SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549



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

For the Quarterly Period Ended ~~March 31,~~June 30, 2019



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)



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

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. Yesx 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). Yesx 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,~~July 31, 2019, the Registrant had 179,197,416 Class A shares and 102,136,875 Class B shares outstanding.

TALLGRASS ENERGY, LP

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

CONDENSED CONSOLIDATED BALANCE SHEETS

Noncontrolling interests ^(a)

See Note 1011 - Partnership Equityfor a complete description of our noncontrolling interests.

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018			2019			2018
	(in thousands, except per unit amounts)						(in thousands, except per unit amounts)
Revenues:
Crude oil transportation services	$	95,156		$	84,738		$	99,456		$	101,166		$	194,612		$	185,904
Natural gas transportation services	33,516			32,196			32,345			31,474			65,861			63,670
Sales of natural gas, NGLs, and crude oil	38,864			38,145			37,843			37,250			76,707			75,395
Processing and other revenues	29,816			24,015			41,880			23,699			71,696			47,714
Total Revenues	197,352			179,094			211,524			193,589			408,876			372,683
Operating Costs and Expenses:
Cost of sales	19,285			26,351			19,268			27,694			38,553			54,045
Cost of transportation services	15,072			10,420			19,754			12,664			34,826			23,084
Operations and maintenance	18,046			16,399			23,472			18,440			41,518			34,839
Depreciation and amortization	31,001			26,123			32,980			27,690			63,981			53,813
General and administrative	32,272			18,426			18,715			19,085			50,987			37,511
Taxes, other than income taxes	10,998			8,879			7,711			8,462			18,709			17,341
Loss (gain) on disposal of assets	214			(9,417		)	28			279			242			(9,138		)
Total Operating Costs and Expenses	126,888			97,181			121,928			114,314			248,816			211,495
Operating Income	70,464			81,913			89,596			79,275			160,060			161,188
Other Income (Expense):
Equity in earnings of unconsolidated investments	88,522			68,402			99,012			78,187			187,534			146,589
Interest expense, net	(39,705		)	(29,761		)	(40,595		)	(31,282		)	(80,300		)	(61,043		)
Other income, net	177			451			198			330			375			781
Total Other Income (Expense)	48,994			39,092			58,615			47,235			107,609			86,327
Net income before tax	119,458			121,005			148,211			126,510			267,669			247,515
Deferred income tax expense	(17,066		)	(6,692		)
Income tax expense							(21,981		)	(16,809		)	(39,047		)	(23,501		)
Net income	102,392			114,313			126,230			109,701			228,622			224,014
Net income attributable to noncontrolling interests	(51,805		)	(97,578		)	(54,611		)	(108,638		)	(106,416		)	(206,216		)
Net income attributable to TGE	$	50,587		$	16,735		$	71,619		$	1,063		$	122,206		$	17,798
Net income per Class A share:
Basic net income per Class A share	$	0.31		$	0.29		$	0.40		$	0.02		$	0.72		$	0.30
Diluted net income per Class A share	$	0.31		$	0.29		$	0.40		$	0.02		$	0.71		$	0.30
Basic average number of Class A shares outstanding	161,425			58,085			179,149			59,397			170,336			58,745
Diluted average number of Class A shares outstanding	162,777			58,210			180,407			59,397			171,825			58,745

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)


	Partners' Capital					Noncontrolling Interests				Total Equity			Partners' Capital							Noncontrolling Interests				Total Equity
	Class A Shares			Class B Shares					Class A Shares					Class B Shares
	(in thousands)												(in thousands)
Balance at January 1, 2019	$	1,725,537		$	—		$	491,571					$	2,217,108		$	1,725,537		$	—			$	491,571			$	2,217,108
Net income	50,587			—		51,805				102,392			50,587				—			51,805				102,392
Dividends paid to Class A shareholders	(81,304		)	—		—				(81,304		)	(81,304		)		—			—				(81,304		)
Distributions to noncontrolling interest	—			—		(66,625		)		(66,625		)
Contributions from noncontrolling interest	—			—		1,282				1,282
Distributions to noncontrolling interests													—				—			(66,625		)		(66,625		)
Contributions from noncontrolling interests													—				—			1,282				1,282
Noncash compensation expense	17,120			—		—				17,120			17,120				—			—				17,120
TGE LTIP shares tendered by employees to satisfy tax withholding obligations	(13,260		)	—		—				(13,260		)	(13,260		)		—			—				(13,260		)
Deferred tax asset	123,051			—		—				123,051			123,051				—			—				123,051
Conversion of Class B shares to Class A shares	68,614			—		(68,614		)		—			68,614				—			(68,614		)		—
Balance at March 31, 2019	$	1,890,345		$	—	$	409,419			$	2,299,764		$	1,890,345			$	—		$	409,419			$	2,299,764
Net income													71,619				—			54,611				126,230
Dividends paid to Class A shareholders													(94,975		)		—			—				(94,975		)
Distributions to noncontrolling interests													—				—			(55,870		)		(55,870		)
Noncash compensation expense													3,450				—			—				3,450
Acquisition of CES													—				—			3,400				3,400
Balance at June 30, 2019													$	1,870,439			$	—		$	411,560			$	2,281,999

	Partners' Capital					Noncontrolling Interests				Total Equity			Partners' Capital							Noncontrolling Interests				Total Equity
	Class A Shares			Class B Shares					Class A Shares					Class B Shares
	(in thousands)												(in thousands)
Balance at January 1, 2018	$	48,613		$	—		$	1,672,566					$	1,721,179		$	48,613		$	—			$	1,672,566			$	1,721,179
Cumulative effect of ASC 606 implementation	4,588			—		39,543				44,131			4,588				—			39,543				44,131
Net income	16,735			—		97,578				114,313			16,735				—			97,578				114,313
Issuance of TEP units to the public, net of offering costs	(5		)	—		(40		)		(45		)	(5		)		—			(40		)		(45		)
Dividends paid to Class A shareholders	(21,346		)	—		—				(21,346		)	(21,346		)		—			—				(21,346		)
Noncash compensation expense	404			—		2,917				3,321			405				—			2,917				3,322
Acquisition of additional TEP common units from TD	(62,222		)	—		(189,520		)		(251,742		)	(62,223		)		—			(189,520		)		(251,743		)
Issuance of Tallgrass Equity units	—			—		644,782				644,782			—				—			644,782				644,782
Acquisition of additional 2% membership interest in Pony Express	(5,268		)	—		(44,732		)		(50,000		)	(5,268		)		—			(44,732		)		(50,000		)
Acquisition of 25.01% membership interest in Rockies Express	34,116			—		74,421				108,537			34,116				—			74,421				108,537
Consolidation of Deeprock North	—			—		31,843				31,843			—				—			31,843				31,843
Contributions from noncontrolling interest	—			—		183				183
Distributions to noncontrolling interest	—			—		(89,073		)		(89,073		)
Contributions from noncontrolling interests													—				—			183				183
Distributions to noncontrolling interests													—				—			(89,073		)		(89,073		)
Balance at March 31, 2018	$	15,615		$	—	$	2,240,468			$	2,256,083		$	15,615			$	—		$	2,240,468			$	2,256,083
Net income													1,063				—			108,638				109,701
Issuance of TEP units to the public, net of offering costs													(22		)		—			(181		)		(203		)
Dividends paid to Class A shareholders													(28,316		)		—			—				(28,316		)
Noncash compensation expense													(74		)		—			280				206
TEP LTIP units tendered by employees to satisfy tax withholding obligations													(190		)		—			(1,531		)		(1,721		)
Conversion of Class B shares to Class A shares													(13,402		)		—			13,402				—
Distributions to noncontrolling interests													—				—			(109,764		)		(109,764		)
Deferred tax asset													7,664				—			—				7,664
Acquisition of additional TEP common units													(351,431		)		—			(1,762,327		)		(2,113,758		)
Issuance of Class A shares													2,113,758				—			—				2,113,758
Balance at June 30, 2018													$	1,744,665			$	—		$	488,985			$	2,233,650

