UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended September 30, 2018

or

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

Commission file number 001-37365

Tallgrass Energy, LP

(Exact name of registrant as specified in its charter)

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)

(913) 928-6060

(Registrant's Telephone Number, Including Area Code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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

On October 31, 2018, the Registrant had 156,308,654 Class A shares and 123,887,893 Class B shares outstanding.

TALLGRASS ENERGY, LP

TABLE OF CONTENTS

PART 1—FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
CONDENSED CONSOLIDATED BALANCE SHEETS	1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME	2
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY	3
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	4
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	6
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3. Quantitative and Qualitative Disclosures About Market Risk	52
Item 4. Controls and Procedures	53
PART II - OTHER INFORMATION	54
Item 1. Legal Proceedings	54
Item 1A. Risk Factors	54
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 3. Defaults Upon Senior Securities	54
Item 4. Mine Safety Disclosures	54
Item 5. Other Information	54
Item 6. Exhibits	54
SIGNATURES	55

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.

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

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

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

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

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

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

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

TBtu: one trillion British Thermal Units.

Tcf: one trillion cubic feet.

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

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

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

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

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

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

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

PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2018		December 31, 2017
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	5,521	$	2,593
Accounts receivable, net	235,700		118,615
Receivable from related parties	3,369		1,340
Inventories	29,317		21,609
Prepayments and other current assets	16,344		13,165
Total Current Assets	290,251		157,322
Property, plant and equipment, net	2,662,055		2,394,337
Goodwill	404,838		404,838
Intangible assets, net	132,826		97,731
Unconsolidated investments	1,872,879		909,531
Deferred financing costs, net	11,778		12,563
Deferred tax asset	291,886		312,997
Deferred charges and other assets	3,527		2,694
Total Assets	$	5,670,040	$	4,292,013
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	223,148	$	98,882
Accounts payable to related parties	—		5,342
Accrued taxes	25,437		19,272
Accrued interest	12,523		25,167
Accrued liabilities	18,032		10,540
Deferred revenue	103,652		88,471
Other current liabilities	14,409		11,202
Total Current Liabilities	397,201		258,876
Long-term debt, net	3,033,674		2,292,993
Other long-term liabilities and deferred credits	20,117		18,965
Total Long-term Liabilities	3,053,791		2,311,958
Commitments and Contingencies
Equity:
Class A Shareholders (155,887,756 and 58,085,002 shares outstanding at September 30, 2018 and December 31, 2017, respectively)	1,738,245		48,613
Class B Shareholders (124,305,459 and 99,154,440 shares outstanding at September 30, 2018 and December 31, 2017, respectively)	—		—
Total Partners' Equity	1,738,245		48,613
Noncontrolling interests (a)	480,803		1,672,566
Total Equity	2,219,048		1,721,179
Total Liabilities and Equity	$	5,670,040	$	4,292,013

^(a)  See Note 11 - Partnership Equityfor a complete description of our noncontrolling interests.

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

1

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands, except per unit amounts)
Revenues:
Crude oil transportation services	$	100,226		$	86,180		$	286,130		$	260,366
Natural gas transportation services	30,953			30,256			94,623			91,370
Sales of natural gas, NGLs, and crude oil	44,072			32,215			119,467			70,514
Processing and other revenues	25,069			27,218			72,783			58,882
Total Revenues	200,320			175,869			573,003			481,132
Operating Costs and Expenses:
Cost of sales	28,556			26,984			82,601			58,740
Cost of transportation services	12,588			10,538			35,672			38,799
Operations and maintenance	18,011			17,412			52,850			45,569
Depreciation and amortization	27,595			23,782			81,408			67,276
General and administrative	16,015			16,489			53,526			46,040
Taxes, other than income taxes	7,750			6,661			25,091			21,799
Gain on disposal of assets	(279		)	—			(9,417		)	(1,264		)
Total Operating Costs and Expenses	110,236			101,866			321,731			276,959
Operating Income	90,084			74,003			251,272			204,173
Other Income (Expense):
Equity in earnings of unconsolidated investments	76,268			123,642			222,857			187,121
Interest expense, net	(34,019		)	(24,408		)	(95,062		)	(61,539		)
Other (expense) income, net	(1,624		)	10,182			(843		)	12,409
Total Other Income (Expense)	40,625			109,416			126,952			137,991
Net income before tax	130,709			183,419			378,224			342,164
Deferred income tax expense	(11,997		)	(12,642		)	(35,498		)	(24,982		)
Net income	118,712			170,777			342,726			317,182
Net income attributable to noncontrolling interests	(59,162		)	(154,911		)	(265,378		)	(280,534		)
Net income attributable to TGE	$	59,550		$	15,866		$	77,348		$	36,648
Net income per Class A share:
Basic net income per Class A share	$	0.38		$	0.27		$	0.85		$	0.63
Diluted net income per Class A share	$	0.38		$	0.27		$	0.85		$	0.63
Basic average number of Class A shares outstanding	155,001			58,075			91,183			58,075
Diluted average number of Class A shares outstanding	156,088			58,192			92,661			58,193

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

2

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)

	Predecessor Equity			Partners' Capital					Noncontrolling Interests			Total Equity
				Class A Shares			Class B Shares
	(in thousands)
Balance at January 1, 2018	$	—		$	48,613		$	—	$	1,672,566		$	1,721,179
Cumulative effect of ASC 606 implementation	—			4,588			—		39,543			44,131
Net income	—			77,348			—		265,378			342,726
Dividends paid to Class A shareholders	—			(126,714		)	—		—			(126,714		)
Noncash compensation expense	—			2,378			—		3,197			5,575
Acquisition of additional TEP common units from TD	—			(62,223		)	—		(189,520		)	(251,743		)
Issuance of Tallgrass Equity units	—			—			—		644,782			644,782
Acquisition of 25.01% membership interest in Rockies Express	—			34,116			—		74,421			108,537
Acquisition of additional 2% membership interest in Pony Express	—			(5,268		)	—		(44,732		)	(50,000		)
Consolidation of Deeprock North	—			—			—		31,843			31,843
Contributions from noncontrolling interest	—			—			—		183			183
Distributions to noncontrolling interest	—						—		(262,856		)	(262,856		)
Issuance of TEP common units to the public, net of offering costs	—			(98		)	—		(279		)	(377		)
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	—			(10,135		)	—		10,135			—
Deferred tax asset	—			13,503			—		—			13,503
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 September 30, 2018	$	—		$	1,738,245		$	—	$	480,803		$	2,219,048
	Predecessor Equity			Partners' Capital					Noncontrolling Interests			Total Equity
				Class A Shares			Class B Shares
	(in thousands)
Balance at January 1, 2017	$	82,295		$	250,967		$	—	$	1,596,152		$	1,929,414
Acquisition of Terminals and NatGas	(82,295		)	(21,314		)	—		(36,391		)	(140,000		)
Net income	—			36,648			—		280,534			317,182
Issuance of TEP common units to the public, net of offering costs	—			11,350			—		101,043			112,393
Dividends paid to Class A shareholders	—			(52,704		)	—		—			(52,704		)
Noncash compensation expense	—			1,186			—		6,169			7,355
TEP LTIP units tendered by employees to satisfy tax withholding obligations	—			(1,263		)	—		(11,139		)	(12,402		)
Partial exercise of call option	—			(12,052		)	—		(72,890		)	(84,942		)
Repurchase of TEP common units from TD	—			(3,618		)	—		(31,717		)	(35,335		)
Acquisition of additional 24.99% membership interest in Rockies Express	—			23,522			—		40,159			63,681
Acquisition of additional 40% membership interest in Deeprock Development	—			—			—		45,869			45,869
Contributions from TD	—			850			—		1,451			2,301
Contributions from noncontrolling interest	—			—			—		1,093			1,093
Distributions to noncontrolling interest	—			—			—		(229,710		)	(229,710		)
Acquisition of noncontrolling interests	—			669			—		(7,109		)	(6,440		)
Balance at September 30, 2017	$	—		$	234,241		$	—	$	1,683,514		$	1,917,755

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

3

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Cash Flows from Operating Activities:
Net income	$	342,726		$	317,182
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	86,121			73,087
Equity in earnings of unconsolidated investments	(222,857		)	(187,121		)
Distributions from unconsolidated investments	222,082			187,624
Deferred income tax expense	35,498			24,982
Other noncash items, net	(4,681		)	(6,772		)
Changes in components of working capital:
Accounts receivable and other	(115,330		)	(34,189		)
Accounts payable and accrued liabilities	104,920			42,680
Deferred revenue	14,265			26,898
Other current assets and liabilities	1,682			5,032
Other operating, net	1,965			974
Net Cash Provided by Operating Activities	466,391			450,377
Cash Flows from Investing Activities:
Contributions to unconsolidated investments	(444,788		)	(31,570		)
Capital expenditures	(265,073		)	(88,050		)
Acquisition of BNN North Dakota, net of cash acquired	(95,000		)	—
Distributions from unconsolidated investments in excess of cumulative earnings	60,720			41,886
Sale of Tallgrass Crude Gathering	50,046			—
Acquisition of Pawnee membership interest	(30,600		)	—
Acquisition of 38% membership interest in Deeprock North	(19,500		)	—
Acquisition of Rockies Express membership interest	—			(400,000		)
Acquisition of Terminals and NatGas	—			(140,000		)
Acquisition of Douglas Gathering System	—			(128,526		)
Acquisition of Deeprock Development	—			(57,202		)
Acquisition of PRB Crude System	—			(36,030		)
Other investing, net	(12,304		)	(13,449		)
Net Cash Used in Investing Activities	(756,499		)	(852,941		)
Cash Flows from Financing Activities:
Proceeds from issuance of long-term debt	500,000			850,000
Distributions to noncontrolling interests	(262,856		)	(229,710		)
Borrowings (repayments) under revolving credit facilities, net	244,000			(136,000		)
Dividends paid to Class A shareholders	(126,714		)	(52,704		)
Acquisition of Pony Express membership interest	(50,000		)	—
Proceeds from public offering of TEP common units, net of offering costs	—			112,393
Partial exercise of call option	—			(72,381		)
Repurchase of TEP common units from TD	—			(35,335		)
Other financing, net	(11,394		)	(32,879		)
Net Cash Provided by Financing Activities	293,036			403,384
Net Change in Cash and Cash Equivalents	2,928			820
Cash and Cash Equivalents, beginning of period	2,593			2,459
Cash and Cash Equivalents, end of period	$	5,521		$	3,279

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

4

Schedule of Noncash Investing and Financing Activities:
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	)	$	—
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	)	$	—
Increase in accrual for payment of property, plant and equipment	$	8,517		$	1,342
TEP common units issued as partial consideration to acquire additional 9% membership interest in Deeprock Development	$	—		$	6,617

^(a)  Represents the acquisition of additional TEP common units in exchange for Class A shares associated with the Merger Agreement as discussed in Note 1 – Description of Business.

