10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended March 31, 2019

or

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

Commission file number 001-37365

Tallgrass Energy, LP

(Exact name of registrant as specified in its charter)

(913) 928-6060

(Registrant's Telephone Number, Including Area Code)

Delaware	47-3159268
(State or other Jurisdiction of Incorporation or Organization)	(IRS Employer Identification Number)
4200 W. 115th Street, Suite 350
Leawood, Kansas	66211
(Address of Principal Executive Offices)	(Zip Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).     Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer", "accelerated filer", "smaller reporting company", and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨
		Emerging growth company	¨

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

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

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol	Name of each exchange on which registered
Class A Shares Representing Limited Partner Interests	TGE	New York Stock Exchange

On May 7, 2019, the Registrant had 179,197,416 Class A shares and 102,136,875 Class B shares outstanding.

TALLGRASS ENERGY, LP

TABLE OF CONTENTS

PART 1—FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
CONDENSED CONSOLIDATED BALANCE SHEETS	1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME	2
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY	3
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	4
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	6
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3. Quantitative and Qualitative Disclosures About Market Risk	43
Item 4. Controls and Procedures	44
PART II - OTHER INFORMATION	45
Item 1. Legal Proceedings	45
Item 1A. Risk Factors	45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3. Defaults Upon Senior Securities	45
Item 4. Mine Safety Disclosures	45
Item 5. Other Information	46
Item 6. Exhibits	46
SIGNATURES	47

Glossary of Common Industry and Measurement Terms

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

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

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

BBtu: one billion British Thermal Units.

Bcf: one billion cubic feet.

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

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

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

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

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

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

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

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

EPA: the United States Environmental Protection Agency.

FERC: the United States Federal Energy Regulatory Commission.

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

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

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

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

GHGs: greenhouse gases.

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

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

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

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

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

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

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

MMBtu: one million British Thermal Units.

Mcf: one thousand cubic feet.

MDth: one thousand dekatherms.

MMcf: one million cubic feet.

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

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

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

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

NYMEX: New York Mercantile Exchange.

NYSE: New York Stock Exchange.

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

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

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

Pipeline loss allowance (or PLA): Crude oil collected from customers under certain crude oil transportation arrangements.

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

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

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

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

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

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

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

TBtu: one trillion British Thermal Units.

Tcf: one trillion cubic feet.

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

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

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

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

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

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

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

PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31, 2019		December 31, 2018
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	15,042	$	9,596
Accounts receivable, net	227,284		236,097
Inventories	27,954		34,316
Prepayments and other current assets	18,219		11,816
Total Current Assets	288,499		291,825
Property, plant and equipment, net	2,750,375		2,802,429
Goodwill	421,983		421,983
Intangible assets, net	223,707		227,103
Unconsolidated investments	1,988,797		1,861,686
Deferred tax asset	379,422		273,531
Deferred charges and other assets	16,442		14,952
Total Assets	$	6,069,225	$	5,893,509
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	187,321	$	201,512
Accrued taxes	26,962		20,734
Accrued interest	12,534		39,217
Accrued liabilities	9,975		23,287
Deferred revenue	123,184		111,095
Other current liabilities	44,651		42,910
Total Current Liabilities	404,627		438,755
Long-term debt, net	3,331,716		3,205,958
Other long-term liabilities and deferred credits	33,118		31,688
Total Long-term Liabilities	3,364,834		3,237,646
Commitments and Contingencies
Equity:
Class A Shareholders (178,104,779 and 156,311,986 shares outstanding at March 31, 2019 and December 31, 2018, respectively)	1,890,345		1,725,537
Class B Shareholders (102,136,875 and 123,887,893 shares outstanding at March 31, 2019 and December 31, 2018, respectively)	—		—
Total Partners' Equity	1,890,345		1,725,537
Noncontrolling interests (a)	409,419		491,571
Total Equity	2,299,764		2,217,108
Total Liabilities and Equity	$	6,069,225	$	5,893,509

^(a)  See Note 10 - Partnership Equityfor a complete description of our noncontrolling interests.

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

1

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three Months Ended March 31,
	2019			2018
	(in thousands, except per unit amounts)
Revenues:
Crude oil transportation services	$	95,156		$	84,738
Natural gas transportation services	33,516			32,196
Sales of natural gas, NGLs, and crude oil	38,864			38,145
Processing and other revenues	29,816			24,015
Total Revenues	197,352			179,094
Operating Costs and Expenses:
Cost of sales	19,285			26,351
Cost of transportation services	15,072			10,420
Operations and maintenance	18,046			16,399
Depreciation and amortization	31,001			26,123
General and administrative	32,272			18,426
Taxes, other than income taxes	10,998			8,879
Loss (gain) on disposal of assets	214			(9,417		)
Total Operating Costs and Expenses	126,888			97,181
Operating Income	70,464			81,913
Other Income (Expense):
Equity in earnings of unconsolidated investments	88,522			68,402
Interest expense, net	(39,705		)	(29,761		)
Other income, net	177			451
Total Other Income (Expense)	48,994			39,092
Net income before tax	119,458			121,005
Deferred income tax expense	(17,066		)	(6,692		)
Net income	102,392			114,313
Net income attributable to noncontrolling interests	(51,805		)	(97,578		)
Net income attributable to TGE	$	50,587		$	16,735
Net income per Class A share:
Basic net income per Class A share	$	0.31		$	0.29
Diluted net income per Class A share	$	0.31		$	0.29
Basic average number of Class A shares outstanding	161,425			58,085
Diluted average number of Class A shares outstanding	162,777			58,210

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

2

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

	Partners' Capital					Noncontrolling Interests			Total Equity
	Class A Shares			Class B Shares
	(in thousands)
Balance at January 1, 2019	$	1,725,537		$	—	$	491,571		$	2,217,108
Net income	50,587			—		51,805			102,392
Dividends paid to Class A shareholders	(81,304		)	—		—			(81,304		)
Distributions to noncontrolling interest	—			—		(66,625		)	(66,625		)
Contributions from noncontrolling interest	—			—		1,282			1,282
Noncash compensation expense	17,120			—		—			17,120
TGE LTIP shares tendered by employees to satisfy tax withholding obligations	(13,260		)	—		—			(13,260		)
Deferred tax asset	123,051			—		—			123,051
Conversion of Class B shares to Class A shares	68,614			—		(68,614		)	—
Balance at March 31, 2019	$	1,890,345		$	—	$	409,419		$	2,299,764
	Partners' Capital					Noncontrolling Interests			Total Equity
	Class A Shares			Class B Shares
	(in thousands)
Balance at January 1, 2018	$	48,613		$	—	$	1,672,566		$	1,721,179
Cumulative effect of ASC 606 implementation	4,588			—		39,543			44,131
Net income	16,735			—		97,578			114,313
Issuance of TEP units to the public, net of offering costs	(5		)	—		(40		)	(45		)
Dividends paid to Class A shareholders	(21,346		)	—		—			(21,346		)
Noncash compensation expense	404			—		2,917			3,321
Acquisition of additional TEP common units from TD	(62,222		)	—		(189,520		)	(251,742		)
Issuance of Tallgrass Equity units	—			—		644,782			644,782
Acquisition of additional 2% membership interest in Pony Express	(5,268		)	—		(44,732		)	(50,000		)
Acquisition of 25.01% membership interest in Rockies Express	34,116			—		74,421			108,537
Consolidation of Deeprock North	—			—		31,843			31,843
Contributions from noncontrolling interest	—			—		183			183
Distributions to noncontrolling interest	—			—		(89,073		)	(89,073		)
Balance at March 31, 2018	$	15,615		$	—	$	2,240,468		$	2,256,083

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

3

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	2019			2018
	(in thousands)
Cash Flows from Operating Activities:
Net income	$	102,392		$	114,313
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	32,799			27,620
Equity in earnings of unconsolidated investments	(88,522		)	(68,402		)
Distributions from unconsolidated investments	87,940			67,059
Deferred income tax expense	17,066			6,692
Noncash compensation expense	17,120			2,814
Other noncash items, net	1,536			(12,024		)
Changes in components of working capital:
Accounts receivable and other	8,985			(12,013		)
Accounts payable and accrued liabilities	(46,186		)	16,354
Deferred revenue	12,125			10,750
Other current assets and liabilities	2,026			(1,671		)
Other operating, net	(3,533		)	108
Net Cash Provided by Operating Activities	143,748			151,600
Cash Flows from Investing Activities:
Capital expenditures	(62,802		)	(58,760		)
Formation of Powder River Gateway joint venture	(37,000		)	—
Contributions to unconsolidated investments	(29,797		)	(8,034		)
Distributions from unconsolidated investments in excess of cumulative earnings	27,158			20,774
Acquisition of BNN North Dakota, net of cash acquired	—			(95,000		)
Sale of Tallgrass Crude Gathering	—			50,046
Acquisition of 38% membership interest in Deeprock North	—			(19,500		)
Other investing, net	15			(12,439		)
Net Cash Used in Investing Activities	(102,426		)	(122,913		)
Cash Flows from Financing Activities:
Borrowings under revolving credit facilities, net	125,000			133,000
Dividends paid to Class A shareholders	(81,304		)	(21,346		)
Distributions to noncontrolling interests	(66,625		)	(89,073		)
TGE LTIP shares tendered by employees to satisfy tax withholding obligations	(13,260		)	—
Acquisition of Pony Express membership interest	—			(50,000		)
Other financing, net	313			394
Net Cash Used in Financing Activities	(35,876		)	(27,025		)
Net Change in Cash and Cash Equivalents	5,446			1,662
Cash and Cash Equivalents, beginning of period	9,596			2,593
Cash and Cash Equivalents, end of period	$	15,042		$	4,255

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

4

	Three Months Ended March 31,
	2019			2018
	(in thousands)
Schedule of Noncash Investing and Financing Activities:
Assets contributed to Powder River Gateway joint venture	$	(86,891	)	$	—
Contribution of 75% membership interest in Iron Horse to Powder River Gateway joint venture	$	(35,613	)	$	—
Accruals for property, plant and equipment	$	18,874		$	1,336
Issuance of Tallgrass Equity units (a)	$	—		$	644,782
Acquisition of Rockies Express membership interest (a)	$	—		$	(393,039	)
Acquisition of additional TEP common units from TD (a)	$	—		$	(251,743	)
Contribution of 38% membership interest in Deeprock North to Deeprock Development	$	—		$	(19,500	)
Issuance of noncontrolling interests in Deeprock Development in exchange for 62% membership interest in Deeprock North	$	—		$	(31,843	)

^(a)  Represents the issuance of Tallgrass Equity units associated with our acquisition of a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units.

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

5

TALLGRASS ENERGY, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. 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 63.55% membership interest as of March 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 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 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: (1) a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System"), (2) natural gas processing facilities in Casper and Douglas, and (3) a natural gas treating facility at West Frenchie Draw. We also provide NGL transportation services in Northeast Colorado and Wyoming. We perform water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, Wyoming, and North Dakota through BNN Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through our 100% membership interest in Tallgrass Terminals, LLC ("Terminals"), which owns and operates crude oil terminals in Colorado, Oklahoma, and Kansas. The Gathering, Processing & Terminalling segment also includes Stanchion Energy, LLC ("Stanchion"), which transacts in crude oil.

6

Blackstone Acquisition

On March 11, 2019, pursuant to the terms of the 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, acquisition vehicles controlled by BIP, collectively, the "Sponsor Entities"), 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"), certain of the Sponsor Entities 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 "Blackstone Acquisition").

As a result of the Blackstone Acquisition, BIP effectively controls our business and affairs through the ownership of 100% of the membership interests in our general partner and the exercise of the rights of such sole member. Additionally, the Sponsor Entities collectively held an approximate 43.8% economic interest in us as of March 31, 2019.

2. Summary of Significant Accounting Policies

Basis of Presentation

These condensed consolidated financial statements and related notes for the three months ended March 31, 2019 and 2018 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of accounting principles generally accepted in the United States of America ("GAAP") for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three months ended March 31, 2019 and 2018 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.

Our financial results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019. The accompanying condensed consolidated interim financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2018 ("2018 Form 10-K") filed with the SEC on February 8, 2019.

The condensed 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.

Use of Estimates

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

Income Taxes

During the three months ended March 31, 2019, we recognized an additional deferred tax asset of $123.1 million upon exercise of the Exchange Right, as discussed in Note 10 – Partnership Equity, with respect to 21,751,018 Class B shares to Class A shares in connection with the Blackstone Acquisition discussed in Note 1 – Description of Business.

As a result of the increased income allocated to TGE resulting from our increased ownership in TEP following the merger transaction effective June 30, 2018 and the exercise of the Exchange Right effective March 11, 2019, our annual effective tax rate increased from 5.15% for the three months ended March 31, 2018 to 14.77% for the three months ended March 31, 2019.

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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 in the Codification intended to increase transparency and comparability among organizations by recognizing right-of-use ("ROU") assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

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 ASC 840. Accordingly, we will not recast comparative periods in the condensed 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 practical expedients related to land easements, allowing us to carry forward our accounting treatment for existing land easements as property, plant and equipment, and short-term leases, allowing us to not recognize ROU assets or lease liabilities for leases with a term of 12 months or less.

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 12 – Leases.

3. Acquisitions

Joint Venture with Silver Creek

In February 2018, we entered into an agreement with Silver Creek Midstream, LLC ("Silver Creek") to form Iron Horse Pipeline, LLC ("Iron Horse"), which owns the Iron Horse Pipeline. Effective January 1, 2019, the joint venture between us and Silver Creek was expanded through contributions to Powder River Gateway, a newly formed entity. We contributed our 75% membership interest in Iron Horse, $37 million in cash, and various other assets, including terminal facilities under construction in Guernsey, Wyoming. Silver Creek contributed the PRE Pipeline and related terminal facilities in Guernsey, Wyoming, as well as their 25% membership interest in Iron Horse. Following the expansion of the joint venture, 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 in Powder River Gateway. As the 51% membership interest does not represent a controlling interest in Powder River Gateway, our investment in Powder River Gateway is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the condensed consolidated balance sheets.

Acquisition of Plaquemines Liquids Terminal, LLC

In November 2018, we entered into a joint venture agreement with Drexel Hamilton Infrastructure Fund I, L.P. ("DHIF") to jointly-own Plaquemines Liquids Terminal, LLC ("PLT"). PLT was formed with the intention of entering into agreements to develop a storage and terminalling facility. If developed, the facility is expected to be capable of offering up to 20 million barrels of storage for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers ("VLCC") vessels for international delivery. In connection with our acquisition of a 100% preferred membership interest and a 80% common membership interest in PLT, we recognized liabilities related 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 condensed 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.

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4. Related Party Transactions

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

	Three Months Ended March 31,
	2019		2018
	(in thousands)
Processing and other revenues (1)	$	1,903	$	1,896

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

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

	March 31, 2019		December 31, 2018
	(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	2,839	$	3,447
Powder River Gateway, LLC	512		—
Pawnee Terminal, LLC	129		115
Iron Horse Pipeline, LLC	—		186
Total receivable from related parties	$	3,480	$	3,748

Gas imbalances with affiliated shippers are as follows:

	March 31, 2019		December 31, 2018
	(in thousands)
Affiliate gas imbalance receivables	$	19	$	19
Affiliate gas imbalance payables	$	2,309	$	742

5. Inventory

The components of inventory at March 31, 2019 and December 31, 2018 consisted of the following:

	March 31, 2019		December 31, 2018
	(in thousands)
Crude oil	$	16,803	$	23,205
Materials and supplies	7,666		8,206
Gas in underground storage	2,413		2,740
Natural gas liquids	1,072		165
Total inventory	$	27,954	$	34,316

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6. Property, Plant and Equipment

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

	March 31, 2019			December 31, 2018
	(in thousands)
Crude oil pipelines	$	1,309,763		$	1,313,976
Gathering, processing and terminalling assets	895,552			889,168
Natural gas pipelines	615,495			607,343
General and other (1)	163,206			180,299
Construction work in progress	171,960			191,994
Accumulated depreciation and amortization	(405,601		)	(380,351		)
Total property, plant and equipment, net	$	2,750,375		$	2,802,429

⁽¹⁾  Includes approximately $30.7 million of land associated with the PLT capital lease as discussed in Note 12 – Leases.

7. Investments in Unconsolidated Affiliates

Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our condensed consolidated balance sheets. During the three months ended March 31, 2019, we recognized equity in earnings associated with our 75% membership interest in Rockies Express of $86.2 million, inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $113.4 million and $17.3 million, respectively.

Summarized financial information for Rockies Express is as follows:

	Three Months Ended March 31,
	2019		2018
	(in thousands)
Revenue	$	230,761	$	230,058
Operating income	$	132,410	$	128,678
Net income to Members	$	103,609	$	90,968

8. Risk Management

We enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We have a comprehensive risk management policy 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, including establishing and monitoring exposure limits.

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.

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Fair Value of Derivative Contracts

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

	Balance Sheet Location	March 31, 2019		December 31, 2018
		(in thousands)
Crude oil derivative contracts (1)	Prepayments and other current assets	$	1,761	$	3,526
Crude oil derivative contracts (2)	Other current liabilities	$	1,129	$	1,642

⁽¹⁾  As of March 31, 2019 and December 31, 2018, the amount shown represents the fair value of crude oil derivative contracts for the forward purchase of 2,135,700 and 2,105,146 barrels of crude oil, respectively, consisting of fixed price and floating price contracts, which will settle throughout 2019.

⁽²⁾  As of March 31, 2019 and December 31, 2018, the amount shown represents the fair value of crude oil derivative contracts for the forward sale of 1,793,000 and 1,274,500 barrels of crude oil, respectively, consisting of fixed price and floating price contracts, which will settle 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 three months ended March 31,2019 and 2018:

	Location of gain recognized in income on derivatives	Amount of gain recognized in income on derivatives
		Three Months Ended March 31,
		2019		2018
		(in thousands)
Crude oil derivative contracts	Sales of natural gas, NGLs, and crude oil	$	11,473	$	4,295

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 March 31, 2019 was:

	Asset Position
	(in thousands)
Gross	$	1,761
Netting agreement impact	—
Cash collateral held	—
Net exposure	$	1,761

As of March 31, 2019, we had $1.1 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.

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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 March 31, 2019 and December 31, 2018, based on the fair value hierarchy:

			Asset Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of March 31, 2019:
Crude oil derivative contracts	$	1,761	$	—	$	1,761	$	—
As of December 31, 2018:
Crude oil derivative contracts	$	3,526	$	—	$	3,526	$	—
			Liability Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of March 31, 2019:
Crude oil derivative contracts	$	1,129	$	—	$	1,129	$	—
As of December 31, 2018:
Crude oil derivative contracts	$	1,642	$	—	$	1,642	$	—

9. Long-term Debt

Our long-term debt is held at TEP and consisted of the following at March 31, 2019 and December 31, 2018:

	March 31, 2019			December 31, 2018
	(in thousands)
Revolving credit facility	$	1,349,000		$	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)	(20,575		)	(21,421		)
Plus: Unamortized premium on 2028 Notes	3,291			3,379
Total long-term debt, net	$	3,331,716		$	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 is presented in noncurrent assets on our condensed consolidated balance sheets.

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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, dated as of September 26, 2018, among the Issuers, the Guarantors and Trustee, (ii) the Indenture governing the 5.50% Senior Notes due 2024, 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, 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 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.

As of March 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 our revolving credit facility as of March 31, 2019 and December 31, 2018:

	March 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	(1,349,000		)	(1,224,000		)
Less: Letters of credit issued under the revolving credit facility	(94		)	(94		)
Available capacity under the revolving credit facility	$	900,906		$	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.

In the Consent and Amendment, the required lenders under the Credit Agreement (i) consented to the 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 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 Blackstone Acquisition.

As of March 31, 2019, TEP was in compliance with the covenants required under its revolving credit facility. As of March 31, 2019, the weighted average interest rate on outstanding borrowings under the revolving credit facility was 4.00%. During the three months ended March 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 4.52%.

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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 condensed consolidated balance sheets as of March 31, 2019 and December 31, 2018, but for which fair value is disclosed:

	Fair Value
	Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Carrying Amount
	(in thousands)
As of March 31, 2019:
Revolving credit facility	$	—	$	1,349,000	$	—	$	1,349,000	$	1,349,000
2023 Notes	$	—	$	504,325	$	—	$	504,325	$	494,892
2024 Notes	$	—	$	771,923	$	—	$	771,923	$	741,565
2028 Notes	$	—	$	754,253	$	—	$	754,253	$	746,259
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 March 31, 2019 and December 31, 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 March 31, 2019.

10. 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)
March 31, 2019	May 15, 2019 (1)	$	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

⁽¹⁾  The dividend announced on April 11, 2019 for the first quarter of 2019 will be paid on May 15, 2019 to Class A shareholders of record at the close of business on April 30, 2019.

