 $ 441,361 (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 $16.4 million of goodwill was recorded in connection with the acquisition of CES on May 1, 2019 as discussed further in Note 3 – Acquisitions and Dispositions . (3) The $3.0 million goodwill adjustment was recorded in connection with a purchase price allocation adjustment related to the NGL Water Solutions Bakken acquisition as discussed further in Note 3 – Acquisitions and Dispositions . Annual Goodwill Impairment Analysis We elected to apply the qualitative assessment option for one of our five reporting units during our 2019 annual goodwill impairment testing. 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 this reporting unit, the results of the qualitative assessment indicated that it was more likely than not that the fair value of the reporting units exceeds its book value. As such, we did not perform a quantitative impairment analysis, and we concluded that no impairment was indicated as of August 31, 2019. For the remaining four reporting units, we did not elect to apply the qualitative assessment option and instead we proceeded directly to the quantitative impairment test. We compared the fair value of the reporting units with their respective book values, including goodwill, by using an income approach based on a discounted cash flow analysis. The fair value of the reporting units was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates, maintenance capital expenditures, and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For these reporting units, the results of the quantitative impairment test indicated no impairment as the fair value of each 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 nine months ended September 30, 2019. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary. Approximately $79.2 million of goodwill is allocated to the Midstream Facilities reporting unit, which is a component of our Gathering, Processing & Terminalling segment. As a result of current market conditions, certain producers from which the Midstream Facilities reporting unit receives natural gas for processing have recently indicated that they currently expect to deliver lower volumes than previously anticipated. The results of the Midstream Facilities reporting unit's impairment testing as of August 31, 2019 indicate that the fair value of the reporting unit exceeds the carrying value by approximately 17% . As a result, no impairment charge was recorded. However our analysis includes assumptions related to the discount rate used to discount future cash flows, and reflects a gradual recovery of commodity prices and a corresponding increase in volumes over time. This reporting unit is sensitive to changes in the discount rate, as such increases in the discount rate, could result in a future impairment. Additionally, if our outlook is not realized, or our producers further decrease volumes, we may recognize an impairment in the future. Other Intangible Assets A summary of amortized intangible assets is as follows: December 31, 2019 December 31, 2018 (in thousands) Pony Express oil conversion use rights $ 105,973 $ 105,973 Customer contracts 60,348 60,348 Customer relationships 85,950 52,100 Plaquemines Liquids Terminal use rights and permits 35,000 35,000 Accumulated amortization (45,719 ) (26,318 ) Intangible assets, net $ 241,552 $ 227,103 Amortization of intangible assets was approximately $19.4 million , $8.1 million , and $3.8 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. Estimated future amortization for the intangible assets is as follows (in thousands): Year Total 2020 $ 20,527 2021 20,474 2022 17,324 2023 17,324 2024 17,324 Thereafter 113,579 Total (1) $ 206,552 (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, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management	Stanchion engages 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. We have a comprehensive risk management policy for Stanchion adopted by the board of directors of our general partner and a Risk Management Committee responsible for the overall management of credit risk and commodity risk at Stanchion, including establishing and monitoring adequacy of, and compliance with, exposure limits. We also occasionally enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs. Fair Value of Derivative Contracts The following table summarizes the fair values of our derivative contracts included in the consolidated balance sheets: Balance Sheet Location December 31, 2019 December 31, 2018 (in thousands) Crude oil derivative contracts Prepayments and other current assets $ 2,536 $ 3,526 Crude oil derivative contracts Other current liabilities $ 60 $ 1,642 As of December 31, 2019 , the amounts shown represent the fair value of crude oil derivative contracts for the forward purchase of 2,394,002 and the forward sale of 5,913,554 barrels of crude oil consisting of fixed price and floating price contracts, which will settle throughout 2020. As of December 31, 2018 , the amounts shown represent the fair value of crude oil derivative contracts for the forward purchase of 2,105,146 and the forward sale of 1,274,500 barrels of crude oil, consisting of fixed price and floating price contracts, which settled throughout 2019. 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, 2019 , 2018 and 2017 : Location of Amount of gain recognized in income on derivatives Year Ended December 31, 2019 2018 2017 (in thousands) Crude oil derivative contracts Sales of natural gas, NGLs, and crude oil $ 55,562 $ 29,510 $ 39 Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ — $ — $ 75 Call option derivative Other income, net $ — $ — $ 1,885 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. On February 1, 2017 , TEP exercised the remainder of the call option covering 1,703,094 common units for a cash payment of $72.4 million . As a result of the exercise, we derecognized the derivative asset balance, recognizing approximately $12.6 million through equity for the year ended December 31, 2017. 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. 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, 2019 was: Asset Position (in thousands) Gross $ 2,536 Netting agreement impact — Cash collateral held — Net exposure $ 2,536 As of December 31, 2019 , we had $2.6 million of cash in margin accounts in support of our commodity derivative contracts. As of December 31, 2018 , we did not have any cash in margin accounts 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, 2019 and 2018 , based on the fair value hierarchy: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2019: Crude oil derivative contracts $ 2,536 $ — $ 2,536 $ — 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, 2019: Crude oil derivative contracts $ 60 $ — $ 60 $ — As of December 31, 2018: Crude oil derivative contracts $ 1,642 $ — $ 1,642 $ —

Long-term Debt

Long-term Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-term Debt	Our long-term debt is held at TEP and consisted of the following at December 31, 2019 and 2018 : December 31, 2019 December 31, 2018 (in thousands) Revolving credit facility $ 1,456,000 $ 1,224,000 4.75% senior notes due October 1, 2023 500,000 500,000 5.50% senior notes due September 15, 2024 750,000 750,000 5.50% senior notes due January 15, 2028 750,000 750,000 Less: Deferred financing costs, net (1) (18,004 ) (21,421 ) Plus: Unamortized premium on 2028 Notes 3,028 3,379 Total long-term debt, net $ 3,441,024 $ 3,205,958 (1) Deferred financing costs, net as presented above relate solely to the Senior Notes (as defined below). Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our consolidated balance sheets. Senior Unsecured Notes On February 27, 2019, TEP and Tallgrass Energy Finance Corp. (together, the "Issuers"), together with the TEP subsidiary guarantors party thereto (the "Guarantors") and U.S. Bank National Association, as trustee (the "Trustee"), entered into supplemental indentures (the "Supplemental Indentures") to amend certain provisions of each of (i) the Indenture governing the 4.75% senior notes due 2023 (the "2023 Notes"), dated as of September 26, 2018, among the Issuers, the Guarantors and Trustee, (ii) the Indenture governing the 5.50% senior notes due 2024 (the "2024 Notes"), dated as of September 1, 2016, among the Issuers, the Guarantors and the Trustee, and (iii) the Indenture governing the 5.50% senior notes due 2028 (the "2028 Notes"), dated as of September 15, 2017, among the Issuers, the Guarantors and the Trustee (collectively, the "Indentures"). The Supplemental Indentures (a) amended the defined term "Change of Control" in each Indenture to provide that the March 2019 Blackstone Acquisition did not constitute a Change of Control under such Indenture, (b) changed the definition of "Qualifying Owners" in the applicable Indenture to provide that Blackstone Infrastructure Partners L.P., Vencap Holdings (1992) Pte. Ltd. and their respective affiliates, funds, holding companies and investment vehicles, among others, are Qualifying Owners under such Indenture, and (c) added to, amended, supplemented or changed certain other defined terms contained in each Indenture related to the foregoing. The Issuers have previously issued $500 million in aggregate principal amount of 4.75% senior notes due 2023 on September 26, 2018. The Indenture governing the 2023 Notes 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 $500 million in aggregate principal amount of 5.50% senior notes due 2028 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 Indenture governing the 2028 Notes 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 also previously issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 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 Indenture governing the 2024 Notes 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, 2019 , TEP was in compliance with the covenants required under the Indentures. Revolving Credit Facility The following table sets forth the available borrowing capacity under the revolving credit facility as of December 31, 2019 and 2018 : December 31, 2019 December 31, 2018 (in thousands) Total capacity under the revolving credit facility $ 2,250,000 $ 2,250,000 Less: Outstanding borrowings under the revolving credit facility (1,456,000 ) (1,224,000 ) Less: Letters of credit issued under the revolving credit facility (94 ) (94 ) Available capacity under the revolving credit facility $ 793,906 $ 1,025,906 On February 22, 2019, TEP and certain of its subsidiaries entered into a Consent and Amendment No. 2 to the Second Amended and Restated Credit Agreement (the "Consent and Amendment") with Wells Fargo Bank, National Association, as administrative agent, and the required lenders party thereto. The Consent and Amendment modified that certain Second Amended and Restated Credit Agreement dated as of June 2, 2017, as previously amended by that certain Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of July 26, 2018 (as amended, the "Credit Agreement"). The Credit Agreement governs our revolving credit facility, which matures on June 2, 2022. In the Consent and Amendment, the required lenders under the Credit Agreement (i) consented to the March 2019 Blackstone Acquisition pursuant to the terms and conditions of the Purchase Agreement, (ii) agreed that no Default (as defined in the Credit Agreement) under the Credit Agreement, if any, that may have resulted from a Change in Control (as defined in the Credit Agreement) caused by the consummation of the March 2019 Blackstone Acquisition pursuant to the terms and conditions set forth in the Purchase Agreement will be deemed to have occurred, and (iii) agreed to modify the definition of "Permitted Holders" in Section 1.01 of the Credit Agreement (which is used in the definition of Change in Control) to reflect the change in ownership as a result of the March 2019 Blackstone Acquisition. 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 Amendment modified certain provisions of the Credit Agreement to, among other things, (i) increase the available amount of the 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. The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP's ability (as well as the ability of its restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions, including distributions from available cash, if a default or event of default under the credit agreement then exists or would result 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, 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, 2019 , TEP was in compliance with the covenants required under its revolving credit facility. The unused portion of the revolving credit facility is subject to a commitment fee, which ranges from 0.250% to 0.375% , based on TEP's total leverage ratio. As of December 31, 2019 , the weighted average interest rate on outstanding borrowings under the revolving credit facility was 3.13% . During the year ended December 31, 2019 , the weighted average effective interest rate under the revolving credit facility, including the interest on outstanding borrowings under the revolving credit facility, commitment fees, and amortization of deferred financing costs, was 4.18% . Tallgrass Equity Revolving Credit Facility On July 26, 2018, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility. Fair Value The following table sets forth the carrying amount and fair value of long-term debt, which is not measured at fair value in the consolidated balance sheets as of December 31, 2019 and 2018 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of December 31, 2019: Revolving credit facility $ — $ 1,456,000 $ — $ 1,456,000 $ 1,456,000 2023 Notes $ — $ 500,065 $ — $ 500,065 $ 495,750 2024 Notes $ — $ 754,043 $ — $ 754,043 $ 742,723 2028 Notes $ — $ 735,375 $ — $ 735,375 $ 746,551 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 The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of December 31, 2019 and 2018 , the fair value of borrowings under the revolving credit facility 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, 2019 .

Partnership Equity

Partnership Equity	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Partnership Equity	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 (in thousands, except per share amounts) December 31, 2019 Not applicable $ — $ — September 30, 2019 November 14, 2019 98,559 0.5500 June 30, 2019 August 14, 2019 96,767 0.5400 March 31, 2019 May 15, 2019 94,975 0.5300 December 31, 2018 February 14, 2019 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 As a result of the Take-Private Merger Agreement discussed in Note 1 – Description of Business , TGE has agreed to not pay dividends with respect to its Class A shares and to not permit Tallgrass Equity to pay any distributions on its TE Units during the pendency of the transactions contemplated by the Take-Private Merger Agreement, in each case, without the prior written consent of Buyer. Therefore, no dividends have been declared for the three months ended December 31, 2019. However, in the event the Take-Private Merger Agreement is terminated, the board of directors of our general partner will promptly fix a record date and declare and pay a dividend to the holders of Class A shares in an amount equal to the amount of dividends that otherwise would have been paid during the pendency of the transactions contemplated by the Take-Private Merger Agreement, all in accordance with our partnership agreement. 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 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 TE Units. The Exchange Right Holders, and any permitted transferees of their TE Units, each have the right to exchange all or a portion of their TE Units for Class A shares at an exchange ratio of one Class A share for each TE 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, 2019 , 21,751,018 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. 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. Following the March 2019 Blackstone Acquisition that closed on March 11, 2019 discussed in Note 1 – Description of Business , the Exchange Rights Holders consist of certain of the Sponsor Entities and certain current and former members of our management. Equity Distribution Agreements Neither TGE nor 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 agreements for net cash proceeds of approximately $112.4 million (net of approximately $1.9 million in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes. 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. Noncontrolling Interests As of December 31, 2019 , noncontrolling interests in our subsidiaries consisted of a 36.25% interest in Tallgrass Equity held by the Exchange Right Holders, as well as noncontrolling interests in certain subsidiaries held by unaffiliated third parties, including an approximate 40% membership interest in Deeprock Development, an approximate 25% membership interest in BNN West Texas, LLC ("BNN West Texas"), a 37% membership interest in BNN Colorado, a 20% common membership interest in PLT, and an approximate 8% membership interest in BNN Eastern. During the year ended December 31, 2019 , we recognized contributions from and distributions to noncontrolling interests of $2.3 million and $237.4 million , respectively. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $229.9 million and distributions to Deeprock Development, BNN West Texas, BNN Colorado, and BNN Eastern noncontrolling interests of $7.5 million in the aggregate. During the year ended December 31, 2018 , we recognized contributions from and made distributions to noncontrolling interests of $1.8 million and $327.6 million , respectively. 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 Pony Express and Deeprock Development noncontrolling interests of $6.2 million in the aggregate. 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. 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 in the aggregate. 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 20 – Legal and Environmental Matters .