^(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 as discussed in Note 3 – Acquisitions and Dispositions.

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

5

TALLGRASS ENERGY, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Description of Business

Tallgrass Energy, LP ("TGE"), formerly known as Tallgrass Energy GP, LP, is a limited partnership that owns, operates, acquires and develops midstream energy assets in North America and has elected to be treated as a corporation for U.S. federal income tax purposes. "We," "us," "our" and similar terms refer to TGE together with its consolidated subsidiaries.

Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity, LLC ("Tallgrass Equity"), in which we directly own an approximate 55.64% membership interest as of September 30, 2018. We are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations.

Our reportable business segments are:

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

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

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

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

Crude Oil Transportation. We provide crude oil transportation to customers in Wyoming, Colorado, Kansas, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a FERC-regulated crude oil pipeline commencing in both Guernsey, Wyoming and Weld County, Colorado and terminating in Cushing, Oklahoma (the "Pony Express System"). In the second quarter of 2018, Pony Express placed into service an extension of the system from an additional origin point in Weld County, Colorado located near Platteville, Colorado.

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

The term "Terminals Predecessor" refers to Terminals and the term "NatGas Predecessor" refers to NatGas prior to their acquisition by TEP on January 1, 2017. Terminals Predecessor and NatGas Predecessor are collectively referred to as the Predecessor Entities. Financial results for all prior periods have been recast to reflect the operations of the Predecessor Entities. Predecessor Equity as presented in the condensed consolidated financial statements represents the capital account activity of Terminals Predecessor and NatGas Predecessor prior to January 1, 2017.

6

Merger Agreement with Tallgrass Energy Partners, LP

TGE previously entered into a definitive Agreement and Plan of Merger, dated as of March 26, 2018 (the "Merger Agreement"), with Tallgrass Equity, Tallgrass Energy Partners, LP, a Delaware limited partnership ("TEP"), Tallgrass MLP GP, LLC, a Delaware limited liability company and the general partner of TEP ("TEP GP"), and Razor Merger Sub, LLC, a Delaware limited liability company. The merger transaction contemplated by the Merger Agreement (the "TEP Merger") was completed effective June 30, 2018, and as a result, 47,693,097 TEP common units held by the public were converted into the right to receive Class A shares of TGE at an exchange ratio of 2.0 Class A shares for each outstanding TEP common unit, TEP's incentive distribution rights were cancelled, TEP's common units are no longer publicly traded, and 100% of TEP's equity interests are now owned by Tallgrass Equity and its subsidiaries. The TEP Merger was accounted for as an acquisition of noncontrolling interest. Following consummation of the TEP Merger, TGE changed its name from "Tallgrass Energy GP, LP" to "Tallgrass Energy, LP" and began trading on the New York Stock Exchange under the ticker symbol "TGE" on July 2, 2018.

2. Summary of Significant Accounting Policies

Basis of Presentation

These condensed consolidated financial statements and related notes for the three and nine months ended September 30, 2018 and 2017 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 nine months ended September 30, 2018 and 2017 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.

Our financial results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2018. 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, 2017 ("2017 Form 10-K") filed with the SEC on February 13, 2018.

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

A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. We have presented separately in our condensed consolidated balance sheets, to the extent material, the liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Our consolidated VIEs did not have material assets that could only be used to settle specific obligations of the consolidated VIEs. Prior to June 29, 2018, both Tallgrass Equity and TEP were considered to be VIEs under the applicable authoritative guidance and included in our consolidated results. As a result of the TEP Merger, and changes in ownership and their respective partnership arrangements, Tallgrass Equity and TEP are no longer considered to be VIEs. We continue to consolidate our membership interests in Tallgrass Equity and TEP through the voting interest model.

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Use of Estimates

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

Accounting Pronouncement Recently Adopted

Revenue Recognition

In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract.

Management completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to members' equity. Consolidated revenues presented in the comparative consolidated financial statements for periods prior to January 1, 2018 have not been revised.

On January 1, 2018, we recorded a cumulative effect adjustment to equity of $44.1 million, increased the carrying amount of our investment in Rockies Express by $42.8 million, and recognized a receivable from Rockies Express of $1.3 million. These adjustments relate to the cumulative effect adjustment recorded by Rockies Express of $125.2 million upon adoption of ASC 606. The cumulative effect adjustment at Rockies Express arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas during the periods prior to implementation.

Through our review process, we also identified the following changes to our revenue recognition policies that did not result in a cumulative effect adjustment on January 1, 2018:

• Gathering & Processing. We have determined that a number of our gathering & processing contracts at TMID do not represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of raw gas will be accounted for as supply arrangements pursuant to ASC 705. As a result, gathering & processing fees previously recognized in revenue will be reported as a reduction to cost of sales under ASC 606.

• Pipeline Loss Allowance. We have determined that pipeline loss allowance, or PLA, collected under certain crude oil transportation arrangements is a component of the transaction price where the PLA both significantly exceeds actual losses and was negotiated with the intent of providing a revenue stream to Pony Express. Under ASC 606, PLA barrels retained from customers will be subject to the guidance for noncash consideration and recognized in revenue at their contract inception fair value.

See Note 12 – Revenue from Contracts with Customers for revenue disclosures related to both the implementation and the additional requirements prescribed by the standard. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities.

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Accounting Pronouncements Not Yet Adopted

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

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP.

Management is currently evaluating the impact of our pending adoption of ASC 842. The status of our implementation is as follows:

• Management has formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain contract types, and project status.

• Management is in the process of gathering data and reviewing contracts in order to identify all impacted contracts.

• Management is evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from its contract review process.

• Management plans to provide internal training and awareness related to the revised guidance to the key stakeholders throughout its organization.

The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. We plan to adopt ASU 2016-02 on January 1, 2019 using the modified retrospective method. ASC 842 provides for a number of practical expedients. We intend to elect the following practical expedients upon adoption of ASC 842:

•An entity need not reassess whether any expired or existing contracts are or contain leases.

•An entity need not reassess the lease classification for any expired or existing leases.

•An entity need not reassess initial direct costs for any existing leases.

• An entity may elect to not assess whether existing or expired land easements that were not previously accounted for as leases are or contain a lease under ASC 842.

While we are still in the process of quantifying the impact of adoption, we do not currently expect the adoption to have a material impact. We expect to recognize a right of use asset and lease liability at the implementation date, but we cannot reasonably estimate the full impact of the standard at this time. Additionally, we are currently evaluating our business processes, systems, and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new lease guidance.

3. Acquisitions and Dispositions

Acquisition of Pawnee

On January 2, 2018, we entered into an agreement to acquire a 51% membership interest in the Pawnee, Colorado crude oil terminal ("Pawnee") from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $30.6 million. The transaction closed on April 1, 2018. As the 51% membership interest does not represent a controlling interest in Pawnee, our investment in Pawnee is recorded under the equity method of accounting and reported as "Unconsolidated investments" on the condensed consolidated balance sheets.

Acquisition of an Additional 25.01% Membership Interest in Rockies Express and Additional TEP Common Units

In February 2018, Tallgrass Development, LP ("TD") merged into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity ("Tallgrass Development Holdings"), and as a result of the merger, Tallgrass Equity acquired a 25.01% membership interest in Rockies Express and an additional 5,619,218 TEP common units. As consideration for the acquisition, TGE and Tallgrass Equity issued 27,554,785 unregistered TGE Class B shares and Tallgrass Equity units, valued at approximately $644.8 million based on the closing price on February 6, 2018, to the limited partners of TD. Subsequent to the closing of the transaction, our aggregate membership interest in Rockies Express is 75%.

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The transfer of the Rockies Express membership interest between TD and Tallgrass Equity is considered a transaction between entities under common control, but does not represent a change in reporting entity. As a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed contribution representing the excess carrying value of the 25.01% membership interest in Rockies Express acquired over the fair value of the consideration paid. For further discussion, see Note 11 - Partnership Equity. As the aggregate 75% membership interest does not represent a controlling interest in Rockies Express, TGE's investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our condensed consolidated balance sheets. As a result of the common control nature of the transaction, the 25.01% membership interest in Rockies Express was transferred to Tallgrass Equity at TD's historical carrying amount, including the remaining unamortized basis difference driven by the difference between the fair value of the investment and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD. For additional information, see Note 7 - Investments in Unconsolidated Affiliates.

The acquisition of an additional 5,619,218 TEP common units is considered an acquisition of noncontrolling interest and resulted in the recognition of a noncash deemed distribution representing the excess purchase price over the $53.8 million carrying value of the 5,619,218 TEP common units acquired as of February 7, 2018. For further discussion, see Note 11 - Partnership Equity.