Exchange Rights

Our current Class B shareholders (collectively, the "Exchange Right Holders") own an equal number of Tallgrass Equity units. The Exchange Right Holders, and any permitted transferees of their Tallgrass Equity units, each have the right to exchange all or a portion of their Tallgrass Equity units for Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us. Upon such exchange, we will cancel the Class B shares received from the exercising party. During the three months ended March 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.

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Following the Blackstone Acquisition that closed on March 11, 2019 discussed in Note 1 – Description of Business, the Exchange Rights Holders currently consist of certain of the Sponsor Entities and certain members of our management.

Noncontrolling Interests

As of March 31, 2019, noncontrolling interests in our subsidiaries consisted of a 36.45% 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, LLC ("Deeprock Development"), an approximate 25% membership interest in BNN West Texas, LLC ("West Texas"), and a 37% membership interest in BNN Colorado Water, LLC ("BNN Colorado"). During the three months ended March 31, 2019, we recognized contributions from and distributions to noncontrolling interests of $1.3 million and $66.6 million, respectively. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $64.4 million and distributions to Deeprock Development and West Texas noncontrolling interests of $2.2 million.

During the three months ended March 31, 2018, we recognized contributions from and made distributions to noncontrolling interests of $0.2 million and $89.1 million, respectively. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $51.3 million, Tallgrass Equity distributions to the Exchange Right Holders of $36.4 million and distributions to Deeprock Development and Pony Express noncontrolling interests of $1.3 million.

Other Contributions and Distributions

During the three months ended March 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.

Share-Based Compensation

The 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 condensed consolidated statements of income during the three months ended March 31, 2019. In addition, 1,767,100 Equity Participation Shares with a weighted average grant date fair value of $15.20 were granted during the three months ended March 31, 2019.

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11. Revenue from Contracts with Customers

Disaggregated Revenue

A summary of our revenue by line of business is as follows:

	Three Months Ended March 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	$	—	$	95,277	$	—	$	—		$	95,277
Natural gas transportation - firm service	32,521		—		—		(396		)	32,125
Water business services	—		—		18,286		—			18,286
Natural gas gathering & processing fees	—		—		6,080		—			6,080
All other (1)	3,321		14,507		3,520		(17,034		)	4,314
Total service revenue	35,842		109,784		27,886		(17,430		)	156,082
Natural gas liquids sales	—		—		16,871		—			16,871
Natural gas sales	—		—		10,401		—			10,401
Crude oil sales	—		—		119		—			119
Total commodity sales revenue	—		—		27,391		—			27,391
Total revenue from contracts with customers	35,842		109,784		55,277		(17,430		)	183,473
Other revenue (2)	—		—		18,757		(4,878		)	13,879
Total revenue (3)	$	35,842	$	109,784	$	74,034	$	(22,308	)	$	197,352

	Three Months Ended March 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	$	—	$	84,738	$	—	$	—		$	84,738
Natural gas transportation - firm service	33,334		—		—		(1,883		)	31,451
Water business services	—		—		13,204		—			13,204
Natural gas gathering & processing fees	—		—		5,044		—			5,044
All other (1)	2,630		3,319		5,706		(6,088		)	5,567
Total service revenue	35,964		88,057		23,954		(7,971		)	140,004
Natural gas liquids sales	—		—		23,609		—			23,609
Natural gas sales	238		—		7,847		—			8,085
Crude oil sales	—		1,909		247		—			2,156
Total commodity sales revenue	238		1,909		31,703		—			33,850
Total revenue from contracts with customers	36,202		89,966		55,657		(7,971		)	173,854
Other revenue (2)	—		—		8,181		(2,941		)	5,240
Total revenue (3)	$	36,202	$	89,966	$	63,838	$	(10,912	)	$	179,094

⁽¹⁾  Includes revenue from crude oil transportation walk up shippers, crude oil terminal services, interruptible natural gas transportation and storage, and natural gas park and loan service.

⁽²⁾  Includes lease and derivative revenue not subject to ASC 606.

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⁽³⁾  Excludes revenue recognized at unconsolidated investments, including $230.8 million and $230.1 million of revenue recognized at Rockies Express for the three months ended March 31, 2019 and 2018, respectively. See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express.

Performance Obligations

On March 31, 2019, we had $1.5 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 the remainder of 2019 and future periods as follows (in thousands):

Year	Estimated Revenue
2019 – remaining	$	439,404
2020	367,732
2021	175,919
2022	171,033
2023	150,810
Thereafter	240,961
Total	$	1,545,859

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.

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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 condensed consolidated balance sheets. Revenue is generally billed and collected monthly based on services provided or commodity volumes sold. In our Crude Oil Transportation segment, we recognize shipper deficiencies, or deferred revenue, for barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers' agreed upon destination point. These shipper deficiencies are charged at the committed tariff rate per barrel and recorded as a contract liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes remote. We also recognize contract liabilities, in the form of deferred revenue, under certain water business services contracts in the Gathering, Processing & Terminalling segment. Contract balances were as follows:

	March 31, 2019		December 31, 2018
	(in thousands)
Accounts receivable from contracts with customers	$	79,855	$	80,935
Other accounts receivable (1)	143,949		151,414
Receivable from related parties	3,480		3,748
Accounts receivable, net	$	227,284	$	236,097
Deferred revenue from contracts with customers (2)	$	123,184	$	111,095

⁽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.

⁽²⁾  Revenue recognized during the three months ended March 31, 2019 that was included in the deferred revenue balance at the beginning of the period was $1.6 million. This revenue primarily represented the utilization of shipper deficiencies at Pony Express.

12. Leases

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 an agreement 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 most of 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 40 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.

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For the three months ended March 31, 2019, operating lease cost and cash paid included in operating cash flows was $0.2 million. During this period the existing finance lease did not have any lease payments or variable lease cost.

Supplemental information related to our existing leases as of March 31, 2019 was as follows:

	Balance Sheet Location	March 31, 2019
Operating Leases:		(in thousands, except lease term and discount rate)
Operating lease right-of-use assets	Deferred charges and other assets	$	2,171
Current operating lease liabilities	Other current liabilities	$	603
Non-current operating lease liabilities	Other long-term liabilities and deferred credits	$	1,568
Finance Leases:
Finance lease right-of-use asset (1)	Property, plant and equipment, net	$	30,704
Weighted Average Remaining Lease Term:
Operating leases		4.6 years
Finance leases		39.7 years
Weighted Average Discount Rate:
Operating leases		4.63		%
Finance leases		7.01		%

⁽¹⁾ 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 March 31, 2019 were as follows:

Year	Operating Leases			Finance Leases (1)
	(in thousands)
2019 – remaining	$	683		$	449
2020	956			449
2021	506			449
2022	240			449
2023	147			449
Thereafter	364			17,770
Total lease payments	2,896			20,015
Less: discounting for present value and other adjustments	(725		)	(20,015		)
Present value of lease liabilities	$	2,171		$	—

⁽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 recognize expense 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 $2.4 million for the three months ended March 31, 2019 and was recorded as "Processing and other revenues" in the condensed 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 $0.2 million for the three months ended March 31, 2019 and was recorded as "Other income, net" in the condensed consolidated statements of income.

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At March 31, 2019, future minimum rental income under non-cancelable operating leases as the lessor were as follows:

Year	Total
	(in thousands)
2019 - remaining	$	5,850
2020	3,952
2021	3,773
2022	3,773
2023	3,773
Thereafter	7,353
Total	$	28,474

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

13. Net Income per Class A Share

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

Diluted net income per Class A share is determined by dividing net income attributable to TGE by the weighted average number of outstanding diluted Class A shares during the period. For purposes of calculating diluted net income per Class A share, we considered the impact of possible future exercises of the Exchange Right by the Exchange Right Holders on both net income attributable to TGE and the diluted weighted average number of Class A shares outstanding. The Exchange Right Holders refers to the group of persons who collectively own all TGE's outstanding Class B shares and an equivalent number of Tallgrass Equity units. The Exchange Right Holders are entitled to exercise the right to exchange their Tallgrass Equity units (together with an equivalent number of TGE Class B shares) for TGE Class A shares at an exchange ratio of one TGE Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. As of March 31, 2019, the Exchange Right Holders primarily consist of certain of the Sponsor Entities and certain 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 Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other hand. As a result, the exchange of any Class B shares for Class A shares does not have a dilutive effect on basic net income per Class A share. However, for the three months ended March 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.

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The following table illustrates the calculation of net income per Class A share for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018
	(in thousands, except per unit amounts)
Basic Net Income per Class A Share
Net income attributable to TGE	$	50,587	$	16,735
Basic weighted average Class A Shares outstanding	161,425		58,085
Basic net income per Class A share	$	0.31	$	0.29
Diluted Net Income per Class A Share
Net income attributable to TGE	$	50,587	$	16,735
Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares	206		69
Net income attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares	$	50,793	$	16,804
Basic weighted average Class A Shares outstanding	161,425		58,085
Equity Participation Shares equivalent shares	1,352		125
Diluted weighted average Class A Shares outstanding	162,777		58,210
Diluted net income per Class A Share	$	0.31	$	0.29

14. Regulatory Matters

There are no regulatory proceedings challenging the rates of Pony Express and Rockies Express. On May 1, 2019, as further described below, TIGT filed with the FERC a pre–filing settlement that establishes, among other things, settlement rates for supporting/non–contesting participants as defined in the pre–filing settlement. On June 29, 2018, Trailblazer Pipeline Company LLC ("Trailblazer") filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act ("NGA"), as further described below. We have also made certain regulatory filings with the FERC, including the following:

Rockies Express

Cheyenne Hub Enhancement Project - FERC Docket No. CP18-103-000

On March 2, 2018, Rockies Express submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub. Rockies Express filed this certificate application in conjunction with a concurrently filed certificate application by Cheyenne Connector, LLC ("Cheyenne Connector") for the Cheyenne Connector Pipeline Project further described below. The comment period for the Cheyenne Hub Enhancement Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Rockies Express has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment. The application is pending before the FERC.

Rockies Express Form No. 501-G Filing - FERC Docket No. RP19-412-000

On December 6, 2018, Rockies Express submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. On March 20, 2019, the FERC issued an order finding that Rockies Express complied with the reporting requirement and terminated the proceeding.

2019 Annual FERC Fuel Tracking Filing - FERC Docket No. RP19-786-000

On February 28, 2019, in Docket No. RP19-786-000, Rockies Express made its annual fuel and power cost tracker filing. The FERC issued an order accepting the filing on March 29, 2019.

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Cheyenne Connector

Cheyenne Connector Pipeline Project - FERC Docket No. CP18-102-000

On March 2, 2018, Cheyenne Connector, an indirect subsidiary of TGE, submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity to construct and operate a 70-mile 36 inch pipeline to transport natural gas from multiple gas processing plants in Weld County, Colorado to Rockies Express' Cheyenne Hub. The comment period for the Cheyenne Connector Pipeline Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Cheyenne Connector has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment. The application is pending before the FERC.

TIGT

TIGT Form No. 501-G Filing - FERC Docket No. RP19-423-000

On December 6, 2018, TIGT submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. On December 18, 2018, one protest and one set of comments were filed by intervenors in the docket. The filing remains pending before the FERC.

2019 Annual Fuel Tracker Filing - FERC Docket No. RP19-715-000

On February 27, 2019, in Docket No. RP19-715-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2019. The FERC accepted the filing on March 22, 2019.

Pre-Filing Settlement - FERC Docket No. RP19-423-001

On May 1, 2019, TIGT filed a pre-filing settlement that, consistent with Article II.B.1 of the Docket No. RP16-137-000 settlement, satisfies TIGT's mandatory filing requirement under Article IIB.1 of such settlement. The pre-filing settlement establishes, inter alia, settlement rates reflecting an overall decrease to recourse rates, contract extensions for maximum recourse rate firm contracts through May 31, 2023, and a moratorium, as well as requires that TIGT file a new NGA Section 4 general rate case 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.

Trailblazer

General Rate Case Filing - FERC Docket No. RP18-922-000, et seq.

On June 29, 2018, Trailblazer filed a general rate case with the FERC, which satisfies the requirement set forth in the settlement resolving Trailblazer's previous general rate case that Trailblazer file a new general rate case with rates to be effective no later than January 1, 2019. The June 29, 2018 filing reflects an overall increase to Trailblazer's cost of service. In the filing, Trailblazer is proposing to maintain its existing bifurcated firm transportation service rate design as well as its current tracking methodologies for the treatment of Fuel and Lost and Unaccounted For ("FL&U") gas and electric power costs. The proposed rates include an increase in rates on Trailblazer's Existing System Firm Transportation Service. The overall rate increase would be partially offset by a proposed decrease in rates for Expansion System Firm Transportation Service and interruptible services. Trailblazer is also proposing to include a cost recovery mechanism in its tariff to recover future eligible costs related to system safety, integrity, reliability, environmental and cybersecurity issues. Under the NGA and the FERC's regulations, Trailblazer's shippers and other interested parties, including the FERC's Trial Staff, have the right to challenge any aspect of Trailblazer's rate case filing. On July 11, 2018, four protests were filed that challenge various aspects of Trailblazer's rate case filing. FERC action remains pending.

On July 31, 2018, the FERC issued an Order accepting and suspending the rate case filing, and establishing hearing and settlement procedures. In the Order, the FERC approved the as-filed rate decreases for Expansion System Firm Transportation Service, as well as Trailblazer's interruptible services, effective August 1, 2018. The Commission also established a paper hearing to examine the extent to which Trailblazer is entitled to an income tax allowance. All remaining issues, including the proposed rate increases to Existing System Firm Transportation Service have been set for hearing and are accepted effective January 1, 2019, subject to refund. On August 30, 2018, Trailblazer and certain of Trailblazer's shippers filed a request for rehearing of the July 31, 2018 Order, which remains pending before the FERC. Consistent with the July 31, 2018 Order, on August 30, 2018, certain of Trailblazer's shippers and other interested parties filed initial briefs regarding the Income Tax Allowance issue. Trailblazer filed its reply brief regarding the same on September 14, 2018. On November 1, 2018, Trailblazer

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filed a supplement to its reply brief addressing a recent FERC order regarding the appropriate methodology used to calculate return on equity and discussing the impact of such order on Trailblazer's proposed Income Tax Allowance.

On February 21, 2019, the FERC issued an Order stating a preliminary finding that a double recovery appears to result from permitting an income tax allowance for the income tax liability attributable to certain private owners' ownership share in Trailblazer in addition to a discounted cash flow return on equity. The FERC also preliminary found that no double recovery resulted from permitting an income tax allowance for the corporate income tax liability attributable to TGE's ownership share in Trailblazer in addition to a discounted cash flow return on equity. The FERC emphasized that the findings are preliminary and may change based upon subsequent evidence and argument. The FERC ordered that the income tax allowance be addressed at the hearing with the other remaining issues. On February 22, 2019, the Chief Administrative Law Judge issued an order directing the ongoing settlement judge procedures and any subsequent hearing in the proceeding to address all income tax allowance issues. 

On August 28, 2018, the participants attended an initial settlement conference. On November 15, 2018, the participants attended a second settlement conference. On December 31, 2018, Trailblazer filed a motion with the FERC to move the suspended tariff records into effect as of January 1, 2019. In January 2019, the participants attended a third settlement conference. In February 2019, the participants attended a fourth settlement conference. On February 14, 2019, Trailblazer filed its 45-day update. On March 14, 2019, the Chief Administrative Law Judge issued an order terminating settlement judge procedures, designating a Presiding Judge for the purpose of conducting a hearing and issuing an initial decision, establishing Track III procedural time standards for the hearing and directing that a prehearing conference be convened within 15 days of the date of the order. On March 19, 2019, the Presiding Judge issued an order to convene the prehearing conference on March 26, 2019. Following the prehearing conference, on March 28, 2019, the Presiding Judge issued an order establishing a procedural schedule and hearing rules in connection with the Chief Administrative Law Judge's March 28, 2019 order extending the Track III procedural deadlines.

2019 Annual Fuel Tracker Filing - FERC Docket No. RP19-888-000

On March 25, 2019, in Docket No. RP19-888-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2018. The FERC accepted the filing on April 18, 2019.

Pony Express

On January 11, 2019, Pony Express filed with the FERC in Docket No. IS19-145-000 certain changes to its tariffs to incorporate the Sterling origin point in Logan County, Colorado in the published rate schedules, to establish a line fill return rate from the Natoma origin point, and to make minor clarifying edits.

Iron Horse

Petition for Declaratory Order - FERC Docket No. OR19-9-000

On November 9, 2018, Iron Horse filed a Petition for Declaratory Order with the FERC, requesting approval of Iron Horse's proposed rate structures, Committed Shipper rights, and prorationing provisions for shippers and various other aspects of the Transportation Service Agreement for service on the pipeline. The FERC granted the Petition on April 11, 2019.

Baseline Tariff Filing - FERC Docket No. IS19-274-000

On April 1, 2019, Iron Horse filed certain baseline tariffs with the FERC, each with an effective date of May 1, 2019.

15. Legal and Environmental Matters

Legal

In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such 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 March 31, 2019 or December 31, 2018.

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Rockies Express

Ohio Public Utility Excise Tax

The Ohio Tax Commissioner has assessed Rockies Express a public utility excise tax on transactions concerning product that entered and exited Rockies Express within the state of Ohio. This tax applies to gross receipts from all business conducted within the state, but exempts all receipts derived wholly from interstate business. Rockies Express has disputed any obligation to pay Ohio's public utility excise tax, but has paid the taxes as assessed in order to preserve its right to appeal. The dispute is currently pending before the Ohio Supreme Court, with a final decision possible by the end of 2019. It is Rockies Express' position that the relevant statute exempts receipts derived wholly from interstate business from the public utility excise tax. The Ohio Supreme Court and the United States Supreme Court have both held that, once it enters an interstate pipeline, natural gas is moving in "interstate commerce" for the duration of its journey until it is delivered to a local distribution system.

As of March 31, 2019, Rockies Express has paid public utility excise taxes to the state of Ohio totaling $7.1 million and has accrued an additional $4.6 million for amounts expected to be assessed for the period from May 1, 2018 through March 31, 2019. While it is difficult to accurately predict how the Ohio Supreme Court will decide the case, Rockies Express is optimistic about the ultimate outcome and has recorded a $11.7 million asset representing the anticipated refund of the public utility excise taxes paid.

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 $6.8 million and $7.4 million at March 31, 2019 and December 31, 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 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

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.

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TMG

Archibald Booster Station

Tallgrass Midstream Gathering, LLC ("TMG") is currently a party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Archibald Booster Station located in Campbell County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling, and quarterly recovery activities at monitoring wells. The facility is currently in compliance with the WDEQ under the remedy agreement.

Irwin Booster Station

TMG is also party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Irwin Booster Station located in Converse County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling. The facility is currently in compliance with the WDEQ under the remedy agreement.

16. Reportable 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.

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.

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

	Three Months Ended March 31, 2019							Three Months Ended March 31, 2018
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Natural Gas Transportation	$	35,842	$	(414	)	$	35,428	$	36,202	$	(1,858	)	$	34,344
Crude Oil Transportation	109,784		(14,422		)	95,362		89,966		(3,319		)	86,647
Gathering, Processing & Terminalling	74,034		(7,472		)	66,562		63,838		(5,735		)	58,103
Total revenue	$	219,660	$	(22,308	)	$	197,352	$	190,006	$	(10,912	)	$	179,094

	Three Months Ended March 31, 2019									Three Months Ended March 31, 2018
Tallgrass Equity Adjusted EBITDA:	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA
	(in thousands)
Natural Gas Transportation	$	138,868		$	(905	)	$	137,963		$	70,652		$	(735	)	$	69,917
Crude Oil Transportation	80,741			(6,160		)	74,581			34,871			1,386			36,257
Gathering, Processing & Terminalling	27,910			7,065			34,975			10,156			(651		)	9,505
Corporate and Other	(1,794		)	—			(1,794		)	(12,269		)	—			(12,269		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investments (1)							88,522									32,413
Gain on disposal of assets (1)							—									3,212
Less:
Interest expense, net (1)							(39,710		)							(10,786		)
Depreciation and amortization expense (1)							(30,728		)							(8,496		)
Distributions from unconsolidated investments (1)							(115,098		)							(43,491		)
Non-cash compensation expense (1)							(17,120		)							(962		)
Deficiency payments, net (1)							(12,144		)							(3,780		)
Non-cash (loss) gain related to derivative instruments (1)							(1,252		)							872
Deferred income tax expense							(17,066		)							(6,692		)
Net income attributable to Exchange Right Holders							(50,542		)							(48,965		)
Net income attributable to TGE							$	50,587								$	16,735

⁽¹⁾  Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.