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	Disaggregated Revenue A summary of our revenue by line of business is as follows: Year Ended December 31, 2019 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 $ — $ 395,297 $ — $ — $ 395,297 Natural gas transportation - firm service 125,170 — — (2,161 ) 123,009 Water business services — — 102,287 — 102,287 Natural gas gathering & processing fees — — 25,679 — 25,679 All other (1) 14,040 80,520 20,977 (74,377 ) 41,160 Total service revenue 139,210 475,817 148,943 (76,538 ) 687,432 Natural gas liquids sales — — 68,238 — 68,238 Natural gas sales 542 — 35,935 — 36,477 Crude oil sales — 10,830 622 — 11,452 Total commodity sales revenue 542 10,830 104,795 — 116,167 Total revenue from contracts with customers 139,752 486,647 253,738 (76,538 ) 803,599 Other revenue (2) — — 82,157 (17,208 ) 64,949 Total revenue (3) $ 139,752 $ 486,647 $ 335,895 $ (93,746 ) $ 868,548 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 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 revenue recognized at unconsolidated investments of $931.0 million and $930.8 million for the years ended December 31, 2019 and 2018 , respectively. 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, 2019 , 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 2020 $ 398,647 2021 287,026 2022 281,798 2023 245,006 2024 206,499 Thereafter 218,956 Total $ 1,637,932 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, in the Gathering, Processing & Terminalling segment under certain water business services contracts subject to minimum volume commitments. We receive deficiency payments for volumes committed by the customer in a month but not physically delivered to the customer or received by us for disposal. These deficiencies are charged at the contracted rate per barrel and recorded as a contract liability until the barrels are received from the customer for disposal, or when the likelihood that the customer will utilize the deficiency balance becomes remote. Balances associated with our contracts with customers were as follows: Contract Liabilities (in thousands) Balance at January 1, 2018 $ 88,471 Additions 34,613 Amounts recognized as revenue (11,989 ) Balance at December 31, 2018 111,095 Additions 35,923 Amounts recognized as revenue (19,086 ) Balance at December 31, 2019 $ 127,932 December 31, 2019 December 31, 2018 January 1, 2018 (in thousands) Accounts receivable from contracts with customers $ 80,756 $ 80,935 $ 61,888 Other accounts receivable (1) 226,756 151,414 56,727 Receivable from related parties 16,769 3,748 1,340 Accounts receivable, net $ 324,281 $ 236,097 $ 119,955 (1) Other accounts receivable primarily consists of receivables under crude oil forward purchase and sale arrangements that are accounted for as derivatives under ASC 815.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases of Lessee Disclosure [Text Block]	We account for leases in accordance with ASC Topic 842, Leases, which we adopted on January 1, 2019, applying the modified retrospective transition approach as of the effective date of adoption. See Note 2 – Summary of Significant Accounting Policies for additional information regarding the impacts of adoption. We enter into operating leases as lessee for certain office space and equipment. We also have a capital lease agreement to lease the land site on which PLT expects to construct storage and terminalling facilities. In November 2018, we entered into a joint venture agreement with DHIF to jointly own PLT, an entity formed with the intention of developing a storage and terminalling facility. At the same time, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT expects to construct the facilities. Under ASC 842, a contract is or contains a lease when, (1) the contract contains an explicitly or implicitly identified asset and (2) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. We assess whether an arrangement is or contains a lease at inception of the contract. For all leases (finance and operating leases), other than those that qualify for the short-term recognition exemption, we recognize as of the lease commencement date on the balance sheet a liability for our obligation related to the lease and a corresponding asset representing our right to use the underlying asset over the period of use. The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As our leases do not provide an implicit rate, we determine the appropriate discount rate using our incremental secured borrowing rate, with consideration given to the nature and term of the leased asset. Our leases have remaining terms of up to approximately 39 years . Certain of our lease agreements contain options to extend or early terminate the agreement. The lease term used to calculate the lease asset and liability at commencement includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. When determining whether it is reasonably certain that we will exercise an option at commencement, we consider various economic factors, including operating strategies, the nature, length, and underlying terms of the agreement, as well as the uncertainty of the condition of leased equipment at the end of the lease term. Based on these determinations, we generally determine that the exercise of renewal options would not be reasonably certain in determining the expected lease term. For the years ended December 31, 2019 , 2018 , and 2017 operating lease cost was $1.6 million , $0.8 million , and $9.1 million , respectively. For the year ended December 31, 2019 , cash paid included in operating cash flows was $1.5 million . During these periods the existing finance lease did not have any lease payments. Supplemental information related to our existing leases as of December 31, 2019 was as follows: Balance Sheet Location December 31, 2019 Operating Leases: (in thousands, except lease term and discount rate) Operating lease right-of-use assets Deferred charges and other assets $ 12,629 (1) Current operating lease liabilities Other current liabilities $ 1,497 (1) Non-current operating lease liabilities Other long-term liabilities and deferred credits $ 11,231 (1) Finance Leases: Finance lease right-of-use asset (2) Property, plant and equipment, net $ 30,704 Weighted Average Remaining Lease Term: Operating leases 15.3 years Finance leases 38.9 years Weighted Average Discount Rate: Operating leases 5.82 % Finance leases 7.01 % (1) Includes right-of-use asset of approximately $9.0 million and current and non-current lease liabilities of $0.1 million and $8.9 million , respectively, related to Guernsey Terminal capacity that we lease from Powder River Gateway. (2) PLT satisfied the initial capital lease obligation of $30.7 million at lease inception and as a result has no outstanding liability or imputed interest on the future minimum rental commitments. Maturities of lease liabilities as of December 31, 2019 were as follows: Year Operating Leases Finance Leases (1) (in thousands) 2020 $ 2,247 $ 449 2021 1,561 449 2022 1,021 449 2023 946 449 2024 910 467 Thereafter 13,644 17,303 Total lease payments 20,329 19,566 Less: discounting for present value and other adjustments (7,601 ) (19,566 ) Present value of lease liabilities $ 12,728 $ — (1) Future lease payments for finance leases consist of the annual payments under the PLT land site lease. At lease inception, the present value of the future lease payments exceeded the fair value of the leased property. As a result, the right of use asset and capital lease obligation were recorded at the $30.7 million fair value of land. On that date, PLT made a payment of $30.7 million , immediately relieving the capital lease obligation. As a result, PLT does not have an outstanding capital lease obligation or impute interest on the future minimum rental commitments and will account for the future lease payments in the period in which they are made. Under various lease agreements, Tallgrass Midstream, LLC ("TMID"), as lessor, leases capacity on NGL pipelines that were constructed for third parties, and Deeprock Development, as lessor, leases capacity at certain of its storage facilities. Rental income for these arrangements was approximately $9.4 million , $10.9 million , and $3.8 million for the years ended December 31, 2019 , 2018 , and 2017 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, Tallgrass Interstate Gas Transmission, LLC ("TIGT"), as lessor, leases a portion of its office space to a third party. Rental income was approximately $0.7 million , $0.8 million , and $0.8 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively, and was recorded as "Other income (expense), net" in the accompanying consolidated statements of income. At December 31, 2019 , future minimum rental income under non-cancelable operating leases as the lessor were as follows: Year Total (in thousands) 2020 $ 5,613 2021 3,773 2022 3,773 2023 3,773 2024 3,773 Thereafter 3,580 Total $ 24,285 Information as of December 31, 2018 under historical lease accounting guidance: At December 31, 2018 , our future minimum rental commitments under major, non-cancelable leases were as follows: Year Operating Leases Capital Lease (in thousands) 2019 $ 1,074 $ 449 2020 922 449 2021 483 449 2022 240 449 2023 147 449 Thereafter 364 17,770 Total $ 3,230 $ 20,015
Lessor, Operating Leases [Text Block]	We account for leases in accordance with ASC Topic 842, Leases, which we adopted on January 1, 2019, applying the modified retrospective transition approach as of the effective date of adoption. See Note 2 – Summary of Significant Accounting Policies for additional information regarding the impacts of adoption. We enter into operating leases as lessee for certain office space and equipment. We also have a capital lease agreement to lease the land site on which PLT expects to construct storage and terminalling facilities. In November 2018, we entered into a joint venture agreement with DHIF to jointly own PLT, an entity formed with the intention of developing a storage and terminalling facility. At the same time, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT expects to construct the facilities. Under ASC 842, a contract is or contains a lease when, (1) the contract contains an explicitly or implicitly identified asset and (2) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. We assess whether an arrangement is or contains a lease at inception of the contract. For all leases (finance and operating leases), other than those that qualify for the short-term recognition exemption, we recognize as of the lease commencement date on the balance sheet a liability for our obligation related to the lease and a corresponding asset representing our right to use the underlying asset over the period of use. The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As our leases do not provide an implicit rate, we determine the appropriate discount rate using our incremental secured borrowing rate, with consideration given to the nature and term of the leased asset. Our leases have remaining terms of up to approximately 39 years . Certain of our lease agreements contain options to extend or early terminate the agreement. The lease term used to calculate the lease asset and liability at commencement includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. When determining whether it is reasonably certain that we will exercise an option at commencement, we consider various economic factors, including operating strategies, the nature, length, and underlying terms of the agreement, as well as the uncertainty of the condition of leased equipment at the end of the lease term. Based on these determinations, we generally determine that the exercise of renewal options would not be reasonably certain in determining the expected lease term. For the years ended December 31, 2019 , 2018 , and 2017 operating lease cost was $1.6 million , $0.8 million , and $9.1 million , respectively. For the year ended December 31, 2019 , cash paid included in operating cash flows was $1.5 million . During these periods the existing finance lease did not have any lease payments. Supplemental information related to our existing leases as of December 31, 2019 was as follows: Balance Sheet Location December 31, 2019 Operating Leases: (in thousands, except lease term and discount rate) Operating lease right-of-use assets Deferred charges and other assets $ 12,629 (1) Current operating lease liabilities Other current liabilities $ 1,497 (1) Non-current operating lease liabilities Other long-term liabilities and deferred credits $ 11,231 (1) Finance Leases: Finance lease right-of-use asset (2) Property, plant and equipment, net $ 30,704 Weighted Average Remaining Lease Term: Operating leases 15.3 years Finance leases 38.9 years Weighted Average Discount Rate: Operating leases 5.82 % Finance leases 7.01 % (1) Includes right-of-use asset of approximately $9.0 million and current and non-current lease liabilities of $0.1 million and $8.9 million , respectively, related to Guernsey Terminal capacity that we lease from Powder River Gateway. (2) PLT satisfied the initial capital lease obligation of $30.7 million at lease inception and as a result has no outstanding liability or imputed interest on the future minimum rental commitments. Maturities of lease liabilities as of December 31, 2019 were as follows: Year Operating Leases Finance Leases (1) (in thousands) 2020 $ 2,247 $ 449 2021 1,561 449 2022 1,021 449 2023 946 449 2024 910 467 Thereafter 13,644 17,303 Total lease payments 20,329 19,566 Less: discounting for present value and other adjustments (7,601 ) (19,566 ) Present value of lease liabilities $ 12,728 $ — (1) Future lease payments for finance leases consist of the annual payments under the PLT land site lease. At lease inception, the present value of the future lease payments exceeded the fair value of the leased property. As a result, the right of use asset and capital lease obligation were recorded at the $30.7 million fair value of land. On that date, PLT made a payment of $30.7 million , immediately relieving the capital lease obligation. As a result, PLT does not have an outstanding capital lease obligation or impute interest on the future minimum rental commitments and will account for the future lease payments in the period in which they are made. Under various lease agreements, Tallgrass Midstream, LLC ("TMID"), as lessor, leases capacity on NGL pipelines that were constructed for third parties, and Deeprock Development, as lessor, leases capacity at certain of its storage facilities. Rental income for these arrangements was approximately $9.4 million , $10.9 million , and $3.8 million for the years ended December 31, 2019 , 2018 , and 2017 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, Tallgrass Interstate Gas Transmission, LLC ("TIGT"), as lessor, leases a portion of its office space to a third party. Rental income was approximately $0.7 million , $0.8 million , and $0.8 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively, and was recorded as "Other income (expense), net" in the accompanying consolidated statements of income. At December 31, 2019 , future minimum rental income under non-cancelable operating leases as the lessor were as follows: Year Total (in thousands) 2020 $ 5,613 2021 3,773 2022 3,773 2023 3,773 2024 3,773 Thereafter 3,580 Total $ 24,285 Information as of December 31, 2018 under historical lease accounting guidance: At December 31, 2018 , our future minimum rental commitments under major, non-cancelable leases were as follows: Year Operating Leases Capital Lease (in thousands) 2019 $ 1,074 $ 449 2020 922 449 2021 483 449 2022 240 449 2023 147 449 Thereafter 364 17,770 Total $ 3,230 $ 20,015

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies Disclosure	See Note 13 – Leases for discussion regarding obligations under operating and finance leases. Other Purchase Obligations At December 31, 2019 , future minimum commitments under long-term, non-cancelable contracts for service contracts, right of way ("ROW") agreements not accounted for as leases, and other purchase obligations were as follows (in thousands): Year Total 2020 $ 16,260 2021 6,618 2022 5,753 2023 4,823 2024 2,141 Thereafter 20,255 Total $ 55,850 Capital Expenditures We had committed approximately $25.5 million for the future purchase of property, plant and equipment at December 31, 2019

Net Income per Class A Share

Net Income per Class A Share	12 Months Ended
	Dec. 31, 2019
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 of TGE's outstanding Class B shares and an equivalent number of TE Units. The Exchange Right Holders are entitled to exercise the right to exchange their TE Units (together with an equivalent number of Class B shares) for Class A shares at an exchange ratio of one Class A share for each TE Unit exchanged, which we refer to as the Exchange Right. As of December 31, 2019 , the Exchange Right Holders primarily consist of certain of the Sponsor Entities and certain current and former members of our 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 TE 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, 2019 and 2018, the assumed issuance of TGE Equity Participation Shares would have had a dilutive effect on basic net income per Class A share as shown in the table below. 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. The following table illustrates the calculation of net income per Class A share for the years ended December 31, 2019 , 2018 , and 2017 : Year Ended December 31, 2019 2018 2017 (in thousands, except per unit amounts) Basic Net Income per Class A Share: Net income (loss) attributable to TGE $ 248,809 $ 137,127 $ (128,729 ) Basic weighted average Class A Shares outstanding 174,816 107,586 58,076 Basic net income (loss) per Class A share $ 1.42 $ 1.27 $ (2.22 ) Diluted Net Income per Class A Share: Net income (loss) attributable to TGE $ 248,809 $ 137,127 $ (128,729 ) Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares 1,137 2,108 — Net income (loss) attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares $ 249,946 $ 139,235 $ (128,729 ) Basic weighted average Class A Shares outstanding 174,816 107,586 58,076 Equity Participation Shares equivalent shares 1,684 2,231 — Diluted weighted average Class A Shares outstanding 176,500 109,817 58,076 Diluted net income (loss) per Class A Share $ 1.42 $ 1.27 $ (2.22 )