As of February 7, 2018, the negative basis difference in Rockies Express carried over from TD was approximately $376.5 million. The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years, which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. At September 30, 2018, the basis difference for our membership interests in Rockies Express was allocated as follows:

	Basis Difference			Amortization Period
	(in thousands)
Long-term debt	$	48,019		2 - 25 years
Property, plant and equipment	(1,156,562		)	35 years
Total basis difference	$	(1,108,543	)

Sale of Tallgrass Crude Gathering

In February 2018, we entered into an agreement with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to sell our 100% membership interest in Tallgrass Crude Gathering, LLC ("TCG"), which owns a 50-mile crude oil gathering system in the Powder River Basin, for approximately $50.0 million. The sale of TCG closed on February 23, 2018. During the nine months ended September 30, 2018, we recognized a gain of $9.4 million on the sale which is presented in the line item "Gain on disposal of assets" in the condensed consolidated statements of income.

Joint Venture with Silver Creek

In February 2018, we entered into an agreement with Silver Creek to form Iron Horse Pipeline, LLC ("Iron Horse"), a new joint venture pipeline to transport crude oil from the Powder River Basin. During the nine months ended September 30, 2018, we contributed an initial $3.5 million and committed to funding our proportionate share of the remaining costs of construction in exchange for a 75% membership interest in Iron Horse. As the 75% membership interest does not represent a controlling interest in Iron Horse, our investment in Iron Horse is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the condensed consolidated balance sheets.

In August 2018, we entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the contribution by us and Silver Creek of additional Powder River Basin assets. Upon the closing of the additional contributions, the expanded joint venture will operate under the name Powder River Gateway, LLC, and will own the Iron Horse pipeline, the Powder River Express Pipeline, and crude oil terminal facilities in Guernsey, Wyoming. We will own a 51% membership interest and continue to operate the joint venture following closing, and Silver Creek will own a 49% membership interest. We expect to close the additional contributions in the fourth quarter of 2018, subject to certain closing conditions.

Acquisition of Additional 2% Membership Interest in Pony Express

In February 2018, we acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from TD for cash consideration of approximately $60 million, bringing our aggregate membership interest in Pony Express to 100%. The acquisition of the remaining 2% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction has not been recast to reflect the additional 2% membership interest.

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Acquisition of BNN North Dakota

In January 2018, we acquired 100% of the membership interests in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC, which were subsequently merged and renamed BNN North Dakota, LLC ("BNN North Dakota"), for approximately $95.0 million, net of cash acquired. BNN North Dakota owns a produced water gathering and disposal system in the Bakken basin with approximately 133,000 acres under dedication. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.

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

Accounts receivable	$	2,457
Inventory	67
Property, plant and equipment	48,900
Intangible asset	46,800			(1)
Accounts payable and accrued liabilities	(3,224		)
Net identifiable assets acquired (excluding cash)	$	95,000

⁽¹⁾  The $46.8 million intangible asset acquired represents three major customer relationships. This intangible asset is amortized on a straight-line basis over a period of 8 - 14 years, the remaining terms of the underlying contracts at the time of acquisition.

At March 31, 2018, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2018. Actual revenue and net income attributable to TGE from BNN North Dakota of $13.3 million and $2.9 million, respectively, was recognized in the accompanying condensed consolidated statements of income for the period from January 12, 2018 to September 30, 2018.

Pro Forma Financial Information

Unaudited pro forma revenue and net income attributable to TGE for the nine months ended September 30, 2018 and 2017 is presented below as if the acquisition of BNN North Dakota had been completed on January 1, 2017.

	Nine Months Ended September 30,
	2018		2017
	(in thousands)
Revenue	$	573,431	$	488,076
Net income attributable to TGE	$	77,374	$	36,384

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.

Acquisition of Deeprock North and Merger with Deeprock Development

In January 2018, we acquired an approximate 38% membership interest in Deeprock North, LLC ("Deeprock North") from Kinder Morgan Deeprock North Holdco LLC for cash consideration of $19.5 million. Immediately following the acquisition, Deeprock North was merged into Deeprock Development, LLC ("Deeprock Development"), and the members of Deeprock North and Deeprock Development received adjusted membership interests in the combined entity. As a result, we recognized additional noncontrolling interests in Deeprock Development of $31.8 million. The acquisition of Deeprock North by Deeprock Development has been accounted for as an asset acquisition, with substantially all of the fair value allocated to the long-lived assets acquired based on their relative fair values. After the acquisition and merger, we own an approximate 60% membership interest in the combined entity.

4. Related Party Transactions

As a result of our relationship with Tallgrass Energy Holdings, LLC ("Tallgrass Energy Holdings") and its affiliates, we have entered into a number of related party transactions. The following disclosure includes those related party transactions which are not otherwise disclosed in these notes to our condensed consolidated financial statements.

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All of our employees are employed by Tallgrass Management, LLC ("Tallgrass Management"). Prior to July 1, 2018, Tallgrass Management was a wholly-owned subsidiary of Tallgrass Energy Holdings. In connection with the closing of the TEP initial public offering on May 17, 2013, TEP and TEP GP entered into an Omnibus Agreement with Tallgrass Energy Holdings and certain of its affiliates (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse Tallgrass Energy Holdings and its affiliates for all expenses they incur and payments they make on TEP's behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by Tallgrass Energy Holdings and its affiliates, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the closing of the TGE initial public offering on May 12, 2015 (the "TGE IPO"), TGE entered into an Omnibus Agreement (the "TGE Omnibus Agreement") with Tallgrass Energy GP, LLC (formerly known as TEGP Management, LLC), Tallgrass Equity and Tallgrass Energy Holdings.

Effective July 1, 2018, Tallgrass Management was contributed to Tallgrass Equity in connection with the TEP Merger. As a result, the costs of employer and director compensation and benefits are now incurred directly by Tallgrass Equity.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
Processing and other revenues (1)	$	1,838	$	3,338	$	5,603	$	6,662
Cost of transportation services (2)	$	—	$	1,062	$	—	$	10,476
Charges to TGE: (3)
Property, plant and equipment, net	$	—	$	765	$	—	$	1,568
Operations and maintenance	$	—	$	7,973	$	—	$	21,680
General and administrative	$	—	$	11,960	$	—	$	32,628

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

⁽²⁾  Reflects rent expense for the crude oil storage at the Deeprock Terminal prior to our consolidation of Deeprock Development during the third quarter of 2017.

⁽³⁾  Charges to TGE, inclusive of Tallgrass Equity and TEP, include indirectly charged wages and salaries, other compensation and benefits, and shared services for periods prior to January 1, 2018. Effective January 1, 2018, these costs are incurred by TEP directly and, in the case of certain employee compensation and benefits, paid on TEP's behalf by its affiliate, Tallgrass Management, LLC, pursuant to the TEP Omnibus Agreement.

Details of balances with affiliates included in "Receivable from related parties" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows:

	September 30, 2018		December 31, 2017
	(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	3,152	$	1,340
Iron Horse Pipeline, LLC	112		—
Pawnee Terminal, LLC	105		—
Total receivable from related parties	$	3,369	$	1,340
Accounts payable to related parties:
Tallgrass Operations, LLC (1)	$	—	$	5,342
Total accounts payable to related parties	$	—	$	5,342

⁽¹⁾  Reflects accounts payable for charges to TGE, inclusive of Tallgrass Equity and TEP, including indirectly charged wages and salaries, other compensation and benefits, and shared services prior to January 1, 2018 as discussed above.

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Gas imbalances with affiliated shippers are as follows:

	September 30, 2018		December 31, 2017
	(in thousands)
Affiliate gas imbalance receivables	$	17	$	18
Affiliate gas imbalance payables	$	689	$	442

5. Inventory

The components of inventory at September 30, 2018 and December 31, 2017 consisted of the following:

	September 30, 2018		December 31, 2017
	(in thousands)
Crude oil	$	18,893	$	12,792
Materials and supplies	6,359		5,891
Natural gas liquids	364		942
Gas in underground storage	3,701		1,984
Total inventory	$	29,317	$	21,609

6. Property, Plant and Equipment

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

	September 30, 2018			December 31, 2017
	(in thousands)
Crude oil pipelines	$	1,290,868		$	1,220,379
Gathering, processing and terminalling assets (1)	791,766			675,092
Natural gas pipelines	612,729			581,400
General and other	125,261			98,680
Construction work in progress	198,356			97,978
Accumulated depreciation and amortization	(356,925		)	(279,192		)
Total property, plant and equipment, net	$	2,662,055		$	2,394,337

⁽¹⁾  Includes approximately $46.2 million and $40.1 million of assets associated with the acquisitions of Deeprock North and BNN North Dakota, respectively, in January 2018.

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 nine months ended September 30, 2018, we recognized equity in earnings associated with our aggregate 75% membership interest in Rockies Express of $220.3 million, inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $278.1 million and $420.3 million, respectively. As discussed in Note 3 – Acquisitions and Dispositions, we acquired an additional 25.01% membership interest in Rockies Express in February 2018.

In July 2018, we made a special contribution of approximately $412.5 million to fund our portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018.

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Summarized financial information for Rockies Express is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
Revenue	$	225,753	$	216,756	$	683,426	$	625,243
Operating income	$	127,119	$	123,965	$	385,831	$	344,037
Net income to Members	$	90,707	$	233,990	$	270,338	$	371,185

8. Goodwill

Reconciliation of Goodwill

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

	Three and Nine Months Ended September 30,
	2018						2017
	Natural Gas Transportation		Gathering, Processing & Terminalling		Total		Natural Gas Transportation		Gathering, Processing & Terminalling			Total
	(in thousands)
Balance at beginning of period	$	255,558	$	149,280	$	404,838	$	255,558	$	87,730		$	343,288
Goodwill acquired	—		—		—		—		61,550		(1)	61,550
Balance at end of period	$	255,558	$	149,280	$	404,838	$	255,558	$	149,280		$	404,838

⁽¹⁾  The $61.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Deeprock Development on July 20, 2017.