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)


	Three Months Ended March 31,						Six Months Ended June 30,
	2019			2018			2019			2018
	(in thousands)						(in thousands)
Cash Flows from Operating Activities:
Net income	$	102,392		$	114,313		$	228,622		$	224,014
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	32,799			27,620			67,434			56,955
Equity in earnings of unconsolidated investments	(88,522		)	(68,402		)	(187,534		)	(146,589		)
Distributions from unconsolidated investments	87,940			67,059			188,043			145,581
Deferred income tax expense	17,066			6,692			38,994			23,501
Noncash compensation expense	17,120			2,814			20,570			4,003
Other noncash items, net	1,536			(12,024		)	1,666			(10,507		)
Changes in components of working capital:
Accounts receivable and other	8,985			(12,013		)	(1,777		)	(93,157		)
Accounts payable and accrued liabilities	(46,186		)	16,354			(29,423		)	106,592
Deferred revenue	12,125			10,750			16,294			10,711
Other current assets and liabilities	2,026			(1,671		)	(3,882		)	7,631
Other operating, net	(3,533		)	108			(8,593		)	2,525
Net Cash Provided by Operating Activities	143,748			151,600			330,414			331,260
Cash Flows from Investing Activities:
Capital expenditures	(62,802		)	(58,760		)	(150,051		)	(176,275		)
Formation of Powder River Gateway joint venture	(37,000		)	—
Contributions to unconsolidated investments	(29,797		)	(8,034		)	(66,084		)	(22,513		)
Distributions from unconsolidated investments in excess of cumulative earnings	27,158			20,774			52,525			36,502
Acquisition of CES, net of cash acquired							(48,416		)	—
Formation of Powder River Gateway joint venture							(37,000		)	—
Acquisition of BNN North Dakota, net of cash acquired	—			(95,000		)	—			(95,000		)
Sale of Tallgrass Crude Gathering	—			50,046			—			50,046
Acquisition of Pawnee Terminal							—			(30,600		)
Acquisition of 38% membership interest in Deeprock North	—			(19,500		)	—			(19,500		)
Other investing, net	15			(12,439		)	246			(12,521		)
Net Cash Used in Investing Activities	(102,426		)	(122,913		)	(248,780		)	(269,861		)
Cash Flows from Financing Activities:
Borrowings under revolving credit facilities, net	125,000			133,000			230,000			242,000
Dividends paid to Class A shareholders	(81,304		)	(21,346		)	(176,279		)	(49,662		)
Distributions to noncontrolling interests	(66,625		)	(89,073		)	(122,495		)	(198,837		)
TGE LTIP shares tendered by employees to satisfy tax withholding obligations	(13,260		)	—			(13,260		)	—
Acquisition of Pony Express membership interest	—			(50,000		)	—			(50,000		)
Other financing, net	313			394			233			(2,462		)
Net Cash Used in Financing Activities	(35,876		)	(27,025		)	(81,801		)	(58,961		)
Net Change in Cash and Cash Equivalents	5,446			1,662			(167		)	2,438
Cash and Cash Equivalents, beginning of period	9,596			2,593			9,596			2,593
Cash and Cash Equivalents, end of period	$	15,042		$	4,255		$	9,429		$	5,031

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 )



	Six Months Ended June 30,
	2019			2018
	(in thousands)

Schedule of Noncash Investing and Financing Activities:
Contribution of assets to Powder River Gateway joint venture	$	(122,504	)	$	—
Accruals for property, plant and equipment	$	22,051		$	5,276
Right-of-use assets obtained in exchange for operating lease obligations	$	9,654		$	—
Acquisition of additional TEP common units ^(a)(b)	$	—		$	(2,365,501	)
Issuance of Class A shares ^(a)	$	—		$	2,113,758
Issuance of Tallgrass Equity units^(b)	$	—		$	644,782
Acquisition of Rockies Express membership interest^(b)	$	—		$	(393,039	)
Issuance of noncontrolling interests in Deeprock Development in exchange for 62% membership interest in Deeprock North	$	—		$	(31,843	)
Contribution of 38% membership interest in Deeprock North to Deeprock Development	$	—		$	(19,500	)

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.

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%~~63.70% membership interest as of ~~March 31,~~June 30, 2019, and Tallgrass Energy Partners, LP ("TEP"), a wholly-owned subsidiary of Tallgrass Equity and its subsidiaries. We are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations.

Our reportable business segments are:

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

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

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

Natural Gas Transportation. We provide natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) our 75% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio (the "Rockies Express Pipeline"), and our 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas"), which operates the Rockies Express Pipeline, (2) the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and (3) the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline").

Crude Oil Transportation. We provide crude oil transportation to customers in Wyoming, Colorado, Kansas, and the surrounding regions through (1) Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a FERC-regulated crude oil pipeline commencing in both Guernsey, Wyoming and Weld County, Colorado and terminating in Cushing, Oklahoma (the "Pony Express System") and (2) our 51% membership interest in Powder River Gateway, LLC ("Powder River Gateway"), which owns the Powder River Express Pipeline ("PRE Pipeline"), a 70-mile FERC-regulated crude oil pipeline that transports crude oil from the Powder River Basin to Guernsey, Wyoming, the Iron Horse Pipeline ("Iron Horse Pipeline"), a 80-mile FERC-regulated crude oil pipeline placed into service in May 2019 that transports crude oil from the Powder River Basin to Guernsey, Wyoming, and crude oil terminal facilities in Guernsey, Wyoming.

Gathering, Processing & Terminalling. We provide natural gas gathering and processing services for customers in Wyoming through: (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, and Ohio through BNN Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through our 100% membership interest in Tallgrass Terminals, LLC ("Terminals"), which owns and operates crude oil terminals in Colorado, Oklahoma, and Kansas. The Gathering, Processing & Terminalling segment also includes Stanchion Energy, LLC ("Stanchion"), which transacts in crude oil.

Blackstone Acquisition

On March 11, 2019, pursuant to the terms of ~~the~~a previously announced definitive purchase agreement (the "Purchase Agreement"), dated January 30, 2019, entered into among acquisition vehicles controlled by affiliates of Blackstone Infrastructure Partners ("BIP" and, 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%~~44.2% economic interest in us as of ~~March 31,~~June 30, 2019.

2. Summary of Significant Accounting Policies

Basis of Presentation

These condensed consolidated financial statements and related notes for the three and six months ended ~~March 31,~~June 30, 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 and six months ended ~~March 31,~~June 30, 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 and six months ended ~~March 31,~~June 30, 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~~six months ended ~~March 31,~~June 30, 2019, we recognized an additional deferred tax asset of $123.1 million upon exercise of the Exchange Right, as discussed in Note 1011 – 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%~~8.94% for the six months ended June 30, 2018 to 14.79% for the six months ended June 30, 2019.