Major Customers and Concentrati

Major Customers and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2019
Risks and Uncertainties [Abstract]
Major Customers and Concentration of Credit Risk	During the years ended December 31, 2019 , 2018 , and 2017 , one non-affiliated customer, Continental Resources, Inc. ("Continental Resources"), accounted for $85.4 million ( 10% ), $81.9 million ( 10% ), and $100.2 million ( 15% ), of our total operating revenues, respectively. Revenues from Continental Resources for the years ended December 31, 2019 and 2018 were earned in our Crude Oil Transportation and Gathering, Processing & Terminalling segments. Revenues from Continental Resources for the year ended December 31, 2017 were earned in our Crude Oil Transportation segment. For the year ended December 31, 2019 , 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 55% Crude Oil Transportation 80% Gathering, Processing & Terminalling 50% 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, 2019
Share-based Payment Arrangement [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, in some cases, 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 $31.6 million , $7.6 million , and $1.6 million for the years ended December 31, 2019 , 2018 , and 2017 respectively, excluding costs associated with TEP's Equity Participation Units prior to the TEP Merger. As of December 31, 2019 , $60.0 million of total compensation cost related to non-vested Equity Participation Shares is expected to be recognized over a weighted-average period of 3.7 years . The March 2019 Blackstone Acquisition discussed in Note 1 – Description of Business constituted a change in control event under certain Equity Participation Share agreements outstanding under the LTIP plan, resulting in the accelerated vesting of 1,092,637 Class A shares (net of tax withholding of approximately 543,909 Class A shares) with a weighted average grant date fair value of $18.82 . These Class A shares were issued in April 2019. The accelerated vesting resulted in the recognition of equity-based compensation costs of $12.5 million in "General and administrative" costs in the consolidated statements of income during the year ended December 31, 2019 . The following table summarizes the changes in the Equity Participation Shares outstanding for the years ended December 31, 2019 , 2018 and 2017 : Equity Participation Shares Weighted Average Outstanding at January 1, 2017 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 Granted 3,204,850 18.14 Vested (2) (2,316,294 ) (18.75 ) Forfeited (55,200 ) (17.18 ) Outstanding at December 31, 2019 3,883,000 $ 17.85 (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. (2) Includes the accelerated vesting of 1,478,986 Class A shares (net of tax withholding of approximately 707,560 Class A shares) upon the change in control event as discussed above and other 2019 transactions.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
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, 2019 . As a result, TGE has no current provision for income taxes for the year ended December 31, 2019 , however, as discussed below one of our consolidated subsidiaries recognized current income tax expense during the year ended December 31, 2019 . Tax Components Components of income tax expense are as follows: Year Ended December 31, 2019 2018 2017 (in thousands) Current income tax expense: Federal income tax $ 728 (1) $ — $ — Deferred income tax expense: Federal income tax 65,009 41,585 200,787 State income tax 4,856 14,124 7,671 Total deferred income tax expense 69,865 55,709 208,458 Total income tax expense $ 70,593 $ 55,709 $ 208,458 (1) As discussed in Note 3 – Acquisitions and Dispositions , a newly formed indirect subsidiary of TGE acquired the outstanding stock of an entity classified as a C corporation for U.S. federal income tax purposes effective May 1, 2019. As a result, we recognized approximately $0.7 million of current income taxes during the year ended December 31, 2019 . 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, 2019 2018 2017 (in thousands) Net income before tax $ 519,148 $ 523,380 $ 432,443 Less: Net income attributable to noncontrolling interests (199,746 ) (330,544 ) (352,714 ) Net income subject to tax $ 319,402 $ 192,836 $ 79,729 Federal statutory income tax rate 21 % 21 % 35 % Income tax at statutory rate $ 67,074 $ 40,496 $ 27,905 State income taxes, net of federal benefit 8,413 5,419 2,392 Change in state tax rate 1,214 8,705 1,353 Valuation allowance (4,771 ) — 3,926 Other (1,337 ) 1,089 — Total income tax expense before change in tax legislation $ 70,593 $ 55,709 $ 35,576 Impact of federal tax legislation on deferred tax asset — — 172,037 Impact of federal tax legislation on valuation allowance — — 845 Total income tax expense $ 70,593 $ 55,709 $ 208,458 Effective tax rate 13.6 % 10.6 % 48.2 % Deferred tax assets result from the following: December 31, 2019 December 31, 2018 (in thousands) Deferred tax assets: Investment in partnerships $ 149,336 $ 198,290 Net operating losses 168,866 80,012 Deferred tax assets before valuation allowance $ 318,202 $ 278,302 Valuation allowance — (4,771 ) Total deferred tax assets $ 318,202 $ 273,531 Deferred tax liabilities: Equity earnings adjustment pursuant to ASC 606 $ 523 $ 817 Property, plant & equipment in corporate subsidiary 8,207 — Total deferred tax liabilities $ 8,730 $ 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 . 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 TE Units, we recognized an additional deferred tax asset of $15.4 million . During 2019, we recognized an additional deferred tax asset of $115.4 million upon exercise of the Exchange Right, as discussed in Note 11 – Partnership Equity , with respect to 21,751,018 Class B shares to Class A shares in connection with the March 2019 Blackstone Acquisition discussed in Note 1 – Description of Business . 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, 2019 , we had a federal net operating loss carry forward of $697.6 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 (net operating losses generated in tax years beginning after December 31, 2017 can be carried forward indefinitely) and the state operating loss carry forwards will expire between 2025 and 2039. During the year ended December 31, 2019 , we released the previously recorded valuation allowance of $4.8 million , as it is more likely than not that the deferred tax assets related to federal and state net operating losses will be realized. 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 2016 through 2019 tax years are open to examination for federal and state income tax.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Regulatory Matters	Ratemaking Process - Natural Gas Transportation & Storage Transportation and storage services on interstate natural gas pipelines are contracted under one of three rate types: recourse, discount, or negotiated. Recourse rates are calculated based on the cost of service being provided and include an allowable rate of return for the pipeline. Recourse rates are established through a FERC rate proceeding and remain effective until a subsequent rate proceeding is filed and approved by the FERC. Discount rates are offered at a discount to the then-effective maximum recourse rate. Discount rates are typically effective for an established term and can vary based on movement of the underlying recourse rate. Negotiated rates can be higher or lower than the then-effective maximum recourse rate, subject to agreement between the pipeline and shipper and approval by the FERC. Negotiated rates are also entered into for a defined term but do not change based on adjustments in the applicable recourse rate for that type of service. On May 1, 2019, TIGT filed with the FERC a pre–filing settlement in Docket No. RP19-423-001 that establishes, among other things, settlement rates reflecting an overall decrease to recourse rates, contract extensions for maximum recourse rate firm contracts through May 31, 2023, and a rate moratorium period through May 31, 2023. The settlement also requires that TIGT file a new general rate case pursuant to Section 4 of the Natural Gas Act ("NGA") on June 1, 2023, provided that TIGT has not preempted this mandatory filing requirement by filing on or before June 1, 2023 for approval of a new pre-filing settlement. The settlement also provided for contract extensions for maximum recourse rate firm contracts through May 31, 2023 and established a rate moratorium that will result in TIGT filing a new rate case or pre-filing settlement on or before June 1, 2023. TIGT's settlement was approved on November 8, 2019 in an order issued by the FERC. On June 29, 2018, Trailblazer Pipeline filed a general rate case with the FERC pursuant to Section 4 of the NGA in Docket No. RP18-922-000. Trailblazer and its customers reached a settlement in principle on October 2, 2019. The settlement continues the bifurcated rate treatment for Trailblazer's "Existing System" and "Expansion System" and maintains the existing fuel retainage and revenue crediting mechanisms. Shippers with firm contracts on the Existing System were given the opportunity to convert their contracts to negotiated rate agreements that would terminate no earlier than December 31, 2026. A rate moratorium will be in effect through December 31, 2025. The settlement was filed with the FERC on December 20, 2019 and is currently awaiting approval from the FERC. The majority of services provided by Rockies Express are contracted under negotiated rate agreements. Currently, there are no regulatory proceedings challenging the transportation rates of Rockies Express. Ratemaking Process - Crude Oil Transportation Pony Express has three types of transportation rates on its system. The first are contract rates, which are contractually agreed to and given in exchange for either commitments to ship on the pipeline or acreage dedications ("Contract Rates"). Contract Rates are generally honored by the FERC during the term of the relevant contracts. The majority of Pony Express' revenue is derived from Contract Rates. The second are indexed rates, which means they may be increased or decreased at any time provided they do not exceed the index ceiling ("Indexed Rates"). The index ceiling is calculated yearly by applying the FERC-approved inflationary adjustment, which may be positive or negative. These rates can be challenged on a cost-of-service basis. Pony Express last adjusted its Indexed Rates in Docket No. IS19-638-000 effective July 1, 2019. The third are volume incentive rates, which reflect a discount to the Indexed Rates and are available to all shippers without a contractual commitment to ship on the pipeline ("Volume Incentive Rates"). These discounts are discretionary and may not be challenged on a cost-of-service basis; however, should Pony Express' Indexed Rates be lowered due to a cost-of-service challenge, the Volume Incentive Rates would also be reduced if they are no longer below the Indexed Rates. Pony Express established its first Volume Incentive Rates effective November 1, 2019 in Docket No. IS20-3-000. Currently, there are no regulatory proceedings challenging transportation rates at Pony Express. Powder River Gateway's crude oil pipeline systems operate with Contract Rates and Indexed Rates, which can be challenged on a cost-of-service basis. Currently, there are no regulatory proceedings challenging transportation rates at Powder River Gateway. In 2020, the FERC will conduct its five-year index review to establish the new FERC approved adder, which will be in effect for the five-year period beginning July 1, 2021. The 2020 review will also consider, among other things, the effects of the Tax Cuts and Jobs Act of 2017 and any applicable impact on a crude oil pipeline's cost of service. Other Regulatory Matters In addition to the ratemaking proceedings discussed above, we have also made certain other regulatory filings with the FERC, including those further described below: 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. Rockies Express 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 further described below. On December 18, 2018, the FERC issued the Environmental Assessment. On September 20, 2019, the FERC issued an order approving the application. A notice to proceed with construction was issued on October 8, 2019. Cheyenne Connector Pipeline - FERC Docket No. CP18-102-000 On March 2, 2018, Cheyenne Connector 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. On September 20, 2019, the FERC issued an order approving the application. A notice to proceed with construction was issued on October 8, 2019.

Legal and Environmental Matters

Legal and Environmental Matters	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Legal and Environmental Matters	Legal In addition to the matters discussed below, we are involved 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, 2019 or 2018 . Rockies Express EM Energy Ohio, LLC On May 15, 2019, EM Energy Ohio, LLC ("EM Energy") and certain of its affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. EM Energy had a firm transportation service agreement with Rockies Express for 50,000 Dth/d through January 5, 2032. Rockies Express and EM Energy have stipulated in the bankruptcy proceeding that the termination date of the transportation service agreement is June 13, 2019. Following the termination, Rockies Express made a drawing equal to the outstanding face amount on the letter of credit supporting EM Energy's obligations under the transportation service agreement and received approximately $16.2 million in June 2019. A portion of the proceeds was used to settle outstanding accounts receivable for transportation services provided to EM Energy and the remaining $13.9 million was recognized as income by Rockies Express. Rockies Express intends to pursue its claim against the bankruptcy estate of EM Energy for damages and to remarket the capacity resulting from the termination of the transportation service agreement. 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 the Rockies Express Pipeline 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 disputed its obligation to pay Ohio's public utility excise tax under the relevant Ohio statute, but made payments in the amounts assessed in order to preserve its right to appeal. On February 11, 2020, the Ohio Supreme Court reached a final decision adverse to the position taken by Rockies Express. As a result of this decision, Rockies Express no longer believes that the refund of prior payments is probable and accordingly has recognized expense totaling $15.8 million during the year ended December 31, 2019. The expense recognized represents payments made to the state of Ohio totaling $12.3 million and an additional $3.5 million for amounts expected to be assessed for the period from May 1, 2019 through December 31, 2019. 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 $6.3 million and $7.4 million at December 31, 2019 and 2018 , 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. Permanent repairs were completed in September 2018. Total cost of remediation was approximately $6.1 million , $5.1 million of which Rockies Express has recovered through insurance. TMID and TIGT Casper Gas 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, 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. TMID and TIGT entered into a Consent Agreement and Final Order to settle this matter with the EPA on February 21, 2019 and made an approximately $0.1 million penalty payment to the EPA. Casper Gas Plant, WDEQ Notice of Violation On November 25, 2014, the 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. TMID and TIGT entered into a Consent Decree to settle this matter with the WDEQ on March 8, 2019 and made an approximately $0.1 million penalty payment to the WDEQ. 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. 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, 2019
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, equity-based compensation expense, and eliminations of intersegment activity. 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 75% membership interest in Rockies Express. Crude Oil Transportation. The Crude Oil Transportation segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, and other nearby oil producing basins. The Crude Oil Transportation segment includes our 51% membership interest in Powder River Gateway. 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. The Gathering, Processing, & Terminalling segment includes our 51% membership interest in Pawnee Terminal, LLC ("Pawnee Terminal"). 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. 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 and comparable picture of our overall financial and operational results. The following tables set forth our segment information for the periods indicated: Year Ended December 31, 2019 2018 2017 Revenue: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 139,752 $ (2,179 ) $ 137,573 $ 140,459 $ (4,661 ) $ 135,798 $ 141,021 $ (6,694 ) $ 134,327 Crude Oil Transportation 486,647 (57,881 ) 428,766 444,454 (39,319 ) 405,135 364,574 (10,676 ) 353,898 Gathering, Processing & Terminalling 335,895 (33,686 ) 302,209 279,665 (27,339 ) 252,326 186,211 (18,538 ) 167,673 Corporate and Other — — — — — — — — — Total revenue $ 962,294 $ (93,746 ) $ 868,548 $ 864,578 $ (71,319 ) $ 793,259 $ 691,806 $ (35,908 ) $ 655,898 Year Ended December 31, 2019 2018 2017 Tallgrass Equity Adjusted EBITDA: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 543,507 $ (4,707 ) $ 538,800 $ 377,224 $ (4,251 ) $ 372,973 $ 180,978 $ (2,176 ) $ 178,802 Crude Oil Transportation 344,333 (19,903 ) 324,430 239,330 (8,147 ) 231,183 140,785 4,878 145,663 Gathering, Processing & Terminalling 121,159 24,610 145,769 59,203 12,398 71,601 16,083 (2,702 ) 13,381 Corporate and Other (12,666 ) — (12,666 ) (21,321 ) — (21,321 ) (37,591 ) — (37,591 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investments (1) 325,385 237,197 66,922 (Loss) gain on disposal of assets (1) (354 ) 4,630 189 Non-cash (loss) gain related to derivative instruments (1) (272 ) 3,340 (64 ) Other non-cash gain 724 — — Gain on remeasurement of unconsolidated investment (1) — — 2,744 Less: Interest expense, net (1) (161,429 ) (95,465 ) (29,403 ) Depreciation and amortization expense (1) (127,503 ) (74,998 ) (26,131 ) Distributions from unconsolidated investments (1) (470,981 ) (302,364 ) (86,551 ) Non-cash compensation expense (1) (31,563 ) (8,634 ) (2,682 ) Deficiency payments, net (1) (16,992 ) (14,443 ) (7,701 ) Loss on debt retirement — (2,245 ) — Income tax expense (1) (70,578 ) (55,709 ) (208,458 ) Net income attributable to Exchange Right Holders (193,961 ) (208,618 ) (137,849 ) Net income (loss) attributable to TGE $ 248,809 $ 137,127 $ (128,729 ) (1) Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity. Year Ended December 31, Capital Expenditures: 2019 2018 2017 (in thousands) Natural Gas Transportation $ 86,892 $ 112,529 $ 16,705 Crude Oil Transportation 94,363 65,745 57,022 Gathering, Processing & Terminalling 96,168 185,732 71,417 Corporate and Other 8,230 4,867 — Total capital expenditures $ 285,653 $ 368,873 $ 145,144 Unconsolidated Investments: December 31, 2019 December 31, 2018 (in thousands) Natural Gas Transportation $ 1,811,051 $ 1,794,987 Crude Oil Transportation 164,773 35,467 Gathering, Processing & Terminalling 30,395 31,232 Total unconsolidated investments $ 2,006,219 $ 1,861,686 Assets: December 31, 2019 December 31, 2018 (in thousands) Natural Gas Transportation $ 2,554,513 $ 2,606,696 Crude Oil Transportation 1,734,278 1,423,740 Gathering, Processing & Terminalling 1,693,474 1,522,559 Corporate and Other 231,821 340,514 Total assets $ 6,214,086 $ 5,893,509

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2019
Selected Quarterly Financial Data (Unaudited) [Abstract]
Quarterly Financial Information	The following tables summarize our unaudited quarterly financial data for 2019 and 2018 : Quarter Ended 2019 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 197,352 $ 211,524 $ 226,709 $ 232,963 Operating income $ 70,464 $ 89,596 $ 105,866 $ 86,834 Net income $ 102,392 $ 126,230 $ 128,489 $ 91,444 Net income allocable to noncontrolling interests $ (51,805 ) $ (54,611 ) $ (55,965 ) $ (37,365 ) Net income attributable to TGE $ 50,587 $ 71,619 $ 72,524 $ 54,079 Basic net income per Class A Share $ 0.31 $ 0.40 $ 0.40 $ 0.30 Diluted net income per Class A Share $ 0.31 $ 0.40 $ 0.40 $ 0.30 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.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements and related notes were prepared in conformity with accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification ("ASC"), the single source of 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. The term "Predecessor Entities" refers to Terminals and NatGas prior to their acquisition by TEP on January 1, 2017. Predecessor Equity as presented in the consolidated financial statements represents the capital account activity of the Predecessor Entities prior to January 1, 2017. For additional information regarding these acquisitions, see Note 3 – Acquisitions and Dispositions . The consolidated financial statements include the accounts of TGE and its subsidiaries and controlled affiliates. 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. We have no elements of other comprehensive income for the periods presented. 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
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.
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 $0.7 million and $7.7 million at December 31, 2019 and 2018 , respectively.
Inventories	Inventories Inventories primarily consist of crude oil, materials and supplies, gas in underground storage, and natural gas liquids. 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 existence, 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 $2.6 million and $3.2 million included in "Prepayments and other current assets" and "Deferred charges and other assets" in the consolidated balance sheets at December 31, 2019 and 2018 , respectively. Regulatory assets at December 31, 2019 and December 31, 2018 were primarily attributable to costs associated with rate case filings and fuel tracker assets at our regulated natural gas pipelines. We recorded regulatory liabilities of approximately $3.0 million and $1.9 million included in "Other current liabilities" in the consolidated balance sheets at December 31, 2019 and 2018 , 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 19 – 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. We recognized intangible assets associated with customer relationships as part of our acquisitions of NGL Water Solutions Bakken, LLC ("NGL Water Solutions Bakken") and BNN Eastern, LLC ("BNN Eastern") in 2018 and 2019, respectively, 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 not be recoverable. 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% - 4.0% 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 (expense), 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 according to the benefit received by the 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 2019 .
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 We adopted Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers" on January 1, 2018, using the modified retrospective method. For periods subsequent to adoption, we account for revenue from contracts with customers in accordance with the five-step model outlined in ASC Topic 606, "Revenue from Contracts with Customers ("ASC 606"). Under the five-step model, we identify the contract, identify the performance obligations, determine the transaction price, allocate the transaction price, and recognize revenue. Revenue is recognized when (or as) the performance obligations are satisfied. For additional information see Note 12 – Revenue from Contracts with Customers .
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 the adequacy of, and compliance with, 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 "Sales of natural gas, NGLs, and crude oil" 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 17 – Equity-Based Compensation , prior to February 2018 a portion of the expense recognized relating to equity-based compensation grants was charged to Tallgrass Development, LP (" 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 for these entities has been recorded in our consolidated financial statements. As discussed in Note 3 – Acquisitions and Dispositions , in April 2019, BNN Eastern, a newly formed indirect subsidiary of TGE, entered into a Stock Purchase Agreement to acquire all of the outstanding stock of CES Holding Company, Inc., which owns all of the issued and outstanding membership interests of K & H Partners LLC. CES Holding Company, Inc. is a C corporation for U.S. federal income tax purposes and is considered a taxable entity for such purposes. 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, 2019 , 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	Accounting Pronouncement Recently 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 within GAAP 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. Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2019. This 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 the previous guidance. Accordingly, 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 have also elected the following practical expedients for all classes of leases: (a) the land easement practical expedient, allowing us to carry forward our accounting treatment for existing land easements as property, plant and equipment, (b) the practical expedient for short-term leases, allowing us to not recognize ROU assets or lease liabilities for leases with a term of 12 months or less, and (c) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease. Excluding ROU assets and lease liabilities relating to agreements between consolidated subsidiaries, adoption of the new standard resulted in the recognition of ROU assets of approximately $2.3 million and current and non-current lease liabilities of approximately $0.6 million and $1.7 million , respectively, for operating leases as of January 1, 2019. Our accounting for finance leases remained substantially unchanged. The adoption of this guidance had no impact to our cash flows from operating, investing, or financing activities. For additional information see Note 13 – Leases . Accounting Pronouncements Not Yet Adopted ASU No. 2016-13, "Financial Instruments–Credit Losses (Topic 326)" In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments–Credit Losses (Topic 326). ASU 2016-13 amends current measurement techniques used to estimate credit losses for financial assets. The amendments in ASU 2016-13 are effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact of ASU 2016-13 but do not anticipate a material impact on our consolidated financial statements. ASU No. 2019-12, "Income Taxes (Topic 740)" In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740), which modifies ASC 740 to simplify the accounting for income taxes. The amendments in ASU 2019-12 are effective for financial statements issued for annual periods beginning after December 15, 2020, and interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact of ASU 2019-12.