	Three Months Ended March 31,
Capital Expenditures:	2019		2018
	(in thousands)
Natural Gas Transportation	$	16,346	$	9,885
Crude Oil Transportation	17,016		16,952
Gathering, Processing & Terminalling	27,814		31,139
Corporate and Other	1,626		784
Total capital expenditures	$	62,802	$	58,760

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Assets:	March 31, 2019		December 31, 2018
	(in thousands)
Natural Gas Transportation	$	2,608,355	$	2,606,696
Crude Oil Transportation	1,711,706		1,423,740
Gathering, Processing & Terminalling	1,471,995		1,522,559
Corporate and Other	277,169		340,514
Total assets	$	6,069,225	$	5,893,509

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17. Subsequent Events

Rockies Express Senior Notes Offering

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.

Acquisition of Central Environmental Services

On April 24, 2019, BNN Eastern, LLC ("BNN Eastern"), an 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, or CES). CES owns a salt water disposal facility located in the Utica and Marcellus area of Ohio. On May 1, 2019, the acquisition closed for total purchase consideration of approximately $52 million paid at closing, and a seller in the transaction received a 7.65% membership interest in BNN Eastern. In addition to the consideration paid at closing, the transaction includes a potential earn out payment to the sellers of approximately $3 million, which is payable in cash or in additional membership interests in BNN Eastern. The initial accounting for the transaction is not yet complete as management does not have the information necessary to prepare pro forma financial information or value the assets acquired and liabilities assumed.

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

As used in this Quarterly Report, unless the context otherwise requires, "we," "us," "our," the "Partnership," "TGE" and similar terms refer to Tallgrass Energy, LP, in its individual capacity or to Tallgrass Energy, LP and its consolidated subsidiaries collectively (including Tallgrass Equity, LLC, Tallgrass Energy Partners, LP and their respective subsidiaries), as the context requires. References to "Tallgrass Equity" refer to Tallgrass Equity, LLC. References to "TEP" refer to Tallgrass Energy Partners, LP. The term our "general partner" refers to Tallgrass Energy GP, LLC. References to "Tallgrass Development" or "TD" refer to Tallgrass Development, LP. 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report. Additionally, the following discussion and analysis should be read in conjunction with our audited financial statements and notes thereto, the related "Management's Discussion and Analysis of Financial Condition and Results of Operations," the discussion of "Risk Factors" and the discussion of TGE's "Business" in our Annual Report on Form 10-K for the year ended December 31, 2018 (our "2018 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 8, 2019.

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

Cautionary Statement Regarding Forward-Looking Statements

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

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

• our ability to pay dividends to our Class A shareholders;

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

• our ability to complete and integrate acquisitions, including integrating the acquisitions discussed in Note 3 – Acquisitions;

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

• our ability to successfully contract or re-contract with our customers;

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

• our ability to successfully implement our business plan;

• changes in general economic conditions;

• competitive conditions in our industry;

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

• actions taken by governmental regulators of our assets, including the FERC;

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

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

• the price and availability of debt and equity financing;

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

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

• competition from the same and alternative energy sources;

• energy efficiency and technology trends;

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

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

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

• interest rates;

• labor relations;

• changes in tax laws, regulations and status;

• the effects of existing and future litigation; and

• certain factors discussed elsewhere in this Quarterly Report.

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

Overview

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.

Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity in which we directly own an approximate 63.70% membership interest as of May 7, 2019. 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.

Recent Developments

TGE Dividend Announced

On April 11, 2019, the Board of Directors of our general partner declared a cash dividend for the quarter ended March 31, 2019 of $0.5300 per Class A share. The distribution will be paid on May 15, 2019, to Class A shareholders of record on April 30, 2019.

Rockies Express Senior Notes Offering

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.

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Acquisition of Central Environmental Services

On April 24, 2019, BNN Eastern, LLC ("BNN Eastern"), an 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, or CES). CES owns a salt water disposal facility located in the Utica and Marcellus area of Ohio. On May 1, 2019, the acquisition closed for total purchase consideration of approximately $52 million paid at closing, and a seller in the transaction received a 7.65% membership interest in BNN Eastern. In addition to the consideration paid at closing, the transaction includes a potential earn out payment to the sellers of approximately $3 million, which is payable in cash or in additional membership interests in BNN Eastern.

How We Evaluate Our Operations

We evaluate our results using, among other measures, contract profile and volumes, operating costs and expenses, Adjusted EBITDA and Cash Available for Dividends. Adjusted EBITDA and Cash Available for Dividends are non-GAAP measures and are defined below.

Contract Profile and Volumes

Our results are driven primarily by the volume of natural gas transportation and storage capacity, crude oil transportation, storage, and terminalling capacity, NGL transportation capacity, and water transportation, gathering, recycling and disposal capacity under firm fee contracts, as well as the volume of natural gas that we gather and process and the fees assessed for such services.

Operating Costs and Expenses

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

Adjusted EBITDA and Cash Available for Dividends

Adjusted EBITDA and Cash Available for Dividends are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

• our operating performance as compared to other publicly traded midstream infrastructure companies, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;

• the ability of our assets to generate sufficient cash flow to make dividends to our shareholders;

• our ability to incur and service debt and fund capital expenditures; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various expansion and growth opportunities.

We believe that the presentation of Adjusted EBITDA and Cash Available for Dividends provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and Cash Available for Dividends should not be considered alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, nor should Adjusted EBITDA and Cash Available for Dividends be considered alternatives to available cash or other definitions in our partnership agreement. Adjusted EBITDA and Cash Available for Dividends have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities. Additionally, because Adjusted EBITDA and Cash Available for Dividends may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and Cash Available for Dividends may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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Non-GAAP Financial Measures

We generally 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. We also use Cash Available for Dividends, which we generally define as Adjusted EBITDA, less cash interest costs, maintenance capital expenditures, and certain cash reserves permitted by our governing documents. Adjusted EBITDA and Cash Available for Dividends are both calculated and presented at the Tallgrass Equity level, before consideration of noncontrolling interest associated with the Exchange Right Holders or calculating distributions from Tallgrass Equity to us, on one hand, and to the Exchange Right Holders, on the other. We believe calculating these measures at Tallgrass Equity provides investors the most complete and comparable picture of our overall financial and operational results and provides a consistent metric for period over period comparisons that is not impacted by any future exercises by the Exchange Right Holders of the Exchange Right, which does not have a dilutive effect on TGE's net income per share.

Maintenance capital expenditures are cash expenditures incurred (including expenditures for the construction or development of new capital assets) that we expect to maintain our long-term operating income or operating capacity. These expenditures typically include certain system integrity, compliance and safety improvements, and are presented net of noncontrolling interest and reimbursements. We collect deficiency payments for volumes committed by our customers to be transported in a month but not physically received for transport or delivered to the customers' agreed upon destination point. These deficiency payments are recorded as a deferred liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes remote.

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Adjusted EBITDA and Cash Available for Dividends are not presentations made in accordance with GAAP. The following table presents a reconciliation of Adjusted EBITDA to Net income attributable to TGE and net cash provided by operating activities and a reconciliation of Cash Available for Dividends to net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated:

	Three Months Ended March 31,
	2019			2018
	(in thousands)
Reconciliation of Tallgrass Equity Adjusted EBITDA to Net income attributable to TGE
Net income attributable to TGE	$	50,587		$	16,735
Add:
Interest expense, net (1)	39,710			10,786
Depreciation and amortization expense (1)	30,728			8,496
Distributions from unconsolidated investments (1)	115,098			43,491
Deficiency payments, net (1)	12,144			3,780
Non-cash compensation expense (1)(2)	17,120			962
Non-cash loss (gain) related to derivative instruments (1)	1,252			(872		)
Deferred income tax expense	17,066			6,692
Net income attributable to Exchange Right Holders	50,542			48,965
Less:
Equity in earnings of unconsolidated investments (1)	(88,522		)	(32,413		)
Gain on disposal of assets (1)	—			(3,212		)
Tallgrass Equity Adjusted EBITDA	$	245,725		$	103,410
Reconciliation of Tallgrass Equity Adjusted EBITDA and Cash Available for Dividends to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	143,748		$	151,600
Add:
Interest expense, net (1)	39,710			10,786
Other, including changes in operating working capital (1)	62,267			(58,976		)
Tallgrass Equity Adjusted EBITDA	$	245,725		$	103,410
Less:
Cash interest cost (1)	(38,139		)	(10,282		)
Maintenance capital expenditures, net (1)	(6,988		)	(1,026		)
Tallgrass Equity Cash Available for Dividends	$	200,598		$	92,102

⁽¹⁾  Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.

⁽²⁾  Represents TGE's portion of non-cash compensation expense related to Equity Participation Shares and TEP's Equity Participation Units, excluding amounts allocated to TD prior to the merger of TD into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity, on February 7, 2018.

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The following table presents a reconciliation of Adjusted EBITDA by segment to segment operating income, the most directly comparable GAAP financial measure, for each of the periods indicated:

	Three Months Ended March 31,
	2019			2018
	(in thousands)
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Natural Gas Transportation Segment (1)
Operating income	$	19,936		$	19,384
Add:
Depreciation and amortization expense (2)	4,948			1,571
Distributions from unconsolidated investment (2)	113,395			43,491
Other, net (2)	589			576
Less:
Adjusted EBITDA attributable to noncontrolling interests	—			5,630
Tallgrass Equity Segment Adjusted EBITDA	$	138,868		$	70,652
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Crude Oil Transportation Segment (1)
Operating income	$	61,437		$	46,527
Add:
Depreciation and amortization expense (2)	13,699			4,348
Deficiency payments, net (2)	5,605			2,641
Less:
Adjusted EBITDA attributable to noncontrolling interests	—			(18,645		)
Tallgrass Equity Segment Adjusted EBITDA	$	80,741		$	34,871
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Gathering, Processing & Terminalling Segment (1)
Operating income	$	8,609		$	23,305
Add:
Depreciation and amortization expense (2)	11,477			2,354
Non-cash loss (gain) related to derivative instruments (2)	1,252			(872		)
Distributions from unconsolidated investments (2)	1,703			—
Deficiency payments, net (2)	6,147			1,014
Other, net (2)	(20		)	—
Less:
Gain on disposal of assets (2)	—			(3,212		)
Adjusted EBITDA attributable to noncontrolling interests	(1,258		)	(12,433		)
Tallgrass Equity Segment Adjusted EBITDA	$	27,910		$	10,156
Total Tallgrass Equity Segment Adjusted EBITDA	$	247,519		$	115,679
Corporate general and administrative costs	(1,794		)	(12,269		)
Total Tallgrass Equity Adjusted EBITDA	$	245,725		$	103,410

⁽¹⁾  Segment results as presented represent total operating income and Adjusted EBITDA, including intersegment activity, for the Natural Gas Transportation, Crude Oil Transportation, and Gathering, Processing & Terminalling segments. For reconciliations to the consolidated financial data, see Note 16 – Reportable Segments.

⁽²⁾  Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.

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Results of Operations

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

	Three Months Ended March 31,
	2019	2018
Natural Gas Transportation Segment:
TIGT and Trailblazer average firm contracted volumes (MMcf/d) (1)	1,914	1,842
Rockies Express average firm contracted volumes (MMcf/d) (2)	4,204	4,107
Crude Oil Transportation Segment:
Crude oil transportation average contracted capacity (Bbls/d)	308,580	303,580
Crude oil transportation average throughput (Bbls/d)	335,749	289,739
Gathering, Processing & Terminalling Segment:
Natural gas processing inlet volumes (MMcf/d)	109	117
Freshwater average volumes (Bbls/d)	27,418	45,512
Produced water gathering and disposal average volumes (Bbls/d)	160,431	85,406

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

⁽²⁾  Volumes transported under long-term firm fee contracts.

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

	Three Months Ended March 31,
	2019			2018
	(in thousands)
Revenues:
Crude oil transportation services	$	95,156		$	84,738
Natural gas transportation services	33,516			32,196
Sales of natural gas, NGLs, and crude oil	38,864			38,145
Processing and other revenues	29,816			24,015
Total Revenues	197,352			179,094
Operating Costs and Expenses:
Cost of sales	19,285			26,351
Cost of transportation services	15,072			10,420
Operations and maintenance	18,046			16,399
Depreciation and amortization	31,001			26,123
General and administrative	32,272			18,426
Taxes, other than income taxes	10,998			8,879
Loss (gain) on disposal of assets	214			(9,417		)
Total Operating Costs and Expenses	126,888			97,181
Operating Income	70,464			81,913
Other Income (Expense):
Equity in earnings of unconsolidated investments	88,522			68,402
Interest expense, net	(39,705		)	(29,761		)
Other income, net	177			451
Total Other Income (Expense)	48,994			39,092
Net income before tax	119,458			121,005
Deferred income tax expense	(17,066		)	(6,692		)
Net income	102,392			114,313
Net income attributable to noncontrolling interests	(51,805		)	(97,578		)
Net income attributable to TGE	$	50,587		$	16,735

Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018

Revenues. Total revenues were $197.4 million for the three months ended March 31, 2019, compared to $179.1 million for the three months ended March 31, 2018, which represents an increase of $18.3 million, or 10%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $19.8 million and $10.2 million in the Crude Oil Transportation and Gathering, Processing & Terminalling segments, respectively, partially offset by a $11.3 million increase in eliminations of intersegment revenue and decreased revenues of $0.4 million in the Natural Gas Transportation segment, as discussed further below.

Operating costs and expenses. Operating costs and expenses were $126.9 million for the three months ended March 31, 2019 compared to $97.2 million for the three months ended March 31, 2018, which represents an increase of $29.7 million, or 31%. The overall increase in operating costs and expenses is driven by increased operating costs and expenses of $24.9 million, $4.9 million, and $0.8 million in the Gathering, Processing & Terminalling, Crude Oil Transportation, and Corporate and Other segments, respectively, partially offset by decreased operating costs and expenses of $0.9 million in the Natural Gas Transportation segment, as discussed further below. The increase in Corporate and Other expenses was primarily driven by a $12.1 million increase in corporate general and administrative costs, partially offset by a $11.3 million increase in eliminations of intersegment operating costs and expenses. The increase in corporate general and administrative costs was primarily due to an increase in equity-based compensation costs related to the accelerated vesting of certain Equity Participation Shares as a result of the change in control triggered by the Blackstone Acquisition.

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Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $88.5 million and $68.4 million for the three months ended March 31, 2019 and 2018, respectively. Equity in earnings of unconsolidated investments of $88.5 million for the three months ended March 31, 2019 primarily reflects our portion of earnings and the $8.5 million of amortization of a negative basis difference associated with our aggregate 75% membership interest in Rockies Express, as well as equity in earnings of $1.4 million and $0.9 million, respectively, related to our 51% membership interests in Pawnee Terminal, LLC ("Pawnee Terminal") and Powder River Gateway. Equity in earnings of unconsolidated investments of $68.4 million for the three months ended March 31, 2018 primarily reflects our portion of earnings and the $8.4 million of amortization of a negative basis difference associated with our 75% membership interest in Rockies Express, inclusive of Tallgrass Equity's additional 25.01% membership interest acquired in February 2018, as well as $1.3 million of equity in earnings related to our 63% membership interest in BNN Colorado. The overall increase was primarily driven by a $19.2 million increase in equity in earnings from Rockies Express as a result of the additional 25% membership interest acquired in February 2018, as well as lower interest expense at Rockies Express due to the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018.

Interest expense, net. Interest expense of $39.7 million for the three months ended March 31, 2019 was primarily composed of interest and fees associated with the TEP revolving credit facility and Senior Notes. Interest expense of $29.8 million for the three months ended March 31, 2018 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities and the 2024 Notes issued on September 1, 2016 and May 16, 2017, and the 2028 Notes issued on September 15, 2017 and December 11, 2017. The increase in interest and fees is primarily due to increased borrowings to fund a portion of our 2018 and 2019 acquisitions and a special contribution to Rockies Express to fund our pro rata portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018, as well as the higher borrowing rate on the Senior Notes, the proceeds of which were used to repay borrowings under the revolving credit facility.

Other income, net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income for the three months ended March 31, 2019 was $0.2 million compared to $0.5 million of other income for the three months ended March 31, 2018.

Deferred income tax expense. Deferred income tax expense for the three months ended March 31, 2019 was $17.1 million, compared to deferred income tax expense of $6.7 million for the three months ended March 31, 2018. The increase in deferred income tax expense was primarily due to our increased ownership in TEP effective June 30, 2018 as a result of the merger transaction with TEP and the exercise of the Exchange Right effective March 11, 2019 and the resulting increase in income allocated to TGE.

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

Segment Financial Data – Natural Gas Transportation (1)	Three Months Ended March 31,
	2019			2018
	(in thousands)
Revenues:
Natural gas transportation services	$	33,930		$	34,054
Sales of natural gas, NGLs, and crude oil	—			237
Processing and other revenues	1,912			1,911
Total revenues	35,842			36,202
Operating costs and expenses:
Cost of sales	—			343
Cost of transportation services	(262		)	132
Operations and maintenance	6,040			6,163
Depreciation and amortization	4,948			4,827
General and administrative	3,880			3,934
Taxes, other than income taxes	1,300			1,419
Total operating costs and expenses	15,906			16,818
Operating income	$	19,936		$	19,384

⁽¹⁾  Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 16 – Reportable Segments.

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Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018

Revenues. Natural Gas Transportation segment revenues were $35.8 million for the three months ended March 31, 2019, compared to $36.2 million for the three months ended March 31, 2018, which represents a decrease of $0.4 million in segment revenues primarily due to a $0.2 million decrease in sales of natural gas driven by decreased volumes of natural gas sold.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $15.9 million for the three months ended March 31, 2019, compared to $16.8 million for the three months ended March 31, 2018, which represents a decrease of $0.9 million, or 5%. The overall decrease in operating costs and expenses was primarily due to a $0.4 million decrease in cost of transportation services driven by increased cash settlements of shipper imbalances at TIGT during the three months ended March 31, 2019 and a $0.3 million decrease in cost of sales driven by decreased volumes of natural gas sold.

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

Segment Financial Data – Crude Oil Transportation (1)	Three Months Ended March 31,
	2019		2018
	(in thousands)
Revenues:
Crude oil transportation services	$	109,578	$	88,057
Sales of natural gas, NGLs, and crude oil	—		1,909
Processing and other revenues	206		—
Total revenues	109,784		89,966
Operating costs and expenses:
Cost of sales	521		1,966
Cost of transportation services	16,898		14,387
Operations and maintenance	3,050		2,870
Depreciation and amortization	13,699		13,366
General and administrative	5,456		4,492
Taxes, other than income taxes	8,723		6,358
Total operating costs and expenses	48,347		43,439
Operating income	$	61,437	$	46,527

⁽¹⁾  Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 16 – Reportable Segments.

Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018

Revenues. Crude Oil Transportation segment revenues were $109.8 million for the three months ended March 31, 2019, compared to $90.0 million for the three months ended March 31, 2018, which represents an increase of $19.8 million, or 22%, in segment revenues driven by a $21.5 millionincrease in crude oil transportation services, partially offset by a $1.9 milliondecrease in sales of crude oil primarily due to decreased volumes sold during the three months ended March 31, 2019. The increase in crude oil transportation services revenue was primarily driven by a $10.6 million increase in walk-up barrels shipped, a $5.7 million increase in committed volume shipments, and a $4.1 million increase due to the FERC annual index adjustments effective July 1, 2018.

Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $48.3 million for the three months ended March 31, 2019 compared to $43.4 million for the three months ended March 31, 2018, which represents an increase of $4.9 million, or 11%. The overall increase in operating costs and expenses was primarily driven by a $2.5 million increase in cost of transportation services driven by higher throughput volumes during the three months ended March 31, 2019 compared to the three months ended March 31, 2018 and a $2.4 million increase in taxes, other than income taxes driven by an increase in property tax assessment estimates.

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

Segment Financial Data – Gathering, Processing & Terminalling (1)	Three Months Ended March 31,
	2019		2018
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	38,864	$	35,999
Processing and other revenues	35,170		27,839
Total revenues	74,034		63,838
Operating costs and expenses:
Cost of sales	18,879		24,566
Cost of transportation services	20,629		6,289
Operations and maintenance	8,956		7,366
Depreciation and amortization	11,750		7,294
General and administrative	4,022		3,333
Taxes, other than income taxes	975		1,102
Loss (gain) on disposal of assets	214		(9,417		)
Total operating costs and expenses	65,425		40,533
Operating income	$	8,609	$	23,305

⁽¹⁾  Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 16 – Reportable Segments.

Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018

Revenues. Gathering, Processing & Terminalling segment revenues were $74.0 million for the three months ended March 31, 2019, compared to $63.8 million for the three months ended March 31, 2018, which represents a $10.2 million, or 16%, increase in segment revenues. The increase in segment revenues was due to a $7.3 million increase in processing and other revenues and a $2.9 million increase in sales of natural gas, NGLs, and crude oil. The increase in processing and other revenues was driven by (i) increased water business services revenue of $5.1 million driven by the acquisition of NGL Water Solutions Bakken, LLC ("NGL Water Solutions Bakken") in November 2018 and increased produced water disposal volumes, partially offset by decreased fresh water transportation volumes and (ii) increased terminal services revenue of $2.2 million driven by the Buckingham Terminal expansion and the Natoma Terminal placed into service in April 2018. The increase in sales of natural gas, NGLs, and crude oil was driven by (i) increased crude oil sales of $7.2 million at Stanchion and (ii) increased sales of natural gas of $2.6 million due to sales of residue gas from the Douglas Gathering System; partially offset by decreased sales of NGLs of $6.7 million primarily due to lower NGL prices.

Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $65.4 million for the three months ended March 31, 2019 compared to $40.5 million for the three months ended March 31, 2018, which represents an increase of $24.9 million, or 61%. The increase in operating costs and expenses was primarily driven by (i) an increase of $14.3 million in the cost of transportation services due to crude oil transportation fees paid by Stanchion and increased water gathering and disposal volumes at Water Solutions, (ii) $0.2 million loss on the disposal of assets during the three months ended March 31, 2019, compared to the $9.4 million gain on disposal of assets on the disposal of Tallgrass Crude Gathering, LLC ("TCG") during the three months ended March 31, 2018, and (iii) increased depreciation and amortization expense of $4.5 million primarily due to acquisitions and assets placed into service in 2018 and 2019 at Water Solutions and Terminals. These increases were partially offset by a $5.7 million decrease in cost of sales primarily due to lower NGL prices as discussed above.

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Liquidity and Capital Resources Overview

Our primary sources of liquidity for the three months ended March 31, 2019 were cash generated from operations and borrowings under our revolving credit facility. We expect our sources of liquidity in the future to include:

• cash generated from our operations;

• borrowing capacity available under our revolving credit facility; and

• future issuances of additional equity and/or debt securities.

We believe that cash on hand, cash generated from operations, and availability under our revolving credit facility will be adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements, and our planned cash dividends to shareholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of cash generated from operations, borrowings under our revolving credit facility and issuances of debt and/or equity securities. For additional information regarding our revolving credit facilities and senior unsecured notes, see Note 9 – Long-term Debt. For additional information regarding our equity transactions, see Note 10 – Partnership Equity.

Our total liquidity as of March 31, 2019 and December 31, 2018 was as follows:

	March 31, 2019			December 31, 2018
	(in thousands)
Cash on hand (1)	$	15,042		$	9,596
Total capacity under the revolving credit facility	2,250,000			2,250,000
Less: Outstanding borrowings under the revolving credit facility	(1,349,000		)	(1,224,000		)
Less: Letters of credit issued under the revolving credit facility	(94		)	(94		)
Available capacity under the revolving credit facility	900,906			1,025,906
Total liquidity	$	915,948		$	1,035,502

⁽¹⁾  Includes cash on hand at TGE and its consolidated subsidiaries.

Working Capital

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

As of March 31, 2019, we had a working capital deficit of $116.1 million compared to a working capital deficit of $146.9 million at December 31, 2018, which represents a decrease in the working capital deficit of $30.8 million. The overall decrease in the working capital deficit was primarily attributable to changes in the following components:

• a decrease in accrued interest of $26.7 million primarily due to timing of interest payments during the first quarter of 2019, partially offset by increased borrowings;

• a decrease in accounts payable of $14.2 million primarily due to a decrease in crude oil purchases at Stanchion, a decrease in capital expenditures at Terminals, and a decrease in producer settlements at TMID, partially offset by an increase in capital expenditures at Pony Express; and

• a decrease in accrued liabilities of $13.3 million primarily due to annual incentive payments made during the quarter.

These working capital decreases were partially offset by:

• an increase in deferred revenue of $12.1 million primarily from deficiency payments collected by Pony Express and Water Solutions; and

• a decrease in accounts receivable of $8.8 million primarily due to a decrease in crude oil sales at Stanchion and lower processed volumes at TMID, partially offset by increased accounts receivable at Water Solutions.

40

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

Cash Flows

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

	Three Months Ended March 31,
	2019			2018
	(in thousands)
Net cash provided by (used in):
Operating activities	$	143,748		$	151,600
Investing activities	$	(102,426	)	$	(122,913	)
Financing activities	$	(35,876	)	$	(27,025	)

Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2018

Operating Activities. Cash flows provided by operating activities were $143.7 million and $151.6 million for the three months ended March 31, 2019 and 2018, respectively. The decrease in net cash flows provided by operating activities of $7.9 million was primarily driven by a net decrease in cash flows from changes in working capital driven by a $62.5 million increase in net cash outflows from accounts payable and accrued liabilities, primarily due to higher crude oil purchases at Stanchion and timing of interest payments, partially offset by a $21.0 million increase in net cash inflows from accounts receivable, primarily due to higher crude oil sales at Stanchion. The decrease in cash flows from changes in working capital was partially offset by a $20.9 million increase in distributions received from unconsolidated affiliates, primarily Rockies Express, as a result of our increased membership interest effective February 7, 2018, as well as lower interest expense at Rockies Express due to the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018.

Investing Activities. Cash flows used in investing activities were $102.4 million for the three months ended March 31, 2019, primarily driven by:

• capital expenditures of $62.8 million, primarily due to spending on construction of the Guernsey and Grasslands Terminals, Pony Express expansion, and a new 70-mile natural gas pipeline located in Colorado ("Cheyenne Connector");

• cash outflows of $37.0 million for the initial capital contribution and formation of the Powder River Gateway joint venture; and

• contributions to unconsolidated investments in the amount of $29.8 million, primarily to fund our share of capital projects at Rockies Express and Powder River Gateway.

These cash outflows were partially offset by $27.2 million of distributions received from Rockies Express in excess of cumulative earnings recognized.

Cash flows used in investing activities were $122.9 million for the three months ended March 31, 2018, primarily driven by:

• cash outflows of $95.0 million for the acquisition of BNN North Dakota;

• capital expenditures of $58.8 million, primarily due to spending on a 55-mile extension on the Pony Express System, construction of the Buckingham Terminal expansion, the Cheyenne Connector, additional water gathering infrastructure located in North Dakota, and construction of the Grasslands and Natoma Terminals; and

• cash outflows of $19.5 million for the acquisition of a 38% membership interest in Deeprock North, LLC.

These cash outflows were partially offset by cash inflows of:

• $50.0 million from the sale of TCG; and

• $20.8 million of distributions received from Rockies Express in excess of cumulative earnings recognized.

Financing Activities. Cash flows used in financing activities were $35.9 million for the three months ended March 31, 2019, primarily driven by:

• dividends paid to Class A shareholders of $81.3 million; and

41

• distributions to noncontrolling interests of $66.6 million, consisting of Tallgrass Equity distributions to the Exchange Right Holders of $64.4 million and distributions to Deeprock Development and West Texas noncontrolling interests of $2.2 million; and

• tax payments funded by shares tendered by employees to satisfy tax withholding obligations of $13.3 million related to the issuance of Class A shares under LTIP plan.

These cash outflows were partially offset by net borrowings under the revolving credit facility of $125.0 million.

Cash flows used in financing activities were $27.0 million for the three months ended March 31, 2018, primarily driven by:

• distributions to noncontrolling interests of $89.1 million, which consisted of distributions to TEP unitholders of $51.3 million, Tallgrass Equity distributions to the Exchange Right Holders of $36.4 million, and distributions to Deeprock Development and Pony Express noncontrolling interests of $1.3 million;

• cash outflows of $50.0 million for the acquisition of an additional 2% membership interest in Pony Express; and

• dividends paid to Class A shareholders of $21.3 million.

These cash outflows were partially offset by net borrowings of $133.0 million under the revolving credit facility and the Tallgrass Equity credit facility that was terminated in July 2018.

Dividends

Dividends to our Class A shareholders. We distribute 100% of TGE's available cash at the end of each quarter to Class A shareholders of record beginning with the quarter ended June 30, 2015. Available cash at TGE is generally defined in our partnership agreement as all cash and cash equivalents on hand at the date of determination in respect of such quarter less reserves established in the discretion of our general partner for future requirements. For a discussion of factors and trends impacting our business, which in turn impacts our ability to pay dividends to our Class A shareholders, please see "—Factors and Trends Impacting Our Business" in our 2018 Form 10-K.

Our dividend for the three months ended March 31, 2019, in the amount of $0.5300 per Class A share, or $95.0 million in the aggregate, was announced on April 11, 2019 and will be paid on May 15, 2019 to Class A shareholders of record on April 30, 2019.

Capital Requirements

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

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

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

The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. We expect to incur approximately $290 million for expansion capital projects and approximately $40 million for maintenance capital expenditures in 2019. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities:

	Three Months Ended March 31,
	2019		2018
	(in thousands)
Maintenance capital expenditures	$	6,988	$	3,030
Expansion capital expenditures	54,141		57,067
Total capital expenditures incurred	$	61,129	$	60,097

Capital expenditures incurred represent capital expenditures paid and accrued during the period. Capital expenditures are presented net of noncontrolling interest, and contributions and reimbursements received. The increase in maintenance capital expenditures to $7.0 million for the three months ended March 31, 2019 from $3.0 million for the three months ended March

42

31, 2018 is primarily driven by increased expenditures in the Natural Gas Transportation and Corporate and Other segments. Maintenance capital expenditures for the three months ended March 31, 2019 in the Corporate and Other segment consisted primarily of spending on information technology assets as a result of our acquisition of these assets from TD in February 2018. Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from year to year and from quarter to quarter. Expansion capital expenditures were $54.1 million for the three months ended March 31, 2019 compared to $57.1 million for the three months ended March 31, 2018. Expansion capital expenditures for the three months ended March 31, 2019 consisted primarily of spending on the construction of the Guernsey and Grasslands Terminals, Pony Express expansion, and Cheyenne Connector. Expansion capital expenditures of $57.1 million for the three months ended March 31, 2018 consisted primarily of spending on a 55-mile extension on the Pony Express System, construction of the Buckingham Terminal expansion, the Cheyenne Connector, additional water gathering infrastructure located in North Dakota, and construction of the Grasslands Terminal and the Natoma Terminal.

During the three months ended March 31, 2019 and 2018, we invested cash of $29.8 million and $8.0 million, respectively, in unconsolidated affiliates, including Rockies Express, Powder River Gateway, and BNN Colorado, prior to our consolidation of BNN Colorado in December 2018, to fund our share of capital projects.

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

Contractual Obligations

There have been no material changes in our contractual obligations as reported in our 2018 Form 10-K.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

The critical accounting policies and estimates used in the preparation of our condensed consolidated financial statements are set forth in our 2018 Form 10-K and have not changed.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Historically, we have had a limited amount of direct commodity price exposure related to natural gas used at TMID and crude oil collected as part of our contractual pipeline loss allowance at Pony Express and Terminals. Accordingly, we have historically entered into derivative contracts with third parties for all or a portion of these volumes for the purpose of hedging our commodity price exposures. In addition, Stanchion transacts in crude oil and enters into physical and financial derivative contracts in connection with these, and other, transactions.

The majority of TMID's Adjusted EBITDA comes from volumetric fee or commodity sensitive contracts. The profitability of our commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. During the three months ended March 31, 2019, TMID represented 4% of our consolidated Adjusted EBITDA.

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

43

The following table summarizes our commodity derivatives and the change in fair value that would be expected from a 10% price increase or decrease as of March 31, 2019, assuming a parallel shift in the forward curve through the end of 2019:

	Fair Value			Effect of 10% Price Increase			Effect of 10% Price Decrease
	(in thousands)
Crude oil derivative contract assets(1)	$	1,761		$	—		$	—
Crude oil derivative contract liabilities(1)	$	(1,129	)	$	(1,481	)	$	1,481

⁽¹⁾  Represents the net forward sale of 246,000 barrels of crude oil in our Gathering, Processing & Terminalling segment which will settle throughout 2019.

Interest Rate Risk

As of March 31, 2019, TEP has issued $2.0 billion of Senior Notes and has a $2.25 billion revolving credit facility with outstanding borrowings of $1.35 billion. Borrowings under TEP's revolving credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. The applicable margin ranges from 0.25% to 1.25% for base rate borrowings and 1.25% to 2.25% for reserve adjusted Eurodollar rate borrowings, based upon TEP's total leverage ratio.

We do not currently hedge the interest rate risk on TEP's borrowings under the revolving credit facility. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the fair value of the debt by $0.7 million based on our outstanding debt under TEP's revolving credit facility as of March 31, 2019.

Credit Risk

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

A substantial majority of our revenue is produced under long-term firm fee contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with a majority of our revenues derived from customers who have BBB- or Baa3 and better credit ratings or are part of corporate families with such credit ratings as of March 31, 2019.

We also have indirect credit risk exposure with respect to our investment in Rockies Express. See Item 1A.—Risk Factors in our 2018 Form 10-K for additional information.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended March 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

44

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Note 15 – Legal and Environmental Matters to the condensed consolidated financial statements included in Part I—Item 1.—Financial Statements of this Quarterly Report, which is incorporated herein by reference.

Item 1A. Risk Factors

Item 1A of our 2018 Form 10-K sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition or operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results for the quarter ended March 31, 2019. There have been no material changes to the risk factors contained in our 2018 Form 10-K.

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

Recent Sales of Unregistered Securities

None.

Repurchases of Registered Equity Securities by Tallgrass Energy, LP or Affiliated Purchasers

We have not engaged, alone or in concert with an "affiliated purchaser," in any repurchases of our registered securities during the period covered by this report and do not have a repurchase plan or program in place. However, following the closing of the Blackstone Acquisition on March 11, 2019, we are under common control with the Sponsor Entities.

On March 11, 2019, BIP announced that in connection with the closing of the Blackstone Acquisition, the Sponsor Entities had pre-funded Prairie Secondary Acquiror LP, a Delaware limited partnership ("Secondary Acquiror 1"), and Prairie Secondary Acquiror E LP, a Delaware limited partnership ("Secondary Acquiror 2" and, collectively with Secondary Acquiror 1, "Prairie Secondary Acquirors"), each of which are managed by BIP Holdings Manager L.L.C., a Delaware limited liability company, with an aggregate of $400 million for the purpose of making potential future acquisitions of additional Class A shares and that the Prairie Secondary Acquirors intended to enter into a 10b5-1(c) purchase plan (the "Blackstone Plan"). The Blackstone Plan commenced on March 14, 2019. See Schedule 13D filed by BIP and certain of its affiliates with the SEC on March 11, 2019, together with all amendments, for more information on the Blackstone Plan.

The table set forth below reflects the purchases of the Sponsor Entities during the period covered by this report, and subsequent to the closing of the Blackstone Acquisition on March 11, 2019.

Period	Total number of Class A shares purchased		Average price paid per Class A share		Total number of Class A shares purchased as part of publicly announced plans or programs		Maximum number (or approximate dollar value) of Class A shares that may yet be purchased under the plans or programs
January 1 to January 31, 2019	—		$	—	—		$	—
February 1 to February 28, 2019	—		$	—	—		$	—
March 1 to March 31, 2019	286,783	(1)	$	24.0776	286,783	(1)	$	143,089,219	(2)
Total	286,783		$	24.0776	286,783		$	143,089,219

⁽¹⁾  Includes (i) 116,664 Class A shares purchased by Secondary Acquiror 1 and (ii) 170,119 Class A shares purchased by Secondary Acquiror 2 pursuant to the Blackstone Plan.

⁽²⁾  Represents the approximate dollar value of Class A shares that may yet be purchased under the Blackstone Plan, which provides for purchases up to $150 million of Class A shares, subject to certain volume and pricing thresholds and other conditions set forth therein.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

45

Item 5. Other Information

On May 3, 2019, our general partner, Tallgrass Management, LLC ("Tallgrass Management") and Gary Brauchle modified the non-compete and non-solicitation provisions of Mr. Brauchle's employment agreement. Mr. Brauchle has agreed not to (i) compete with Tallgrass Management or certain of its affiliates through certain specified competitors or acquirors during the term of his employment and for a period of one year thereafter, or (ii) solicit Tallgrass Management's or any of its affiliates' employees or interfere with certain business relationships during the term of his employment and for a period of one year thereafter.

Item 6. Exhibits

Exhibit No.	Description
3.1	Third Amended and Restated Limited Liability Company Agreement of Tallgrass Energy GP, LLC, dated March 11, 2019 (incorporated by reference to Exhibit 3.1 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on March 11, 2019).
4.1	Supplemental Indenture to the 2023 Notes Indenture, dated as of February 27, 2019, among the Issuers, the Guarantors and the Trustee (incorporated by reference to Exhibit 4.1 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on February 28, 2019).
4.2	Supplemental Indenture to the 2024 Notes Indenture, dated as of February 27, 2019, among the Issuers, the Guarantors and the Trustee (incorporated by reference to Exhibit 4.2 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on February 28, 2019).
4.3	Supplemental Indenture to the 2028 Notes Indenture, dated as of February 27, 2019, among the Issuers, the Guarantors and the Trustee (incorporated by reference to Exhibit 4.3 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on February 28, 2019).
10.1	Consent and Amendment No. 2 to Second Amended and Restated Credit Agreement, dated February 22, 2019, by and among Tallgrass Energy Partners, LP, the subsidiary guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the required lenders named therein (incorporated by reference to Exhibit 10.1 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on February 28, 2019).
10.2	Amended and Restated Registration Rights Agreement, dated March 11, 2019, by and among Tallgrass Energy, LP and each of the Holders listed on an annex thereto (incorporated by reference to Exhibit 10.1 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on March 11, 2019).
10.3	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.2 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on March 11, 2019).
10.4	Third Amended and Restated Employment Agreement, dated March 11, 2019, by and among Tallgrass Management, LLC, Tallgrass Energy GP, LLC and David G. Dehaemers, Jr. (incorporated by reference to Exhibit 10.3 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on March 11, 2019).
10.5	Form of Non-CEO Employment Agreement (incorporated by reference to Exhibit 10.4 to Tallgrass Energy, LP’s Current Report on Form 8-K filed on March 11, 2019).
31.1*	Rule 13a-14(a)/15d-14(a) Certification of David G. Dehaemers, Jr.
31.2*	Rule 13a-14(a)/15d-14(a) Certification of Gary J. Brauchle.
32.1*	Section 1350 Certification of David G. Dehaemers, Jr.
32.2*	Section 1350 Certification of Gary J. Brauchle.
101.INS*	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

* - filed herewith

46

SIGNATURES

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

		Tallgrass Energy, LP
		(registrant)
		By:	Tallgrass Energy GP, LLC, its general partner
Date:	May 7, 2019	By:	/s/ Gary J. Brauchle
			Name:	Gary J. Brauchle
			Title:	Executive Vice President and Chief Financial Officer
				(Duly Authorized Officer and Principal Financial Officer)

47

EX-31.1

Exhibit 31.1

Certification by Chief Executive Officer pursuant to

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Date: May 7, 2019

EX-31.2

Exhibit 31.2

Certification by Chief Financial Officer pursuant to

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

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

I, Gary J. Brauchle, certify that:

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

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

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

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

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

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

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

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

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

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

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

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

Date: May 7, 2019

EX-32.1

Exhibit 32.1

Certification Pursuant to

18 U.S.C. Section 1350,

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

In connection with the quarterly report of Tallgrass Energy, LP (the “Partnership”) on Form 10-Q for the quarter ended March 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David G. Dehaemers, Jr., Chief Executive Officer of Tallgrass Energy GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:

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

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

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

Date: May 7, 2019

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

EX-32.2

Exhibit 32.2

Certification Pursuant to

18 U.S.C. Section 1350,

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

In connection with the quarterly report of Tallgrass Energy, LP (the “Partnership”) on Form 10-Q for the quarter ended March 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gary J. Brauchle, Executive Vice President and Chief Financial Officer of Tallgrass Energy GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:

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

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

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

Date: May 7, 2019

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

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Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 07, 2019
Document Information [Line Items]
Entity Registrant Name	TALLGRASS ENERGY, LP
Entity Central Index Key	0001633651
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	Q1
Trading Symbol	TGE
Amendment Flag	false
Entity Emerging Growth Company	false
Entity Small Business	false
Capital Unit, Class A
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		179,197,416
Capital Unit, Class B
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		102,136,875

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CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current Assets:
Cash and cash equivalents	$ 15,042	$ 9,596
Accounts receivable, net	227,284	236,097
Inventories	27,954	34,316
Prepayments and other current assets	18,219	11,816
Total Current Assets	288,499	291,825
Property, plant and equipment, net	2,750,375	2,802,429
Goodwill	421,983	421,983
Intangible assets, net	223,707	227,103
Unconsolidated investments	1,988,797	1,861,686
Deferred tax asset	379,422	273,531
Deferred charges and other assets	16,442	14,952
Total Assets	6,069,225	5,893,509
Current Liabilities:
Accounts payable	187,321	201,512
Accrued taxes	26,962	20,734
Accrued interest	12,534	39,217
Accrued liabilities	9,975	23,287
Deferred revenue	123,184	111,095
Other current liabilities	44,651	42,910
Total Current Liabilities	404,627	438,755
Long-term debt, net	3,331,716	3,205,958
Other long-term liabilities and deferred credits	33,118	31,688
Total Long-term Liabilities	3,364,834	3,237,646
Commitments and Contingencies
Equity [Abstract]
Total Partners' Equity	1,890,345	1,725,537
Noncontrolling interests (a)	409,419	491,571
Total Equity	2,299,764	2,217,108
Total Liabilities and Equity	6,069,225	5,893,509
Common Class A
Equity [Abstract]
Total Partners' Equity	1,890,345	1,725,537
Common Class B
Equity [Abstract]
Total Partners' Equity	$ 0	$ 0