As discussed in Note 3 – Acquisitions, a newly formed indirect subsidiary of TGE acquired the outstanding stock of an entity classified as a C corporation for federal income tax purposes effective May 1, 2019. As a result, we recognized approximately $53,000 of current income taxes during the three months ended ~~March 31, 2018 to 14.77% for the three months ended March 31,~~June 30, 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 following practical ~~expedients related to~~expedients: (a) the land ~~easements,~~easement practical expedient, allowing us to carry forward our accounting treatment for existing land easements as property, plant and equipment, ~~and~~(b) the practical expedient for short-term leases, allowing us to not recognize ROU assets or lease liabilities for leases with a term of 12 months or ~~less.~~less, and (c) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease.

Excluding ROU assets and lease liabilities relating to agreements between consolidated subsidiaries, adoption of the new standard resulted in the recognition of ROU assets of approximately $2.3 million, and current and non-current lease liabilities of approximately $0.6 million and $1.7 million, respectively, for operating leases as of January 1, 2019. Our accounting for finance leases remained substantially unchanged. The adoption of this guidance had no impact to our cash flows from operating, investing, or financing activities. For additional information see Note 1213 – Leases.

Accounting Pronouncements Not Yet Adopted

ASU No. 2016-13, "Financial Instruments–Credit Losses (Topic 326)"

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments–Credit Losses (Topic 326). ASU 2016-13 amends current measurement techniques used to estimate credit losses for financial assets. The amendments in ASU 2016-13 are effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact of ASU 2016-13.

3. Acquisitions

Acquisition of Central Environmental Services

In April 2019, BNN Eastern, LLC ("BNN Eastern"), a newly formed indirect subsidiary of TGE, entered into a Stock Purchase Agreement to acquire all of the outstanding stock of CES Holding Company, Inc., which owns all of the issued and outstanding membership interests of K & H Partners LLC, a company doing business as Central Environmental Services ("CES"). CES Holding Company, Inc. is a C corporation for federal income tax purposes and is considered a taxable entity for such purposes. CES owns and operates a salt water disposal facility located in the Utica and Marcellus area of Ohio. On May 1, 2019, the acquisition closed for cash consideration of approximately $52 million paid at closing, and the issuance of a 7.65% membership interest in BNN Eastern to one of the sellers in the transaction. In addition, the transaction includes a potential earn out payment to the sellers of approximately $3 million based on the achievement of certain milestones during 2019, which is payable in cash or in additional membership interests in BNN Eastern. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.

The following represents the provisional fair value of assets acquired and liabilities assumed (in thousands):



Accounts receivable	$	1,391
Prepayments	67
Property, plant and equipment	6,900
Intangible asset	35,800			⁽¹⁾
Accounts payable and accrued liabilities	(1,518		)	⁽²⁾
Deferred tax liability	(8,557		)
Net identifiable assets acquired	34,083
Goodwill	17,734
Net assets acquired (excluding cash)	$	51,817


⁽¹⁾	The $35.8 million intangible asset acquired represents customer relationships and is amortized on a straight-line basis over a period of 8 years.


⁽²⁾	Includes the estimated fair value of the liability for contingent consideration of $0.7 million.

At June 30, 2019, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. We are in the process of identifying and measuring all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. The 7.65% equity interest in BNN Eastern held by noncontrolling interests was recorded at its acquisition date fair value of $3.4 million. The fair value of the noncontrolling interests were determined using a discounted cash flow analysis and adjusted for lack of control. These fair value measurements are based on significant inputs, such as forecasted cash flows and discount rates, that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820. The goodwill recognized of $17.7 million is primarily attributed to synergies expected from combining the operations of TGE and CES. All the goodwill was assigned to our Gathering, Processing & Terminalling segment.

Actual revenue and net income attributable to TGE from CES of $2.1 million and $0.1 million, respectively, was recognized in the accompanying condensed consolidated statements of income for the period from May 1, 2019 to June 30, 2019.

Pro Forma Financial Information

Unaudited pro forma revenue and net income attributable to TGE for the three and six months ended June 30, 2019 and 2018 is presented below as if the acquisition of CES had been completed on January 1, 2018.



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	(in thousands)
Revenue	$	212,687	$	197,068	$	413,668	$	378,772
Net income attributable to TGE	$	71,820	$	1,230	$	123,041	$	18,054

The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TGE would have been if the transaction had in fact occurred on the date or for the period indicated, nor does it purport to project the results of operations or financial position of TGE for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transaction or the costs to achieve these cost savings, operating synergies, and revenue enhancements.

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 with a carrying value of $35.6 million, $37 million in cash, and various other assets, including terminal facilities under construction in Guernsey, ~~Wyoming.~~Wyoming, valued at $86.9 million. 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 Silver Creek retained certain participating rights with respect to Powder River Gateway, the 51% membership interest does not represent a controlling interest in Powder River ~~Gateway,~~Gateway. Accordingly, 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.

Consolidation of BNN Colorado

At December 31, 2018, the assets acquired and liabilities assumed were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2019.

Acquisition of NGL Water Solutions Bakken

In November 2018, we acquired 100% of the membership interests in NGL Water Solutions Bakken, LLC ("NGL Water Solutions Bakken"), a produced water disposal system in the Bakken basin, for cash consideration of approximately $91.0 million, subject to working capital adjustments. NGL Water Solutions Bakken was subsequently merged into BNN North Dakota. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.

The following represents the fair value of assets acquired and liabilities assumed:



	Preliminary			Adjustments			Final
	(in thousands)
Accounts receivable	$	3,599		$	(3,599	)	$	—
Prepayments and other current assets	5			—			5
Property, plant and equipment	17,200			—			17,200
Intangible asset	54,000			—			54,000
Accounts payable and accrued liabilities	(949		)	644			(305		)
Net identifiable assets acquired	73,855			(2,955		)	70,900
Goodwill	17,145			2,955			20,100
Net assets acquired	$	91,000		$	—		$	91,000

At December 31, 2018, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. During the six months ended June 30, 2019, the preliminary purchase price allocation was adjusted for certain immaterial items related to working capital adjustments and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2019.

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~~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.

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	(in thousands)
Processing and other revenues ⁽¹⁾	$	1,907	$	1,869	$	3,810	$	3,765
Cost of transportation services ⁽²⁾	$	520	$	—	$	520	$	—


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


⁽²⁾	Reflects rent expense for crude oil storage and terminalling services provided by Powder River Gateway.

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



	June 30, 2019		December 31, 2018
	(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	3,280	$	3,447
Powder River Gateway, LLC	497		—
Pawnee Terminal, LLC	110		115
Iron Horse Pipeline, LLC	—		186
Total receivable from related parties	$	3,887	$	3,748

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~~Details of gas imbalances with affiliated shippers included in "Prepayments and other current assets" and "Other current liabilities" in the condensed consolidated balance sheets are as follows:



	June 30, 2019		December 31, 2018
	(in thousands)
Affiliate gas imbalance receivables	$	39	$	19
Affiliate gas imbalance payables	$	1,163	$	742

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,~~June 30, 2019 and December 31, 2018 consisted of the following:



	June 30, 2019		December 31, 2018
	(in thousands)
Crude oil	$	21,790	$	23,205
Materials and supplies	7,667		8,206
Gas in underground storage	2,663		2,740
Natural gas liquids	549		165
Total inventory	$	32,669	$	34,316

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

6. Property, Plant and Equipment

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



	June 30, 2019			December 31, 2018
	(in thousands)
Crude oil pipelines	$	1,314,055		$	1,313,976
Gathering, processing and terminalling assets	912,812			889,168
Natural gas pipelines	621,917			607,343
General and other ⁽¹⁾	164,356			180,299
Construction work in progress	238,077			191,994
Accumulated depreciation and amortization	(430,252		)	(380,351		)
Total property, plant and equipment, net	$	2,820,965		$	2,802,429

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 1213 – 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~~six months ended ~~March 31,~~June 30, 2019, we recognized equity in earnings associated with our 75% membership interest in Rockies Express of ~~$86.2~~$182.9 million, inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of ~~$113.4~~$235.1 million and ~~$17.3~~$43.6 million, respectively.