Leases (Policies)

Leases (Policies)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lessee, Leases	Under ASC 842, a contract is or contains a lease when, (1) the contract contains an explicitly or implicitly identified asset and (2) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. We assess whether an arrangement is or contains a lease at inception of the contract. For all leases (finance and operating leases), other than those that qualify for the short-term recognition exemption, we recognize as of the lease commencement date on the balance sheet a liability for our obligation related to the lease and a corresponding asset representing our right to use the underlying asset over the period of use. The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As our leases do not provide an implicit rate, we determine the appropriate discount rate using our incremental secured borrowing rate, with consideration given to the nature and term of the leased asset.
Lessor, Leases	Under ASC 842, a contract is or contains a lease when, (1) the contract contains an explicitly or implicitly identified asset and (2) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. We assess whether an arrangement is or contains a lease at inception of the contract. For all leases (finance and operating leases), other than those that qualify for the short-term recognition exemption, we recognize as of the lease commencement date on the balance sheet a liability for our obligation related to the lease and a corresponding asset representing our right to use the underlying asset over the period of use. The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As our leases do not provide an implicit rate, we determine the appropriate discount rate using our incremental secured borrowing rate, with consideration given to the nature and term of the leased asset.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
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% - 4.0% 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, 2019
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	Pro Forma Financial Information Unaudited pro forma revenue and net income attributable to TGE for the years ended December 31, 2019 and 2018 is presented below as if the acquisition of CES had been completed on January 1, 2018. 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 attributable to TGE for the year ended December 31, 2017 is presented below as if the acquisitions of Tallgrass Crude Gathering and Deeprock Development had been completed on January 1, 2016. Year Ended December 31, 2019 2018 2017 (in thousands) Revenue $ 873,340 $ 827,998 $ 686,803 Net income (loss) attributable to TGE $ 249,644 $ 141,988 $ (129,155 )
CES Holding Company, Inc.
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: Preliminary Adjustments Final (in thousands) Accounts receivable $ 1,391 $ — $ 1,391 Prepayments 67 — 67 Property, plant and equipment 6,900 4,400 11,300 Intangible asset 35,800 (2,900 ) 32,900 (1) Accounts payable and accrued liabilities (1,518 ) — (1,518 ) (2) Deferred tax liability (8,557 ) (189 ) (8,746 ) Net identifiable assets acquired 34,083 1,311 35,394 Goodwill 17,734 (1,311 ) 16,423 Net assets acquired (excluding cash) $ 51,817 $ — $ 51,817 (1) The $32.9 million intangible asset acquired represents customer relationships and is amortized on a straight-line basis over a period of 8 years. (2) Includes the estimated fair value of the liability for contingent consideration of $0.7 million .
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: Preliminary Adjustments Final (in thousands) Accounts receivable $ 3,599 $ (3,599 ) $ — Prepayments and other current assets 5 — 5 Property, plant and equipment 17,200 — 17,200 Intangible asset 54,000 — 54,000 (1) Accounts payable and accrued liabilities (949 ) 644 (305 ) Net identifiable assets acquired 73,855 (2,955 ) 70,900 Goodwill 17,145 2,955 20,100 Net assets acquired $ 91,000 $ — $ 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
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, 2019
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, 2019 2018 2017 (in thousands) Processing and other revenues (1) $ 7,394 $ 7,483 $ 8,516 Cost of transportation services (2) $ 940 $ — $ 10,476 Charges to TGE: (3) Property, plant and equipment, net $ — $ — $ 2,679 Other deferred charges $ — $ — $ 25 Operations and maintenance $ — $ — $ 29,881 General and administrative $ — $ — $ 41,676 (1) Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline. (2) Reflects rent expense for crude oil storage and terminalling services provided by Powder River Gateway and 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 pursuant to an Omnibus Agreement entered into by TEP and TEP GP with Tallgrass Energy Holdings, LLC and certain of its affiliates in connection with the closing of our initial public offering on May 17, 2013. Effective January 1, 2018, these costs are incurred by TGE directly.
Schedule of Balances with Affiliates Included in Consolidated Balance Sheets	Details of balances with affiliates included in "Accounts receivable, net" in the consolidated balance sheets are as follows: December 31, 2019 December 31, 2018 (in thousands) Receivable from related parties: Powder River Gateway, LLC $ 12,071 $ — Rockies Express Pipeline LLC 3,998 3,447 Cheyenne Connector, LLC 575 — Pawnee Terminal, LLC 125 115 Iron Horse Pipeline, LLC — 186 Total receivable from related parties $ 16,769 $ 3,748
Schedule of Balances of Gas Imbalance with Affiliated Shippers	Details of gas imbalances with affiliated shippers included in "Prepayments and other current assets" and "Other current liabilities" in the consolidated balance sheets are as follows: December 31, 2019 December 31, 2018 (in thousands) Affiliate gas imbalance receivables $ 74 $ 19 Affiliate gas imbalance payables $ 991 $ 742

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2019
Inventory Disclosure [Abstract]
Schedule of Components of Inventory	The components of inventory at December 31, 2019 and 2018 consisted of the following: December 31, 2019 December 31, 2018 (in thousands) Crude oil $ 46,164 $ 23,205 Gas in underground storage 1,772 2,740 Materials and supplies 650 8,206 Natural gas liquids 495 165 Total inventory $ 49,081 $ 34,316

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2018 (in thousands) Crude oil pipelines $ 1,375,036 $ 1,313,976 Gathering, processing and terminalling assets 1,007,648 889,168 Natural gas pipelines 625,631 607,343 General and other (1) 175,537 180,299 Construction work in progress 72,842 191,994 Accumulated depreciation and amortization (482,176 ) (380,351 ) Total property, plant and equipment, net (2) $ 2,774,518 $ 2,802,429 (1) Includes approximately $30.7 million of land associated with the PLT capital lease as discussed in Note 13 – Leases . (2) Property, plant and equipment, net includes approximately $464.8 million of assets at our regulated natural gas pipelines at December 31, 2019 .

Investments in Unconsolidated_2

Investments in Unconsolidated Affiliaties - (Tables)	12 Months Ended
	Dec. 31, 2019
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	The following tables summarize the combined financial information of our investments in unconsolidated affiliates during the periods in which we held a membership interest for the periods indicated: December 31, 2019 2018 (in thousands) Current assets $ 201,621 $ 132,213 Noncurrent assets $ 6,430,144 $ 6,031,066 Current liabilities $ 216,596 $ 694,951 Noncurrent liabilities $ 2,211,448 $ 1,502,906 Members' equity $ 4,203,721 $ 3,965,422 Year Ended December 31, 2019 2018 2017 (in thousands) Revenue $ 931,025 $ 930,771 $ 860,115 Operating income $ 499,493 $ 524,607 $ 480,337 Net income $ 394,725 $ 376,934 $ 465,592
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	At December 31, 2019 , the basis difference for our membership interests in Rockies Express was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 42,845 2 - 25 years Property, plant and equipment (1,108,670 ) 35 years Total basis difference $ (1,065,825 )
Equity Method Investments [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	The following table summarizes our investments in unconsolidated affiliates: Percentage Ownership at December 31, 2019 Carrying Value as of December 31, 2019 2018 (in thousands) Rockies Express Pipeline LLC 75 % $ 1,714,857 $ 1,794,987 Cheyenne Connector, LLC 50 % 96,194 — Powder River Gateway, LLC 51 % 164,773 — Pawnee Terminal, LLC 51 % 30,395 31,232 Iron Horse Pipeline, LLC Not applicable — 35,467 Total investments in unconsolidated affiliates $ 2,006,219 $ 1,861,686

Goodwill and Intangible Assets

Goodwill and Intangible Assets - (Tables)	12 Months Ended
	Dec. 31, 2019
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: Natural Gas Transportation Gathering, Processing & Terminalling Total (in thousands) Balance at December 31, 2017 $ 255,558 $ 149,280 $ 404,838 Goodwill acquired — 17,145 (1) 17,145 Balance at December 31, 2018 255,558 166,425 421,983 Goodwill acquired — 16,423 (2) 16,423 Other adjustments — 2,955 (3) 2,955 Balance at December 31, 2019 $ 255,558 $ 185,803 $ 441,361 (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 $16.4 million of goodwill was recorded in connection with the acquisition of CES on May 1, 2019 as discussed further in Note 3 – Acquisitions and Dispositions . (3) The $3.0 million goodwill adjustment was recorded in connection with a purchase price allocation adjustment related to the NGL Water Solutions Bakken acquisition 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, 2019 December 31, 2018 (in thousands) Pony Express oil conversion use rights $ 105,973 $ 105,973 Customer contracts 60,348 60,348 Customer relationships 85,950 52,100 Plaquemines Liquids Terminal use rights and permits 35,000 35,000 Accumulated amortization (45,719 ) (26,318 ) Intangible assets, net $ 241,552 $ 227,103
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense	Estimated future amortization for the intangible assets is as follows (in thousands): Year Total 2020 $ 20,527 2021 20,474 2022 17,324 2023 17,324 2024 17,324 Thereafter 113,579 Total (1) $ 206,552 (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, 2019
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 Location December 31, 2019 December 31, 2018 (in thousands) Crude oil derivative contracts Prepayments and other current assets $ 2,536 $ 3,526 Crude oil derivative contracts Other current liabilities $ 60 $ 1,642 As of December 31, 2019 , the amounts shown represent the fair value of crude oil derivative contracts for the forward purchase of 2,394,002 and the forward sale of 5,913,554 barrels of crude oil consisting of fixed price and floating price contracts, which will settle throughout 2020. As of December 31, 2018 , the amounts shown represent the fair value of crude oil derivative contracts for the forward purchase of 2,105,146 and the forward sale of 1,274,500 barrels of crude oil, consisting of fixed price and floating price contracts, which settled throughout 2019.
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, 2019 , 2018 and 2017 : Location of Amount of gain recognized in income on derivatives Year Ended December 31, 2019 2018 2017 (in thousands) Crude oil derivative contracts Sales of natural gas, NGLs, and crude oil $ 55,562 $ 29,510 $ 39 Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ — $ — $ 75 Call option derivative Other income, net $ — $ — $ 1,885
Derivative Instruments Maximum Potential Exposure to Credit Loss	The maximum potential exposure to credit losses on our crude oil derivative contracts at December 31, 2019 was: Asset Position (in thousands) Gross $ 2,536 Netting agreement impact — Cash collateral held — Net exposure $ 2,536
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, 2019 and 2018 , based on the fair value hierarchy: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2019: Crude oil derivative contracts $ 2,536 $ — $ 2,536 $ — 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, 2019: Crude oil derivative contracts $ 60 $ — $ 60 $ — As of December 31, 2018: Crude oil derivative contracts $ 1,642 $ — $ 1,642 $ —

Long-term Debt (Tables)

Long-term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of Debt	Our long-term debt is held at TEP and consisted of the following at December 31, 2019 and 2018 : December 31, 2019 December 31, 2018 (in thousands) Revolving credit facility $ 1,456,000 $ 1,224,000 4.75% senior notes due October 1, 2023 500,000 500,000 5.50% senior notes due September 15, 2024 750,000 750,000 5.50% senior notes due January 15, 2028 750,000 750,000 Less: Deferred financing costs, net (1) (18,004 ) (21,421 ) Plus: Unamortized premium on 2028 Notes 3,028 3,379 Total long-term debt, net $ 3,441,024 $ 3,205,958 (1) Deferred financing costs, net as presented above relate solely to the Senior Notes (as defined below). Deferred financing costs associated with our revolving credit facility 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 revolving credit facility as of December 31, 2019 and 2018 : December 31, 2019 December 31, 2018 (in thousands) Total capacity under the revolving credit facility $ 2,250,000 $ 2,250,000 Less: Outstanding borrowings under the revolving credit facility (1,456,000 ) (1,224,000 ) Less: Letters of credit issued under the revolving credit facility (94 ) (94 ) Available capacity under the revolving credit facility $ 793,906 $ 1,025,906
Carrying Amount and Fair Value of Long-term Debt	The following table sets forth the carrying amount and fair value of long-term debt, which is not measured at fair value in the consolidated balance sheets as of December 31, 2019 and 2018 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of December 31, 2019: Revolving credit facility $ — $ 1,456,000 $ — $ 1,456,000 $ 1,456,000 2023 Notes $ — $ 500,065 $ — $ 500,065 $ 495,750 2024 Notes $ — $ 754,043 $ — $ 754,043 $ 742,723 2028 Notes $ — $ 735,375 $ — $ 735,375 $ 746,551 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

Partnership Equity (Tables)