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - shares	Mar. 31, 2019	Dec. 31, 2018
Common Class A
Shares, Outstanding	178,104,779	156,311,986
Common Class B
Shares, Outstanding	102,136,875	123,887,893

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) shares in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Revenues:
Total Revenues	$ 197,352,000	$ 179,094,000
Operating Costs and Expenses:
Operations and maintenance	18,046,000	16,399,000
Depreciation and amortization	31,001,000	26,123,000
General and administrative	32,272,000	18,426,000
Taxes, other than income taxes	10,998,000	8,879,000
Loss (gain) on disposal of assets	(214,000)	9,417,000
Total Operating Costs and Expenses	126,888,000	97,181,000
Operating Income	70,464,000	81,913,000
Other Income (Expense):
Equity in earnings of unconsolidated investments	88,522,000	68,402,000
Interest expense, net	(39,705,000)	(29,761,000)
Other income, net	177,000	451,000
Total Other Income (Expense)	48,994,000	39,092,000
Net income before tax	119,458,000	121,005,000
Deferred income tax expense	(17,066,000)	(6,692,000)
Net income	102,392,000	114,313,000
Net income attributable to noncontrolling interests	(51,805,000)	(97,578,000)
Net income attributable to TGE	$ 50,587,000	$ 16,735,000
Earnings Per Share, Basic and Diluted [Abstract]
Basic net income per Class A share	$ 0.31	$ 0.29
Diluted net income per Class A share	$ 0.31	$ 0.29
Basic average number of Class A shares outstanding	161,425	58,085
Diluted average number of Class A shares outstanding	162,777	58,210
Crude oil transportation services
Revenues:
Total Revenues	$ 95,156,000	$ 84,738,000
Natural gas transportation services
Revenues:
Total Revenues	33,516,000	32,196,000
Sales of natural gas, NGLs, and crude oil
Revenues:
Total Revenues	38,864,000	38,145,000
Processing and other revenues
Revenues:
Total Revenues	29,816,000	24,015,000
Cost of Sales
Operating Costs and Expenses:
Cost of sales and transportation services	19,285,000	26,351,000
Cost of transportation services
Operating Costs and Expenses:
Cost of sales and transportation services	$ 15,072,000	$ 10,420,000

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED) - USD ($) $ in Thousands	Total	Pony Express Pipeline	Noncontrolling Interest	Noncontrolling Interest Tallgrass Energy Partners	Noncontrolling Interest Pony Express Pipeline	Noncontrolling Interest Rockies Express Pipeline LLC	Noncontrolling Interest Deeprock Development, LLC	Total Partner Equity Including Portion Attributable to Noncontrolling Interest	Total Partner Equity Including Portion Attributable to Noncontrolling Interest Tallgrass Energy Partners	Total Partner Equity Including Portion Attributable to Noncontrolling Interest Pony Express Pipeline	Total Partner Equity Including Portion Attributable to Noncontrolling Interest Rockies Express Pipeline LLC	Total Partner Equity Including Portion Attributable to Noncontrolling Interest Deeprock Development, LLC	Common Class A	Common Class A Tallgrass Energy Partners	Common Class A Pony Express Pipeline	Common Class A Rockies Express Pipeline LLC	Common Class B	Common Class B Tallgrass Energy Partners	Common Class B Pony Express Pipeline	Common Class B Rockies Express Pipeline LLC
Partners' Capital, Including Portion Attributable to Noncontrolling Interest			$ 1,672,566					$ 1,721,179					$ 48,613				$ 0
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	$ 114,313		97,578					114,313					16,735				0
Dividends paid to Class A shareholders			0					(21,346)					(21,346)				0
Distributions to noncontrolling interest	(89,073)	$ (50,000)	(89,073)					(89,073)					0				0
Contributions from noncontrolling interest			183					183					0				0
Noncash compensation expense			2,917					3,321					404				0
Consolidation of Deeprock North							$ 31,843					$ 31,843
Cumulative effect of ASC 606 implementation | Accounting Standards Update 2014-09			39,543					44,131					4,588
Issuance of TEP units to the public, net of offering costs				$ (40)					$ (45)					$ (5)				$ 0
Other Significant Noncash Transaction, Payments to Acquire Units				$ (189,520)					$ (251,742)					$ (62,222)
Issuance of Tallgrass Equity units			644,782					644,782
Acquisitions		16,200			$ (44,732)	$ 74,421				$ (50,000)	$ 108,537				$ (5,268)	$ 34,116			$ 0	$ 0
Partners' Capital, Including Portion Attributable to Noncontrolling Interest			2,240,468					2,256,083					15,615				0
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	2,217,108		491,571					2,217,108					1,725,537				0
Net income	102,392		51,805					102,392					50,587				0
Dividends paid to Class A shareholders			0					(81,304)					(81,304)				0
Distributions to noncontrolling interest	(66,625)	$ 0	(66,625)					(66,625)					0				0
Contributions from noncontrolling interest			1,282					1,282					0				0
Noncash compensation expense			0					17,120					17,120				0
TGE LTIP shares tendered by employees to satisfy tax withholding obligations			0					(13,260)					13,260				0
Partners Capital Deferred Tax Asset			0					123,051					123,051				0
Partners' Capital Account, Exchanges and Conversions			(68,614)										68,614
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	$ 2,299,764		$ 409,419					$ 2,299,764					$ 1,890,345				$ 0

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash Flows from Operating Activities:
Net income	$ 102,392	$ 114,313
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	32,799	27,620
Equity in earnings of unconsolidated investments	(88,522)	(68,402)
Distributions from unconsolidated investments	87,940	67,059
Deferred income tax expense	17,066	6,692
Share-based Compensation	17,120	2,814
Other noncash items, net	1,536	(12,024)
Changes in components of working capital
Accounts receivable and other	8,985	(12,013)
Accounts payable and accrued liabilities	(46,186)	16,354
Deferred revenue	12,125	10,750
Other current assets and liabilities	2,026	(1,671)
Other operating, net	(3,533)	108
Net Cash Provided by Operating Activities	143,748	151,600
Cash Flows from Investing Activities:
Capital expenditures	(62,802)	(58,760)
Payments to Acquire Equity Method Investments	(29,797)	(8,034)
Distributions from unconsolidated investments in excess of cumulative earnings	27,158	20,774
Sale of Tallgrass Crude Gathering	0	50,046
Other investing, net	15	(12,439)
Net Cash Used in Investing Activities	(102,426)	(122,913)
Net Cash Used in Financing Activities
Borrowings under revolving credit facilities, net	125,000	133,000
Dividends paid to Class A shareholders	(81,304)	(21,346)
Distributions to noncontrolling interest	(66,625)	(89,073)
Other financing, net	313	394
Net Cash Used in Financing Activities	(35,876)	(27,025)
Net Change in Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents	5,446	1,662
Cash and Cash Equivalents, beginning of period	9,596	2,593
Cash and Cash Equivalents, end of period	15,042	4,255
Supplemental Cash Flow Disclosures
Assets contributed to Powder River Gateway joint venture	(86,891)
Noncash Acquisition, Contribution of membership interest	0	(19,500)
Capital Expenditures Incurred but Not yet Paid	18,874	1,336
Shares Issued	0	644,782
Issuance of noncontrolling interests in Deeprock Development in exchange for 62% membership interest in Deeprock North	0	(31,843)
BNN North Dakota
Cash Flows from Investing Activities:
Payments to Acquire Businesses, Net of Cash Acquired	0	(95,000)
Deeprock North, LLC
Cash Flows from Investing Activities:
Payments to Acquire Assets, Investing Activities	0	(19,500)
Tallgrass Energy Partners
Supplemental Cash Flow Disclosures
Other Significant Noncash Transaction, Value of Consideration Given	0	(251,743)
Pony Express Pipeline
Net Cash Used in Financing Activities
Distributions to noncontrolling interest	0	(50,000)
Rockies Express Pipeline LLC
Supplemental Cash Flow Disclosures
Other Significant Noncash Transaction, Value of Consideration Given	0	(393,039)
Powder River Gateway
Cash Flows from Investing Activities:
Payments to Acquire Equity Method Investments	(37,000)
Iron Horse Pipeline, LLC
Supplemental Cash Flow Disclosures
Noncash Acquisition, Contribution of membership interest	(35,613)
Common Class A
Cash Flows from Operating Activities:
Net income	50,587	16,735
Net Cash Used in Financing Activities
Distributions to noncontrolling interest	0	$ 0
TGE LTIP shares tendered by employees to satisfy tax withholding obligations	$ 13,260

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Description of Business

3 Months Ended

Mar. 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 63.55% membership interest as of March 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 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 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: (1) a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System"), (2) natural gas processing facilities in Casper and Douglas, and (3) a natural gas treating facility at West Frenchie Draw. We also provide NGL transportation services in Northeast Colorado and Wyoming. We perform water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, Wyoming, and North Dakota through BNN Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through our 100% membership interest in Tallgrass Terminals, LLC ("Terminals"), which owns and operates crude oil terminals in Colorado, Oklahoma, and Kansas. The Gathering, Processing & Terminalling segment also includes Stanchion Energy, LLC ("Stanchion"), which transacts in crude oil.

Blackstone Acquisition

On March 11, 2019, pursuant to the terms of the 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, acquisition vehicles controlled by BIP, collectively, the "Sponsor Entities"), 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"), certain of the Sponsor Entities 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 "Blackstone Acquisition").

As a result of the Blackstone Acquisition, BIP effectively controls our business and affairs through the ownership of 100% of the membership interests in our general partner and the exercise of the rights of such sole member. Additionally, the Sponsor Entities collectively held an approximate 43.8% economic interest in us as of March 31, 2019.

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Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2019

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Basis of Presentation

These condensed consolidated financial statements and related notes for the three months ended March 31, 2019 and 2018 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of accounting principles generally accepted in the United States of America ("GAAP") for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three months ended March 31, 2019 and 2018 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.

Our financial results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019. The accompanying condensed consolidated interim financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2018 ("2018 Form 10-K") filed with the SEC on February 8, 2019.

The condensed 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.

Use of Estimates

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

Income Taxes

During the three months ended March 31, 2019, we recognized an additional deferred tax asset of $123.1 million upon exercise of the Exchange Right, as discussed in Note 10 – Partnership Equity, with respect to 21,751,018 Class B shares to Class A shares in connection with the Blackstone Acquisition discussed in Note 1 – Description of Business.

As a result of the increased income allocated to TGE resulting from our increased ownership in TEP following the merger transaction effective June 30, 2018 and the exercise of the Exchange Right effective March 11, 2019, our annual effective tax rate increased from 5.15% for the three months ended March 31, 2018 to 14.77% for the three months ended March 31, 2019.

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 in the Codification intended to increase transparency and comparability among organizations by recognizing right-of-use ("ROU") assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

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 ASC 840. Accordingly, we will not recast comparative periods in the condensed 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 practical expedients related to land easements, allowing us to carry forward our accounting treatment for existing land easements as property, plant and equipment, and short-term leases, allowing us to not recognize ROU assets or lease liabilities for leases with a term of 12 months or less.

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 12 – Leases.

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Acquisitions

3 Months Ended

Mar. 31, 2019

Business Combinations [Abstract]

Acquisitions

Joint Venture with Silver Creek

In February 2018, we entered into an agreement with Silver Creek Midstream, LLC ("Silver Creek") to form Iron Horse Pipeline, LLC ("Iron Horse"), which owns the Iron Horse Pipeline. Effective January 1, 2019, the joint venture between us and Silver Creek was expanded through contributions to Powder River Gateway, a newly formed entity. We contributed our 75% membership interest in Iron Horse, $37 million in cash, and various other assets, including terminal facilities under construction in Guernsey, Wyoming. Silver Creek contributed the PRE Pipeline and related terminal facilities in Guernsey, Wyoming, as well as their 25% membership interest in Iron Horse. Following the expansion of the joint venture, 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 in Powder River Gateway. As the 51% membership interest does not represent a controlling interest in Powder River Gateway, our investment in Powder River Gateway is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the condensed consolidated balance sheets.

Acquisition of Plaquemines Liquids Terminal, LLC

In November 2018, we entered into a joint venture agreement with Drexel Hamilton Infrastructure Fund I, L.P. ("DHIF") to jointly-own Plaquemines Liquids Terminal, LLC ("PLT"). PLT was formed with the intention of entering into agreements to develop a storage and terminalling facility. If developed, the facility is expected to be capable of offering up to 20 million barrels of storage for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers ("VLCC") vessels for international delivery. In connection with our acquisition of a 100% preferred membership interest and a 80% common membership interest in PLT, we recognized liabilities related 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 condensed 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.

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Related Party Transactions

3 Months Ended

Mar. 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:

	Three Months Ended March 31,
	2019		2018
	(in thousands)
Processing and other revenues (1)	$	1,903	$	1,896

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

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

	March 31, 2019		December 31, 2018
	(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	2,839	$	3,447
Powder River Gateway, LLC	512		—
Pawnee Terminal, LLC	129		115
Iron Horse Pipeline, LLC	—		186
Total receivable from related parties	$	3,480	$	3,748

Gas imbalances with affiliated shippers are as follows:

	March 31, 2019		December 31, 2018
	(in thousands)
Affiliate gas imbalance receivables	$	19	$	19
Affiliate gas imbalance payables	$	2,309	$	742

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Inventory

3 Months Ended

Mar. 31, 2019

Inventory Disclosure [Abstract]

Inventory

The components of inventory at March 31, 2019 and December 31, 2018 consisted of the following:

	March 31, 2019		December 31, 2018
	(in thousands)
Crude oil	$	16,803	$	23,205
Materials and supplies	7,666		8,206
Gas in underground storage	2,413		2,740
Natural gas liquids	1,072		165
Total inventory	$	27,954	$	34,316

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Property, Plant and Equipment

3 Months Ended

Mar. 31, 2019

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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

	March 31, 2019			December 31, 2018
	(in thousands)
Crude oil pipelines	$	1,309,763		$	1,313,976
Gathering, processing and terminalling assets	895,552			889,168
Natural gas pipelines	615,495			607,343
General and other (1)	163,206			180,299
Construction work in progress	171,960			191,994
Accumulated depreciation and amortization	(405,601		)	(380,351		)
Total property, plant and equipment, net	$	2,750,375		$	2,802,429

⁽¹⁾  Includes approximately $30.7 million of land associated with the PLT capital lease as discussed in Note 12 – Leases.

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Investments in Unconsolidated Affiliates

3 Months Ended

Mar. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments and Joint Ventures Disclosure

Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our condensed consolidated balance sheets. During the three months ended March 31, 2019, we recognized equity in earnings associated with our 75% membership interest in Rockies Express of $86.2 million, inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $113.4 million and $17.3 million, respectively.

Summarized financial information for Rockies Express is as follows:

	Three Months Ended March 31,
	2019		2018
	(in thousands)
Revenue	$	230,761	$	230,058
Operating income	$	132,410	$	128,678
Net income to Members	$	103,609	$	90,968

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Risk Management

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Risk Management

We enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We have a comprehensive risk management policy 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, including establishing and monitoring exposure limits.

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

Fair Value of Derivative Contracts

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

	Balance Sheet Location	March 31, 2019		December 31, 2018
		(in thousands)
Crude oil derivative contracts (1)	Prepayments and other current assets	$	1,761	$	3,526
Crude oil derivative contracts (2)	Other current liabilities	$	1,129	$	1,642

⁽¹⁾  As of March 31, 2019 and December 31, 2018, the amount shown represents the fair value of crude oil derivative contracts for the forward purchase of 2,135,700 and 2,105,146 barrels of crude oil, respectively, consisting of fixed price and floating price contracts, which will settle throughout 2019.

⁽²⁾  As of March 31, 2019 and December 31, 2018, the amount shown represents the fair value of crude oil derivative contracts for the forward sale of 1,793,000 and 1,274,500 barrels of crude oil, respectively, consisting of fixed price and floating price contracts, which will settle 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 three months ended March 31,2019 and 2018:

	Location of gain recognized in income on derivatives	Amount of gain recognized in income on derivatives
		Three Months Ended March 31,
		2019		2018
		(in thousands)
Crude oil derivative contracts	Sales of natural gas, NGLs, and crude oil	$	11,473	$	4,295

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 March 31, 2019 was:

	Asset Position
	(in thousands)
Gross	$	1,761
Netting agreement impact	—
Cash collateral held	—
Net exposure	$	1,761

As of March 31, 2019, we had $1.1 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 March 31, 2019 and December 31, 2018, based on the fair value hierarchy:

			Asset Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of March 31, 2019:
Crude oil derivative contracts	$	1,761	$	—	$	1,761	$	—
As of December 31, 2018:
Crude oil derivative contracts	$	3,526	$	—	$	3,526	$	—
			Liability Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of March 31, 2019:
Crude oil derivative contracts	$	1,129	$	—	$	1,129	$	—
As of December 31, 2018:
Crude oil derivative contracts	$	1,642	$	—	$	1,642	$	—

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Long-term Debt

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Long-term Debt

Our long-term debt is held at TEP and consisted of the following at March 31, 2019 and December 31, 2018:

	March 31, 2019			December 31, 2018
	(in thousands)
Revolving credit facility	$	1,349,000		$	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)	(20,575		)	(21,421		)
Plus: Unamortized premium on 2028 Notes	3,291			3,379
Total long-term debt, net	$	3,331,716		$	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 is presented in noncurrent assets on our condensed 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, dated as of September 26, 2018, among the Issuers, the Guarantors and Trustee, (ii) the Indenture governing the 5.50% Senior Notes due 2024, 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, 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 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.

As of March 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 our revolving credit facility as of March 31, 2019 and December 31, 2018:

	March 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	(1,349,000		)	(1,224,000		)
Less: Letters of credit issued under the revolving credit facility	(94		)	(94		)
Available capacity under the revolving credit facility	$	900,906		$	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.

In the Consent and Amendment, the required lenders under the Credit Agreement (i) consented to the 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 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 Blackstone Acquisition.

As of March 31, 2019, TEP was in compliance with the covenants required under its revolving credit facility. As of March 31, 2019, the weighted average interest rate on outstanding borrowings under the revolving credit facility was 4.00%. During the three months ended March 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 4.52%.

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 condensed consolidated balance sheets as of March 31, 2019 and December 31, 2018, but for which fair value is disclosed:

	Fair Value
	Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Carrying Amount
	(in thousands)
As of March 31, 2019:
Revolving credit facility	$	—	$	1,349,000	$	—	$	1,349,000	$	1,349,000
2023 Notes	$	—	$	504,325	$	—	$	504,325	$	494,892
2024 Notes	$	—	$	771,923	$	—	$	771,923	$	741,565
2028 Notes	$	—	$	754,253	$	—	$	754,253	$	746,259
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 March 31, 2019 and December 31, 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 March 31, 2019.

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Partnership Equity

3 Months Ended

Mar. 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)
March 31, 2019	May 15, 2019 (1)	$	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

⁽¹⁾  The dividend announced on April 11, 2019 for the first quarter of 2019 will be paid on May 15, 2019 to Class A shareholders of record at the close of business on April 30, 2019.

Exchange Rights

Our current Class B shareholders (collectively, the "Exchange Right Holders") own an equal number of Tallgrass Equity units. The Exchange Right Holders, and any permitted transferees of their Tallgrass Equity units, each have the right to exchange all or a portion of their Tallgrass Equity units for Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us. Upon such exchange, we will cancel the Class B shares received from the exercising party. During the three months ended March 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.

Following the Blackstone Acquisition that closed on March 11, 2019 discussed in Note 1 – Description of Business, the Exchange Rights Holders currently consist of certain of the Sponsor Entities and certain members of our management.

Noncontrolling Interests

As of March 31, 2019, noncontrolling interests in our subsidiaries consisted of a 36.45% 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, LLC ("Deeprock Development"), an approximate 25% membership interest in BNN West Texas, LLC ("West Texas"), and a 37% membership interest in BNN Colorado Water, LLC ("BNN Colorado"). During the three months ended March 31, 2019, we recognized contributions from and distributions to noncontrolling interests of $1.3 million and $66.6 million, respectively. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $64.4 million and distributions to Deeprock Development and West Texas noncontrolling interests of $2.2 million.

During the three months ended March 31, 2018, we recognized contributions from and made distributions to noncontrolling interests of $0.2 million and $89.1 million, respectively. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $51.3 million, Tallgrass Equity distributions to the Exchange Right Holders of $36.4 million and distributions to Deeprock Development and Pony Express noncontrolling interests of $1.3 million.