Summarized financial information for Rockies Express is as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	(in thousands)
Revenue	$	232,323	$	227,615	$	463,084	$	457,673
Operating income	$	134,311	$	130,034	$	266,721	$	258,712
Net income to Members	$	117,635	$	88,663	$	221,244	$	179,631

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
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.

8. Goodwill

Reconciliation of Goodwill

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



	Natural Gas Transportation		Gathering, Processing & Terminalling			Total
	(in thousands)
Balance at December 31, 2018	$	255,558	$	166,425		$	421,983
Goodwill acquired	—		17,734		⁽¹⁾	17,734
Other adjustments	—		2,955		⁽²⁾	2,955
Balance at June 30, 2019	$	255,558	$	187,114		$	442,672


⁽¹⁾	The $17.7 million of goodwill was recorded in connection with the acquisition of CES on May 1, 2019 as discussed further in Note 3 – Acquisitions.


⁽²⁾	The $3.0 million goodwill adjustment was recorded in connection with a purchase price allocation adjustment related to the NGL Water Solutions Bakken acquisition as discussed further in Note 3 – Acquisitions.

9. 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~~Stanchion engages in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We have a comprehensive risk management policy for Stanchion adopted by the board of directors of our general partner and a Risk Management Committee responsible for the overall management of credit risk and commodity risk at Stanchion, including establishing and monitoring exposure limits. We also occasionally enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities.

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

Fair Value of Derivative Contracts

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



	Balance Sheet Location	June 30, 2019		December 31, 2018
		(in thousands)
Crude oil derivative contracts ⁽¹⁾	Prepayments and other current assets	$	1,843	$	3,526
Crude oil derivative contracts ⁽²⁾	Other current liabilities	$	17	$	1,642

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,~~June 30, 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~~1,709,914 and 2,105,146 barrels of crude oil, respectively, consisting of fixed price and floating price contracts, which will settle throughout ~~2019.~~2019 and 2020.


⁽²⁾	As of ~~March 31,~~June 30, 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~~1,416,008 and 1,274,500 barrels of crude oil, respectively, consisting of fixed price and floating price contracts, which will settle throughout ~~2019.~~2019 and 2020.

Effect of Derivative Contracts in the Statements of Income

The following table summarizes the impact of derivative contracts not designated as hedging contracts for the three and six months ended ~~March 31,~~June 30, 2019 and 2018:



	Location of gain recognized in income on derivatives	Amount of gain recognized in income on derivatives
		Three Months Ended June 30,				Six Months Ended June 30,
		2019		2018		2019		2018
		(in thousands)
Crude oil derivative contracts	Sales of natural gas, NGLs, and crude oil	$	14,584	$	2,935	$	26,057	$	7,230

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,~~June 30, 2019 was:



	Asset Position
	(in thousands)
Gross	$	1,843
Netting agreement impact	—
Cash collateral held	—
Net exposure	$	1,843

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

As of ~~March 31,~~June 30, 2019, we had ~~$1.1~~$1.4 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,~~June 30, 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 June 30, 2019:
Crude oil derivative contracts	$	1,843	$	—	$	1,843	$	—
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 June 30, 2019:
Crude oil derivative contracts	$	17	$	—	$	17	$	—
As of December 31, 2018:
Crude oil derivative contracts	$	1,642	$	—	$	1,642	$	—

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
$ —

9.10. Long-term Debt

Our long-term debt is held at TEP and consisted of the following at ~~March 31,~~June 30, 2019 and December 31, 2018:


	March 31, 2019			December 31, 2018			June 30, 2019			December 31, 2018
	(in thousands)						(in thousands)
Revolving credit facility	$	1,349,000		$	1,224,000		$	1,454,000		$	1,224,000
4.75% senior notes due October 1, 2023	500,000			500,000			500,000			500,000
5.50% senior notes due September 15, 2024	750,000			750,000			750,000			750,000
5.50% senior notes due January 15, 2028	750,000			750,000			750,000			750,000
Less: Deferred financing costs, net ⁽¹⁾	(20,575		)	(21,421		)	(19,714		)	(21,421		)
Plus: Unamortized premium on 2028 Notes	3,291			3,379			3,204			3,379
Total long-term debt, net	$	3,331,716		$	3,205,958		$	3,437,490		$	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 isare 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~~senior notes due 2023 (the "2023 Notes"), dated as of September 26, 2018, among the Issuers, the Guarantors and Trustee, (ii) the Indenture governing the 5.50% ~~Senior Notes~~senior notes due 2024 (the "2024 Notes"), dated as of September 1, 2016, among the Issuers, the Guarantors and the Trustee, and (iii) the Indenture governing the 5.50% senior notes due 2028 (the "2028 Notes"), dated as of September 15, 2017, among the Issuers, the Guarantors and the Trustee (collectively, the "Indentures"). The Supplemental Indentures (a) amended the defined term "Change of Control" in each Indenture to provide that the Blackstone Acquisition did not constitute a Change of Control under such Indenture, (b) changed the definition of "Qualifying Owners" in the applicable Indenture to provide that Blackstone Infrastructure Partners L.P., Vencap Holdings (1992) Pte. Ltd. and their respective affiliates, funds, holding companies and investment vehicles, among others, are Qualifying Owners under such Indenture, and (c) added to, amended, supplemented or changed certain other defined terms contained in each Indenture related to the foregoing.

The 2023 Notes, 2024 Notes, and 2028 Notes are together referred to as the "Senior Notes." As of ~~March 31,~~June 30, 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,~~June 30, 2019 and December 31, 2018:



	June 30, 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	(1,454,000		)	(1,224,000		)
Less: Letters of credit issued under the revolving credit facility	(94		)	(94		)
Available capacity under the revolving credit facility	$	795,906		$	1,025,906

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,~~June 30, 2019, TEP was in compliance with the covenants required under its revolving credit facility. As of ~~March 31,~~June 30, 2019, the weighted average interest rate on outstanding borrowings under the revolving credit facility was ~~4.00%~~3.90%. During the ~~three~~six months ended ~~March 31,~~June 30, 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%~~4.46%.

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,~~June 30, 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 June 30, 2019:
Revolving credit facility	$	—	$	1,454,000	$	—	$	1,454,000	$	1,454,000
2023 Notes	$	—	$	508,020	$	—	$	508,020	$	495,177
2024 Notes	$	—	$	775,740	$	—	$	775,740	$	741,954
2028 Notes	$	—	$	759,075	$	—	$	759,075	$	746,359
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

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,~~June 30, 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,~~June 30, 2019.