Annual Goodwill Impairment Analysis

We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. We evaluate goodwill for impairment at the reporting unit level, which is the same as, or one level below, an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or proceeding directly to the quantitative impairment test depending on facts and circumstances of the reporting unit. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. If we, after performing the qualitative assessment, determine it is "more likely than not" that the fair value of a reporting unit is greater than its carrying amount, then goodwill is not considered impaired. When goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the reporting unit's fair value, then the reporting unit should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.

We elected to apply the qualitative assessment option for four of our five reporting units. In conducting the qualitative assessment we considered relevant factors and circumstances that affect the fair value or carrying amount of the reporting entity. Such factors included changes in discount rates, projected cash flows, macroeconomic considerations, industry and market considerations, overall financial performance, prior quantitative results, and entity and reporting unit specific events. For each of these reporting units, the results of the qualitative assessment indicated that it was more likely than not that the fair value of the reporting units exceeded their respective book values. As such, we did not perform a quantitative impairment analysis, and we concluded that no impairment was indicated as of August 31, 2018.

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We did not elect to apply the qualitative assessment option for one reporting unit during our 2018 annual goodwill impairment testing; instead we proceeded directly to the quantitative impairment test. We compared the fair value of the reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. The fair value of the reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates, maintenance capital expenditures, and the weighted average cost of capital. The fair value of the reporting unit was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For this reporting unit, the results of the quantitative impairment test indicated no impairment as the fair value of the reporting unit was greater than its respective book value. As a result, in accordance with the Codification guidance, we did not record a goodwill impairment during the nine months ended September 30, 2018. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow model and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary.

9. Risk Management

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

Fair Value of Derivative Contracts

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

	Balance Sheet Location	September 30, 2018		December 31, 2017
		(in thousands)
Crude oil derivative contracts (1)	Current assets	$	6,014	$	—
Crude oil derivative contracts (2)	Current liabilities	$	4,163	$	2,368

⁽¹⁾  As of September 30, 2018, the fair value shown for crude oil derivative contracts represents the forward purchase of 3,565,000 barrels which will settle throughout the fourth quarter of 2018 and 2019.

⁽²⁾  As of September 30, 2018, the fair value shown for crude oil derivative contracts represents the forward sale of 3,163,500 barrels of crude oil which will settle throughout the fourth quarter of 2018 and 2019. As of December 31, 2017, the fair value shown for crude oil derivative contracts represents the forward sale of 356,000 barrels of crude oil which settled in the first quarter of 2018.

Effect of Derivative Contracts in the Statements of Income

The following table summarizes the impact of derivative contracts not designated as hedging contracts for the three and nine months ended September 30,2018 and 2017:

	Location of gain (loss) recognized in income on derivatives	Amount of gain (loss) recognized in income on derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,
		2018		2017			2018		2017
		(in thousands)
Crude oil derivative contracts	Sales of natural gas, NGLs, and crude oil	$	9,435	$	175		$	16,665	$	1,065
Natural gas derivative contracts	Sales of natural gas, NGLs, and crude oil	$	—	$	(22	)	$	—	$	84
Call option derivative	Other income, net	$	—	$	—		$	—	$	1,885

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Call Option Derivative

As part of our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted TEP an 18 month call option at an exercise price of $42.50 per TEP common unit covering the 6,518,000 TEP common units issued to TD as a portion of the consideration. On February 1, 2017, we exercised the remainder of the call option covering an additional 1,703,094 TEP common units for a cash payment of $72.4 million. These TEP common units were deemed canceled upon the exercise of the call option and as of the applicable exercise date were no longer issued and outstanding.

Credit Risk

We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our commodity derivatives consist of market participants and major financial institutions. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. The counterparty to our call option derivative was TD.

Our derivative contracts are entered into with counterparties through central trading organizations such as futures, options or stock exchanges or counterparties outside of central trading organizations. While we typically enter into derivative transactions with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. The maximum potential exposure to credit losses on our crude oil derivative contracts at September 30, 2018 was:

	Asset Position
	(in thousands)
Gross	$	6,014
Netting agreement impact	—
Cash collateral held	—
Net exposure	$	6,014

As of September 30, 2018 and December 31, 2017, we had $1.1 million and $3.0 million, respectively, of cash in margin accounts and outstanding letters of credit in support of our commodity derivative contracts.

Fair Value

Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). OTC commodity derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy. The call option granted by TD was valued using a Black-Scholes option pricing model. Key inputs to the valuation model included the term of the option, risk free rate, the exercise price and current market price, expected volatility and expected distribution yield of the underlying units. The call option valuation was classified within Level 2 of the fair value hierarchy as the value was based on significant observable inputs.

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The following table summarizes the fair value measurements of our derivative contracts as of September 30, 2018 and December 31, 2017, 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 September 30, 2018:
Crude oil derivative contracts	$	6,014	$	—	$	6,014	$	—
			Liability Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of September 30, 2018:
Crude oil derivative contracts	$	4,163	$	—	$	4,163	$	—
As of December 31, 2017:
Crude oil derivative contracts	$	2,368	$	—	$	2,368	$	—

10. Long-term Debt

Long-term debt consisted of the following at September 30, 2018 and December 31, 2017:

	September 30, 2018			December 31, 2017
	(in thousands)
Tallgrass Equity revolving credit facility (1)	$	—		$	146,000
TEP revolving credit facility	1,051,000			661,000
TEP 4.75% senior notes due October 1, 2023	500,000			—
TEP 5.50% senior notes due September 15, 2024	750,000			750,000
TEP 5.50% senior notes due January 15, 2028	750,000			750,000
Less: Deferred financing costs, net (2)	(20,793		)	(17,737		)
Plus: Unamortized premium on 2028 Notes	3,467			3,730
Total long-term debt, net	$	3,033,674		$	2,292,993

⁽¹⁾  On July 26, 2018, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility.

⁽²⁾  Deferred financing costs, net as presented above relate solely to the Senior Notes (as defined below). Deferred financing costs associated with our revolving credit facilities are presented in noncurrent assets on our condensed consolidated balance sheets.

TEP Senior Unsecured Notes

On September 26, 2018, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 26, 2018 (the "2023 Indenture") pursuant to which the Issuers issued $500 million in aggregate principal amount of 4.75% senior notes due 2023 (the "2023 Notes"). The 2023 Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all TEP's properties to, another person.

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The Issuers have also previously issued $500 million in aggregate principal amount of 5.50% senior notes due 2028 (the "2028 Notes") on September 15, 2017 and an additional $250 million in aggregate principal amount of the 2028 Notes on December 11, 2017. The 2028 Notes issued on September 15, 2017 and December 11, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date and offering price. The 2028 Notes are governed by an Indenture dated September 15, 2017 (the "2028 Indenture") which contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all TEP's properties to, another person.

In addition, the Issuers have previously issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes") on September 1, 2016 and an additional $350 million in aggregate principal amount of the 2024 Notes on May 16, 2017. The 2024 Notes issued on September 1, 2016 and May 16, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date, offering price and first interest payment date. The 2024 Notes are governed by an Indenture dated September 1, 2016 (the "2024 Indenture") which contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests in the event of default or noncompliance with the covenants required, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates.

The 2023 Notes, 2024 Notes, and 2028 Notes are together referred to as the "Senior Notes." As of September 30, 2018, TEP was in compliance with the covenants required under the 2023 Indenture, the 2024 Indenture, and the 2028 Indenture.

TEP Revolving Credit Facility

The following table sets forth the available borrowing capacity under the TEP revolving credit facility as of September 30, 2018 and December 31, 2017:

	September 30, 2018			December 31, 2017
	(in thousands)
Total capacity under the TEP revolving credit facility	$	2,250,000		$	1,750,000
Less: Outstanding borrowings under the TEP revolving credit facility	(1,051,000		)	(661,000		)
Less: Letters of credit issued under the TEP revolving credit facility	(94		)	(94		)
Available capacity under the TEP revolving credit facility	$	1,198,906		$	1,088,906

On July 26, 2018, TEP and certain of its subsidiaries entered into Amendment No. 1 (the "Amendment") to its existing revolving credit facility with Wells Fargo Bank, National Association, as administrative agent and collateral agent, and a syndicate of lenders (the "Credit Agreement"). The Amendment modified certain provisions of the Credit Agreement to, among other things, (i) increase the available amount of the TEP revolving credit facility to $2.25 billion, (ii) reduce certain applicable margins in the pricing grids used to determine the interest rate and revolving credit commitment fees, (iii) modify the use of proceeds to allow TEP to pay off the Tallgrass Equity revolving credit facility, and (iv) increase the maximum total leverage ratio to 5.50 to 1.00.

TEP's revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP's ability (as well as the ability of its restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions, including distributions from available cash, if a default or event of default under the credit agreement then exists or would result therefrom, change the nature of its business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than 5.50 to 1.00 (5.00 to 1.00 prior to the Amendment), a consolidated senior secured leverage ratio of not more than 3.75 to 1.00 and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of September 30, 2018, TEP was in compliance with the covenants required under its revolving credit facility.

The unused portion of TEP's revolving credit facility is subject to a commitment fee, which ranges from 0.250% to 0.375% (0.250% to 0.500% prior to the Amendment), based on TEP's total leverage ratio. As of September 30, 2018, the weighted average interest rate on outstanding borrowings under the TEP revolving credit facility was 3.54%. During the nine months ended September 30, 2018, the weighted average effective interest rate under the TEP revolving credit facility, including the interest on outstanding borrowings under TEP's revolving credit facility, commitment fees, and amortization of deferred financing costs, was 3.98%.