Other Contributions and Distributions

During the three months ended March 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.

Share-Based Compensation

The 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 condensed consolidated statements of income during the three months ended March 31, 2019. In addition, 1,767,100 Equity Participation Shares with a weighted average grant date fair value of $15.20 were granted during the three months ended March 31, 2019.

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Revenue from Contracts with Customers

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customers

Disaggregated Revenue

A summary of our revenue by line of business is as follows:

	Three Months Ended March 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	$	—	$	95,277	$	—	$	—		$	95,277
Natural gas transportation - firm service	32,521		—		—		(396		)	32,125
Water business services	—		—		18,286		—			18,286
Natural gas gathering & processing fees	—		—		6,080		—			6,080
All other (1)	3,321		14,507		3,520		(17,034		)	4,314
Total service revenue	35,842		109,784		27,886		(17,430		)	156,082
Natural gas liquids sales	—		—		16,871		—			16,871
Natural gas sales	—		—		10,401		—			10,401
Crude oil sales	—		—		119		—			119
Total commodity sales revenue	—		—		27,391		—			27,391
Total revenue from contracts with customers	35,842		109,784		55,277		(17,430		)	183,473
Other revenue (2)	—		—		18,757		(4,878		)	13,879
Total revenue (3)	$	35,842	$	109,784	$	74,034	$	(22,308	)	$	197,352

	Three Months Ended March 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	$	—	$	84,738	$	—	$	—		$	84,738
Natural gas transportation - firm service	33,334		—		—		(1,883		)	31,451
Water business services	—		—		13,204		—			13,204
Natural gas gathering & processing fees	—		—		5,044		—			5,044
All other (1)	2,630		3,319		5,706		(6,088		)	5,567
Total service revenue	35,964		88,057		23,954		(7,971		)	140,004
Natural gas liquids sales	—		—		23,609		—			23,609
Natural gas sales	238		—		7,847		—			8,085
Crude oil sales	—		1,909		247		—			2,156
Total commodity sales revenue	238		1,909		31,703		—			33,850
Total revenue from contracts with customers	36,202		89,966		55,657		(7,971		)	173,854
Other revenue (2)	—		—		8,181		(2,941		)	5,240
Total revenue (3)	$	36,202	$	89,966	$	63,838	$	(10,912	)	$	179,094

⁽¹⁾  Includes revenue from crude oil transportation walk up shippers, crude oil terminal services, interruptible natural gas transportation and storage, and natural gas park and loan service.

⁽²⁾  Includes lease and derivative revenue not subject to ASC 606.

⁽³⁾  Excludes revenue recognized at unconsolidated investments, including $230.8 million and $230.1 million of revenue recognized at Rockies Express for the three months ended March 31, 2019 and 2018, respectively. See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express.

Performance Obligations

On March 31, 2019, we had $1.5 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 the remainder of 2019 and future periods as follows (in thousands):

Year	Estimated Revenue
2019 – remaining	$	439,404
2020	367,732
2021	175,919
2022	171,033
2023	150,810
Thereafter	240,961
Total	$	1,545,859

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 condensed consolidated balance sheets. Revenue is generally billed and collected monthly based on services provided or commodity volumes sold. In our Crude Oil Transportation segment, we recognize shipper deficiencies, or deferred revenue, for barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers' agreed upon destination point. These shipper deficiencies are charged at the committed tariff rate per barrel and recorded as a contract liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes remote. We also recognize contract liabilities, in the form of deferred revenue, under certain water business services contracts in the Gathering, Processing & Terminalling segment. Contract balances were as follows:

	March 31, 2019		December 31, 2018
	(in thousands)
Accounts receivable from contracts with customers	$	79,855	$	80,935
Other accounts receivable (1)	143,949		151,414
Receivable from related parties	3,480		3,748
Accounts receivable, net	$	227,284	$	236,097
Deferred revenue from contracts with customers (2)	$	123,184	$	111,095

⁽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.

⁽²⁾  Revenue recognized during the three months ended March 31, 2019 that was included in the deferred revenue balance at the beginning of the period was $1.6 million. This revenue primarily represented the utilization of shipper deficiencies at Pony Express.

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Net Income per Class A Share

3 Months Ended

Mar. 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 TGE's outstanding Class B shares and an equivalent number of Tallgrass Equity units. The Exchange Right Holders are entitled to exercise the right to exchange their Tallgrass Equity units (together with an equivalent number of TGE Class B shares) for TGE Class A shares at an exchange ratio of one TGE Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. As of March 31, 2019, the Exchange Right Holders primarily consist of certain of the Sponsor Entities and certain 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 Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other hand. As a result, the exchange of any Class B shares for Class A shares does not have a dilutive effect on basic net income per Class A share. However, for the three months ended March 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 following table illustrates the calculation of net income per Class A share for the three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018
	(in thousands, except per unit amounts)
Basic Net Income per Class A Share
Net income attributable to TGE	$	50,587	$	16,735
Basic weighted average Class A Shares outstanding	161,425		58,085
Basic net income per Class A share	$	0.31	$	0.29
Diluted Net Income per Class A Share
Net income attributable to TGE	$	50,587	$	16,735
Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares	206		69
Net income attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares	$	50,793	$	16,804
Basic weighted average Class A Shares outstanding	161,425		58,085
Equity Participation Shares equivalent shares	1,352		125
Diluted weighted average Class A Shares outstanding	162,777		58,210
Diluted net income per Class A Share	$	0.31	$	0.29

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Regulatory Matters

3 Months Ended

Mar. 31, 2019

Regulated Operations [Abstract]

Regulatory Matters

There are no regulatory proceedings challenging the rates of Pony Express and Rockies Express. On May 1, 2019, as further described below, TIGT filed with the FERC a pre–filing settlement that establishes, among other things, settlement rates for supporting/non–contesting participants as defined in the pre–filing settlement. On June 29, 2018, Trailblazer Pipeline Company LLC ("Trailblazer") filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act ("NGA"), as further described below. We have also made certain regulatory filings with the FERC, including the following:

Rockies Express

Cheyenne Hub Enhancement Project - FERC Docket No. CP18-103-000

On March 2, 2018, Rockies Express submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub. Rockies Express filed this certificate application in conjunction with a concurrently filed certificate application by Cheyenne Connector, LLC ("Cheyenne Connector") for the Cheyenne Connector Pipeline Project further described below. The comment period for the Cheyenne Hub Enhancement Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Rockies Express has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment. The application is pending before the FERC.

Rockies Express Form No. 501-G Filing - FERC Docket No. RP19-412-000

On December 6, 2018, Rockies Express submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. On March 20, 2019, the FERC issued an order finding that Rockies Express complied with the reporting requirement and terminated the proceeding.

2019 Annual FERC Fuel Tracking Filing - FERC Docket No. RP19-786-000

On February 28, 2019, in Docket No. RP19-786-000, Rockies Express made its annual fuel and power cost tracker filing. The FERC issued an order accepting the filing on March 29, 2019.

Cheyenne Connector

Cheyenne Connector Pipeline Project - FERC Docket No. CP18-102-000

On March 2, 2018, Cheyenne Connector, an indirect subsidiary of TGE, submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity to construct and operate a 70-mile 36 inch pipeline to transport natural gas from multiple gas processing plants in Weld County, Colorado to Rockies Express' Cheyenne Hub. The comment period for the Cheyenne Connector Pipeline Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Cheyenne Connector has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment. The application is pending before the FERC.

TIGT

TIGT Form No. 501-G Filing - FERC Docket No. RP19-423-000

On December 6, 2018, TIGT submitted its one-time informational filing in compliance with Order No. 849, which required interstate natural gas pipelines to make a one-time informational filing on the rate effect of the changes in tax laws and policy following the Tax Cuts and Jobs Act and the FERC's changes to its Income Tax Policy Statement following the decision of the U.S. Court of Appeals for the D.C. Circuit in United Airlines, Inc. v. FERC in 2016. On December 18, 2018, one protest and one set of comments were filed by intervenors in the docket. The filing remains pending before the FERC.

2019 Annual Fuel Tracker Filing - FERC Docket No. RP19-715-000

On February 27, 2019, in Docket No. RP19-715-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2019. The FERC accepted the filing on March 22, 2019.

Pre-Filing Settlement - FERC Docket No. RP19-423-001

On May 1, 2019, TIGT filed a pre-filing settlement that, consistent with Article II.B.1 of the Docket No. RP16-137-000 settlement, satisfies TIGT's mandatory filing requirement under Article IIB.1 of such settlement. The pre-filing settlement establishes, inter alia, settlement rates reflecting an overall decrease to recourse rates, contract extensions for maximum recourse rate firm contracts through May 31, 2023, and a moratorium, as well as requires that TIGT file a new NGA Section 4 general rate case 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.

Trailblazer

General Rate Case Filing - FERC Docket No. RP18-922-000, et seq.

On June 29, 2018, Trailblazer filed a general rate case with the FERC, which satisfies the requirement set forth in the settlement resolving Trailblazer's previous general rate case that Trailblazer file a new general rate case with rates to be effective no later than January 1, 2019. The June 29, 2018 filing reflects an overall increase to Trailblazer's cost of service. In the filing, Trailblazer is proposing to maintain its existing bifurcated firm transportation service rate design as well as its current tracking methodologies for the treatment of Fuel and Lost and Unaccounted For ("FL&U") gas and electric power costs. The proposed rates include an increase in rates on Trailblazer's Existing System Firm Transportation Service. The overall rate increase would be partially offset by a proposed decrease in rates for Expansion System Firm Transportation Service and interruptible services. Trailblazer is also proposing to include a cost recovery mechanism in its tariff to recover future eligible costs related to system safety, integrity, reliability, environmental and cybersecurity issues. Under the NGA and the FERC's regulations, Trailblazer's shippers and other interested parties, including the FERC's Trial Staff, have the right to challenge any aspect of Trailblazer's rate case filing. On July 11, 2018, four protests were filed that challenge various aspects of Trailblazer's rate case filing. FERC action remains pending.

On July 31, 2018, the FERC issued an Order accepting and suspending the rate case filing, and establishing hearing and settlement procedures. In the Order, the FERC approved the as-filed rate decreases for Expansion System Firm Transportation Service, as well as Trailblazer's interruptible services, effective August 1, 2018. The Commission also established a paper hearing to examine the extent to which Trailblazer is entitled to an income tax allowance. All remaining issues, including the proposed rate increases to Existing System Firm Transportation Service have been set for hearing and are accepted effective January 1, 2019, subject to refund. On August 30, 2018, Trailblazer and certain of Trailblazer's shippers filed a request for rehearing of the July 31, 2018 Order, which remains pending before the FERC. Consistent with the July 31, 2018 Order, on August 30, 2018, certain of Trailblazer's shippers and other interested parties filed initial briefs regarding the Income Tax Allowance issue. Trailblazer filed its reply brief regarding the same on September 14, 2018. On November 1, 2018, Trailblazer filed a supplement to its reply brief addressing a recent FERC order regarding the appropriate methodology used to calculate return on equity and discussing the impact of such order on Trailblazer's proposed Income Tax Allowance.

On February 21, 2019, the FERC issued an Order stating a preliminary finding that a double recovery appears to result from permitting an income tax allowance for the income tax liability attributable to certain private owners' ownership share in Trailblazer in addition to a discounted cash flow return on equity. The FERC also preliminary found that no double recovery resulted from permitting an income tax allowance for the corporate income tax liability attributable to TGE's ownership share in Trailblazer in addition to a discounted cash flow return on equity. The FERC emphasized that the findings are preliminary and may change based upon subsequent evidence and argument. The FERC ordered that the income tax allowance be addressed at the hearing with the other remaining issues. On February 22, 2019, the Chief Administrative Law Judge issued an order directing the ongoing settlement judge procedures and any subsequent hearing in the proceeding to address all income tax allowance issues. 

On August 28, 2018, the participants attended an initial settlement conference. On November 15, 2018, the participants attended a second settlement conference. On December 31, 2018, Trailblazer filed a motion with the FERC to move the suspended tariff records into effect as of January 1, 2019. In January 2019, the participants attended a third settlement conference. In February 2019, the participants attended a fourth settlement conference. On February 14, 2019, Trailblazer filed its 45-day update. On March 14, 2019, the Chief Administrative Law Judge issued an order terminating settlement judge procedures, designating a Presiding Judge for the purpose of conducting a hearing and issuing an initial decision, establishing Track III procedural time standards for the hearing and directing that a prehearing conference be convened within 15 days of the date of the order. On March 19, 2019, the Presiding Judge issued an order to convene the prehearing conference on March 26, 2019. Following the prehearing conference, on March 28, 2019, the Presiding Judge issued an order establishing a procedural schedule and hearing rules in connection with the Chief Administrative Law Judge's March 28, 2019 order extending the Track III procedural deadlines.

2019 Annual Fuel Tracker Filing - FERC Docket No. RP19-888-000

On March 25, 2019, in Docket No. RP19-888-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2018. The FERC accepted the filing on April 18, 2019.

Pony Express

On January 11, 2019, Pony Express filed with the FERC in Docket No. IS19-145-000 certain changes to its tariffs to incorporate the Sterling origin point in Logan County, Colorado in the published rate schedules, to establish a line fill return rate from the Natoma origin point, and to make minor clarifying edits.

Iron Horse

Petition for Declaratory Order - FERC Docket No. OR19-9-000

On November 9, 2018, Iron Horse filed a Petition for Declaratory Order with the FERC, requesting approval of Iron Horse's proposed rate structures, Committed Shipper rights, and prorationing provisions for shippers and various other aspects of the Transportation Service Agreement for service on the pipeline. The FERC granted the Petition on April 11, 2019.

Baseline Tariff Filing - FERC Docket No. IS19-274-000

On April 1, 2019, Iron Horse filed certain baseline tariffs with the FERC, each with an effective date of May 1, 2019.

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Legal and Environmental Matters

3 Months Ended

Mar. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Legal and Environmental Matters

Legal

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

We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, have recorded no reserve for legal claims as of March 31, 2019 or December 31, 2018.

Rockies Express

Ohio Public Utility Excise Tax

The Ohio Tax Commissioner has assessed Rockies Express a public utility excise tax on transactions concerning product that entered and exited Rockies Express within the state of Ohio. This tax applies to gross receipts from all business conducted within the state, but exempts all receipts derived wholly from interstate business. Rockies Express has disputed any obligation to pay Ohio's public utility excise tax, but has paid the taxes as assessed in order to preserve its right to appeal. The dispute is currently pending before the Ohio Supreme Court, with a final decision possible by the end of 2019. It is Rockies Express' position that the relevant statute exempts receipts derived wholly from interstate business from the public utility excise tax. The Ohio Supreme Court and the United States Supreme Court have both held that, once it enters an interstate pipeline, natural gas is moving in "interstate commerce" for the duration of its journey until it is delivered to a local distribution system.

As of March 31, 2019, Rockies Express has paid public utility excise taxes to the state of Ohio totaling $7.1 million and has accrued an additional $4.6 million for amounts expected to be assessed for the period from May 1, 2018 through March 31, 2019. While it is difficult to accurately predict how the Ohio Supreme Court will decide the case, Rockies Express is optimistic about the ultimate outcome and has recorded a $11.7 million asset representing the anticipated refund of the public utility excise taxes paid.

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 $6.8 million and $7.4 million at March 31, 2019 and December 31, 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 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

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.

TMG

Archibald Booster Station

Tallgrass Midstream Gathering, LLC ("TMG") is currently a party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Archibald Booster Station located in Campbell County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling, and quarterly recovery activities at monitoring wells. The facility is currently in compliance with the WDEQ under the remedy agreement.

Irwin Booster Station

TMG is also party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Irwin Booster Station located in Converse County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling. The facility is currently in compliance with the WDEQ under the remedy agreement.

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Reporting Segments

3 Months Ended

Mar. 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.

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:

	Three Months Ended March 31, 2019							Three Months Ended March 31, 2018
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Natural Gas Transportation	$	35,842	$	(414	)	$	35,428	$	36,202	$	(1,858	)	$	34,344
Crude Oil Transportation	109,784		(14,422		)	95,362		89,966		(3,319		)	86,647
Gathering, Processing & Terminalling	74,034		(7,472		)	66,562		63,838		(5,735		)	58,103
Total revenue	$	219,660	$	(22,308	)	$	197,352	$	190,006	$	(10,912	)	$	179,094

	Three Months Ended March 31, 2019									Three Months Ended March 31, 2018
Tallgrass Equity Adjusted EBITDA:	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA
	(in thousands)
Natural Gas Transportation	$	138,868		$	(905	)	$	137,963		$	70,652		$	(735	)	$	69,917
Crude Oil Transportation	80,741			(6,160		)	74,581			34,871			1,386			36,257
Gathering, Processing & Terminalling	27,910			7,065			34,975			10,156			(651		)	9,505
Corporate and Other	(1,794		)	—			(1,794		)	(12,269		)	—			(12,269		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investments (1)							88,522									32,413
Gain on disposal of assets (1)							—									3,212
Less:
Interest expense, net (1)							(39,710		)							(10,786		)
Depreciation and amortization expense (1)							(30,728		)							(8,496		)
Distributions from unconsolidated investments (1)							(115,098		)							(43,491		)
Non-cash compensation expense (1)							(17,120		)							(962		)
Deficiency payments, net (1)							(12,144		)							(3,780		)
Non-cash (loss) gain related to derivative instruments (1)							(1,252		)							872
Deferred income tax expense							(17,066		)							(6,692		)
Net income attributable to Exchange Right Holders							(50,542		)							(48,965		)
Net income attributable to TGE							$	50,587								$	16,735

⁽¹⁾  Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.

	Three Months Ended March 31,
Capital Expenditures:	2019		2018
	(in thousands)
Natural Gas Transportation	$	16,346	$	9,885
Crude Oil Transportation	17,016		16,952
Gathering, Processing & Terminalling	27,814		31,139
Corporate and Other	1,626		784
Total capital expenditures	$	62,802	$	58,760

Assets:	March 31, 2019		December 31, 2018
	(in thousands)
Natural Gas Transportation	$	2,608,355	$	2,606,696
Crude Oil Transportation	1,711,706		1,423,740
Gathering, Processing & Terminalling	1,471,995		1,522,559
Corporate and Other	277,169		340,514
Total assets	$	6,069,225	$	5,893,509

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Subsequent Events

3 Months Ended

Mar. 31, 2019

Subsequent Events [Abstract]

Subsequent Events

Rockies Express Senior Notes Offering

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.

Acquisition of Central Environmental Services

On April 24, 2019, BNN Eastern, LLC ("BNN Eastern"), an 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, or CES). CES owns a salt water disposal facility located in the Utica and Marcellus area of Ohio. On May 1, 2019, the acquisition closed for total purchase consideration of approximately $52 million paid at closing, and a seller in the transaction received a 7.65% membership interest in BNN Eastern. In addition to the consideration paid at closing, the transaction includes a potential earn out payment to the sellers of approximately $3 million, which is payable in cash or in additional membership interests in BNN Eastern. The initial accounting for the transaction is not yet complete as management does not have the information necessary to prepare pro forma financial information or value the assets acquired and liabilities assumed.

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Leases

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Leases

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 an agreement 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 most of 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 40 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 three months ended March 31, 2019, operating lease cost and cash paid included in operating cash flows was $0.2 million. During this period the existing finance lease did not have any lease payments or variable lease cost.

Supplemental information related to our existing leases as of March 31, 2019 was as follows:

	Balance Sheet Location	March 31, 2019
Operating Leases:		(in thousands, except lease term and discount rate)
Operating lease right-of-use assets	Deferred charges and other assets	$	2,171
Current operating lease liabilities	Other current liabilities	$	603
Non-current operating lease liabilities	Other long-term liabilities and deferred credits	$	1,568
Finance Leases:
Finance lease right-of-use asset (1)	Property, plant and equipment, net	$	30,704
Weighted Average Remaining Lease Term:
Operating leases		4.6 years
Finance leases		39.7 years
Weighted Average Discount Rate:
Operating leases		4.63		%
Finance leases		7.01		%

⁽¹⁾ 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 March 31, 2019 were as follows:

Year	Operating Leases			Finance Leases (1)
	(in thousands)
2019 – remaining	$	683		$	449
2020	956			449
2021	506			449
2022	240			449
2023	147			449
Thereafter	364			17,770
Total lease payments	2,896			20,015
Less: discounting for present value and other adjustments	(725		)	(20,015		)
Present value of lease liabilities	$	2,171		$	—

⁽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 recognize expense 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 $2.4 million for the three months ended March 31, 2019 and was recorded as "Processing and other revenues" in the condensed 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 $0.2 million for the three months ended March 31, 2019 and was recorded as "Other income, net" in the condensed consolidated statements of income.