Partnership Equity (Tables)	12 Months Ended
	Dec. 31, 2019
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 (in thousands, except per share amounts) December 31, 2019 Not applicable $ — $ — September 30, 2019 November 14, 2019 98,559 0.5500 June 30, 2019 August 14, 2019 96,767 0.5400 March 31, 2019 May 15, 2019 94,975 0.5300 December 31, 2018 February 14, 2019 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
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 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 Revenue from Contracts with Customers - (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	A summary of our revenue by line of business is as follows: Year Ended December 31, 2019 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 $ — $ 395,297 $ — $ — $ 395,297 Natural gas transportation - firm service 125,170 — — (2,161 ) 123,009 Water business services — — 102,287 — 102,287 Natural gas gathering & processing fees — — 25,679 — 25,679 All other (1) 14,040 80,520 20,977 (74,377 ) 41,160 Total service revenue 139,210 475,817 148,943 (76,538 ) 687,432 Natural gas liquids sales — — 68,238 — 68,238 Natural gas sales 542 — 35,935 — 36,477 Crude oil sales — 10,830 622 — 11,452 Total commodity sales revenue 542 10,830 104,795 — 116,167 Total revenue from contracts with customers 139,752 486,647 253,738 (76,538 ) 803,599 Other revenue (2) — — 82,157 (17,208 ) 64,949 Total revenue (3) $ 139,752 $ 486,647 $ 335,895 $ (93,746 ) $ 868,548 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 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 revenue recognized at unconsolidated investments of $931.0 million and $930.8 million for the years ended December 31, 2019 and 2018 , respectively. 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 2020 $ 398,647 2021 287,026 2022 281,798 2023 245,006 2024 206,499 Thereafter 218,956 Total $ 1,637,932
Contract with Customer, Asset and Liability	Balances associated with our contracts with customers were as follows: Contract Liabilities (in thousands) Balance at January 1, 2018 $ 88,471 Additions 34,613 Amounts recognized as revenue (11,989 ) Balance at December 31, 2018 111,095 Additions 35,923 Amounts recognized as revenue (19,086 ) Balance at December 31, 2019 $ 127,932 December 31, 2019 December 31, 2018 January 1, 2018 (in thousands) Accounts receivable from contracts with customers $ 80,756 $ 80,935 $ 61,888 Other accounts receivable (1) 226,756 151,414 56,727 Receivable from related parties 16,769 3,748 1,340 Accounts receivable, net $ 324,281 $ 236,097 $ 119,955 (1) Other accounts receivable primarily consists of receivables under crude oil forward purchase and sale arrangements that are accounted for as derivatives under ASC 815.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lessee, Supplemental Balance Sheet	Supplemental information related to our existing leases as of December 31, 2019 was as follows: Balance Sheet Location December 31, 2019 Operating Leases: (in thousands, except lease term and discount rate) Operating lease right-of-use assets Deferred charges and other assets $ 12,629 (1) Current operating lease liabilities Other current liabilities $ 1,497 (1) Non-current operating lease liabilities Other long-term liabilities and deferred credits $ 11,231 (1) Finance Leases: Finance lease right-of-use asset (2) Property, plant and equipment, net $ 30,704 Weighted Average Remaining Lease Term: Operating leases 15.3 years Finance leases 38.9 years Weighted Average Discount Rate: Operating leases 5.82 % Finance leases 7.01 % (1) Includes right-of-use asset of approximately $9.0 million and current and non-current lease liabilities of $0.1 million and $8.9 million , respectively, related to Guernsey Terminal capacity that we lease from Powder River Gateway. (2) PLT satisfied the initial capital lease obligation of $30.7 million at lease inception and as a result has no outstanding liability or imputed interest on the future minimum rental commitments.
Finance Lease, Liability, Maturity	Maturities of lease liabilities as of December 31, 2019 were as follows: Year Operating Leases Finance Leases (1) (in thousands) 2020 $ 2,247 $ 449 2021 1,561 449 2022 1,021 449 2023 946 449 2024 910 467 Thereafter 13,644 17,303 Total lease payments 20,329 19,566 Less: discounting for present value and other adjustments (7,601 ) (19,566 ) Present value of lease liabilities $ 12,728 $ — (1) Future lease payments for finance leases consist of the annual payments under the PLT land site lease. At lease inception, the present value of the future lease payments exceeded the fair value of the leased property. As a result, the right of use asset and capital lease obligation were recorded at the $30.7 million fair value of land. On that date, PLT made a payment of $30.7 million , immediately relieving the capital lease obligation. As a result, PLT does not have an outstanding capital lease obligation or impute interest on the future minimum rental commitments and will account for the future lease payments in the period in which they are made.
Lessee, Operating Lease, Liability, Maturity	Maturities of lease liabilities as of December 31, 2019 were as follows: Year Operating Leases Finance Leases (1) (in thousands) 2020 $ 2,247 $ 449 2021 1,561 449 2022 1,021 449 2023 946 449 2024 910 467 Thereafter 13,644 17,303 Total lease payments 20,329 19,566 Less: discounting for present value and other adjustments (7,601 ) (19,566 ) Present value of lease liabilities $ 12,728 $ — (1) Future lease payments for finance leases consist of the annual payments under the PLT land site lease. At lease inception, the present value of the future lease payments exceeded the fair value of the leased property. As a result, the right of use asset and capital lease obligation were recorded at the $30.7 million fair value of land. On that date, PLT made a payment of $30.7 million , immediately relieving the capital lease obligation. As a result, PLT does not have an outstanding capital lease obligation or impute interest on the future minimum rental commitments and will account for the future lease payments in the period in which they are made.
Lessor, Operating Lease, Payments to be Received, Maturity	At December 31, 2019 , future minimum rental income under non-cancelable operating leases as the lessor were as follows: Year Total (in thousands) 2020 $ 5,613 2021 3,773 2022 3,773 2023 3,773 2024 3,773 Thereafter 3,580 Total $ 24,285
Schedule of Future Minimum Rental Payments for Operating Leases	At December 31, 2018 , our future minimum rental commitments under major, non-cancelable leases were as follows: Year Operating Leases Capital Lease (in thousands) 2019 $ 1,074 $ 449 2020 922 449 2021 483 449 2022 240 449 2023 147 449 Thereafter 364 17,770 Total $ 3,230 $ 20,015
Schedule of Future Minimum Lease Payments for Capital Leases	At December 31, 2018 , our future minimum rental commitments under major, non-cancelable leases were as follows: Year Operating Leases Capital Lease (in thousands) 2019 $ 1,074 $ 449 2020 922 449 2021 483 449 2022 240 449 2023 147 449 Thereafter 364 17,770 Total $ 3,230 $ 20,015

Commitments and Contingencies -

Commitments and Contingencies - (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Other Commitments	At December 31, 2019 , future minimum commitments under long-term, non-cancelable contracts for service contracts, right of way ("ROW") agreements not accounted for as leases, and other purchase obligations were as follows (in thousands): Year Total 2020 $ 16,260 2021 6,618 2022 5,753 2023 4,823 2024 2,141 Thereafter 20,255 Total $ 55,850 Capital Expenditures We had committed approximately $25.5 million for the future purchase of property, plant and equipment at December 31, 2019

Net Income per Class A Share (T

Net Income per Class A Share (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 , 2018 , and 2017 : Year Ended December 31, 2019 2018 2017 (in thousands, except per unit amounts) Basic Net Income per Class A Share: Net income (loss) attributable to TGE $ 248,809 $ 137,127 $ (128,729 ) Basic weighted average Class A Shares outstanding 174,816 107,586 58,076 Basic net income (loss) per Class A share $ 1.42 $ 1.27 $ (2.22 ) Diluted Net Income per Class A Share: Net income (loss) attributable to TGE $ 248,809 $ 137,127 $ (128,729 ) Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares 1,137 2,108 — Net income (loss) attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares $ 249,946 $ 139,235 $ (128,729 ) Basic weighted average Class A Shares outstanding 174,816 107,586 58,076 Equity Participation Shares equivalent shares 1,684 2,231 — Diluted weighted average Class A Shares outstanding 176,500 109,817 58,076 Diluted net income (loss) per Class A Share $ 1.42 $ 1.27 $ (2.22 )

Major Customers and Concentra_2

Major Customers and Concentration of Credit Risk (Tables)	12 Months Ended
	Dec. 31, 2019
Risks and Uncertainties [Abstract]
Schedules of Concentration of Risk	For the year ended December 31, 2019 , 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 55% Crude Oil Transportation 80% Gathering, Processing & Terminalling 50%

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Share-based Compensation, Activity	The following table summarizes the changes in the Equity Participation Shares outstanding for the years ended December 31, 2019 , 2018 and 2017 : Equity Participation Shares Weighted Average Outstanding at January 1, 2017 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 Granted 3,204,850 18.14 Vested (2) (2,316,294 ) (18.75 ) Forfeited (55,200 ) (17.18 ) Outstanding at December 31, 2019 3,883,000 $ 17.85 (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. (2) Includes the accelerated vesting of 1,478,986 Class A shares (net of tax withholding of approximately 707,560 Class A shares) upon the change in control event as discussed above and other 2019 transactions.

Income Taxes - (Tables)

Income Taxes - (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense	Components of income tax expense are as follows: Year Ended December 31, 2019 2018 2017 (in thousands) Current income tax expense: Federal income tax $ 728 (1) $ — $ — Deferred income tax expense: Federal income tax 65,009 41,585 200,787 State income tax 4,856 14,124 7,671 Total deferred income tax expense 69,865 55,709 208,458 Total income tax expense $ 70,593 $ 55,709 $ 208,458 (1) As discussed in Note 3 – Acquisitions and Dispositions , a newly formed indirect subsidiary of TGE acquired the outstanding stock of an entity classified as a C corporation for U.S. federal income tax purposes effective May 1, 2019. As a result, we recognized approximately $0.7 million of current income taxes during the year ended December 31, 2019 .
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, 2019 2018 2017 (in thousands) Net income before tax $ 519,148 $ 523,380 $ 432,443 Less: Net income attributable to noncontrolling interests (199,746 ) (330,544 ) (352,714 ) Net income subject to tax $ 319,402 $ 192,836 $ 79,729 Federal statutory income tax rate 21 % 21 % 35 % Income tax at statutory rate $ 67,074 $ 40,496 $ 27,905 State income taxes, net of federal benefit 8,413 5,419 2,392 Change in state tax rate 1,214 8,705 1,353 Valuation allowance (4,771 ) — 3,926 Other (1,337 ) 1,089 — Total income tax expense before change in tax legislation $ 70,593 $ 55,709 $ 35,576 Impact of federal tax legislation on deferred tax asset — — 172,037 Impact of federal tax legislation on valuation allowance — — 845 Total income tax expense $ 70,593 $ 55,709 $ 208,458 Effective tax rate 13.6 % 10.6 % 48.2 %
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets result from the following: December 31, 2019 December 31, 2018 (in thousands) Deferred tax assets: Investment in partnerships $ 149,336 $ 198,290 Net operating losses 168,866 80,012 Deferred tax assets before valuation allowance $ 318,202 $ 278,302 Valuation allowance — (4,771 ) Total deferred tax assets $ 318,202 $ 273,531 Deferred tax liabilities: Equity earnings adjustment pursuant to ASC 606 $ 523 $ 817 Property, plant & equipment in corporate subsidiary 8,207 — Total deferred tax liabilities $ 8,730 $ 817

Reporting Segments (Tables)

Reporting Segments (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 Revenue: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 139,752 $ (2,179 ) $ 137,573 $ 140,459 $ (4,661 ) $ 135,798 $ 141,021 $ (6,694 ) $ 134,327 Crude Oil Transportation 486,647 (57,881 ) 428,766 444,454 (39,319 ) 405,135 364,574 (10,676 ) 353,898 Gathering, Processing & Terminalling 335,895 (33,686 ) 302,209 279,665 (27,339 ) 252,326 186,211 (18,538 ) 167,673 Corporate and Other — — — — — — — — — Total revenue $ 962,294 $ (93,746 ) $ 868,548 $ 864,578 $ (71,319 ) $ 793,259 $ 691,806 $ (35,908 ) $ 655,898
Summary of TGE's Segment Information of Earnings	Year Ended December 31, 2019 2018 2017 Tallgrass Equity Adjusted EBITDA: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 543,507 $ (4,707 ) $ 538,800 $ 377,224 $ (4,251 ) $ 372,973 $ 180,978 $ (2,176 ) $ 178,802 Crude Oil Transportation 344,333 (19,903 ) 324,430 239,330 (8,147 ) 231,183 140,785 4,878 145,663 Gathering, Processing & Terminalling 121,159 24,610 145,769 59,203 12,398 71,601 16,083 (2,702 ) 13,381 Corporate and Other (12,666 ) — (12,666 ) (21,321 ) — (21,321 ) (37,591 ) — (37,591 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investments (1) 325,385 237,197 66,922 (Loss) gain on disposal of assets (1) (354 ) 4,630 189 Non-cash (loss) gain related to derivative instruments (1) (272 ) 3,340 (64 ) Other non-cash gain 724 — — Gain on remeasurement of unconsolidated investment (1) — — 2,744 Less: Interest expense, net (1) (161,429 ) (95,465 ) (29,403 ) Depreciation and amortization expense (1) (127,503 ) (74,998 ) (26,131 ) Distributions from unconsolidated investments (1) (470,981 ) (302,364 ) (86,551 ) Non-cash compensation expense (1) (31,563 ) (8,634 ) (2,682 ) Deficiency payments, net (1) (16,992 ) (14,443 ) (7,701 ) Loss on debt retirement — (2,245 ) — Income tax expense (1) (70,578 ) (55,709 ) (208,458 ) Net income attributable to Exchange Right Holders (193,961 ) (208,618 ) (137,849 ) Net income (loss) attributable to TGE $ 248,809 $ 137,127 $ (128,729 ) (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: 2019 2018 2017 (in thousands) Natural Gas Transportation $ 86,892 $ 112,529 $ 16,705 Crude Oil Transportation 94,363 65,745 57,022 Gathering, Processing & Terminalling 96,168 185,732 71,417 Corporate and Other 8,230 4,867 — Total capital expenditures $ 285,653 $ 368,873 $ 145,144
Summary of TGE's Segment Information of Unconsolidated Investments	Unconsolidated Investments: December 31, 2019 December 31, 2018 (in thousands) Natural Gas Transportation $ 1,811,051 $ 1,794,987 Crude Oil Transportation 164,773 35,467 Gathering, Processing & Terminalling 30,395 31,232 Total unconsolidated investments $ 2,006,219 $ 1,861,686
Summary of TGE's Segment Information of Assets	Assets: December 31, 2019 December 31, 2018 (in thousands) Natural Gas Transportation $ 2,554,513 $ 2,606,696 Crude Oil Transportation 1,734,278 1,423,740 Gathering, Processing & Terminalling 1,693,474 1,522,559 Corporate and Other 231,821 340,514 Total assets $ 6,214,086 $ 5,893,509

Selected Quarterly Financial _2

Selected Quarterly Financial Data (Unaudited) - (Tables)	12 Months Ended
	Dec. 31, 2019
Selected Quarterly Financial Data (Unaudited) [Abstract]
Schedule of Quarterly Financial Information	The following tables summarize our unaudited quarterly financial data for 2019 and 2018 : Quarter Ended 2019 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 197,352 $ 211,524 $ 226,709 $ 232,963 Operating income $ 70,464 $ 89,596 $ 105,866 $ 86,834 Net income $ 102,392 $ 126,230 $ 128,489 $ 91,444 Net income allocable to noncontrolling interests $ (51,805 ) $ (54,611 ) $ (55,965 ) $ (37,365 ) Net income attributable to TGE $ 50,587 $ 71,619 $ 72,524 $ 54,079 Basic net income per Class A Share $ 0.31 $ 0.40 $ 0.40 $ 0.30 Diluted net income per Class A Share $ 0.31 $ 0.40 $ 0.40 $ 0.30 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.

Description of Business - Addit

Description of Business - Additional Information (Detail) $ / shares in Units, $ in Billions	Mar. 11, 2019USD ($)shares	Jun. 30, 2018shares	Jun. 30, 2020$ / shares	Dec. 31, 2018	Dec. 31, 2019mi	Jan. 01, 2019
Organization [Line Items]
Equity interest ownership percentage					20.00%
Exchange Ratio		2
Sale of Stock, Consideration Received on Transaction | $	$ 3.2
Rockies Express Pipeline LLC
Organization [Line Items]
Equity interest ownership percentage					75.00%
Powder River Gateway
Organization [Line Items]
Equity interest ownership percentage					51.00%	51.00%
Tallgrass Energy Partners
Organization [Line Items]
Ownership Interest				100.00%
Limited Partner Common Units		47,693,097
Powder River Express Pipeline
Organization [Line Items]
Miles of Pipeline | mi					70
Iron Horse Pipeline, LLC
Organization [Line Items]
Miles of Pipeline | mi					80
Tallgrass NatGas Operator, LLC
Organization [Line Items]
Ownership Interest					100.00%
Tallgrass Energy GP, LLC | Sponsor Entities
Organization [Line Items]
Ownership Interest	100.00%
Tallgrass Terminals, LLC
Organization [Line Items]
Ownership Interest					100.00%
Tallgrass Equity, LLC | Tallgrass Energy, LP (TGE)
Organization [Line Items]
Ownership Interest					63.75%
Tallgrass Equity, LLC | Sponsor Entities
Organization [Line Items]
Partners' Capital Account, Units, Sold in Private Placement	100,655,121
Tallgrass Energy, LP (TGE) | Sponsor Entities
Organization [Line Items]
Ownership Interest					44.10%
Tallgrass Energy, LP (TGE) | Common Class A | Sponsor Entities
Organization [Line Items]
Partners' Capital Account, Units, Sold in Private Placement	21,751,018
Tallgrass Energy, LP (TGE) | Common Class B | Sponsor Entities
Organization [Line Items]
Partners' Capital Account, Units, Sold in Private Placement	100,655,121
Subsequent Event [Member]
Organization [Line Items]
Proposed Sale of Stock, Price Per Share | $ / shares			$ 22.45

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Jan. 01, 2019USD ($)	Aug. 06, 2012mi
Business Acquisition [Line Items]
Accounts Receivable, Allowance for Credit Loss	$ 700	$ 7,700
Regulatory Assets	2,600	3,200
Regulatory Liabilities	$ 3,000	1,900
Loss on debt retirement		$ 2,200
Equity interest ownership percentage	20.00%
Operating Lease, Right-of-Use Asset	$ 12,629
Operating Lease, Liability, Current	1,497
Operating Lease, Liability, Noncurrent	$ 11,231
Crude oil pipelines
Business Acquisition [Line Items]
Depreciation Rate	2.80%
Replacement Gas Facilities
Business Acquisition [Line Items]
Depreciation Rate	10.00%
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 | 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	4.00%
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
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 Relationships
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life	8 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
Accounting Standards Update 2016-02
Business Acquisition [Line Items]
Operating Lease, Right-of-Use Asset			$ 2,300
Operating Lease, Liability, Current			600
Operating Lease, Liability, Noncurrent			$ 1,700