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Fair Value

The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of September 30, 2018 and December 31, 2017, but for which fair value is disclosed:

	Fair Value
	Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Carrying Amount
	(in thousands)
As of September 30, 2018:
Revolving credit facility	$	—	$	1,051,000	$	—	$	1,051,000	$	1,051,000
2023 Notes	$	—	$	500,310	$	—	$	500,310	$	495,637
2024 Notes	$	—	$	766,635	$	—	$	766,635	$	740,969
2028 Notes	$	—	$	759,458	$	—	$	759,458	$	746,068
As of December 31, 2017:
Revolving credit facilities	$	—	$	807,000	$	—	$	807,000	$	807,000
2024 Notes	$	—	$	771,645	$	—	$	771,645	$	739,824
2028 Notes	$	—	$	758,168	$	—	$	758,168	$	746,169

The long-term debt borrowed under the revolving credit facilities is carried at amortized cost. As of September 30, 2018 and December 31, 2017, the fair value of borrowings under the revolving credit facilities approximates the carrying amount of the borrowings using a discounted cash flow analysis. The Senior Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the Senior Notes is based upon quoted market prices adjusted for illiquid markets. We are not aware of any factors that would significantly affect the estimated fair value subsequent to September 30, 2018.

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		Dividend per Class A Share
		(in thousands, except per share amounts)
September 30, 2018	November 14, 2018 (1)	$	79,717	$	0.5100
June 30, 2018	August 14, 2018	77,052		0.4975
March 31, 2018	May 15, 2018	28,316		0.4875
December 31, 2017	February 14, 2018	21,346		0.3675
September 30, 2017	November 14, 2017	20,617		0.3550
June 30, 2017	August 14, 2017	19,891		0.3425
March 31, 2017	May 15, 2017	16,697		0.2875

⁽¹⁾  The dividend announced on October 15, 2018 for the third quarter of 2018 will be paid on November 14, 2018 to Class A shareholders of record at the close of business on October 31, 2018.

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Subsidiary Distributions

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

		Distributions								Distribution per Limited Partner Common Unit
		Limited Partner Common Units		General Partner
Three Months Ended	Date Paid			Incentive Distribution Rights		General Partner Units		Total
		(in thousands, except per unit amounts)
March 31, 2018	May 15, 2018	$	71,370	$	39,816	$	1,267	$	112,453	$	0.9750
December 31, 2017	February 14, 2018	70,638		39,125		1,251		111,014		0.9650
September 30, 2017	November 14, 2017	69,174		37,744		1,219		108,137		0.9450
June 30, 2017	August 14, 2017	67,671		36,342		1,186		105,199		0.9250
March 31, 2017	May 15, 2017	60,486		29,840		1,040		91,366		0.8350

As a result of the TEP Merger, Tallgrass Equity and its wholly-owned subsidiary, Tallgrass Equity Investments, LLC, will receive all distributions paid by TEP for the second quarter of 2018 and subsequent periods.

Exchange Rights

Our current Class B shareholders (collectively, the "Exchange Right Holders") own an equal number of 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 nine months ended September 30, 2018, 2,403,766 Class A shares were issued and an equal number of Class B shares were cancelled as a result of the exercise of the Exchange Right. During the period from October 1, 2018 to October 31, 2018, 417,566 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.

Equity Distribution Agreements

Neither TGE or TEP currently have equity distribution agreements in place. TEP was previously a party to equity distribution agreements pursuant to which it sold from time to time through a group of managers, as its sales agents, TEP common units representing limited partner interests. Following the TEP Merger, these agreements were terminated effective July 2, 2018. During the nine months ended September 30, 2018, TEP did not issue any common units under its equity distribution agreements. During the nine months ended September 30, 2017, TEP issued and sold 2,341,061 common units with a weighted average sales price of $48.82 per unit under its equity distribution agreements for net cash proceeds of approximately $112.4 million (net of approximately $1.9 million in commissions and professional service expenses).

Repurchase of TEP Common Units Owned by TD

Following an offer received from TD with respect to TEP common units owned by TD not subject to the call option, TEP repurchased 736,262 TEP common units from TD at an aggregate price of approximately $35.3 million, or $47.99 per common unit, on February 1, 2017, which was approved by the conflicts committee of the board of directors of TEP's general partner. These common units were deemed canceled upon TEP's purchase and as of such transaction date were no longer issued and outstanding.

Noncontrolling Interests

As of September 30, 2018, noncontrolling interests in our subsidiaries consisted of a 44.36% interest in Tallgrass Equity held by the Exchange Right Holders and an approximate 40% membership interest in Deeprock Development. During the nine months ended September 30, 2018, we recognized contributions from and distributions to noncontrolling interests of $0.2 million and $262.9 million, respectively. Contributions from noncontrolling interests consisted primarily of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $160.6 million, distributions to TEP unitholders of $97.7 million, and distributions to Deeprock Development and Pony Express noncontrolling interests of $4.6 million.

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During the nine months ended September 30, 2017, we recognized contributions from and distributions to noncontrolling interests of $1.1 million and $229.7 million, respectively. Contributions from noncontrolling interests consisted primarily of contributions from TD to Pony Express. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $135.4 million, Tallgrass Equity distributions to the Exchange Right Holders of $90.0 million and distributions to Pony Express noncontrolling interests of $4.3 million.

Other Contributions and Distributions

During the nine months ended September 30, 2018, TGE recognized the following other contributions and distributions:

• TGE was deemed to have made a noncash capital distribution of $198.0 million, which represents the excess purchase price over the $53.8 million carrying value of the 5,619,218 TEP common units acquired as of February 7, 2018; and

• TGE was deemed to have received a noncash capital contribution of $108.5 million, which represents the excess carrying value of the 25.01% membership interest in Rockies Express acquired as of February 7, 2018 over the fair value of the consideration paid.

During the nine months ended September 30, 2017, TGE recognized the following other contributions and distributions:

• TEP received contributions from TD of $2.3 million primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 15 – Legal and Environmental Matters.

12. Revenue from Contracts with Customers

Implementation of ASC Topic 606

As discussed in Note 2 – Summary of Significant Accounting Policies, we adopted the guidance in ASC Topic 606 effective January 1, 2018 using the modified retrospective method of adoption. As a result, revenue reported for the three and nine months ended September 30, 2017 has not been revised. The following tables provide the impact of ASC Topic 606 on our condensed consolidated balance sheet as of September 30, 2018 and the condensed consolidated statements of income for the three and nine months ended September 30, 2018:

	September 30, 2018
	As currently reported		Under previous guidance		Impact of ASC Topic 606
	(in thousands)
Unconsolidated investments	$	1,872,879	$	1,796,606	$	76,273	(1)

	Three Months Ended September 30, 2018
	As currently reported		Under previous guidance		Impact of ASC Topic 606
	(in thousands)
Crude oil transportation services	$	100,226	$	100,348	$	(122	)	(2)
Sales of natural gas, NGLs, and crude oil	$	44,072	$	45,225	$	(1,153	)	(3)
Processing and other revenues	$	25,069	$	25,630	$	(561	)	(1)(3)
Cost of sales	$	28,556	$	30,248	$	(1,692	)	(2)(3)
Equity in earnings of unconsolidated investments	$	76,268	$	64,704	$	11,564		(1)
Net income attributable to TGE	$	59,550	$	53,366	$	6,184
Basic net income per Class A share	$	0.38	$	0.34	$	0.04
Diluted net income per Class A share	$	0.38	$	0.34	$	0.04

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	Nine Months Ended September 30, 2018
	As currently reported		Under previous guidance		Impact of ASC Topic 606
	(in thousands)
Crude oil transportation services	$	286,130	$	286,136	$	(6	)	(2)
Sales of natural gas, NGLs, and crude oil	$	119,467	$	122,834	$	(3,367	)	(3)
Processing and other revenues	$	72,783	$	75,846	$	(3,063	)	(1)(3)
Cost of sales	$	82,601	$	88,846	$	(6,245	)	(2)(3)
Equity in earnings of unconsolidated investments	$	222,857	$	189,450	$	33,407		(1)
Net income attributable to TGE	$	77,348	$	67,701	$	9,647
Basic net income per Class A share	$	0.85	$	0.74	$	0.11
Diluted net income per Class A share	$	0.85	$	0.74	$	0.11

⁽¹⁾  Reflects the impact on our investment in Rockies Express and the management fee collected by NatGas of the cumulative effect adjustment at Rockies Express, which arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas.

⁽²⁾  Reflects the impact to revenue and cost of sales to value PLA barrels collected under certain crude oil transportation arrangements at their contract inception fair value in revenue and record an associated lower of cost or net realizable value adjustment in cost of sales.

⁽³⁾  Reflects the reclassification of certain gathering and processing fees collected under arrangements determined to be supply arrangements, rather than customer arrangements under ASC 606, to cost of sales and the reclassification of certain commodities retained as consideration for processing services to processing fee revenue.

Disaggregated Revenue

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

	Three Months Ended September 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	$	—	$	100,614	$	—	$	—		$	100,614
Natural gas transportation - firm service	31,070		—		—		(793		)	30,277
Water business services	—		—		12,837		—			12,837
Natural gas gathering & processing fees	—		—		6,631		—			6,631
All other (1)	2,551		13,321		6,709		(17,636		)	4,945
Total service revenue	33,621		113,935		26,177		(18,429		)	155,304
Natural gas liquids sales	—		—		26,201		—			26,201
Natural gas sales	456		—		5,517		—			5,973
Crude oil sales	—		2,315		147		—			2,462
Total commodity sales revenue	456		2,315		31,865		—			34,636
Total revenue from contracts with customers	34,077		116,250		58,042		(18,429		)	189,940
Other revenue (2)	—		—		13,570		(3,190		)	10,380
Total revenue (3)	$	34,077	$	116,250	$	71,612	$	(21,619	)	$	200,320

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	Nine Months Ended September 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	$	—	$	286,594	$	—	$	—		$	286,594
Natural gas transportation - firm service	96,166		—		—		(4,074		)	92,092
Water business services	—		—		38,246		—			38,246
Natural gas gathering & processing fees	—		—		17,429		—			17,429
All other (1)	8,240		26,124		18,809		(36,832		)	16,341
Total service revenue	104,406		312,718		74,484		(40,906		)	450,702
Natural gas liquids sales	—		—		77,287		—			77,287
Natural gas sales	802		—		17,907		—			18,709
Crude oil sales	—		6,290		515		—			6,805
Total commodity sales revenue	802		6,290		95,709		—			102,801
Total revenue from contracts with customers	105,208		319,008		170,193		(40,906		)	553,503
Other revenue (2)	—		—		28,869		(9,369		)	19,500
Total revenue (3)	$	105,208	$	319,008	$	199,062	$	(50,275	)	$	573,003

⁽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 $225.8 million and $683.4 million of revenue recognized at Rockies Express for the three and nine months ended September 30, 2018, respectively. See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express.