At March 31, 2019, future minimum rental income under non-cancelable operating leases as the lessor were as follows:

Year	Total
	(in thousands)
2019 - remaining	$	5,850
2020	3,952
2021	3,773
2022	3,773
2023	3,773
Thereafter	7,353
Total	$	28,474

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

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2019

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

These condensed consolidated financial statements and related notes for the three months ended March 31, 2019 and 2018 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of accounting principles generally accepted in the United States of America ("GAAP") for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three months ended March 31, 2019 and 2018 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.

Our financial results for the three months ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019. The accompanying condensed consolidated interim financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2018 ("2018 Form 10-K") filed with the SEC on February 8, 2019.

Consolidation

The condensed 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.

Use of Estimates

Use of Estimates

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

Income Tax, Policy

Income Taxes

During the three months ended March 31, 2019, we recognized an additional deferred tax asset of $123.1 million upon exercise of the Exchange Right, as discussed in Note 10 – Partnership Equity, with respect to 21,751,018 Class B shares to Class A shares in connection with the Blackstone Acquisition discussed in Note 1 – Description of Business.

As a result of the increased income allocated to TGE resulting from our increased ownership in TEP following the merger transaction effective June 30, 2018 and the exercise of the Exchange Right effective March 11, 2019, our annual effective tax rate increased from 5.15% for the three months ended March 31, 2018 to 14.77% for the three months ended March 31, 2019.

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 in the Codification intended to increase transparency and comparability among organizations by recognizing right-of-use ("ROU") assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

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 ASC 840. Accordingly, we will not recast comparative periods in the condensed 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 practical expedients related to land easements, allowing us to carry forward our accounting treatment for existing land easements as property, plant and equipment, and short-term leases, allowing us to not recognize ROU assets or lease liabilities for leases with a term of 12 months or less.

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 12 – Leases.

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Leases - (Policies)

3 Months Ended

Mar. 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 most of 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.

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Related Party Transactions (Tables)

3 Months Ended

Mar. 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:

	Three Months Ended March 31,
	2019		2018
	(in thousands)
Processing and other revenues (1)	$	1,903	$	1,896

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

Schedule of Balances with Affiliates Included in Consolidated Balance Sheets

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

	March 31, 2019		December 31, 2018
	(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	2,839	$	3,447
Powder River Gateway, LLC	512		—
Pawnee Terminal, LLC	129		115
Iron Horse Pipeline, LLC	—		186
Total receivable from related parties	$	3,480	$	3,748

Schedule of Balances of Gas Imbalance with Affiliated Shippers

Gas imbalances with affiliated shippers are as follows:

	March 31, 2019		December 31, 2018
	(in thousands)
Affiliate gas imbalance receivables	$	19	$	19
Affiliate gas imbalance payables	$	2,309	$	742

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Inventory - (Tables)

3 Months Ended

Mar. 31, 2019

Inventory Disclosure [Abstract]

Schedule of Components of Inventory

The components of inventory at March 31, 2019 and December 31, 2018 consisted of the following:

	March 31, 2019		December 31, 2018
	(in thousands)
Crude oil	$	16,803	$	23,205
Materials and supplies	7,666		8,206
Gas in underground storage	2,413		2,740
Natural gas liquids	1,072		165
Total inventory	$	27,954	$	34,316

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 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:

	March 31, 2019			December 31, 2018
	(in thousands)
Crude oil pipelines	$	1,309,763		$	1,313,976
Gathering, processing and terminalling assets	895,552			889,168
Natural gas pipelines	615,495			607,343
General and other (1)	163,206			180,299
Construction work in progress	171,960			191,994
Accumulated depreciation and amortization	(405,601		)	(380,351		)
Total property, plant and equipment, net	$	2,750,375		$	2,802,429

⁽¹⁾  Includes approximately $30.7 million of land associated with the PLT capital lease as discussed in Note 12 – Leases.

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Investments in Unconsolidated Affiliates - (Tables)

3 Months Ended

Mar. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Summarized financial information for Rockies Express is as follows:

	Three Months Ended March 31,
	2019		2018
	(in thousands)
Revenue	$	230,761	$	230,058
Operating income	$	132,410	$	128,678
Net income to Members	$	103,609	$	90,968

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Risk Management (Tables)

3 Months Ended

Mar. 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 condensed consolidated balance sheets:

	Balance Sheet Location	March 31, 2019		December 31, 2018
		(in thousands)
Crude oil derivative contracts (1)	Prepayments and other current assets	$	1,761	$	3,526
Crude oil derivative contracts (2)	Other current liabilities	$	1,129	$	1,642

⁽¹⁾  As of March 31, 2019 and December 31, 2018, the amount shown represents the fair value of crude oil derivative contracts for the forward purchase of 2,135,700 and 2,105,146 barrels of crude oil, respectively, consisting of fixed price and floating price contracts, which will settle throughout 2019.

⁽²⁾  As of March 31, 2019 and December 31, 2018, the amount shown represents the fair value of crude oil derivative contracts for the forward sale of 1,793,000 and 1,274,500 barrels of crude oil, respectively, consisting of fixed price and floating price contracts, which will settle 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 three months ended March 31,2019 and 2018:

	Location of gain recognized in income on derivatives	Amount of gain recognized in income on derivatives
		Three Months Ended March 31,
		2019		2018
		(in thousands)
Crude oil derivative contracts	Sales of natural gas, NGLs, and crude oil	$	11,473	$	4,295

Derivative Instruments Maximum Potential Exposure to Credit Loss

The maximum potential exposure to credit losses on our crude oil derivative contracts at March 31, 2019 was:

	Asset Position
	(in thousands)
Gross	$	1,761
Netting agreement impact	—
Cash collateral held	—
Net exposure	$	1,761

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 March 31, 2019 and December 31, 2018, based on the fair value hierarchy:

			Asset Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of March 31, 2019:
Crude oil derivative contracts	$	1,761	$	—	$	1,761	$	—
As of December 31, 2018:
Crude oil derivative contracts	$	3,526	$	—	$	3,526	$	—
			Liability Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of March 31, 2019:
Crude oil derivative contracts	$	1,129	$	—	$	1,129	$	—
As of December 31, 2018:
Crude oil derivative contracts	$	1,642	$	—	$	1,642	$	—

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Long-term Debt (Tables)

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Schedule of Debt

Our long-term debt is held at TEP and consisted of the following at March 31, 2019 and December 31, 2018:

	March 31, 2019			December 31, 2018
	(in thousands)
Revolving credit facility	$	1,349,000		$	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)	(20,575		)	(21,421		)
Plus: Unamortized premium on 2028 Notes	3,291			3,379
Total long-term debt, net	$	3,331,716		$	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 is presented in noncurrent assets on our condensed consolidated balance sheets.

Schedule of Line of Credit Facility

The following table sets forth the available borrowing capacity under our revolving credit facility as of March 31, 2019 and December 31, 2018:

	March 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	(1,349,000		)	(1,224,000		)
Less: Letters of credit issued under the revolving credit facility	(94		)	(94		)
Available capacity under the revolving credit facility	$	900,906		$	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 condensed consolidated balance sheets as of March 31, 2019 and December 31, 2018, but for which fair value is disclosed:

	Fair Value
	Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Carrying Amount
	(in thousands)
As of March 31, 2019:
Revolving credit facility	$	—	$	1,349,000	$	—	$	1,349,000	$	1,349,000
2023 Notes	$	—	$	504,325	$	—	$	504,325	$	494,892
2024 Notes	$	—	$	771,923	$	—	$	771,923	$	741,565
2028 Notes	$	—	$	754,253	$	—	$	754,253	$	746,259
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

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Partnership Equity - Dividends Declared (Tables)

3 Months Ended

Mar. 31, 2019

Equity [Abstract]

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)
March 31, 2019	May 15, 2019 (1)	$	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

⁽¹⁾  The dividend announced on April 11, 2019 for the first quarter of 2019 will be paid on May 15, 2019 to Class A shareholders of record at the close of business on April 30, 2019.

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Revenue from Contracts with Customers - (Tables)

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

A summary of our revenue by line of business is as follows:

	Three Months Ended March 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	$	—	$	95,277	$	—	$	—		$	95,277
Natural gas transportation - firm service	32,521		—		—		(396		)	32,125
Water business services	—		—		18,286		—			18,286
Natural gas gathering & processing fees	—		—		6,080		—			6,080
All other (1)	3,321		14,507		3,520		(17,034		)	4,314
Total service revenue	35,842		109,784		27,886		(17,430		)	156,082
Natural gas liquids sales	—		—		16,871		—			16,871
Natural gas sales	—		—		10,401		—			10,401
Crude oil sales	—		—		119		—			119
Total commodity sales revenue	—		—		27,391		—			27,391
Total revenue from contracts with customers	35,842		109,784		55,277		(17,430		)	183,473
Other revenue (2)	—		—		18,757		(4,878		)	13,879
Total revenue (3)	$	35,842	$	109,784	$	74,034	$	(22,308	)	$	197,352

	Three Months Ended March 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	$	—	$	84,738	$	—	$	—		$	84,738
Natural gas transportation - firm service	33,334		—		—		(1,883		)	31,451
Water business services	—		—		13,204		—			13,204
Natural gas gathering & processing fees	—		—		5,044		—			5,044
All other (1)	2,630		3,319		5,706		(6,088		)	5,567
Total service revenue	35,964		88,057		23,954		(7,971		)	140,004
Natural gas liquids sales	—		—		23,609		—			23,609
Natural gas sales	238		—		7,847		—			8,085
Crude oil sales	—		1,909		247		—			2,156
Total commodity sales revenue	238		1,909		31,703		—			33,850
Total revenue from contracts with customers	36,202		89,966		55,657		(7,971		)	173,854
Other revenue (2)	—		—		8,181		(2,941		)	5,240
Total revenue (3)	$	36,202	$	89,966	$	63,838	$	(10,912	)	$	179,094

⁽¹⁾  Includes revenue from crude oil transportation walk up shippers, crude oil terminal services, interruptible natural gas transportation and storage, and natural gas park and loan service.

⁽²⁾  Includes lease and derivative revenue not subject to ASC 606.

⁽³⁾  Excludes revenue recognized at unconsolidated investments, including $230.8 million and $230.1 million of revenue recognized at Rockies Express for the three months ended March 31, 2019 and 2018, respectively. See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express.

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

We expect to recognize the total backlog during the remainder of 2019 and future periods as follows (in thousands):

Year	Estimated Revenue
2019 – remaining	$	439,404
2020	367,732
2021	175,919
2022	171,033
2023	150,810
Thereafter	240,961
Total	$	1,545,859

Contract with Customer, Asset and Liability

Contract balances were as follows:

	March 31, 2019		December 31, 2018
	(in thousands)
Accounts receivable from contracts with customers	$	79,855	$	80,935
Other accounts receivable (1)	143,949		151,414
Receivable from related parties	3,480		3,748
Accounts receivable, net	$	227,284	$	236,097
Deferred revenue from contracts with customers (2)	$	123,184	$	111,095

⁽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.

⁽²⁾  Revenue recognized during the three months ended March 31, 2019 that was included in the deferred revenue balance at the beginning of the period was $1.6 million. This revenue primarily represented the utilization of shipper deficiencies at Pony Express.

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Net Income per Class A Share (Tables)

3 Months Ended

Mar. 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 three months ended March 31, 2019 and 2018:

	Three Months Ended March 31,
	2019		2018
	(in thousands, except per unit amounts)
Basic Net Income per Class A Share
Net income attributable to TGE	$	50,587	$	16,735
Basic weighted average Class A Shares outstanding	161,425		58,085
Basic net income per Class A share	$	0.31	$	0.29
Diluted Net Income per Class A Share
Net income attributable to TGE	$	50,587	$	16,735
Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares	206		69
Net income attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares	$	50,793	$	16,804
Basic weighted average Class A Shares outstanding	161,425		58,085
Equity Participation Shares equivalent shares	1,352		125
Diluted weighted average Class A Shares outstanding	162,777		58,210
Diluted net income per Class A Share	$	0.31	$	0.29

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Reporting Segments (Tables)

3 Months Ended

Mar. 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:

	Three Months Ended March 31, 2019							Three Months Ended March 31, 2018
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Natural Gas Transportation	$	35,842	$	(414	)	$	35,428	$	36,202	$	(1,858	)	$	34,344
Crude Oil Transportation	109,784		(14,422		)	95,362		89,966		(3,319		)	86,647
Gathering, Processing & Terminalling	74,034		(7,472		)	66,562		63,838		(5,735		)	58,103
Total revenue	$	219,660	$	(22,308	)	$	197,352	$	190,006	$	(10,912	)	$	179,094

Summary of TGE's Segment Information of Earnings

	Three Months Ended March 31, 2019									Three Months Ended March 31, 2018
Tallgrass Equity Adjusted EBITDA:	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA
	(in thousands)
Natural Gas Transportation	$	138,868		$	(905	)	$	137,963		$	70,652		$	(735	)	$	69,917
Crude Oil Transportation	80,741			(6,160		)	74,581			34,871			1,386			36,257
Gathering, Processing & Terminalling	27,910			7,065			34,975			10,156			(651		)	9,505
Corporate and Other	(1,794		)	—			(1,794		)	(12,269		)	—			(12,269		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investments (1)							88,522									32,413
Gain on disposal of assets (1)							—									3,212
Less:
Interest expense, net (1)							(39,710		)							(10,786		)
Depreciation and amortization expense (1)							(30,728		)							(8,496		)
Distributions from unconsolidated investments (1)							(115,098		)							(43,491		)
Non-cash compensation expense (1)							(17,120		)							(962		)
Deficiency payments, net (1)							(12,144		)							(3,780		)
Non-cash (loss) gain related to derivative instruments (1)							(1,252		)							872
Deferred income tax expense							(17,066		)							(6,692		)
Net income attributable to Exchange Right Holders							(50,542		)							(48,965		)
Net income attributable to TGE							$	50,587								$	16,735

⁽¹⁾  Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.

Summary of TGE's Segment Information of Capital Expenditures

	Three Months Ended March 31,
Capital Expenditures:	2019		2018
	(in thousands)
Natural Gas Transportation	$	16,346	$	9,885
Crude Oil Transportation	17,016		16,952
Gathering, Processing & Terminalling	27,814		31,139
Corporate and Other	1,626		784
Total capital expenditures	$	62,802	$	58,760

Summary of TGE's Segment Information of Assets

Assets:	March 31, 2019		December 31, 2018
	(in thousands)
Natural Gas Transportation	$	2,608,355	$	2,606,696
Crude Oil Transportation	1,711,706		1,423,740
Gathering, Processing & Terminalling	1,471,995		1,522,559
Corporate and Other	277,169		340,514
Total assets	$	6,069,225	$	5,893,509

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Leases - (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Lessee, Operating Leases

Supplemental information related to our existing leases as of March 31, 2019 was as follows:

	Balance Sheet Location	March 31, 2019
Operating Leases:		(in thousands, except lease term and discount rate)
Operating lease right-of-use assets	Deferred charges and other assets	$	2,171
Current operating lease liabilities	Other current liabilities	$	603
Non-current operating lease liabilities	Other long-term liabilities and deferred credits	$	1,568
Finance Leases:
Finance lease right-of-use asset (1)	Property, plant and equipment, net	$	30,704
Weighted Average Remaining Lease Term:
Operating leases		4.6 years
Finance leases		39.7 years
Weighted Average Discount Rate:
Operating leases		4.63		%
Finance leases		7.01		%

⁽¹⁾ 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.

Lessee, Finance Leases

Supplemental information related to our existing leases as of March 31, 2019 was as follows:

	Balance Sheet Location	March 31, 2019
Operating Leases:		(in thousands, except lease term and discount rate)
Operating lease right-of-use assets	Deferred charges and other assets	$	2,171
Current operating lease liabilities	Other current liabilities	$	603
Non-current operating lease liabilities	Other long-term liabilities and deferred credits	$	1,568
Finance Leases:
Finance lease right-of-use asset (1)	Property, plant and equipment, net	$	30,704
Weighted Average Remaining Lease Term:
Operating leases		4.6 years
Finance leases		39.7 years
Weighted Average Discount Rate:
Operating leases		4.63		%
Finance leases		7.01		%

⁽¹⁾ 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.

Lessee, Operating Lease, Liability, Maturity

Maturities of lease liabilities as of March 31, 2019 were as follows:

Year	Operating Leases			Finance Leases (1)
	(in thousands)
2019 – remaining	$	683		$	449
2020	956			449
2021	506			449
2022	240			449
2023	147			449
Thereafter	364			17,770
Total lease payments	2,896			20,015
Less: discounting for present value and other adjustments	(725		)	(20,015		)
Present value of lease liabilities	$	2,171		$	—

⁽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 recognize expense for the future lease payments in the period in which they are made.

Finance Lease, Liability, Maturity

Maturities of lease liabilities as of March 31, 2019 were as follows:

Year	Operating Leases			Finance Leases (1)
	(in thousands)
2019 – remaining	$	683		$	449
2020	956			449
2021	506			449
2022	240			449
2023	147			449
Thereafter	364			17,770
Total lease payments	2,896			20,015
Less: discounting for present value and other adjustments	(725		)	(20,015		)
Present value of lease liabilities	$	2,171		$	—

⁽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 recognize expense for the future lease payments in the period in which they are made.

Lessor, Operating Lease, Payments to be Received, Maturity

At March 31, 2019, future minimum rental income under non-cancelable operating leases as the lessor were as follows:

Year	Total
	(in thousands)
2019 - remaining	$	5,850
2020	3,952
2021	3,773
2022	3,773
2023	3,773
Thereafter	7,353
Total	$	28,474

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

XML

Description of Business - Additional Information (Detail) $ in Billions		3 Months Ended
	Mar. 11, 2019 USD ($) shares	Mar. 31, 2019 mi	Jan. 01, 2019
Organization [Line Items]
Miles of Pipeline | mi		70
Sale of Stock, Consideration Received on Transaction | $	$ 3.2
Rockies Express Pipeline LLC
Organization [Line Items]
Equity method investment, ownership percentage		75.00%
Powder River Gateway
Organization [Line Items]
Equity method investment, ownership percentage		51.00%	51.00%
Tallgrass Energy, LP (TGE)
Organization [Line Items]
Ownership Interest		43.80%
Tallgrass Equity, LLC
Organization [Line Items]
Ownership Interest		63.55%
Partners' Capital Account, Units, Sold in Private Placement | shares	100,655,121
Tallgrass Terminals, LLC
Organization [Line Items]
Ownership Interest		100.00%
Tallgrass NatGas Operator, LLC
Organization [Line Items]
Ownership Interest		100.00%
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 Energy GP, LLC
Organization [Line Items]
Ownership Interest	100.00%	100.00%
Common Class A | Tallgrass Energy, LP (TGE)
Organization [Line Items]
Partners' Capital Account, Units, Sold in Private Placement | shares	21,751,018
Common Class B | Tallgrass Energy, LP (TGE)
Organization [Line Items]
Partners' Capital Account, Units, Sold in Private Placement | shares	100,655,121

XML

Summary of Significant Accounting Policies Summary of Significant Account Policies (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Jan. 01, 2019
Income Tax Contingency [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	14.77%	5.15%
Operating Lease, Right-of-Use Asset	$ 2,171
Operating Lease, Liability, Current	603
Operating Lease, Liability, Noncurrent	$ 1,568
Common Class A
Income Tax Contingency [Line Items]
Conversion of Stock, Shares Issued	21,751,018
Accounting Standards Update 2016-02
Income Tax Contingency [Line Items]
Operating Lease, Right-of-Use Asset			$ 2,300
Operating Lease, Liability, Current			600
Operating Lease, Liability, Noncurrent			$ 1,700
Total Partner Equity Including Portion Attributable to Noncontrolling Interest
Income Tax Contingency [Line Items]
Partners Capital Deferred Tax Asset	$ 123,051

XML

Acquisitions- Additional Information (Details) - USD ($) $ in Thousands			3 Months Ended
	Jan. 01, 2019	Nov. 05, 2018	Mar. 31, 2019	Mar. 31, 2018
Business Acquisition [Line Items]
Contributions to unconsolidated investments			$ (29,797)	$ (8,034)
Facility storage capacity		$ 20,000
Drexel Hamilton Infrastructure Fund I, L.P. (DHIF)
Business Acquisition [Line Items]
Right to receive special distributions		$ 35,000
Special Distribution, Current-portion			25,000
Special Distribution, Non-current portion			$ 10,000
Plaquemines Liquids Terminal, LLC
Business Acquisition [Line Items]
Preferred Membership Interest, Ownership Percentage		100.00%
Business Acquisition, Percentage of Voting Interests Acquired		80.00%
Powder River Gateway
Business Acquisition [Line Items]
Equity method investment, ownership percentage	51.00%		51.00%
Contributions to unconsolidated investments	$ (37,000)		$ (37,000)
Powder River Gateway | Silver Creek Midstream, LLC
Business Acquisition [Line Items]
Equity method investment, ownership percentage	49.00%
Iron Horse Pipeline, LLC
Business Acquisition [Line Items]
Equity method investment, ownership percentage	75.00%
Iron Horse Pipeline, LLC | Silver Creek Midstream, LLC
Business Acquisition [Line Items]
Equity method investment, ownership percentage	25.00%