Acquisitions & Dispositions CES

Acquisitions & Dispositions CES Acquisition, Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	May 01, 2019	Sep. 30, 2019	Dec. 31, 2019	Jun. 30, 2019	Dec. 31, 2018	Nov. 05, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill						$ 35,000
Goodwill			$ 441,361		$ 421,983		$ 404,838
Goodwill, Purchase Accounting Adjustments			$ 2,955
CES Holding Company, Inc.
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables	$ 1,391	$ 1,391
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets	67	67
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	6,900	11,300
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment		4,400
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	35,800	32,900
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Intangibles		(2,900)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable	(1,518)	(1,518)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities	(8,557)	(8,746)
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Deferred Tax Liability		(189)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	34,083	35,394
Goodwill	17,734	16,423
Goodwill, Purchase Accounting Adjustments		(1,311)
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	$ 51,817	51,817
Finite-Lived Intangible Asset, Useful Life	8 years
Business Combination, Contingent Consideration, Liability		700
Adjustments
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net		1,311		$ (2,955)
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net		$ 0		$ 0

BNN Colorado, Assets Acquired a

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

BNN North Dakota Acquisitions,

BNN North Dakota Acquisitions, Assets Acquired & Liabilities Assumed (Details) - USD ($) $ in Thousands	Nov. 30, 2018	Jan. 12, 2018	Jun. 30, 2019	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018	Nov. 05, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill							$ 35,000
Goodwill				$ 441,361		$ 421,983		$ 404,838
Goodwill, Purchase Accounting Adjustments				$ 2,955
NGL Water Solutions Bakken, LLC
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables	$ 3,599		$ 0
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Assets			(3,599)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Prepaid Expense and Other Assets	5		5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	17,200		17,200
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	54,000		54,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable	(949)		(305)
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Liabilities			644
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	73,855		70,900
Goodwill	17,145		20,100
Goodwill, Purchase Accounting Adjustments			2,955
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	$ 91,000		91,000
NGL Water Solutions Bakken, LLC | Minimum
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life	3 years
NGL Water Solutions Bakken, LLC | Maximum
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life	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
BNN North Dakota | Minimum
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life		8 years
BNN North Dakota | Maximum
Business Acquisition [Line Items]
Finite-Lived Intangible Asset, Useful Life		14 years
Adjustments
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net			(2,955)		$ 1,311
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net			$ 0		$ 0

TCG Acquisition, Assets Acquire

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

DRD Acquisition, Assets Acquire

DRD Acquisition, Assets Acquired & Liabilities Assumed (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jul. 20, 2017
Business Acquisition [Line Items]
Goodwill	$ 441,361	$ 421,983	$ 404,838
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

Pro Forma Revenue & Net Income

Pro Forma Revenue & Net Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Combinations [Abstract]
Pro Forma Revenue	$ 873,340	$ 827,998	$ 686,803
Pro Forma Net income (loss) attributable to TGE	$ 249,644	$ 141,988	$ (129,155)

Acquisitions & Dispositions - A

Acquisitions & Dispositions - Additional Information (Details)	Nov. 04, 2019USD ($)	May 01, 2019USD ($)	Jan. 31, 2019USD ($)	Nov. 30, 2018USD ($)	Nov. 05, 2018USD ($)	Apr. 01, 2018USD ($)	Feb. 23, 2018USD ($)	Feb. 07, 2018USD ($)shares	Feb. 06, 2018USD ($)	Feb. 01, 2018USD ($)	Jan. 12, 2018USD ($)	Jan. 02, 2018USD ($)	Jan. 01, 2018	Aug. 03, 2017USD ($)ami	Jul. 21, 2017USD ($)shares	Jul. 20, 2017USD ($)	Jun. 05, 2017USD ($)mi	Jan. 01, 2017USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)mi	Sep. 30, 2019USD ($)	Dec. 31, 2019USD ($)mi	Dec. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jun. 30, 2019USD ($)	Jan. 01, 2019	Dec. 01, 2018USD ($)	Mar. 31, 2017	May 06, 2016	Jan. 01, 2016
Business Acquisition [Line Items]
Equity interest ownership percentage																							20.00%		20.00%
Proceeds from Divestiture of Interest in Consolidated Subsidiaries	$ 59,700,000																								$ 59,693,000
Goodwill																			$ 421,983,000	$ 421,983,000	$ 404,838,000	$ 404,838,000	$ 441,361,000		441,361,000	$ 421,983,000	$ 421,983,000	$ 404,838,000
Payments to Acquire Assets, Investing Activities					$ 30,700,000																					30,704,000		128,526,000
Preferred Membership Interest, Ownership Percentage					100.00%
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill					$ 35,000,000
Contributions to unconsolidated investments																									(115,545,000)	(473,946,000)		(45,948,000)
Payments to Acquire Interest in Subsidiaries and Affiliates																										0		400,000,000
Units Acquired | shares								5,619,218
Issuance of Noncontrolling Interest in Subsidiary in Exchange for Membership Interest																									$ 0	(31,843,000)
Proceeds from Divestiture of Businesses																										50,046,000
Cheyenne Connector, LLC
Business Acquisition [Line Items]
Equity interest ownership percentage	50.00%																						50.00%		50.00%
Powder River Gateway
Business Acquisition [Line Items]
Equity interest ownership percentage																							51.00%		51.00%					51.00%
Contributions to unconsolidated investments																									$ (37,000,000)
Deeprock North, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired												38.00%
Contributions to unconsolidated investments												$ (19,500,000)														(19,500,000)		0
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			$ (37,000,000)				$ (3,500,000)
Pawnee Terminal
Business Acquisition [Line Items]
Equity interest ownership percentage						51.00%																	51.00%		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%
Contributions to unconsolidated investments																									$ (62,200,000)
Silver Creek Midstream, LLC | Powder River Gateway
Business Acquisition [Line Items]
Equity interest ownership percentage																														49.00%
Silver Creek Midstream, LLC | Iron Horse Pipeline, LLC
Business Acquisition [Line Items]
Equity interest ownership percentage			25.00%
Iron Horse Pipeline, LLC
Business Acquisition [Line Items]
Miles of Pipeline | mi																							80		80
DCP Midstream, LP | Cheyenne Connector, LLC
Business Acquisition [Line Items]
Equity interest ownership percentage	50.00%
Cheyenne Connector, LLC
Business Acquisition [Line Items]
Miles of Pipeline | mi																							70		70
PRE Pipeline
Business Acquisition [Line Items]
Miles of Pipeline | mi																							70		70
BNN Eastern, LLC
Business Acquisition [Line Items]
Equity interest held by noncontrolling interests																							7.65%		7.65%
Noncontrolling Interest, Increase from Business Combination																									$ 3,400,000
Issuance of Noncontrolling Interest in Subsidiary in Exchange for Membership Interest																									(3,400,000)
Tallgrass Crude Gathering, LLC
Business Acquisition [Line Items]
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
Drexel Hamilton Infrastructure Fund I, L.P. (DHIF)
Business Acquisition [Line Items]
Right to receive special distributions					$ 35,000,000
Special Distribution, Current-portion																								$ 25,000,000
Special Distribution, Non-current portion																								10,000,000
NGL Water Solutions Bakken, LLC
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross				$ 91,000,000
Goodwill				$ 17,145,000																									$ 20,100,000
Business Acquisition, Percentage of Voting Interests Acquired				100.00%
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill				$ 54,000,000																									$ 54,000,000
CES Holding Company, Inc.
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 52,000,000
Business Combination, Contingent Consideration Arrangements, Range of Outcomes, Value, High		3,000,000
Goodwill		17,734,000																						16,423,000
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual																							$ 6,400,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual																							800,000
Payments to Acquire Businesses, Net of Cash Acquired																									$ 48,416,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill		$ 35,800,000																						$ 32,900,000
NGL Water Solutions Bakken
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross																										91,000,000
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
BNN Colorado Water, LLC
Business Acquisition [Line Items]
Equity interest held by noncontrolling interests																															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)
Acquisition, noncontrolling interest, fair value																															$ 10,100,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill																															$ 7,922,000
BNN North Dakota
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual																											18,800,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual																											4,700,000
Business Acquisition, Percentage of Voting Interests Acquired											100.00%
Payments to Acquire Businesses, Net of Cash Acquired											$ 95,000,000															95,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill											$ 46,800,000
Terminals and NatGas
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross																		$ 140,000,000								0		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%
Goodwill																$ 61,550,000
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
Acquisition, noncontrolling interest, fair value																45,900,000
Payments to Acquire Businesses, Net of Cash Acquired																57,200,000										0		57,202,000
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]
Payments to Acquire Businesses, Gross														$ 36,000,000												0		36,030,000
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 Acquisition, Percentage of Voting Interests Acquired														100.00%
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill														$ 6,694,000
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								25.01%																								24.99%	25.00%
Payments to Acquire Interest in Subsidiaries and Affiliates																												$ 400,000,000
Rockies Express Pipeline LLC | Tallgrass Development LP
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired																																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%
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
Common 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 Common Units								$ 53,800,000
Construction work in progress
Business Acquisition [Line Items]
Property, Plant and Equipment, Gross																			$ 191,994,000	$ 191,994,000			$ 72,842,000		$ 72,842,000	$ 191,994,000	$ 191,994,000
Construction work in progress | Cheyenne Connector, LLC
Business Acquisition [Line Items]
Property, Plant and Equipment, Gross	$ 134,400,000

Related Party Transactions - Sc

Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Revenue from affiliated companies	$ 7,394	$ 7,483	$ 8,516
Costs of transportation services from affiliated companies	940	0	10,476
Other Deferred Charges
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	0	0	25
Operation and maintenance
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	0	0	29,881
General and administrative expense
Related Party Transaction [Line Items]
General and administrative costs from transactions with affiliated companies	0	0	41,676
Property, Plant and Equipment
Related Party Transaction [Line Items]
Property, plant and equipment, net	$ 0	$ 0	$ 2,679

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, 2019	Dec. 31, 2018	Jan. 01, 2018
Related Party Transaction [Line Items]
Receivable from related parties	$ 16,769	$ 3,748	$ 1,340
Powder River Gateway
Related Party Transaction [Line Items]
Receivable from related parties	12,071	0
Rockies Express Pipeline LLC
Related Party Transaction [Line Items]
Receivable from related parties	3,998	3,447
Cheyenne Connector, LLC
Related Party Transaction [Line Items]
Receivable from related parties	575	0
Pawnee Terminal, LLC
Related Party Transaction [Line Items]
Receivable from related parties	125	115
Iron Horse Pipeline, LLC
Related Party Transaction [Line Items]
Receivable from related parties	$ 0	$ 186

Related Party Transactions - _3

Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Affiliate gas imbalance receivables	$ 74	$ 19
Affiliate gas imbalance payables	$ 991	$ 742

Inventory (Details)

Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Inventory [Line Items]
Inventories	$ 49,081	$ 34,316
Crude Oil
Inventory [Line Items]
Inventories	46,164	23,205
Gas in underground storage
Inventory [Line Items]
Inventories	1,772	2,740
Materials and supplies
Inventory [Line Items]
Inventories	650	8,206
Natural Gas Liquids
Inventory [Line Items]
Inventories	$ 495	$ 165

Property, Plant and Equipment -

Property, Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Accumulated depreciation and amortization	$ (482,176,000)	$ (380,351,000)
Property, plant and equipment, net	2,774,518,000	2,802,429,000
Crude oil pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,375,036,000	1,313,976,000
Gathering, processing and terminalling assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,007,648,000	889,168,000
Natural gas pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	625,631,000	607,343,000
Property, plant and equipment, net	464,800,000
General and other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	175,537,000	180,299,000
Construction work in progress
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	72,842,000	$ 191,994,000
Plaquemines Liquids Terminal, LLC | General and other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 30,700,000

Property, Plant and Equipment_2

Property, Plant and Equipment - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Depreciation expense	$ 109,400,000	$ 102,700,000	$ 86,900,000
Capitalized interest	$ 7,500,000	$ 5,200,000	$ 1,100,000

Investments in Unconsolidated_3

Investments in Unconsolidated Affiliaties Equity Method Investments Ownership Percentages and Carrying Value (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Nov. 04, 2019	Jan. 01, 2019	Dec. 31, 2018	Feb. 23, 2018	May 06, 2016
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage	20.00%
Unconsolidated investments	$ 2,006,219			$ 1,861,686
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage	75.00%
Unconsolidated investments	$ 1,714,857			1,794,987		$ 436,000
Cheyenne Connector, LLC
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage	50.00%	50.00%
Unconsolidated investments	$ 96,194			0
Powder River Gateway
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage	51.00%		51.00%
Unconsolidated investments	$ 164,773			0
Pawnee Terminal, LLC
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage	51.00%
Unconsolidated investments	$ 30,395			31,232
Iron Horse Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage					75.00%
Unconsolidated investments	$ 0			$ 35,467

Investments in Unconsolidated_4

Investments in Unconsolidated Affiliates - Equity Method Investments (Details) - Rockies Express Pipeline LLC - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	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	$ (1,065,825)	$ 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	$ 42,845
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	$ (1,108,670)
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, 2019	Dec. 31, 2018	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment, Summarized Financial Information, Current Assets	$ 201,621	$ 132,213
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	6,430,144	6,031,066
Equity Method Investment, Summarized Financial Information, Current Liabilities	216,596	694,951
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	2,211,448	1,502,906
Equity Method Investment Summarized Financial Information, Equity	4,203,721	3,965,422
Equity Method Investment, Summarized Financial Information, Revenue	931,025	930,771	$ 860,115
Equity Method Investment Summarized Financial Information Operating Income	499,493	524,607	480,337
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	$ 394,725	$ 376,934	$ 465,592

Investments in Unconsolidated_5

Investments in Unconsolidated Affiliaties - (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 31, 2020	Nov. 04, 2019	Apr. 12, 2019	Jan. 01, 2019	Feb. 07, 2018	Jul. 20, 2017	Mar. 31, 2017	May 06, 2016
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage	20.00%
Unconsolidated investments	$ 2,006,219	$ 1,861,686
Equity in earnings of unconsolidated investments	325,385	306,819	$ 237,110
Contributions to unconsolidated investments	$ (115,545)	(473,946)	$ (45,948)
Cheyenne Connector, LLC
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage	50.00%				50.00%
Unconsolidated investments	$ 96,194	0
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage	75.00%
Unconsolidated investments	$ 1,714,857	1,794,987									$ 436,000
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ (1,065,825)							$ 376,500		$ 386,800	$ 404,700
Basis Difference, Amortization Period	35 years
Depreciation Rate	2.86%
Equity in earnings of unconsolidated investments	$ 316,400
Distributions to unconsolidated affiliates	458,700
Contributions to unconsolidated investments	$ (62,200)
Debt Instrument, Face Amount						$ 550,000
Debt Instrument, Interest Rate, Stated Percentage						4.95%
Debt Instrument, Repurchase Amount						$ 525,000
Powder River Gateway
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage	51.00%						51.00%
Unconsolidated investments	$ 164,773	$ 0
Contributions to unconsolidated investments	$ (37,000)
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired								(25.01%)		(24.99%)	(25.00%)
Kinder Morgan Cushing, LLC | Deeprock Development, LLC
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired									(40.00%)
DCP Midstream, LP | Cheyenne Connector, LLC
Schedule of Equity Method Investments [Line Items]
Equity interest ownership percentage					50.00%
Subsequent Event [Member] | Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Face Amount				$ 750,000
REX 2025 Senior Notes | Subsequent Event [Member] | Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Face Amount				$ 400,000
Debt Instrument, Interest Rate, Stated Percentage				3.60%
REX 2030 Senior Notes | Subsequent Event [Member] | Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Face Amount				$ 350,000
Debt Instrument, Interest Rate, Stated Percentage				4.80%
REX 2020 Senior Notes | Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.625%

Goodwill and Intangible Asset_2

Goodwill and Intangible Assets - Schedule of Goodwill by Segment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill	$ 441,361	$ 421,983	$ 404,838
Goodwill, Acquired During Period	16,423	17,145
Goodwill, Purchase Accounting Adjustments	2,955
Natural Gas Transportation
Goodwill [Line Items]
Goodwill	255,558	255,558	255,558
Goodwill, Acquired During Period	0	0
Goodwill, Purchase Accounting Adjustments	0
Gathering, Processing & Terminalling
Goodwill [Line Items]
Goodwill	185,803	166,425	$ 149,280
Goodwill, Acquired During Period	16,423	$ 17,145
Goodwill, Purchase Accounting Adjustments	$ 2,955