Performance Obligations

A performance obligation is a promise in a contract to transfer a distinct good or service to the customer, and is the unit of account in ASC Topic 606. A contract's transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. The majority of our contracts have a single performance obligation and are billed and collected monthly.

All of our segments engage in commodity sales, in which our performance obligations include an obligation to deliver the specified volume of a commodity to the designated receipt point. Revenue from commodity sales is recognized at a point in time when the customer obtains control of the commodity, typically upon delivery to the designated delivery point when the customer accepts and takes possession of the commodity.

In the Natural Gas Transportation segment, our performance obligations typically include an obligation to stand ready to provide natural gas transportation, storage, or an integrated transportation and storage service over the life of the contract, which is a series. These performance obligations are satisfied over time using each day of service to measure progress toward satisfaction of the performance obligation.

In the Crude Oil Transportation segment, our performance obligations typically include an obligation to provide crude oil transportation services over the life of the contract, which is a series. These performance obligations are satisfied over time using barrels delivered to measure progress toward satisfaction of the performance obligation.

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In the Gathering, Processing & Terminalling segment, the performance obligations vary based on the operating asset and type of contract. In our natural gas gathering and processing arrangements, performance obligations typically include an obligation to provide an integrated processing service over the life of the contract, which is a series. These performance obligations are satisfied over time using each unit of gas processed to measure progress toward satisfaction of the performance obligation. In our freshwater supply arrangements, performance obligations typically include an obligation to deliver a specified volume of water to the designated receipt point. These performance obligations are satisfied at a point in time when the customer obtains control of the water. In our produced water gathering and disposal arrangements, performance obligations typically include an obligation to provide an integrated produced water gathering and disposal service over the life of the contract, which is a series. These performance obligations are satisfied over time using barrels disposed to measure progress toward satisfaction of the performance obligation.

On September 30, 2018, 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 2018 and future periods as follows (in thousands):

Year	Estimated Revenue
2018	$	129,104
2019	496,227
2020	328,066
2021	148,967
2022	136,316
Thereafter	271,512
Total	$	1,510,192

Contract Estimates

Accounting for long-term contracts involves the use of various techniques to estimate total contract revenue. Contract estimates are based on various assumptions to project the outcome of future events that often span several years. These assumptions include the anticipated volumes of crude oil expected to be delivered by our customers for transport in future periods.

The nature of our contracts gives rise to several types of variable consideration, including PLA, volumetric charges for actual volumes delivered, overrun charges, and other fees that are contingent on the actual volumes delivered by our customers. As the amount of variable consideration is allocable to each distinct performance obligation within the series of performance obligations that comprise the single performance obligation and the uncertainty related to the consideration is resolved each month as the distinct service is provided, we do not estimate the total variable consideration for the single overall performance obligation. Consequently, we are able to include in the transaction price each month the actual amount of variable consideration because no uncertainty exists surrounding the services provided that month.

Certain of our contracts include provisions in which a portion of the consideration is noncash. In our Crude Oil Transportation segment, we collect PLA from our customers. As crude oil is transported, we earn, and take title to, a portion of the oil transported for our services. Any PLA that remains after replacing losses in transit can be sold. Where PLA is determined to be a component of compensation for the transportation services provided, crude oil retained is recognized in revenue at its contract inception fair value. In our Gathering, Processing & Terminalling segment, we retain commodity products as consideration under certain of our gathering and processing arrangements. Processing fee revenue is recorded when the performance obligation is completed based on the value of the product received at the time services are performed. At this time, the variability of the non-cash consideration related to both form (price) and other-than-form (volume and product mix), which are interrelated, is resolved.

As a significant change in one or more of these estimates could affect the amount and timing of revenue recognized under our customer contracts, we review and update our contract-related estimates regularly.

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Contract Balances

The timing of revenue recognition, billings, and cash collections may result in billed accounts receivable, unbilled receivables (contract assets), and deferred revenue (contract liabilities) on our condensed consolidated balance sheets. Revenue is generally billed and collected monthly based on services provided or commodity volumes sold. In our Crude Oil Transportation segment, we recognize shipper deficiencies, or deferred revenue, for barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers' agreed upon destination point. These shipper deficiencies are charged at the committed tariff rate per barrel and recorded as a contract liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes remote. We also recognize contract liabilities, in the form of deferred revenue, under certain water business services contracts in the Gathering, Processing & Terminalling segment. Contract balances as of September 30, 2018 were as follows:

	September 30, 2018		January 1, 2018
	(in thousands)
Accounts receivable from contracts with customers	$	67,603	$	61,888
Other accounts receivable	168,097		56,727
Accounts receivable, net	$	235,700	$	118,615
Deferred revenue from contracts with customers (1)	$	103,652	$	88,471

⁽¹⁾  Revenue recognized during the three and nine months ended September 30, 2018 that was included in the deferred revenue balance at the beginning of the period was $2.0 million and $9.3 million, respectively. This revenue primarily represented the utilization of shipper deficiencies at Pony Express.

13. Net Income per Class A Share

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

Diluted net income per Class A share is determined by dividing net income attributable to TGE by the weighted average number of outstanding diluted Class A shares during the period. For purposes of calculating diluted net income per Class A share, we considered the impact of possible future exercises of the Exchange Right by the Exchange Right Holders on both net income attributable to TGE and the diluted weighted average number of Class A shares outstanding. The Exchange Right Holders refers to the group of persons who collectively own all TGE's outstanding Class B shares and an equivalent number of Tallgrass Equity units. The Exchange Right Holders are entitled to exercise the right to exchange their Tallgrass Equity units (together with an equivalent number of TGE Class B shares) for TGE Class A shares at an exchange ratio of one TGE Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right Holders primarily consist of Kelso & Company and its affiliated investment funds, The Energy & Minerals Group and its affiliated investment funds, and Tallgrass KC, LLC, which is an entity owned by certain members of TGE's management.

Pursuant to the TGE partnership agreement and the Tallgrass Equity limited liability company agreement, our capital structure and the capital structure of Tallgrass Equity will generally replicate one another in order to maintain the one-for-one exchange ratio between the Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other hand. As a result, the exchange of any Class B shares for Class A shares does not have a dilutive effect on basic net income per Class A share. However, for the three and nine months ended September 30, 2018 and 2017, the potential issuance of TGE Equity Participation Shares would have had a dilutive effect on basic net income per Class A share. Effective June 30, 2018 with the completion of the TEP Merger, as discussed in Note 1 – Description of Business, TEP's outstanding Equity Participation Units were converted to Equity Participation Shares at a ratio of 2.0 Equity Participation Shares for each outstanding TEP Equity Participation Unit. As of September 30, 2018, TGE has 1,968,908 outstanding Equity Participation Shares with a weighted average grant date fair value of $18.93, and expects to recognize $19.6 million of total compensation cost related to non-vested Equity Participation Shares over a weighted average period of 2.9 years.

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The following table illustrates the calculation of net income per Class A share for the three and nine months ended September 30, 2018 and 2017:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except per unit amounts)
Basic Net Income per Class A Share
Net income attributable to TGE	$	59,550	$	15,866	$	77,348	$	36,648
Basic weighted average Class A Shares outstanding	155,001		58,075		91,183		58,075
Basic net income per Class A share	$	0.38	$	0.27	$	0.85	$	0.63
Diluted Net Income per Class A Share
Net income attributable to TGE	$	59,550	$	15,866	$	77,348	$	36,648
Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares	304		64		1,097		132
Net income attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares	$	59,854	$	15,930	$	78,445	$	36,780
Basic weighted average Class A Shares outstanding	155,001		58,075		91,183		58,075
Equity Participation Shares equivalent shares	1,087		117		1,478		118
Diluted weighted average Class A Shares outstanding	156,088		58,192		92,661		58,193
Diluted net income per Class A Share	$	0.38	$	0.27	$	0.85	$	0.63

14. Regulatory Matters

There are no regulatory proceedings challenging the rates of Pony Express, Rockies Express, or Tallgrass Interstate Gas Transmission, LLC ("TIGT"). On June 29, 2018, Trailblazer Pipeline Company LLC ("Trailblazer") filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act ("NGA"), as further described below. We have also made certain regulatory filings with the FERC, including the following:

Pony Express

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

On November 30, 2017, Pony Express filed with the FERC in Docket No. IS18-60-000 certain changes to its tariffs to reflect the addition of two new destination points, which became effective January 1, 2018.

On December 29, 2017, Pony Express filed with the FERC in Docket No. IS18-113-000 certain changes to its tariffs to reflect a new origin point in Rooks County, Kansas, which became effective on February 1, 2018.

On February 28, 2018, Pony Express filed with the FERC in Docket No. IS18-199-000 certain changes to its tariffs to reflect a new origin point in Platteville, Colorado, which became effective on April 1, 2018.

On March 1, 2018, Pony Express submitted proposed revisions to its Rules and Regulations Tariff in Docket No. IS18-204-000 to establish the right to accept "Specialty Batches" of oil that do not conform to the Quality Specifications reflected in the tariff, provided that the acceptance is operationally feasible. These tariff changes became effective on April 1, 2018.

On April 11, 2018, Pony Express filed with the FERC in Docket No. IS18–267–000 certain changes to its tariffs to reflect additional contract rates from a new origin point in Platteville, Colorado, which became effective May 1, 2018.