~~10.~~11. 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		Date Paid	Dividends to Class A Shareholders		Dividends per Class A Share
		(in thousands, except per share amounts)					(in thousands, except per share amounts)
June 30, 2019						August 14, 2019 ⁽¹⁾	$	96,767	$	0.5400
March 31, 2019	May 15, 2019 ⁽¹⁾	$	94,975	$	0.5300	May 15, 2019	94,975		0.5300
December 31, 2018	February 14, 2019	81,304		0.5200		February 14, 2019	81,304		0.5200
September 30, 2018	November 14, 2018	79,717		0.5100		November 14, 2018	79,717		0.5100
June 30, 2018	August 14, 2018	77,052		0.4975		August 14, 2018	77,052		0.4975
March 31, 2018	May 15, 2018	28,316		0.4875		May 15, 2018	28,316		0.4875

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~~six months ended ~~March 31,~~June 30, 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,~~June 30, 2019, noncontrolling interests in our subsidiaries consisted of a ~~36.45%~~36.30% 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 ("BNN West Texas"), ~~and~~ a 37% membership interest in BNN Colorado Water, LLC ("BNN Colorado")., a 20% common membership interest in PLT, and an approximate 8% membership interest in BNN Eastern. During the ~~three~~six months ended ~~March 31,~~June 30, 2019, we recognized contributions from and distributions to noncontrolling interests of $1.3 million and ~~$66.6~~$122.5 million, respectively. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of ~~$64.4~~$118.6 million and distributions to Deeprock Development, ~~and~~BNN West Texas, and BNN Colorado noncontrolling interests of ~~$2.2 million.~~$3.9 million in the aggregate.

During the ~~three~~six months ended ~~March 31,~~June 30, 2018, we recognized contributions from and made distributions to noncontrolling interests of $0.2 million and ~~$89.1~~$198.8 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~~$98.2 million, distributions to TEP unitholders of $97.7 million, and distributions to Deeprock Development and Pony Express noncontrolling interests of ~~$1.3 million.~~$2.9 million in the aggregate.

Other Contributions and Distributions

During the ~~three~~six months ended ~~March 31,~~June 30, 2018, TGE recognized the following other contributions and distributions:

~~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.~~

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~~six months ended ~~March 31,~~June 30, 2019. In addition, ~~1,767,100~~1,775,600 Equity Participation Shares with a weighted average grant date fair value of ~~$15.20~~$15.21 were granted during the ~~three~~six months ended ~~March 31,~~June 30, 2019.

~~11.~~

12. 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											Three Months Ended June 30, 2019
	Natural Gas Transportation segment		Crude Oil Transportation segment		Gathering, Processing, & Terminalling segment		Corporate and Other			Total Revenue		Natural Gas Transportation segment		Crude Oil Transportation segment		Gathering, Processing, & Terminalling segment		Corporate and Other			Total Revenue
	(in thousands)											(in thousands)
Crude oil transportation - committed shipper revenue	$	—	$	95,277	$	—	$	—		$	95,277	$	—	$	99,439	$	—	$	—		$	99,439
Natural gas transportation - firm service	32,521		—		—		(396		)	32,125		31,984		—		—		(488		)	31,496
Water business services	—		—		18,286		—			18,286		—		—		31,299		—			31,299
Natural gas gathering & processing fees	—		—		6,080		—			6,080		—		—		5,330		—			5,330
All other⁽¹⁾	3,321		14,507		3,520		(17,034		)	4,314		2,768		16,001		3,744		(18,714		)	3,799
Total service revenue	35,842		109,784		27,886		(17,430		)	156,082		34,752		115,440		40,373		(19,202		)	171,363
Natural gas liquids sales	—		—		16,871		—			16,871		—		—		13,176		—			13,176
Natural gas sales	—		—		10,401		—			10,401		119		—		5,108		—			5,227
Crude oil sales	—		—		119		—			119		—		4,730		127		—			4,857
Total commodity sales revenue	—		—		27,391		—			27,391		119		4,730		18,411		—			23,260
Total revenue from contracts with customers	35,842		109,784		55,277		(17,430		)	183,473		34,871		120,170		58,784		(19,202		)	194,623
Other revenue⁽²⁾	—		—		18,757		(4,878		)	13,879		—		—		21,978		(5,077		)	16,901
Total revenue⁽³⁾	$	35,842	$	109,784	$	74,034	$	(22,308	)	$	197,352	$	34,871	$	120,170	$	80,762	$	(24,279	)	$	211,524

Other revenue⁽²⁾

Total revenue⁽³⁾

Excludes revenue recognized at unconsolidated investments, including ~~$230.8~~$232.3 million and ~~$230.1~~$463.1 million of revenue recognized at Rockies Express for the three and six months ended ~~March 31,~~June 30, 2019, ~~and 2018,~~ respectively. See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express.



	Three Months Ended June 30, 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	$	—	$	101,242	$	—	$	—		$	101,242
Natural gas transportation - firm service	31,762		—		—		(1,398		)	30,364
Water business services	—		—		12,205		—			12,205
Natural gas gathering & processing fees	—		—		5,754		—			5,754
All other⁽¹⁾	3,059		9,484		6,394		(13,108		)	5,829
Total service revenue	34,821		110,726		24,353		(14,506		)	155,394
Natural gas liquids sales	—		—		27,477		—			27,477
Natural gas sales	108		—		4,543		—			4,651
Crude oil sales	—		2,066		121		—			2,187
Total commodity sales revenue	108		2,066		32,141		—			34,315
Total revenue from contracts with customers	34,929		112,792		56,494		(14,506		)	189,709
Other revenue⁽²⁾	—		—		7,118		(3,238		)	3,880
Total revenue⁽³⁾	$	34,929	$	112,792	$	63,612	$	(17,744	)	$	193,589



	Six Months Ended June 30, 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	$	—	$	185,980	$	—	$	—		$	185,980
Natural gas transportation - firm service	65,096		—		—		(3,281		)	61,815
Water business services	—		—		25,409		—			25,409
Natural gas gathering & processing fees	—		—		10,798		—			10,798
All other⁽¹⁾	5,689		12,803		12,100		(19,196		)	11,396
Total service revenue	70,785		198,783		48,307		(22,477		)	295,398
Natural gas liquids sales	—		—		51,086		—			51,086
Natural gas sales	346		—		12,390		—			12,736
Crude oil sales	—		3,975		368		—			4,343
Total commodity sales revenue	346		3,975		63,844		—			68,165
Total revenue from contracts with customers	71,131		202,758		112,151		(22,477		)	363,563
Other revenue⁽²⁾	—		—		15,299		(6,179		)	9,120
Total revenue⁽³⁾	$	71,131	$	202,758	$	127,450	$	(28,656	)	$	372,683

Excludes revenue recognized at unconsolidated investments, including $227.6 million and $457.7 million of revenue recognized at Rockies Express for the three and six months ended June 30, 2018, respectively. See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express.

Performance Obligations

On ~~March 31,~~June 30, 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	$	337,924
2020	377,823
2021	178,407
2022	174,065
2023	154,302
Thereafter	243,270
Total	$	1,465,791

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

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.