Goodwill and Intangible Asset_3

Goodwill and Intangible Assets - Intangible Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Acquired Finite-Lived Intangible Assets [Line Items]
Accumulated amortization	$ 45,719	$ 26,318
Intangible assets, net	241,552	227,103
Use Rights
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	105,973	105,973
Customer Contracts
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	60,348	60,348
Customer Relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	85,950	52,100
Plaquemines Liquids Terminal, LLC | Use Rights
Acquired Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	$ 35,000	$ 35,000

Goodwill and Intangible Asset_4

Goodwill and Intangible Assets - Future Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	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]
2020	$ 20,527
2021	20,474
2022	17,324
2023	17,324
2024	17,324
Thereafter	113,579
Total (1)	$ 206,552
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 Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Aug. 31, 2019
Goodwill [Line Items]
Goodwill	$ 441,361	$ 421,983	$ 404,838
Amortization of Intangible Assets	19,400	$ 8,100	$ 3,800
Tallgrass Midstream, LLC
Goodwill [Line Items]
Goodwill	$ 79,200
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount				17.00%

Risk Management - Schedule of F

Risk Management - Schedule of Fair Value of Derivative Contracts (Details) - Energy Related Derivative $ in Thousands	Dec. 31, 2019USD ($)bbl	Dec. 31, 2018USD ($)bbl
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 2,536	$ 3,526
Not Designated as Hedging Instrument | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 2,536	$ 3,526
Derivative, Nonmonetary Notional Amount | bbl	2,394,002	2,105,146
Not Designated as Hedging Instrument | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability at fair value	$ 60	$ 1,642
Derivative, Nonmonetary Notional Amount | bbl	5,913,554	1,274,500

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Energy Related Derivative
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain recognized in income on derivatives	$ 55,562	$ 29,510	$ 39
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain recognized in income on derivatives	0	0	75
Equity Option
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain recognized in income on derivatives	$ 0	$ 0	$ 1,885

Risk Management - Derivative In

Risk Management - Derivative Instruments Maximum Potential Exposure to Credit Loss (Details) - Energy Related Derivative $ in Thousands	Dec. 31, 2019USD ($)
Concentration Risk [Line Items]
Gross	$ 2,536
Netting agreement impact	0
Cash collateral held	0
Net exposure	$ 2,536

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, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 2,536	$ 3,526
Derivative liability at fair value	60	1,642
Quoted prices in active markets for identical assets (Level 1)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	0	0
Derivative liability at fair value	0	0
Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	2,536	3,526
Derivative liability at fair value	60	1,642
Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	0	0
Derivative liability at fair value	$ 0	$ 0

Risk Management - Additional In

Risk Management - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 01, 2017	Jan. 01, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Feb. 01, 2018
Derivative [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased	736,262
Partial exercise of call option	$ 35,300
Partial exercise of call option					$ (84,942)
Margin Deposit Assets			$ 2,600
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
Partial exercise of call option	$ 72,400		$ 0	$ 0	72,381
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
Call Option
Derivative [Line Items]
Partial exercise of call option					$ 12,600

Long-term Debt - Schedule of De

Long-term Debt - Schedule of Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Less: Deferred financing costs, net	$ (18,004)	$ (21,421)
Plus: Unamortized premium on 2028 Notes	3,028	3,379
Total long-term debt, net	3,441,024	3,205,958
Revolving Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross	1,456,000	1,224,000
Total long-term debt, net	1,456,000	1,224,000
2023 Senior Notes
Debt Instrument [Line Items]
Total long-term debt, net	495,750	494,603
2023 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	500,000	500,000
2024 Senior Notes
Debt Instrument [Line Items]
Total long-term debt, net	742,723	741,196
2024 Senior Notes | 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	746,551	746,159
2028 Senior Notes | 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 (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018	Jul. 26, 2018
Line of Credit Facility [Line Items]
Long-term Debt	$ (3,441,024,000)	$ (3,205,958,000)
Revolving Credit Facility
Line of Credit Facility [Line Items]
Long-term Debt	(1,456,000,000)	(1,224,000,000)
Letters of Credit Outstanding, Amount	(94,000)	(94,000)
Line of Credit Facility, Remaining Borrowing Capacity	793,906,000	1,025,906,000
Wells Fargo Bank, National Association | Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,250,000,000	$ 2,250,000,000	$ 2,250,000,000

Long-term Debt - Carrying Amoun

Long-term Debt - Carrying Amount and Fair Value of Long-term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term Debt	$ 3,441,024	$ 3,205,958
2023 Senior Notes
Debt Instrument [Line Items]
Fair Value	500,065	485,285
Long-term Debt	495,750	494,603
2023 Senior Notes | Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Fair Value	0	0
2023 Senior Notes | Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Fair Value	500,065	485,285
2023 Senior Notes | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Fair Value	0	0
2024 Senior Notes
Debt Instrument [Line Items]
Fair Value	754,043	737,745
Long-term Debt	742,723	741,196
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	754,043	737,745
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	735,375	726,503
Long-term Debt	746,551	746,159
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	735,375	726,503
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	1,456,000	1,224,000
Long-term Debt	1,456,000	1,224,000
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	1,456,000	1,224,000
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 ($)	Sep. 01, 2016USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt							$ 0	$ 500,000,000	$ 1,103,750,000
Revolving Credit Facility
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate							3.13%
Debt Instrument, Interest Rate, Effective Percentage							4.18%
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	$ 2,250,000,000
Maximum | Revolving Credit Facility
Debt Instrument [Line Items]
Consolidated leverage ratio		5.50					5.50
Consolidated Senior Secured Leverage Ratio One							3.75
Credit facility commitment fee							0.375%
Minimum | Revolving Credit Facility
Debt Instrument [Line Items]
Consolidated Interest Coverage Ratio One							2.50
Credit facility commitment fee							0.25%
2023 Senior Notes | Senior Notes
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
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
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 - TGE Summar

Partnership Equity - TGE Summary of Distributions (Details) - Tallgrass Energy, LP (TGE) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017
Distribution Made to Limited Partner [Line Items]
Dividends	$ 0	$ 98,559	$ 96,767	$ 94,975	$ 81,304	$ 79,717	$ 77,052	$ 28,316	$ 21,346	$ 20,617	$ 19,891	$ 16,697
Dividends Payable, Amount Per Share	$ 0	$ 0.5500	$ 0.5400	$ 0.5300	$ 0.5200	$ 0.5100	$ 0.4975	$ 0.4875	$ 0.3675	$ 0.3550	$ 0.3425	$ 0.2875

Partnership Equity - TEP Summar

Partnership Equity - 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
Distribution Made to Limited Partner [Line Items]
Limited Partner Common Distributions	$ 71,370	$ 70,638	$ 69,174	$ 67,671	$ 60,486
Incentive Distribution Rights, Distribution	39,816	39,125	37,744	36,342	29,840
General Partner Distributions	1,267	1,251	1,219	1,186	1,040
Total Distributions	$ (112,453)	$ (111,014)	$ (108,137)	$ (105,199)	$ (91,366)
Distribution per Limited Partner Unit	$ 0.9750	$ 0.9650	$ 0.9450	$ 0.9250	$ 0.8350

Partnership Equity - Additional

Partnership Equity - Additional Information (Detail) - USD ($)	Feb. 01, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Feb. 07, 2018	Feb. 01, 2018	Mar. 31, 2017	May 06, 2016	Jan. 01, 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
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders		$ 2,323,000	$ 1,787,000	$ 1,589,000
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders		237,350,000	327,578,000	317,102,000
Tallgrass Equity distributions to noncontrolling interest		237,350,000	327,578,000	317,102,000
Payments to Noncontrolling Interests		7,500,000	6,200,000	6,200,000
Payments for Purchase of Common Stock			(198,000,000)
Units Acquired					5,619,218
Contributions from TD				2,301,000
Terminals and NatGas
Limited Partners' Capital Account [Line Items]
Acquisitions				(140,000,000)
Carrying Value of Assets Acquired				$ 82,300,000
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Acquisitions			(50,000,000)
Carrying Value of Assets Acquired						$ 33,800,000
Tallgrass Energy Partners
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Units, Sold in Public Offering				2,341,061
Shares Issued, Price Per Share				$ 48.82
Issuance of units to public, net of offering costs			377,000	$ 112,420,000
Limited Partners' Offering Costs				1,900,000
Payments for Repurchase of Common Stock		$ 0	0	35,335,000
Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Acquisitions			$ 108,537,000	63,681,000
Tallgrass Equity, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests		36.25%
Deeprock Development, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests		40.00%
Acquisitions				45,869,000
BNN West Texas, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests		25.00%
BNN Colorado Water, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests		37.00%
Plaquemines Liquids Terminal, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests		20.00%
BNN Eastern, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests		7.65%
Common Class A
Limited Partners' Capital Account [Line Items]
Conversion of Stock, Shares Issued		21,751,018	2,821,332
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders		$ 0	$ 0	0
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders		0	0	0
Contributions from TD				850,000
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)
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
Payments for Repurchase of Common Stock				3,618,000
Common Class A | Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Acquisitions			34,116,000	23,522,000
Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					25.01%		24.99%	25.00%
Acquisitions			108,500,000	63,700,000
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Payments to Noncontrolling Interests			50,000,000
Business Acquisition, Percentage of Voting Interests Acquired						2.00%			31.30%
Acquisitions			16,200,000
Terminals and NatGas
Limited Partners' Capital Account [Line Items]
Acquisitions				57,700,000
Tallgrass Development LP | Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired							24.99%
Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Noncontrolling Interest, Increase from Contributions from Noncontrolling Interest Holders		2,323,000	1,787,000	1,589,000
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders		237,350,000	327,578,000	317,102,000
Tallgrass Equity distributions to noncontrolling interest		$ 229,900,000	223,700,000	125,200,000
Carrying Value of Common Units					$ 53,800,000
Contributions from TD				1,451,000
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)
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
Payments for Repurchase of Common Stock				(31,717,000)
Tallgrass Equity distributions to noncontrolling interest			97,700,000	185,700,000
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

Revenue from Contracts with C_3

Revenue from Contracts with Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 868,548	$ 793,259
Equity Method Investment, Summarized Financial Information, Revenue	931,025	930,771	$ 860,115
Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	395,297	392,276
Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	123,009	123,456
Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	102,287	52,333
Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	25,679	24,109
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	41,160	21,605
Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	687,432	613,779
Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	68,238	101,382
Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	36,477	30,753
Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	11,452	6,942
Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	116,167	139,077
Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	803,599	752,856
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	64,949	40,403
Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	139,752	140,459
Natural Gas Transportation | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Natural Gas Transportation | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	125,170	128,041
Natural Gas Transportation | Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Natural Gas Transportation | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Natural Gas Transportation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	14,040	11,223
Natural Gas Transportation | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	139,210	139,264
Natural Gas Transportation | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Natural Gas Transportation | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	542	1,195
Natural Gas Transportation | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Natural Gas Transportation | Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	542	1,195
Natural Gas Transportation | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	139,752	140,459
Natural Gas Transportation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	486,647	444,454
Crude Oil Transportation | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	395,297	392,276
Crude Oil Transportation | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Crude Oil Transportation | Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Crude Oil Transportation | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Crude Oil Transportation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	80,520	45,888
Crude Oil Transportation | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	475,817	438,164
Crude Oil Transportation | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Crude Oil Transportation | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Crude Oil Transportation | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	10,830	6,290
Crude Oil Transportation | Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	10,830	6,290
Crude Oil Transportation | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	486,647	444,454
Crude Oil Transportation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Gathering, Processing & Terminalling
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	335,895	279,665
Gathering, Processing & Terminalling | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Gathering, Processing & Terminalling | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Gathering, Processing & Terminalling | Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	102,287	52,333
Gathering, Processing & Terminalling | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	25,679	24,109
Gathering, Processing & Terminalling | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	20,977	18,444
Gathering, Processing & Terminalling | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	148,943	94,886
Gathering, Processing & Terminalling | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	68,238	101,382
Gathering, Processing & Terminalling | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	35,935	29,558
Gathering, Processing & Terminalling | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	622	652
Gathering, Processing & Terminalling | Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	104,795	131,592
Gathering, Processing & Terminalling | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	253,738	226,478
Gathering, Processing & Terminalling | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	82,157	53,187
Corporate and Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(93,746)	(71,319)
Corporate and Other | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Corporate and Other | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(2,161)	(4,585)
Corporate and Other | Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Corporate and Other | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Corporate and Other | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(74,377)	(53,950)
Corporate and Other | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(76,538)	(58,535)
Corporate and Other | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Corporate and Other | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Corporate and Other | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Corporate and Other | Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	0
Corporate and Other | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(76,538)	(58,535)
Corporate and Other | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ (17,208)	$ (12,784)

Revenue from Contracts with C_4

Revenue from Contracts with Customers - Remaining Performance Obligation (Details) $ in Thousands	Dec. 31, 2019USD ($)
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	$ 398,647
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	$ 287,026
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	$ 281,798
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	$ 245,006
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	1 year
Revenue, Remaining Performance Obligation, Amount	$ 206,499
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	110 years 3 months
Revenue, Remaining Performance Obligation, Amount	$ 1,637,932

Revenue from Contracts with C_5

Revenue from Contracts with Customers - Contract with Customer, Asset and Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2018
Revenue from Contract with Customer [Abstract]
Contract with Customer, Liability	$ 127,932	$ 111,095	$ 88,471
Deferred Revenue, Additions	35,923	34,613
Contract with Customer, Liability, Revenue Recognized	(19,086)	(11,989)
Contract with Customer, Asset, after Allowance for Credit Loss	80,756	80,935	61,888
Accounts and Other Receivables, Net, Current	226,756	151,414	56,727
Accounts Receivable, Related Parties, Current	16,769	3,748	1,340
Accounts receivable, net	$ 324,281	$ 236,097	$ 119,955

Leases Leases - Supplemental In

Leases Leases - Supplemental Information (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Nov. 05, 2018
Lessee, Lease, Description [Line Items]
Operating Lease, Right-of-Use Asset	$ 12,629
Operating Lease, Liability, Current	1,497
Operating Lease, Liability, Noncurrent	11,231
Finance Lease, Right-of-Use Asset	$ 30,704
Operating Lease, Weighted Average Remaining Lease Term	15 years 3 months 18 days
Finance Lease, Weighted Average Remaining Lease Term	38 years 10 months 24 days
Operating Lease, Weighted Average Discount Rate, Percent	5.82%
Finance Lease, Weighted Average Discount Rate, Percent	7.01%
Capital Lease Obligations		$ 30,700
Powder River Gateway
Lessee, Lease, Description [Line Items]
Operating Lease, Right-of-Use Asset	$ 9,000
Operating Lease, Liability, Current	100
Operating Lease, Liability, Noncurrent	$ 8,900

Leases Leases, Maturity Analysi

Leases Leases, Maturity Analysis of Operating and Finance Leases (Details) - USD ($) $ in Thousands	Nov. 05, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Leases [Abstract]
2020				$ 2,247
2021				1,561
2022				1,021
2023				946
2024				910
Thereafter				13,644
Total lease payments				20,329
Less discounting for present value and other adjustments				(7,601)
Operating Lease, Liability				12,728
2020				449
2021				449
2022				449
2023				449
2024				467
Thereafter				17,303
Total lease payments				19,566
Less discounting for present value and other adjustments				(19,566)
Finance Lease, Liability				$ 0
Capital Lease Obligations	$ 30,700
Payments to Acquire Assets, Investing Activities	$ 30,700	$ 30,704	$ 128,526

Leases Lessor, Operating Leases

Leases Lessor, Operating Leases, Payments to be Received (Details) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
Lessor, Operating Lease, Payments to be Received, Remainder of Fiscal Year	$ 5,613
Lessor, Operating Lease, Payments to be Received, Two Years	3,773
Lessor, Operating Lease, Payments to be Received, Three Years	3,773
Lessor, Operating Lease, Payments to be Received, Four Years	3,773
Lessor, Operating Lease, Payments to be Received, Five Years	3,773
Lessor, Operating Lease, Payments to be Received, Thereafter	3,580
Lessor, Operating Lease, Payments to be Received	$ 24,285

Leases Schedule of Future Minim

Leases Schedule of Future Minimum Lease Payments for Operating and Capital Leases (Details) $ in Thousands	Dec. 31, 2018USD ($)
Leases [Abstract]
2019	$ 1,074
2020	922
2021	483
2022	240
2023	147
Thereafter	364
Total	3,230
2019	449
2020	449
2021	449
2022	449
2023	449
Thereafter	17,770
Total	$ 20,015