On May 2, 2018, Pony Express filed with the FERC in Docket No. IS18-297-000 certain changes to its rules and regulations applicable to new intermediate off-system storage points, which became effective May 15, 2018.

On May 31, 2018, Pony Express made tariff filings with the FERC in Docket No. IS18-570-000 to increase the contract and non-contract rates by an amount reflecting the FERC annual index adjustment of approximately 4.4% which became effective July 1, 2018.

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Rockies Express

Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000

On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The facilities increased the Rockies Express Zone 3 east-to-west mainline capacity by 0.8 Bcf/d. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities. The project was placed in-service for the full 0.8 Bcf/d on January 6, 2017.

Electric Power Charge Clarification - FERC Docket No. RP17-285

On December 21, 2016, in Docket No. RP17-285, Rockies Express proposed certain revisions to the General Terms and Conditions of its tariff to clarify that the electric power costs associated with the operation of gas coolers installed in association with the Zone 3 Capacity Enhancement Project at both electric and gas powered stations, will be included in the Power Cost Tracker. Several shippers submitted comments on the proposal. The FERC issued an order on January 19, 2017 accepting the proposed revisions permitting the recovery of electric power costs from the operation of both gas and electric powered compressor stations, subject to certain clarifications.

2017 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP17-401 and RP17-1064

On February 13, 2017, in Docket No. RP17-401, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2017. The FERC issued an order accepting the filing, including certain requested waivers, on March 21, 2017. On September 20, 2017, Rockies Express made its interim fuel tracker filing in Docket No. RP17-1064 with a proposed effective date of November 1, 2017. The FERC issued an order accepting the filing on October 18, 2017.

Increased Frequency of FL&U and PCT Adjustments - FERC Docket No. RP18-228

On December 1, 2017, in Docket No. RP18-228, Rockies Express made a filing with the FERC to increase the frequency in which it may adjust fixed fuel and lost and unaccounted for retainages and power cost tracker charges during the year so that its recovery of fixed fuel and lost and unaccounted for charges and power costs more closely track usage. Rockies Express proposed an effective date of April 1, 2018. The comment period ended on December 13, 2017, and no parties opposed Rockies Express' filing. On April 4, 2018, the FERC issued a letter order accepting Rockies Express' proposal, subject to certain modifications. Rockies Express submitted a compliance filing reflecting the approved tariff provisions and requested modifications on April 10, 2018. No comments on the compliance filing were submitted by the comment deadline of April 16, 2018. On April 18, 2018, the FERC issued an order accepting Rockies Express' compliance filing effective April 19, 2018.

2018 Annual FERC Fuel Tracking Filing - FERC Docket No. RP18-453

On February 20, 2018, in Docket No. RP18-453, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2018. The FERC issued an order accepting the filing on March 19, 2018.

Cheyenne Hub Enhancement Project - FERC Docket CP18-103

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 FERC's relevant program offices. On October 11, 2018, 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.

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Cheyenne Connector

Cheyenne Connector Pipeline Project - FERC Docket CP18-102

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

TIGT

General Rate Case Filing - FERC Docket No. RP16-137-000, et seq.

On October 30, 2015, in Docket No. RP16-137-000, et seq., TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA. The general rate case was ultimately resolved via settlement, which the FERC approved on November 2, 2016, and a compliance filing that modernized TIGT's FERC Gas Tariff, consistent with prior FERC orders, which the FERC accepted on March 16, 2017. Per the terms of the settlement, TIGT is required to file a new general rate case on May 1, 2019 (provided that such rate case is not pre-empted by a pre-filing settlement).

2017 Annual Fuel Tracker Filing - FERC Docket No. RP17-428-000

On February 27, 2017, in Docket No. RP17-428-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2017. The filing incorporated the FL&U tracker and power cost tracker mechanisms agreed to in the TIGT Rate Case Settlement. The FERC accepted the filing on March 21, 2017.

Electric Power Charge Clarification - FERC Docket No. RP17-1051-000

On September 15, 2017, in Docket No. RP17-1051-000, TIGT proposed certain revisions to its tariff to clarify, amongst other things, that the electric power costs associated with the operation of gas coolers at both electric and gas powered stations are properly included in the Power Cost Tracker. The FERC issued an order on October 3, 2017 accepting the proposed revisions.

2018 Annual Fuel Tracker Filing - FERC Docket No. RP18-533-000

On March 1, 2018, in Docket No. RP18-533-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2018. The FERC accepted the filing on March 22, 2018.

Trailblazer

2017 Annual and Interim Fuel Tracker Filings - FERC Docket Nos. RP17-549-000 and RP17-1052-000

On March 22, 2017, in Docket No. RP17-549-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2017. The FERC accepted the filing on April 19, 2017. On September 15, 2017, Trailblazer made its interim fuel tracker filing in Docket No. RP17-1052-000 with a proposed effective date of November 1, 2017. The FERC accepted the filing on October 13, 2017.

2018 Annual Fuel Tracker Filing - FERC Docket No. RP18-580-000

On March 22, 2018, in Docket No. in Docket No. RP18-580-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2018. The FERC accepted the filing on April 20, 2018.

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

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

On July 31, 2018, the FERC issued an Order accepting and suspending the rate case filing, and establishing hearing and settlement procedures. In the Order, the FERC approved the as-filed rate decreases for Expansion System Firm Transportation Service, as well as Trailblazer’s interruptible services, effective August 1, 2018. The Commission also established a paper hearing to examine the extent to which Trailblazer is entitled to an Income Tax Allowance. All remaining issues, including the proposed rate increases to Existing System Firm Transportation Service have been set for hearing and are accepted effective January 1, 2019, subject to refund. On August 30, 2018, Trailblazer and certain of Trailblazer's shippers filed a request for rehearing of the July 31, 2018 Order, which remains pending before the FERC. Consistent with the July 31, 2018 Order, on August 30, 2018, certain of Trailblazer's shippers and other interested parties filed initial briefs regarding the Income Tax Allowance issue. Trailblazer filed its reply brief regarding the same on September 14, 2018. The briefs remain pending before the FERC. On August 28, 2018, the participants attended an initial settlement conference. On September 12, 2018, the Chief Administrative Law Judge issued an order continuing settlement judge procedures. The second settlement conference is scheduled for November 15, 2018.

15. Legal and Environmental Matters

Legal

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

We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, have recorded no reserve for legal claims as of September 30, 2018 or December 31, 2017.

Rockies Express

Ultra Resources

In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, seeking approximately $303 million in damages and other relief. On April 29, 2016, Ultra and certain of its debtor affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District of Texas, which operated as a stay of the Harris County state court proceeding.

On January 12, 2017, Rockies Express and Ultra entered into an agreement to settle Rockies Express' approximately $303 million claim against Ultra. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37 per dth/d, or approximately $26.8 million annually. TEP received its proportionate distribution from the cash settlement payment in July 2017.

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Environmental, Health and Safety

We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We currently believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of $7.5 million and $7.7 million at September 30, 2018 and December 31, 2017, respectively.

Rockies Express

Seneca Lateral

On January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations. The release required Rockies Express to shut off the flow through the segment until February 27, 2018, when temporary repairs were completed allowing the segment to be placed back into service. Total cost of remediation is expected to be approximately $6.1 million prior to any insurance recoveries. Rockies Express expects to recover a significant majority of these costs from insurance. Permanent repairs were completed in September 2018.

TMID

Casper Plant, EPA Notice of Violation

In August 2011, the EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, Tallgrass Midstream, LLC ("TMID") received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including the expected inclusion of TIGT as a party to any possible settlement as a result of TIGT owning a compressor that is located adjacent to the Casper Gas Plant site.

Casper Gas Plant

On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing.

TMG

Archibald Booster Station

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

Irwin Booster Station

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

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Trailblazer

Pipeline Integrity Management Program

Starting in 2014 Trailblazer's operating capacity was decreased as a result of smart tool surveys that identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing subscription levels or had a material adverse financial impact on us. However, Trailblazer continued performing remediation to increase and maximize its operating capacity over the long-term and expects to spend in excess of $20 million during 2018 for this pipe replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable operating capacity. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms.

In connection with TEP's acquisition of Trailblazer in April 2014, TD agreed to indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline. The contractual indemnity was capped at $20 million and subject to a $1.5 million deductible. TEP received the entirety of the $20 million from TD pursuant to the contractual indemnity as of December 31, 2017.

Pony Express

Pipeline Integrity

In connection with certain crack tool runs on the Pony Express System completed in 2015, 2016, and 2017, Pony Express completed approximately $18 million of remediation for anomalies identified on the Pony Express System associated with the initial conversion and commissioning of portions of the pipeline converted from natural gas to crude oil service. Remediation work was substantially complete as of March 31, 2018.

16. Reportable Segments

Our operations are located in the United States. We are organized into three reportable segments: (1) Natural Gas Transportation, (2) Crude Oil Transportation, and (3) Gathering, Processing & Terminalling. Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with our revolving credit facility and the Senior Notes, public company costs, and equity-based compensation expense.

Natural Gas Transportation. The Natural Gas Transportation segment is engaged in the ownership and operation of FERC-regulated interstate natural gas pipelines and an integrated natural gas storage facility that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. The Natural Gas Transportation segment includes our aggregate 75% membership interest in Rockies Express, inclusive of the additional 25.01% membership interest acquired effective February 7, 2018.

Crude Oil Transportation. The Crude Oil Transportation segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, and other nearby oil producing basins.

Gathering, Processing & Terminalling. The Gathering, Processing & Terminalling segment is engaged in the ownership and operation of natural gas gathering and processing facilities that produce NGLs and residue gas sold in local wholesale markets or delivered into pipelines for transportation to additional end markets; our crude oil terminal services; water business services provided primarily to the oil and gas exploration and production industry; the transportation of NGLs; and Stanchion.