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 at June 30, 2019 and December 31, 2018 were as follows:

Other accounts receivable⁽¹⁾

Deferred revenue from contracts with customers⁽²⁾

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 ana joint venture agreement with DHIF to ~~jointly-own~~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 4039 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 and six months ended ~~March 31,~~June 30, 2019, operating lease cost was $0.3 million and $0.5 million, respectively. For the six months ended June 30, 2019, cash paid included in operating cash flows was ~~$0.2~~$0.5 million. During ~~this period~~these periods 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,~~June 30, 2019 was as follows:

Maturities of lease liabilities as of ~~March 31,~~June 30, 2019 were as follows:

Finance Leases⁽¹⁾

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~~$2.3 million and $4.7 million for the three and six months ended ~~March 31,~~June 30, 2019, respectively, 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 and $0.4 million for the three and six months ended ~~March 31,~~June 30, 2019, respectively, and was recorded as "Other income, net" in the condensed consolidated statements of income.

At ~~March 31,~~June 30, 2019, future minimum rental income under non-cancelable operating leases as the lessor were as follows:



Year	Total
	(in thousands)
2019 - remaining	$	4,643
2020	4,871
2021	3,773
2022	3,773
2023	3,773
Thereafter	7,353
Total	$	28,186

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

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.~~14. Net Income per Class A Share

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

Diluted net income per Class A share is determined by dividing net income attributable to TGE by the weighted average number of outstanding diluted Class A shares during the period. For purposes of calculating diluted net income per Class A share, we considered the impact of possible future exercises of the Exchange Right by the Exchange Right Holders on both net income attributable to TGE and the diluted weighted average number of Class A shares outstanding. The Exchange Right Holders refers to the group of persons who collectively own all of TGE's outstanding Class B shares and an equivalent number of 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,~~June 30, 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 and six months ended ~~March 31,~~June 30, 2019, ~~and 2018,~~ the assumed issuance of TGE Equity Participation Shares would have had a dilutive effect on basic net income per Class A share as shown in the table below.

The potential issuance of TGE Equity Participation Shares would not have had a dilutive effect on the basic net income per Class A share for the three and six months ended June 30, 2018.

The following table illustrates the calculation of net income per Class A share for the three and six months ended ~~March 31,~~June 30, 2019 and 2018:



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
	(in thousands, except per unit amounts)
Basic Net Income per Class A Share
Net income attributable to TGE	$	71,619	$	1,063	$	122,206	$	17,798
Basic weighted average Class A Shares outstanding	179,149		59,397		170,336		58,745
Basic net income per Class A share	$	0.40	$	0.02	$	0.72	$	0.30
Diluted Net Income per Class A Share
Net income attributable to TGE	$	71,619	$	1,063	$	122,206	$	17,798
Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares	326		—		557		—
Net income attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares	$	71,945	$	1,063	$	122,763	$	17,798
Basic weighted average Class A Shares outstanding	179,149		59,397		170,336		58,745
Equity Participation Shares equivalent shares	1,258		—		1,489		—
Diluted weighted average Class A Shares outstanding	180,407		59,397		171,825		58,745
Diluted net income per Class A Share	$	0.40	$	0.02	$	0.71	$	0.30

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.~~15. 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 other regulatory filings with the FERC, including ~~the following:~~those further described below.

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 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~~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 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 2016 rate case settlement approved in Docket No. RP16-137-000, ~~settlement,~~ satisfies TIGT's mandatory rate case filing requirement under Article ~~IIB.1~~II.B.1 of such settlement. The pre-filing settlement establishes, ~~inter alia,~~among other things, settlement rates reflecting an overall decrease to recourse rates, contract extensions for maximum recourse rate firm contracts through May 31, 2023, and a rate moratorium ~~as well as~~period through May 31, 2023. The settlement also 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. TIGT has also requested that FERC terminate the pending Form No. 501-G proceeding in Docket No. RP19-423-000 upon approval of the pre-filing settlement. The filing remains pending before the FERC.

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~~order accepting and suspending the rate case filing, and establishing hearing and settlement procedures. In the ~~Order,~~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~~FERC 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~~were set for an administrative law judge hearing and ~~are~~ accepted effective January 1, 2019, subject to refund. On ~~August 30,~~December 31, 2018, Trailblazer filed a motion with FERC to move the suspended tariff records into effect as of January 1, 2019.

Trailblazer and certain of ~~Trailblazer's~~its shippers ~~filed a request for~~sought rehearing of the July 31, 2018 ~~Order, which remains pending before~~order. On July 2, 2019, 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~~issued an order on rehearing and clarification dismissing in part and denying in part the requests for rehearing and clarification, but granting Trailblazer's ~~proposed Income Tax Allowance.~~request for clarification that it may implement any resulting increases and decreases in the rates of its two systems in a single compliance filing at the conclusion of the proceeding.

On February 21, 2019, the FERC issued an ~~Order stating~~order following the paper hearing on the income tax allowance issue, making 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~~preliminarily 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 administrative law judge hearing with the other remaining ~~issues. On February 22,~~issues, and its initial findings may change based upon subsequent evidence and argument.

In March 2019, the Chief Administrative Law Judge ~~issued an order directing the ongoing~~terminated settlement judge procedures and ~~any subsequent hearing in~~established 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 administrative law judge 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,~~hearing currently scheduled to begin in ~~Docket No. RP19-888-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2018.~~January 2020. The ~~FERC accepted the filing on April 18, 2019.~~

~~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.~~

~~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.~~case remains ongoing.

~~15.~~16. Legal and Environmental Matters

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,~~June 30, 2019 or December 31, 2018.

On May 15, 2019, EM Energy Ohio, LLC ("EM Energy") and certain of its affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. EM Energy had a firm transportation service agreement with Rockies Express for 50,000 Dth/d through January 5, 2032. Rockies Express and EM Energy have stipulated in the bankruptcy proceeding that the termination date of the transportation service agreement is June 13, 2019. Following the termination, Rockies Express made a drawing equal to the outstanding face amount on the letter of credit supporting EM Energy's obligations under the transportation service agreement and received approximately $16.2 million in June 2019. A portion of the proceeds was used to settle outstanding accounts receivable for transportation services provided to EM Energy and the remaining $13.9 million was recognized as income by Rockies Express. Rockies Express intends to pursue its claim against the bankruptcy estate of EM Energy for damages and to remarket the capacity resulting from the termination of the transportation service agreement.

Ohio Public Utility Excise Tax

The Ohio Tax Commissioner has assessed Rockies Express a public utility excise tax on transactions concerning product that entered and exited 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,~~June 30, 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~~$5.8 million for amounts expected to be assessed for the period from May 1, 2018 through ~~March 31,~~June 30, 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~~$12.9 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~~$6.7 million and $7.4 million at ~~March 31,~~June 30, 2019 and December 31, 2018, respectively.

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.

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.

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.

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.~~17. 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. The Gathering, Processing & Terminalling segment includes our 51% membership interest in Pawnee Terminal.

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

We consider Adjusted EBITDA to be our primary segment performance measure as we believe it is the most meaningful measure to assess our financial condition and results of operations as a public entity. We define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments and deficiency payments received from or utilized by our customers. Adjusted EBITDA is calculated and presented at the Tallgrass Equity level, before consideration of noncontrolling interest associated with the Exchange Right Holders, which we believe provides investors the most complete and comparable picture of our overall financial and operational results.