XML

Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Related Party Transactions [Abstract]
Revenue from affiliated companies	$ 1,903	$ 1,896

XML

Related Party Transactions - Schedule of Balances with Affiliates in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Receivable from related parties	$ 3,480	$ 3,748
Rockies Express Pipeline LLC
Related Party Transaction [Line Items]
Receivable from related parties	2,839	3,447
Powder River Gateway
Related Party Transaction [Line Items]
Receivable from related parties	512	0
Pawnee Terminal, LLC
Related Party Transaction [Line Items]
Receivable from related parties	129	115
Iron Horse Pipeline, LLC
Related Party Transaction [Line Items]
Receivable from related parties	$ 0	$ 186

XML

Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Affiliate gas imbalance receivables	$ 19	$ 19
Affiliate gas imbalance payables	$ 2,309	$ 742

XML

Inventory - (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Inventory Disclosure [Abstract]
Crude oil	$ 16,803	$ 23,205
Materials and supplies	7,666	8,206
Gas in underground storage	2,413	2,740
Natural gas liquids	1,072	165
Inventory, Net	$ 27,954	$ 34,316

XML

Property Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($)	Mar. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Accumulated depreciation and amortization	$ (405,601,000)	$ (380,351,000)
Property, plant and equipment	2,750,375,000	2,802,429,000
Crude oil pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,309,763,000	1,313,976,000
Gathering, processing and terminalling assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	895,552,000	889,168,000
Natural gas pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	615,495,000	607,343,000
General and other (1)
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	163,206,000	180,299,000
Construction work in progress
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	171,960,000	$ 191,994,000
Plaquemines Liquids Terminal, LLC | General and other (1)
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 30,700,000.0

XML

Investments in Unconsolidated Affiliates - Equity Method Investments (Details) - Rockies Express Pipeline LLC - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Revenue	$ 230,761	$ 230,058
Equity Method Investment, Summarized Financial Information, Operating income	132,410	128,678
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	$ 103,609	$ 90,968

XML

Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated investments	$ 88,522	$ 68,402
Contributions to unconsolidated investments	$ (29,797)	$ (8,034)
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage	75.00%
Equity in earnings of unconsolidated investments	$ 86,237
Distributions from unconsolidated investments Unconsolidated Subsidiaries	113,400
Contributions to unconsolidated investments	$ (17,289)

XML

Risk Management - Schedule of Fair Value of Derivative Contracts (Detail) - Energy Related Derivative $ in Thousands	Mar. 31, 2019 USD ($) bbl	Dec. 31, 2018 USD ($) bbl
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 1,761	$ 3,526
Derivative liability at fair value	1,129	1,642
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	1,761	3,526
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability at fair value	$ 1,129	$ 1,642
Commodity | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,135,700	2,105,146
Commodity | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	1,793,000	1,274,500

XML

Risk Management - Derivative Contracts Included in Consolidated Statement of Income (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Not Designated as Hedging Instrument | Energy Related Derivative
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain recognized in income on derivatives	$ 11,473	$ 4,295

XML

Risk Management - Derivative Instruments Maximum Potential Exposure to Credit Loss (Details) - Energy Related Derivative	Mar. 31, 2019 USD ($)
Concentration Risk [Line Items]
Gross	$ 1,761,000
Netting agreement impact	0
Cash collateral held	0
Net exposure	$ 1,761,000

XML

Risk Management - Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification (Detail) - Energy Related Derivative - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 1,761	$ 3,526
Derivative liability at fair value	1,129	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	1,761	3,526
Derivative liability at fair value	1,129	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

XML

Risk Management Risk Management - Additional Information (Details) $ in Millions	Mar. 31, 2019 USD ($)
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash in Margin Accounts	$ 1.1

XML

Long-term Debt - Schedule of Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Less: Deferred financing costs, net	$ (20,575)	$ (21,421)
Plus: Unamortized premium on 2028 Notes	3,291	3,379
Total long-term debt, net	3,331,716	3,205,958
Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Debt, Gross	1,349,000	1,224,000
Total long-term debt, net	1,349,000	1,224,000
2023 Senior Notes
Debt Instrument [Line Items]
Total long-term debt, net	494,892	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	741,565	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	746,259	746,159
2028 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 750,000	$ 750,000

XML

Long-term Debt - Capacity under Revolving Credit Facility (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Long-term Debt	$ (3,331,716)	$ (3,205,958)
Revolving Credit Facility
Line of Credit Facility [Line Items]
Long-term Debt	(1,349,000)	(1,224,000)
Letters of Credit Outstanding, Amount	(94)	(94)
Line of Credit Facility, Remaining Borrowing Capacity	900,906	1,025,906
Wells Fargo Bank, National Association | Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 2,250,000	$ 2,250,000

XML

Long-term Debt - Carrying Amount and Fair Value of Long-term Debt (Detail) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term Debt	$ 3,331,716	$ 3,205,958
2023 Senior Notes
Debt Instrument [Line Items]
Fair Value	504,325	485,285
Long-term Debt	494,892	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	504,325	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	771,923	737,745
Long-term Debt	741,565	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	771,923	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	754,253	726,503
Long-term Debt	746,259	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	754,253	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	1,349,000	1,224,000
Long-term Debt	1,349,000	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	1,349,000	1,224,000
Revolving Credit Facility | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Fair Value	$ 0	$ 0

XML

Long-term Debt - Additional Information (Detail)	Mar. 31, 2019
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	4.00%
Debt Instrument, Interest Rate, Effective Percentage	4.52%
2023 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.75%
2024 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
2028 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.50%

XML

Partnership Equity - TGE Summary of Dividends (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018
Equity [Abstract]
Dividends	$ 94,975	$ 81,304	$ 79,717	$ 77,052	$ 28,316
Dividends Payable, Amount Per Share	$ 0.5300	$ 0.5200	$ 0.5100	$ 0.4975	$ 0.4875

XML

Partnership Equity - Additional Information (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Feb. 07, 2018	Feb. 01, 2018
Limited Partners' Capital Account [Line Items]
Distributions to noncontrolling interest	$ (66,625,000)	$ (89,073,000)
Payments for Purchase of Common Stock		(198,000,000)
Units Acquired			5,619,218
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number	1,092,637
Share-based compensation, Shares Withheld for Taxes	543,909
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 18.82
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	$ 12,500,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	1,767,100
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 15.20
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Distributions to noncontrolling interest	$ 0	(50,000,000)
Acquisitions		16,200,000
Carrying Value of Assets Acquired				$ 33,800,000
Tallgrass Equity, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests	36.45%
Deeprock Development, LLC
Limited Partners' Capital Account [Line Items]
Equity interest held by noncontrolling interests	40.00%
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%
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				2.00%
Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			25.01%
Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Contributions from noncontrolling interest	$ 1,282,000	183,000
Distributions to noncontrolling interest	(66,625,000)	(89,073,000)
Tallgrass Equity distributions to noncontrolling interests	64,400,000	36,400,000
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	2,200,000.0	1,300,000.0
Carrying Value of Common Units			$ 53,800,000
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]
Partners' Capital Account, Distributions		(51,300,000)
Noncontrolling Interest | Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Acquisitions		74,421,000
Total Partner Equity Including Portion Attributable to Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Contributions from noncontrolling interest	1,282,000	183,000
Distributions to noncontrolling interest	$ (66,625,000)	(89,073,000)
Total Partner Equity Including Portion Attributable to Noncontrolling Interest | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Acquisitions		(50,000,000)
Total Partner Equity Including Portion Attributable to Noncontrolling Interest | Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Acquisitions		$ 108,537,000
Common Class A
Limited Partners' Capital Account [Line Items]
Conversion of Stock, Shares Issued	21,751,018

XML

Revenue from Contracts with Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	$ 197,352	$ 179,094
Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	95,277	84,738
Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	32,125	31,451
Water business services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	18,286	13,204
Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6,080	5,044
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	4,314	5,567
Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	156,082	140,004
Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	16,871	23,609
Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	10,401	8,085
Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	119	2,156
Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	27,391	33,850
Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	183,473	173,854
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	13,879	5,240
Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	35,842	36,202
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	32,521	33,334
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	3,321	2,630
Natural Gas Transportation | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	35,842	35,964
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	0	238
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	0	238
Natural Gas Transportation | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	35,842	36,202
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	109,784	89,966
Crude Oil Transportation | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	95,277	84,738
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	14,507	3,319
Crude Oil Transportation | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	109,784	88,057
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	0	1,909
Crude Oil Transportation | Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	0	1,909
Crude Oil Transportation | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	109,784	89,966
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	74,034	63,838
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	18,286	13,204
Gathering, Processing & Terminalling | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	6,080	5,044
Gathering, Processing & Terminalling | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	3,520	5,706
Gathering, Processing & Terminalling | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	27,886	23,954
Gathering, Processing & Terminalling | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	16,871	23,609
Gathering, Processing & Terminalling | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	10,401	7,847
Gathering, Processing & Terminalling | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	119	247
Gathering, Processing & Terminalling | Energy Commodities and Service
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	27,391	31,703
Gathering, Processing & Terminalling | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	55,277	55,657
Gathering, Processing & Terminalling | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	18,757	8,181
Corporate and Other
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(22,308)	(10,912)
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	(396)	(1,883)
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	(17,034)	(6,088)
Corporate and Other | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(17,430)	(7,971)
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	(17,430)	(7,971)
Corporate and Other | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Including Assessed Tax	(4,878)	(2,941)
Rockies Express Pipeline LLC
Disaggregation of Revenue [Line Items]
Equity Method Investment, Summarized Financial Information, Revenue	$ 230,761	$ 230,058

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Revenue from Contract with Customer - Remaining Performance Obligation (Details) $ in Thousands	Mar. 31, 2019 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	9 months
Revenue, Remaining Performance Obligation, Amount	$ 439,404
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	$ 367,732
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	$ 175,919
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	$ 171,033
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	$ 150,810
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	111 years
Revenue, Remaining Performance Obligation, Amount	$ 1,545,859

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Revenue from Contracts with Customers - Contract with Customer, Asset and Liability (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Contract with Customer, Asset, Net	$ 79,855	$ 80,935
Accounts and Other Receivables, Net, Current	143,949	151,414
Accounts Receivable, Related Parties, Current	3,480	3,748
Accounts receivable, net	227,284	236,097
Deferred revenue	123,184	$ 111,095
Contract with Customer, Liability, Revenue Recognized	$ 1,600

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Net Income per Class A Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share [Abstract]
Net income attributable to TGE	$ 50,587	$ 16,735
Basic average number of Class A shares outstanding	161,425	58,085
Basic net income per Class A share	$ 0.31	$ 0.29
Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares	$ 206	$ 69
Net income attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares	$ 50,793	$ 16,804
Equity Participation Shares equivalent shares	1,352	125
Diluted average number of Class A shares outstanding	162,777	58,210
Diluted net income per Class A Share	$ 0.31	$ 0.29

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Regulatory Matters (Details)	Mar. 31, 2019 mi
Regulated Operations [Abstract]
Miles of Pipeline	70
Size of Pipeline	36

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Legal and Environmental Matters - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Accrued taxes	$ 26,962	$ 20,734
Environmental accruals	6,800	7,400
Total Remediation costs		$ 6,100
Insurance Recoveries	5,100
Payments for Environmental Liabilities	100
Rockies Express Pipeline LLC
Loss Contingencies [Line Items]
Excise and Sales Taxes	7,100
Accrued taxes	4,600
Income Taxes Receivable	$ 11,700

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Reporting Segments - Summary of TGE's Segment Information of Revenue (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Segment Reporting Information [Line Items]
Total Revenues	$ 197,352	$ 179,094
TGE
Segment Reporting Information [Line Items]
Total Revenues	197,352	179,094
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues	35,428	34,344
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues	95,362	86,647
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues	66,562	58,103
TGE | Operating Segments
Segment Reporting Information [Line Items]
Total Revenues	219,660	190,006
TGE | Operating Segments | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues	35,842	36,202
TGE | Operating Segments | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues	109,784	89,966
TGE | Operating Segments | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues	74,034	63,838
TGE | Inter-Segment
Segment Reporting Information [Line Items]
Total Revenues	(22,308)	(10,912)
TGE | Inter-Segment | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues	(414)	(1,858)
TGE | Inter-Segment | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues	(14,422)	(3,319)
TGE | Inter-Segment | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues	$ (7,472)	$ (5,735)

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Reporting Segments - Summary of TGE's Segment Information of Earnings (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Reconciliation to Net Income:
Equity in earnings of unconsolidated investments	$ 88,522	$ 68,402
Loss (gain) on disposal of assets	(214)	9,417
Interest expense, net	39,705	29,761
Depreciation and amortization	(31,001)	(26,123)
Distributions from unconsolidated investments	(87,940)	(67,059)
Share-based Compensation	(17,120)	(2,814)
Deferred income tax expense	(17,066)	(6,692)
Net income attributable to noncontrolling interests	(51,805)	(97,578)
Net income attributable to TGE	50,587	16,735
TGE
Reconciliation to Net Income:
Net income attributable to TGE	50,587	16,735
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	137,963	69,917
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	74,581	36,257
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	34,975	9,505
TGE | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	(1,794)	(12,269)
TGE | Operating Segments | Natural Gas Transportation
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	138,868	70,652
TGE | Operating Segments | Crude Oil Transportation
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	80,741	34,871
TGE | Operating Segments | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	27,910	10,156
TGE | Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	(1,794)	(12,269)
TGE | Inter-Segment | Natural Gas Transportation
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	(905)	(735)
TGE | Inter-Segment | Crude Oil Transportation
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	(6,160)	1,386
TGE | Inter-Segment | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	7,065	(651)
TGE | Inter-Segment | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted Earnings Before Interest Taxes Depreciation And Amortization	0	0
TGE | Segment Reconciling Items
Reconciliation to Net Income:
Equity in earnings of unconsolidated investments	(88,522)	32,413
Loss (gain) on disposal of assets	0	(3,212)
Interest expense, net	(39,710)	(10,786)
Depreciation and amortization	(30,728)	(8,496)
Distributions from unconsolidated investments	(115,098)	(43,491)
Share-based Compensation	(17,120)	(962)
Deficiency Payments	12,144	3,780
Non-cash (loss) gain on derivative instruments	(1,252)	872
Deferred income tax expense	(17,066)	(6,692)
Exchange Right Holders | TGE | Segment Reconciling Items
Reconciliation to Net Income:
Net income attributable to noncontrolling interests	$ 50,542	$ 48,965

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Reporting Segments - Summary of TGE's Segment Information for Payments to Acquire Plant, Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Segment Reporting Information [Line Items]
Capital expenditures	$ 62,802	$ 58,760
TGE
Segment Reporting Information [Line Items]
Capital expenditures	62,802	58,760
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Capital expenditures	16,346	9,885
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Capital expenditures	17,016	16,952
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Capital expenditures	27,814	31,139
TGE | Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 1,626	$ 784

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Reporting Segments - Summary of TGE's Segment Information of Assets (Detail) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Assets	$ 6,069,225	$ 5,893,509
TGE
Segment Reporting Information [Line Items]
Assets	6,069,225	5,893,509
TGE | Natural Gas Transportation
Segment Reporting Information [Line Items]
Assets	2,608,355	2,606,696
TGE | Crude Oil Transportation
Segment Reporting Information [Line Items]
Assets	1,711,706	1,423,740
TGE | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Assets	1,471,995	1,522,559
TGE | Corporate and Other
Segment Reporting Information [Line Items]
Assets	$ 277,169	$ 340,514

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Reporting Segments - Additional Information (Detail) - Segment	3 Months Ended
	Mar. 31, 2019	Jan. 01, 2019
Segment Reporting Information [Line Items]
Number of reportable segments	3
Rockies Express Pipeline LLC
Segment Reporting Information [Line Items]
Equity method investment, ownership percentage	75.00%
Powder River Gateway
Segment Reporting Information [Line Items]
Equity method investment, ownership percentage	51.00%	51.00%

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Subsequent Events (Details) - Subsequent Event - USD ($) $ in Thousands	May 01, 2019	Apr. 12, 2019
Subsequent Event [Line Items]
Potential Earnout	$ 3,000
BNN Eastern, LLC
Subsequent Event [Line Items]
Equity interest held by noncontrolling interests	7.65%
Senior Notes | Rockies Express Pipeline LLC
Subsequent Event [Line Items]
Long-term Debt, Gross		$ 550,000
Debt Instrument, Interest Rate, Stated Percentage		4.95%
Central Environmental Services (CES)
Subsequent Event [Line Items]
Payments to Acquire Businesses, Gross	$ 52,000
Term Loan | Rockies Express Pipeline LLC
Subsequent Event [Line Items]
Short-term Debt		$ 525,000

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Leases Leases - Supplemental Information (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Nov. 05, 2018
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 2,171
Operating Lease, Liability, Current	603
Operating Lease, Liability, Noncurrent	1,568
Finance Lease, Right-of-Use Asset	$ 30,704
Operating Lease, Weighted Average Remaining Lease Term	4 years 7 months
Finance Lease, Weighted Average Remaining Lease Term	39 years 8 months
Operating Lease, Weighted Average Discount Rate, Percent	4.63%
Finance Lease, Weighted Average Discount Rate, Percent	7.01%
Capital Lease Obligations		$ 30,700

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Leases Leases, Maturity Analysis of Operating and Finance Leases (Details) - USD ($) $ in Thousands	Nov. 05, 2018	Mar. 31, 2019
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Remainder of Fiscal Year		$ 683
Lessee, Operating Lease, Liability, Payments, Due Year Two		956
Lessee, Operating Lease, Liability, Payments, Due Year Three		506
Lessee, Operating Lease, Liability, Payments, Due Year Four		240
Lessee, Operating Lease, Liability, Payments, Due Year Five		147
Lessee, Operating Lease, Liability, Payments, Due after Year Five		364
Lessee, Operating Lease, Liability, Payments, Due		2,896
Lessee, Operating Lease, Liability, Undiscounted Excess Amount		(725)
Operating Lease, Liability		2,171
Lessee, Finance Lease, Liability, Payments, Due Remainder of Fiscal Year		449
Finance Lease, Liability, Payments, Due Year Two		449
Finance Lease, Liability, Payments, Due Year Three		449
Finance Lease, Liability, Payments, Due Year Four		449
Finance Lease, Liability, Payments, Due Year Five		449
Finance Lease, Liability, Payments, Due after Year Five		17,770
Finance Lease, Liability, Payments, Due		20,015
Finance Lease, Liability, Undiscounted Excess Amount		(20,015)
Finance Lease, Liability		$ 0
Capital Lease Obligations	$ 30,700
Payments to Acquire Assets, Investing Activities	$ 30,700

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Leases Lessor, Operating Leases, Payments to be Received (Details) $ in Thousands	Mar. 31, 2019 USD ($)
Leases [Abstract]
Lessor, Operating Lease, Payments to be Received, Remainder of Fiscal Year	$ 5,850
Lessor, Operating Lease, Payments to be Received, Two Years	3,952
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	7,353
Lessor, Operating Lease, Payments to be Received	$ 28,474

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Leases Schedule of Future Minimum Lease Payments for Operating and Capital Leases (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Leases [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 1,074
Operating Leases, Future Minimum Payments, Due in Two Years	922
Operating Leases, Future Minimum Payments, Due in Three Years	483
Operating Leases, Future Minimum Payments, Due in Four Years	240
Operating Leases, Future Minimum Payments, Due in Five Years	147
Operating Leases, Future Minimum Payments, Due Thereafter	364
Operating Leases, Future Minimum Payments Due	3,230
Capital Leases, Future Minimum Payments Due, Next Twelve Months	449
Capital Leases, Future Minimum Payments Due in Two Years	449
Capital Leases, Future Minimum Payments Due in Three Years	449
Capital Leases, Future Minimum Payments Due in Four Years	449
Capital Leases, Future Minimum Payments Due in Five Years	449
Capital Leases, Future Minimum Payments Due Thereafter	17,770
Capital Leases, Future Minimum Payments Due	$ 20,015

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Leases - Additional Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Description	We enter into operating leases as lessee for certain office space and equipment.
Lessee, Finance Lease, Description	We also have a capital lease agreement to lease the land site on which PLT expects to construct storage and terminalling facilities.
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	$ 0.2
Operating Lease, Lease Income, Lease Payments	2.4
Operating Lease, Payments	$ 0.2
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:DeferredCostsAndOtherAssets
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherAccruedLiabilitiesCurrent
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:LiabilitiesOtherThanLongtermDebtNoncurrent
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:PropertyPlantAndEquipmentNet
Maximum
Lessee, Lease, Description [Line Items]
Lessee Operating and Finance Leases Remaining Lease Term	40 years
Tallgrass Interstate Gas Transmission, LLC
Lessee, Lease, Description [Line Items]
Operating Lease, Lease Income, Lease Payments	$ 0.2