Leases - Additional Information

Leases - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Option to Extend	Certain of our lease agreements contain options to extend or early terminate the agreement. The lease term used to calculate the lease asset and liability at commencement includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. When determining whether it is reasonably certain that we will exercise an option at commencement, we consider various economic factors, including operating strategies, the nature, length, and underlying terms of the agreement, as well as the uncertainty of the condition of leased equipment at the end of the lease term. Based on these determinations, we generally determine that the exercise of renewal options would not be reasonably certain in determining the expected lease term.
Operating Lease, Cost	$ 1.6	$ 0.8	$ 9.1
Operating Lease, Payments	1.5
Operating Lease, Lease Income, Lease Payments	$ 9.4	10.9	3.8
Maximum
Lessee, Lease, Description [Line Items]
Lessee, Finance Lease, Term of Contract	39 years
Tallgrass Interstate Gas Transmission, LLC (TIGT)
Lessee, Lease, Description [Line Items]
Operating Lease, Lease Income, Lease Payments	$ 0.7	$ 0.8	$ 0.8

Commitments and Contingencies_2

Commitments and Contingencies - Other Commitments (Details) $ in Thousands	Dec. 31, 2019USD ($)
Commitments and Contingencies Disclosure [Abstract]
2020	$ 16,260
2021	6,618
2022	5,753
2023	4,823
2024	2,141
Thereafter	20,255
Total Other Purchase Obligations	$ 55,850

Commitments and Contingencies_3

Commitments and Contingencies - Additional Information - (Details) $ in Millions	Dec. 31, 2019USD ($)
Commitments and Contingencies Disclosure [Abstract]
Commitments for Future Capital Expenditures	$ 25.5

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share [Abstract]
Net income (loss) attributable to TGE	$ 54,079	$ 72,524	$ 71,619	$ 50,587	$ 59,779	$ 59,550	$ 1,063	$ 16,735	$ 248,809	$ 137,127	$ (128,729)
Basic weighted average Class A Shares outstanding									174,816	107,586	58,076
Basic net income (loss) per Class A share	$ 0.30	$ 0.40	$ 0.40	$ 0.31	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ 1.42	$ 1.27	$ (2.22)
Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares									$ 1,137	$ 2,108	$ 0
Net income (loss) attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares									$ 249,946	$ 139,235	$ (128,729)
Equity Participation Shares equivalent shares									1,684	2,231	0
Diluted weighted average Class A Shares outstanding									176,500	109,817	58,076
Diluted net income (loss) per Class A share	$ 0.30	$ 0.40	$ 0.40	$ 0.31	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ 1.42	$ 1.27	$ (2.22)

Major Customers and Concentra_3

Major Customers and Concentration of Credit Risk (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Concentration Risk [Line Items]
Total Revenues	$ 232,963	$ 226,709	$ 211,524	$ 197,352	$ 220,256	$ 200,320	$ 193,589	$ 179,094	$ 868,548	$ 793,259	$ 655,898
Continental Resources
Concentration Risk [Line Items]
Total Revenues									$ 85,400	$ 81,900	$ 100,200
Concentration Risk, Percentage									10.00%	10.00%	15.00%
Natural Gas Transportation
Concentration Risk [Line Items]
Concentration Risk, Percentage									55.00%
Crude Oil Transportation
Concentration Risk [Line Items]
Concentration Risk, Percentage									80.00%
Gathering, Processing & Terminalling
Concentration Risk [Line Items]
Concentration Risk, Percentage									50.00%

Equity- Based Compensation - Sc

Equity- Based Compensation - Schedule of Share-based Compensation (Details)	Mar. 11, 2019$ / shares	Jun. 30, 2018	Dec. 31, 2019$ / sharesshares	Dec. 31, 2018$ / sharesshares	Dec. 31, 2017$ / sharesshares	Dec. 31, 2016$ / 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			3,883,000	3,049,644	224,998	205,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | shares			3,204,850	1,138,200	30,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | shares			(2,316,294)	(20,664)	(10,002)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period | shares			(55,200)	(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			$ 17.85	$ 18.25	$ 25.91	$ 25.83
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares			18.14	17.01	23.66
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ / shares	$ (18.82)		(18.75)	(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			$ (17.18)	$ (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) $ / shares in Units, $ in Millions	Mar. 11, 2019$ / sharesshares	Jun. 30, 2018	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / shares	Dec. 31, 2017USD ($)$ / shares	Aug. 02, 2018shares	May 12, 2015shares
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Exchange Ratio		2
Share-based Payment Arrangement, Expense | $			$ 31.6	$ 7.6	$ 1.6
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount | $			$ 60
Weighted average period in which compensation cost related to nonvested EPUs expected to be recognized			3 years 8 months 12 days
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number	1,092,637		1,478,986
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ / shares	$ 18.82		$ 18.75	$ 19.19	$ 14.26
Share-based Payment Arrangement, Accelerated Cost | $			$ 12.5
Share-based compensation, Shares Withheld for Taxes	543,909		707,560
Maximum
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized							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						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, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Current Federal Tax Expense	$ 728
Federal income tax	65,009	$ 41,585	$ 200,787
State income tax	4,856	14,124	7,671
Deferred income tax expense	69,865	55,709	208,458
Income tax expense	$ 70,593	$ 55,709	$ 208,458

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Contingency [Line Items]
Net income before tax									$ 519,148	$ 523,380	$ 432,443
Net income attributable to noncontrolling interests	$ (37,365)	$ (55,965)	$ (54,611)	$ (51,805)	$ (65,166)	$ (59,162)	$ (108,638)	$ (97,578)	(199,746)	(330,544)	(352,714)
Income Loss From Continuing Operations Before Income Taxes Extraordinary Items But After Deducting Income And Taxes Attributable To Noncontrolling Interest									$ 319,402	$ 192,836	$ 79,729
Federal statutory income tax rate									21.00%	21.00%	35.00%
Income tax at statutory rate									$ 67,074	$ 40,496	$ 27,905
State income taxes, net of federal benefit									8,413	5,419	2,392
Change in tax rate										172,900
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount									(4,771)	0	3,926
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount									(1,337)	1,089
Total income tax expense before change in tax legislation									70,593	55,709	35,576
Income tax expense									$ 70,593	$ 55,709	$ 208,458
Effective tax rate									13.60%	10.60%	48.20%
State and Local Jurisdiction
Income Tax Contingency [Line Items]
Change in tax rate									$ 1,214	$ 8,705	$ 1,353
US Treasury and Government
Income Tax Contingency [Line Items]
Change in tax rate									0	0	172,037
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount									$ 0	$ 0	$ 845

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Investment in Subsidiaries	$ 149,336	$ 198,290
Deferred Tax Assets, Operating Loss Carryforwards	168,866	80,012
Deferred Tax Assets, Gross	318,202	278,302
Deferred Tax Assets, Valuation Allowance	0	(4,771)
Deferred Tax Assets, Net	318,202	273,531
Deferred Tax Liabilities, Investment in Noncontrolled Affiliates	523	817
Deferred Tax Liabilities, Property, Plant and Equipment	8,207
Deferred Tax Liabilities, Net	$ 8,730	$ 817

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Mar. 11, 2019	Jun. 14, 2018	May 12, 2015
Operating Loss Carryforwards [Line Items]
Deferred tax asset	$ 318,202,000	$ 273,531,000		$ 115,400,000	$ 15,400,000	$ 445,200,000
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	(4,771,000)	0	$ 3,926,000
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ 172,900,000
US Treasury and Government
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 697,600,000
Common Class A
Operating Loss Carryforwards [Line Items]
Conversion of Stock, Shares Issued	21,751,018	2,821,332

Regulatory Matters (Details)

Regulatory Matters (Details)	12 Months Ended
	Dec. 31, 2019Bcf / dmi
Regulatory Matters [Line Items]
Capacity Enhancement | Bcf / d	0.8
Cheyenne Connector, LLC
Regulatory Matters [Line Items]
Miles of Pipeline | mi	70
Size of Pipeline	36

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

Jun. 17, 2014USD ($)

Jan. 31, 2017bbl

Dec. 31, 2019USD ($)energy_per_duration

Dec. 31, 2018USD ($)mi

Dec. 31, 2017USD ($)

Dec. 31, 2016Bcf / d

Dec. 31, 2015mi

Dec. 31, 2017USD ($)

Dec. 31, 2017USD ($)

Apr. 14, 2016USD ($)

Loss Contingencies [Line Items]

Letters of Credit Draw

$ 16,200,000

Environmental accruals

$ 6,300,000

$ 7,400,000

Document Period End Date

Dec. 31, 2019

Insurance Recoveries

$ 5,100,000

Payments for Environmental Liabilities

$ 100,000

Environmental Remediation Expense

$ 21,000,000

$ 21,800,000

Contributions from TD

$ 2,301,000

Aggregate cost of crack tool runs

$ 18,000,000

Crude Oil Spilled or Leaked | bbl

10,000

Crude oil recovered | bbl

9,000

Rockies Express Pipeline LLC

Loss Contingencies [Line Items]

Firm Transportation MDQ | energy_per_duration

50,000

Excise and Sales Taxes

$ 15,800,000

Excise Tax Paid

12,300,000

Accrued taxes

3,500,000

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

Contributions from TD

20,000,000

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

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

EM Energy Ohio, LLC | Rockies Express Pipeline LLC

Loss Contingencies [Line Items]

Other Income

$ 13,900,000

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Total Revenues	$ 232,963	$ 226,709	$ 211,524	$ 197,352	$ 220,256	$ 200,320	$ 193,589	$ 179,094	$ 868,548	$ 793,259	$ 655,898
TGE
Segment Reporting Information [Line Items]
Total Revenues									868,548	793,259	655,898
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues									137,573	135,798	134,327
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues									428,766	405,135	353,898
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues									302,209	252,326	167,673
TGE | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues									0	0	0
TGE | Operating Segments
Segment Reporting Information [Line Items]
Total Revenues									962,294	864,578	691,806
TGE | Operating Segments | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues									139,752	140,459	141,021
TGE | Operating Segments | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues									486,647	444,454	364,574
TGE | Operating Segments | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues									335,895	279,665	186,211
TGE | Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues									0	0	0
TGE | Inter-Segment
Segment Reporting Information [Line Items]
Total Revenues									(93,746)	(71,319)	(35,908)
TGE | Inter-Segment | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues									(2,179)	(4,661)	(6,694)
TGE | Inter-Segment | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues									(57,881)	(39,319)	(10,676)
TGE | Inter-Segment | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues									(33,686)	(27,339)	(18,538)
TGE | Inter-Segment | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues									$ 0	$ 0	$ 0

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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Equity in earnings of unconsolidated investments									$ 325,385	$ 306,819	$ 237,110
Loss (gain) on disposal of assets									(373)	11,043	599
Interest expense, net									161,407	133,319	89,348
Depreciation, Depletion and Amortization, Nonproduction									(128,825)	(110,862)	(90,800)
Proceeds from Equity Method Investment, Distribution									(326,018)	(306,934)	(237,192)
Share-based Payment Arrangement, Noncash Expense									(31,293)	(10,665)	(8,898)
Loss on debt retirement										2,200
Income tax expense									(70,593)	(55,709)	(208,458)
Net income attributable to noncontrolling interests	$ 37,365	$ 55,965	$ 54,611	$ 51,805	$ 65,166	$ 59,162	$ 108,638	$ 97,578	199,746	330,544	352,714
Net income (loss) attributable to TGE	$ 54,079	$ 72,524	$ 71,619	$ 50,587	$ 59,779	$ 59,550	$ 1,063	$ 16,735	248,809	137,127	(128,729)
TGE
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Net income (loss) attributable to TGE									248,809	137,127	(128,729)
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									538,800	372,973	178,802
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									324,430	231,183	145,663
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									145,769	71,601	13,381
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									(12,666)	(21,321)	(37,591)
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									543,507	377,224	180,978
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									344,333	239,330	140,785
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									121,159	59,203	16,083
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									(12,666)	(21,321)	(37,591)
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									(4,707)	(4,251)	(2,176)
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									(19,903)	(8,147)	4,878
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									24,610	12,398	(2,702)
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									325,385	237,197	66,922
Loss (gain) on disposal of assets									(354)	4,630	189
Non-cash (loss) gain related to derivative instrument									(272)	3,340	(64)
Other non-cash gain									724
Gain on remeasurement of unconsolidated investment									0	0	2,744
Interest expense, net									(161,429)	(95,465)	(29,403)
Depreciation, Depletion and Amortization, Nonproduction									(127,503)	(74,998)	(26,131)
Proceeds from Equity Method Investment, Distribution									(470,981)	(302,364)	(86,551)
Share-based Payment Arrangement, Noncash Expense									(31,563)	(8,634)	(2,682)
Deficiency Payments									(16,992)	(14,443)	(7,701)
Loss on debt retirement									0	2,245	0
Income tax expense									(70,578)	(55,709)	(208,458)
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									$ (193,961)	$ (208,618)	$ (137,849)

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Capital expenditures	$ 285,653	$ 368,873	$ 145,144
TGE
Segment Reporting Information [Line Items]
Capital expenditures	285,653	368,873	145,144
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Capital expenditures	86,892	112,529	16,705
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Capital expenditures	94,363	65,745	57,022
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Capital expenditures	96,168	185,732	71,417
TGE | Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 8,230	$ 4,867	$ 0

Reporting Segments - Summary _4

Reporting Segments - Summary of TGE's Segment Information of Unconsolidated Investments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Unconsolidated investments	$ 2,006,219	$ 1,861,686
TGE
Segment Reporting Information [Line Items]
Unconsolidated investments	2,006,219	1,861,686
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Unconsolidated investments	1,811,051	1,794,987
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Unconsolidated investments	164,773	35,467
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Unconsolidated investments	$ 30,395	$ 31,232

Reporting Segments - Summary _5

Reporting Segments - Summary of TGE's Segment Information of Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Assets	$ 6,214,086	$ 5,893,509
TGE
Segment Reporting Information [Line Items]
Assets	6,214,086	5,893,509
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Assets	2,554,513	2,606,696
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Assets	1,734,278	1,423,740
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Assets	1,693,474	1,522,559
TGE | Corporate and Other
Segment Reporting Information [Line Items]
Assets	$ 231,821	$ 340,514

Reporting Segments - Additional

Reporting Segments - Additional Information (Details) - Segment	12 Months Ended
	Dec. 31, 2019	Jan. 01, 2019	Apr. 01, 2018
Segment Reporting Information [Line Items]
Number of Reportable Segments	3
Equity interest ownership percentage	20.00%
Powder River Gateway
Segment Reporting Information [Line Items]
Equity interest ownership percentage	51.00%	51.00%
Rockies Express Pipeline LLC
Segment Reporting Information [Line Items]
Equity interest ownership percentage	75.00%
Pawnee Terminal
Segment Reporting Information [Line Items]
Equity interest ownership percentage	51.00%		51.00%

Selected Quarterly Financial _3

Selected Quarterly Financial Data (Unaudited) - (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Selected Quarterly Financial Data (Unaudited) [Abstract]
Total revenues	$ 232,963	$ 226,709	$ 211,524	$ 197,352	$ 220,256	$ 200,320	$ 193,589	$ 179,094	$ 868,548	$ 793,259	$ 655,898
Operating income	86,834	105,866	89,596	70,464	99,359	90,084	79,275	81,913	352,760	350,631	271,847
Net income	91,444	128,489	126,230	102,392	124,945	118,712	109,701	114,313	448,555	467,671	223,985
Net income attributable to noncontrolling interests	37,365	55,965	54,611	51,805	65,166	59,162	108,638	97,578	199,746	330,544	352,714
Net income (loss) attributable to TGE	$ 54,079	$ 72,524	$ 71,619	$ 50,587	$ 59,779	$ 59,550	$ 1,063	$ 16,735	$ 248,809	$ 137,127	$ (128,729)
Basic net income (loss) per Class A share	$ 0.30	$ 0.40	$ 0.40	$ 0.31	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ 1.42	$ 1.27	$ (2.22)
Diluted net income (loss) per Class A share	$ 0.30	$ 0.40	$ 0.40	$ 0.31	$ 0.38	$ 0.38	$ 0.02	$ 0.29	$ 1.42	$ 1.27	$ (2.22)

Uncategorized Items - tge201912

Label	Element	Value
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 44,131,000
Noncontrolling Interest [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	39,543,000
Common Class A [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	4,588,000
Common Class B [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 0