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



	Six Months Ended June 30, 2019							Six Months Ended June 30, 2018
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Natural Gas Transportation	$	70,713	$	(901	)	$	69,812	$	71,131	$	(3,320	)	$	67,811
Crude Oil Transportation	229,954		(30,359		)	199,595		202,758		(12,744		)	190,014
Gathering, Processing & Terminalling	154,796		(15,327		)	139,469		127,450		(12,592		)	114,858
Corporate and Other	—		—			—		—		—			—
Total revenue	$	455,463	$	(46,587	)	$	408,876	$	401,339	$	(28,656	)	$	372,683

Equity in earnings of unconsolidated investments ⁽¹⁾

Gain on disposal of assets ⁽¹⁾

Non-cash gain (loss) related to derivative instruments ⁽¹⁾

Interest expense, net ⁽¹⁾



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	2932
Item 3. Quantitative and Qualitative Disclosures About Market Risk	4347
Item 4. Controls and Procedures	4448
PART II - OTHER INFORMATION	4549
Item 1. Legal Proceedings	4549
Item 1A. Risk Factors	4549
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	4549
Item 3. Defaults Upon Senior Securities	4550
Item 4. Mine Safety Disclosures	4550
Item 5. Other Information	4650
Item 6. Exhibits	4650
SIGNATURES	4751


	March 31, 2019		December 31, 2018		June 30, 2019		December 31, 2018
	(in thousands)				(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	15,042	$	9,596	$	9,429	$	9,596
Accounts receivable, net	227,284		236,097		235,665		236,097
Inventories	27,954		34,316		32,669		34,316
Prepayments and other current assets	18,219		11,816		15,967		11,816
Total Current Assets	288,499		291,825		293,730		291,825
Property, plant and equipment, net	2,750,375		2,802,429		2,820,965		2,802,429
Goodwill	421,983		421,983		442,672		421,983
Intangible assets, net	223,707		227,103		253,885		227,103
Unconsolidated investments	1,988,797		1,861,686		1,998,628		1,861,686
Deferred tax asset	379,422		273,531		357,429		273,531
Deferred charges and other assets	16,442		14,952		30,685		14,952
Total Assets	$	6,069,225	$	5,893,509	$	6,197,994	$	5,893,509
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	187,321	$	201,512	$	181,726	$	201,512
Accrued taxes	26,962		20,734		21,366		20,734
Accrued interest	12,534		39,217		38,880		39,217
Accrued liabilities	9,975		23,287		15,750		23,287
Deferred revenue	123,184		111,095		127,353		111,095
Other current liabilities	44,651		42,910		40,248		42,910
Total Current Liabilities	404,627		438,755		425,323		438,755
Long-term debt, net	3,331,716		3,205,958		3,437,490		3,205,958
Other long-term liabilities and deferred credits	33,118		31,688		53,182		31,688
Total Long-term Liabilities	3,364,834		3,237,646		3,490,672		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)	—		—
Class A Shareholders (179,197,416 and 156,311,986 shares outstanding at June 30, 2019 and December 31, 2018, respectively)					1,870,439		1,725,537
Class B Shareholders (102,136,875 and 123,887,893 shares outstanding at June 30, 2019 and December 31, 2018, respectively)					—		—
Total Partners' Equity	1,890,345		1,725,537		1,870,439		1,725,537
Noncontrolling interests ^(a)	409,419		491,571		411,560		491,571
Total Equity	2,299,764		2,217,108		2,281,999		2,217,108
Total Liabilities and Equity	$	6,069,225	$	5,893,509	$	6,197,994	$	5,893,509


	March 31, 2019		December 31, 2018		June 30, 2019		December 31, 2018
	(in thousands)				(in thousands)
Accounts receivable from contracts with customers	$	79,855	$	80,935	$	83,308	$	80,935
Other accounts receivable⁽¹⁾	143,949		151,414		148,470		151,414
Receivable from related parties	3,480		3,748		3,887		3,748
Accounts receivable, net	$	227,284	$	236,097	$	235,665	$	236,097

Deferred revenue from contracts with customers⁽²⁾	$	123,184	$	111,095	$	127,353	$	111,095


	Balance Sheet Location	March 31, 2019			Balance Sheet Location	June 30, 2019
Operating Leases:		(in thousands, except lease term and discount rate)				(in thousands, except lease term and discount rate)
Operating lease right-of-use assets	Deferred charges and other assets	$	2,171		Deferred charges and other assets	$	11,609		⁽¹⁾
Current operating lease liabilities	Other current liabilities	$	603		Other current liabilities	$	988		⁽¹⁾
Non-current operating lease liabilities	Other long-term liabilities and deferred credits	$	1,568		Other long-term liabilities and deferred credits	$	10,647		⁽¹⁾

Finance Leases:
Finance lease right-of-use asset ⁽¹⁾⁽²⁾	Property, plant and equipment, net	$	30,704		Property, plant and equipment, net	$	30,704

Weighted Average Remaining Lease Term:
Operating leases		4.6 years				16.0 years
Finance leases		39.7 years				39.4 years

Weighted Average Discount Rate:
Operating leases		4.63		%		5.59		%
Finance leases		7.01		%		7.01		%



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


^(a)	See Note 1011 - Partnership Equityfor a complete description of our noncontrolling interests.


^(a)	Represents the acquisition of additional TEP common units in exchange for Class A shares associated with the merger transaction with TEP.


^(b)	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.


⁽¹⁾	The dividend announced on ~~April~~July 11, 2019 for the ~~first~~second quarter of 2019 will be paid on ~~May 15,~~August 14, 2019 to Class A shareholders of record at the close of business on ~~April 30,~~July 31, 2019.


	Three Months Ended March 31, 2018											Six Months Ended June 30, 2019
	Natural Gas Transportation segment		Crude Oil Transportation segment		Gathering, Processing, & Terminalling segment		Corporate and Other			Total Revenue		Natural Gas Transportation segment		Crude Oil Transportation segment		Gathering, Processing, & Terminalling segment		Corporate and Other			Total Revenue
	(in thousands)											(in thousands)
Crude oil transportation - committed shipper revenue	$	—	$	84,738	$	—	$	—		$	84,738	$	—	$	194,716	$	—	$	—		$	194,716
Natural gas transportation - firm service	33,334		—		—		(1,883		)	31,451		64,505		—		—		(884		)	63,621
Water business services	—		—		13,204		—			13,204		—		—		49,585		—			49,585
Natural gas gathering & processing fees	—		—		5,044		—			5,044		—		—		11,410		—			11,410
All other⁽¹⁾	2,630		3,319		5,706		(6,088		)	5,567		6,089		30,508		7,264		(35,748		)	8,113
Total service revenue	35,964		88,057		23,954		(7,971		)	140,004		70,594		225,224		68,259		(36,632		)	327,445
Natural gas liquids sales	—		—		23,609		—			23,609		—		—		30,047		—			30,047
Natural gas sales	238		—		7,847		—			8,085		119		—		15,509		—			15,628
Crude oil sales	—		1,909		247		—			2,156		—		4,730		246		—			4,976
Total commodity sales revenue	238		1,909		31,703		—			33,850		119		4,730		45,802		—			50,651
Total revenue from contracts with customers	36,202		89,966		55,657		(7,971		)	173,854		70,713		229,954		114,061		(36,632		)	378,096
Other revenue⁽²⁾	—		—		8,181		(2,941		)	5,240		—		—		40,735		(9,955		)	30,780
Total revenue⁽³⁾	$	36,202	$	89,966	$	63,838	$	(10,912	)	$	179,094	$	70,713	$	229,954	$	154,796	$	(46,587	)	$	408,876


⁽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~~$232.3 million and ~~$230.1~~$463.1 million of revenue recognized at Rockies Express for the three and six months ended ~~March 31,~~June 30, 2019, ~~and 2018,~~ respectively. See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express.


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


⁽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 and six months ended ~~March 31,~~June 30, 2019 that was included in the deferred revenue balance at the beginning of the period was ~~$1.6 million.~~$4.9 million and $6.5 million, respectively. This revenue primarily represented the utilization of shipper deficiencies at Pony Express.


⁽¹⁾	Includes right-of-use asset of approximately $9.1 million and current and non-current lease liabilities of $0.1 million and $9.0 million, respectively, related to Guernsey Terminal capacity that we lease from Powder River Gateway.


⁽²⁾	PLT satisfied the initial capital lease obligation of $30.7 million at lease inception and as a result has no outstanding liability or imputed interest on the future minimum rental commitments.



	Six Months Ended June 30, 2019									Six Months Ended June 30, 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	$	283,128		$	(2,090	)	$	281,038		$	131,736		$	(1,480	)	$	130,256
Crude Oil Transportation	170,698			(13,154		)	157,544			63,376			1,151			64,527
Gathering, Processing & Terminalling	51,769			15,244			67,013			16,323			329			16,652
Corporate and Other	(5,568		)	—			(5,568		)	(18,502		)	—			(18,502		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investments ⁽¹⁾							187,534									76,967
Gain on disposal of assets ⁽¹⁾							—									3,109
Less:
Interest expense, net ⁽¹⁾							(80,311		)							(23,189		)
Depreciation and amortization expense ⁽¹⁾							(63,319		)							(18,438		)
Distributions from unconsolidated investments ⁽¹⁾							(240,568		)							(97,299		)
Non-cash compensation expense ⁽¹⁾							(20,570		)							(1,971		)
Deficiency payments, net ⁽¹⁾							(16,570		)							(3,737		)
Non-cash (loss) gain related to derivative instruments ⁽¹⁾							(1,029		)							313
Income tax expense ⁽¹⁾							(39,043		)							(23,501		)
Net income attributable to Exchange Right Holders							(103,945		)							(87,389		)
Net income attributable to TGE							$	122,206								$	17,798


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



	Six Months Ended June 30,
Capital Expenditures:	2019		2018
	(in thousands)
Natural Gas Transportation	$	54,174	$	72,882
Crude Oil Transportation	54,045		24,945
Gathering, Processing & Terminalling	38,549		76,342
Corporate and Other	3,283		2,106
Total capital expenditures	$	150,051	$	176,275



Assets:	June 30, 2019		December 31, 2018
	(in thousands)
Natural Gas Transportation	$	2,645,996	$	2,606,696
Crude Oil Transportation	1,749,987		1,423,740
Gathering, Processing & Terminalling	1,541,970		1,522,559
Corporate and Other	260,041		340,514
Total assets	$	6,197,994	$	5,893,509


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


⁽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.


⁽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 1617 – Reportable Segments.


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


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


Segment Financial Data – Natural Gas Transportation ⁽¹⁾	Three Months Ended March 31,					Three Months Ended June 30,				Six Months Ended June 30,
	2019			2018		2019		2018		2019		2018
	(in thousands)					(in thousands)
Revenues:
Natural gas transportation services	$	33,930		$	34,054	$	32,832	$	32,936	$	66,762	$	66,990
Sales of natural gas, NGLs, and crude oil	—			237		119		108		119		345
Processing and other revenues	1,912			1,911		1,920		1,885		3,832		3,796
Total revenues	35,842			36,202		34,871		34,929		70,713		71,131
Operating costs and expenses:
Cost of sales	—			343		841		88		841		431
Cost of transportation services	(262		)	132		594		822		332		954
Operations and maintenance	6,040			6,163		6,981		7,324		13,021		13,487
Depreciation and amortization	4,948			4,827		4,959		4,851		9,907		9,678
General and administrative	3,880			3,934		3,381		3,957		7,261		7,891
Taxes, other than income taxes	1,300			1,419		1,145		1,005		2,445		2,424
Total operating costs and expenses	15,906			16,818		17,901		18,047		33,807		34,865
Operating income	$	19,936		$	19,384	$	16,970	$	16,882	$	36,906	$	36,266


Segment Financial Data – Crude Oil Transportation ⁽¹⁾	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018		2019		2018
	(in thousands)				(in thousands)
Revenues:
Crude oil transportation services	$	109,578	$	88,057	$	115,393	$	110,591	$	224,971	$	198,648
Sales of natural gas, NGLs, and crude oil	—		1,909		4,730		2,066		4,730		3,975
Processing and other revenues	206		—		47		135		253		135
Total revenues	109,784		89,966		120,170		112,792		229,954		202,758
Operating costs and expenses:
Cost of sales	521		1,966		4,088		2,029		4,609		3,995
Cost of transportation services	16,898		14,387		19,632		17,647		36,530		32,034
Operations and maintenance	3,050		2,870		3,794		3,010		6,844		5,880
Depreciation and amortization	13,699		13,366		13,744		13,593		27,443		26,959
General and administrative	5,456		4,492		4,474		4,320		9,930		8,812
Taxes, other than income taxes	8,723		6,358		5,475		6,479		14,198		12,837
Total operating costs and expenses	48,347		43,439		51,207		47,078		99,554		90,517
Operating income	$	61,437	$	46,527	$	68,963	$	65,714	$	130,400	$	112,241


Segment Financial Data – Gathering, Processing & Terminalling ⁽¹⁾	Three Months Ended March 31,					Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018			2019		2018		2019		2018
	(in thousands)					(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	38,864	$	35,999		$	32,994	$	35,076	$	71,858	$	71,075
Processing and other revenues	35,170		27,839			47,768		28,536		82,938		56,375
Total revenues	74,034		63,838			80,762		63,612		154,796		127,450
Operating costs and expenses:
Cost of sales	18,879		24,566			14,434		25,698		33,313		50,264
Cost of transportation services	20,629		6,289			23,712		11,818		44,341		18,107
Operations and maintenance	8,956		7,366			12,697		8,106		21,653		15,472
Depreciation and amortization	11,750		7,294			13,167		8,070		24,917		15,364
General and administrative	4,022		3,333			3,636		2,941		7,658		6,274
Taxes, other than income taxes	975		1,102			1,091		978		2,066		2,080
Loss (gain) on disposal of assets	214		(9,417		)	28		279		242		(9,138		)
Total operating costs and expenses	65,425		40,533			68,765		57,890		134,190		98,423
Operating income	$	8,609	$	23,305		$	11,997	$	5,722	$	20,606	$	29,027


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


•	a decrease in accrued liabilities of $7.5 million primarily due to annual incentive payments made during the first quarter of 2019; and


•	an increase in prepayments and other current assets of $4.2 million primarily due to timing of prepaid insurance renewals made during 2019.


	Fair Value			Effect of 10% Price Increase			Effect of 10% Price Decrease		Fair Value			Effect of 10% Price Increase			Effect of 10% Price Decrease
	(in thousands)								(in thousands)
Crude oil derivative contract assets⁽¹⁾	$	1,761		$	—		$	—	$	1,843		$	110		$	(110	)
Crude oil derivative contract liabilities⁽¹⁾	$	(1,129	)	$	(1,481	)	$	1,481	$	(17	)	$	(1,502	)	$	1,502