These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for their respective operations. During the second quarter of 2018, upon completion of the TEP Merger, management updated TGE's internal reporting. Beginning in the second quarter of 2018, we consider Adjusted EBITDA, as described below, to be our primary segment performance measure.

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

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

	Three Months Ended September 30, 2018							Three Months Ended September 30, 2017
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Natural Gas Transportation	$	34,077	$	(816	)	$	33,261	$	36,084	$	(1,883	)	$	34,201
Crude Oil Transportation	116,250		(13,579		)	102,671		93,029		(6,947		)	86,082
Gathering, Processing & Terminalling	71,612		(7,224		)	64,388		57,736		(2,150		)	55,586
Total revenue	$	221,939	$	(21,619	)	$	200,320	$	186,849	$	(10,980	)	$	175,869

	Nine Months Ended September 30, 2018							Nine Months Ended September 30, 2017
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Natural Gas Transportation	$	105,208	$	(4,136	)	$	101,072	$	105,622	$	(4,770	)	$	100,852
Crude Oil Transportation	319,008		(26,323		)	292,685		273,768		(6,947		)	266,821
Gathering, Processing & Terminalling	199,062		(19,816		)	179,246		121,415		(7,956		)	113,459
Total revenue	$	623,278	$	(50,275	)	$	573,003	$	500,805	$	(19,673	)	$	481,132

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	Three Months Ended September 30, 2018									Three Months Ended September 30, 2017
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	$	121,433		$	(1,460	)	$	119,973		$	68,665		$	(530	)	$	68,135
Crude Oil Transportation	87,567			(5,008		)	82,559			37,425			(124		)	37,301
Gathering, Processing & Terminalling	13,679			6,468			20,147			(1,387		)	654			(733		)
Corporate and Other	(2,317		)	—			(2,317		)	(9,890		)	—			(9,890		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investments (1)							76,268									34,841
Non-cash gain (loss) related to derivative instruments (1)							2,993									(194		)
Gain on disposal of assets (1)							279									—
Gain on remeasurement of unconsolidated investment (1)							—									2,744
Less:
Interest expense, net (1)							(34,019		)							(7,966		)
Depreciation and amortization expense (1)							(27,356		)							(6,611		)
Distributions from unconsolidated investments (1)							(100,720		)							(39,118		)
Non-cash compensation expense (1)							(2,767		)							(664		)
Deficiency payments, net (1)							(3,468		)							(645		)
Loss on debt retirement							(2,245		)
Deferred income tax expense							(11,997		)							(12,642		)
Net income attributable to Exchange Right Holders							(57,780		)							(48,692		)
Net income attributable to TGE							$	59,550								$	15,866

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	Nine Months Ended September 30, 2018									Nine Months Ended September 30, 2017
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	$	253,169		$	(2,940	)	$	250,229		$	133,536		$	(1,349	)	$	132,187
Crude Oil Transportation	150,943			(3,857		)	147,086			105,784			2,286			108,070
Gathering, Processing & Terminalling	30,002			6,797			36,799			10,447			(937		)	9,510
Corporate and Other	(20,819		)	—			(20,819		)	(25,631		)	—			(25,631		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investments (1)							153,235									52,853
Gain on disposal of assets (1)							3,388									376
Non-cash gain related to derivative instruments (1)							3,306									470
Gain on remeasurement of unconsolidated investment (1)							—									2,744
Less:
Interest expense, net (1)							(57,208		)							(20,476		)
Depreciation and amortization expense (1)							(45,794		)							(19,218		)
Distributions from unconsolidated investments (1)							(198,019		)							(64,848		)
Non-cash compensation expense (1)							(4,738		)							(1,614		)
Deficiency payments, net (1)							(7,205		)							(7,548		)
Loss on debt retirement							(2,245		)
Deferred income tax expense							(35,498		)							(24,982		)
Net income attributable to Exchange Right Holders							(145,169		)							(105,245		)
Net income attributable to TGE							$	77,348								$	36,648

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

	Nine Months Ended September 30,
Capital Expenditures:	2018		2017
	(in thousands)
Natural Gas Transportation	$	96,290	$	9,829
Crude Oil Transportation	39,847		28,785
Gathering, Processing & Terminalling	125,866		49,436
Corporate and Other	3,070		—
Total capital expenditures	$	265,073	$	88,050

Assets:	September 30, 2018		December 31, 2017
	(in thousands)
Natural Gas Transportation	$	2,602,761	$	1,606,666
Crude Oil Transportation	1,417,853		1,407,758
Gathering, Processing & Terminalling	1,316,487		943,340
Corporate and Other	332,939		334,249
Total assets	$	5,670,040	$	4,292,013

34

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

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report. Additionally, the following discussion and analysis should be read in conjunction with our audited financial statements and notes thereto, the related "Management's Discussion and Analysis of Financial Condition and Results of Operations," the discussion of "Risk Factors" and the discussion of TGE's "Business" in our Annual Report on Form 10-K for the year ended December 31, 2017 (our "2017 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 13, 2018.

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

Cautionary Statement Regarding Forward-Looking Statements

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

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

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

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

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

• the demand for our services, including natural gas transportation and storage; crude oil transportation; and natural gas gathering and processing, crude oil storage and terminalling services, and water business services; as well as our ability to successfully contract or re-contract with our customers;

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

• our ability to successfully implement our business plan;

• changes in general economic conditions;

• competitive conditions in our industry;

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

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

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

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

35

• the price and availability of debt and equity financing;

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

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

• competition from the same and alternative energy sources;

• energy efficiency and technology trends;

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

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

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

• interest rates;

• labor relations;

• changes in tax laws, regulations and status;

• the effects of future litigation; and

• certain factors discussed elsewhere in this Quarterly Report.

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

Overview

TGE is a limited partnership that owns, operates, acquires and develops midstream energy assets in North America and has elected to be treated as a corporation for U.S. federal income tax purposes.

Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity in which we directly own an approximate 55.79% membership interest as of October 31, 2018. We are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations.

Our reportable business segments are:

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

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

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

Recent Developments

TGE Dividend Announced

On October 15, 2018, the board of directors of our general partner declared a cash dividend for the quarter ended September 30, 2018 of $0.5100 per Class A share. The dividend will be paid on November 14, 2018, to Class A shareholders of record on October 31, 2018.

36

Joint Venture with Silver Creek

In August 2018, we entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the contribution by us and Silver Creek of additional Powder River Basin assets. Upon the closing of the additional contributions, the expanded joint venture will operate under the name Powder River Gateway, LLC, and will own the Iron Horse pipeline, the Powder River Express Pipeline, and crude oil terminal facilities in Guernsey, Wyoming. We will own a 51% membership interest and continue to operate the joint venture following closing, and Silver Creek will own a 49% membership interest. We expect to close the additional contributions in the fourth quarter of 2018, subject to certain closing conditions.

How We Evaluate Our Operations

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

Contract Profile and Volumes

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

Operating Costs and Expenses

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

Adjusted EBITDA and Cash Available for Dividends

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

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

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

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

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

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

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Non-GAAP Financial Measures

We generally define Adjusted EBITDA as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments and deficiency payments received from or utilized by our customers. We also use Cash Available for Dividends, which we generally define as Adjusted EBITDA, less cash interest costs, maintenance capital expenditures, distributions to noncontrolling interests in excess of earnings allocated to noncontrolling interests, and certain cash reserves permitted by our governing documents. Adjusted EBITDA and Cash Available for Dividends are both calculated and presented at the Tallgrass Equity level, before consideration of noncontrolling interest associated with the Exchange Right Holders or calculating distributions from Tallgrass Equity to us, on one hand, and to the Exchange Right Holders, on the other. We believe calculating these measures at Tallgrass Equity provides investors the most complete picture of our overall financial and operational results and provides a consistent metric for period over period comparisons that is not impacted by any future exercises by the Exchange Right Holders of the Exchange Right, which does not have a dilutive effect on TGE's net income per share.

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Reconciliation of Tallgrass Equity Adjusted EBITDA to Net Income
Net income attributable to TGE	$	59,550		$	15,866		$	77,348		$	36,648
Add:
Interest expense, net (1)	34,019			7,966			57,208			20,476
Depreciation and amortization expense (1)	27,356			6,611			45,794			19,218
Distributions from unconsolidated investments (1)	100,720			39,118			198,019			64,848
Deficiency payments, net (1)	3,468			645			7,205			7,548
Non-cash compensation expense (1)(2)	2,767			664			4,738			1,614
Loss on debt retirement	2,245			—			2,245			—
Deferred income tax expense	11,997			12,642			35,498			24,982
Net income attributable to Exchange Right Holders	57,780			48,692			145,169			105,245
Less:
Equity in earnings of unconsolidated investments (1)	(76,268		)	(34,841		)	(153,235		)	(52,853		)
Gain on disposal of assets (1)	(279		)	—			(3,388		)	(376		)
Non-cash (gain) loss related to derivative instruments (1)	(2,993		)	194			(3,306		)	(470		)
Gain on remeasurement of unconsolidated investment (1)	—			(2,744		)	—			(2,744		)
Tallgrass Equity Adjusted EBITDA	$	220,362		$	94,813		$	413,295		$	224,136
Reconciliation of Tallgrass Equity Adjusted EBITDA and Cash Available for Dividends to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	135,131		$	212,407		$	466,391		$	450,377
Add:
Interest expense, net (1)	34,019			7,966			57,208			20,476
Other, including changes in operating working capital (1)	51,212			(125,560		)	(110,304		)	(246,717		)
Tallgrass Equity Adjusted EBITDA	$	220,362		$	94,813		$	413,295		$	224,136
Less:
Cash interest cost (1)	(32,728		)	(7,546		)	(54,909		)	(19,188		)
Maintenance capital expenditures, net (1)	(4,638		)	(1,038		)	(8,409		)	(2,188		)
Tallgrass Equity Cash Available for Dividends	$	182,996		$	86,229		$	349,977		$	202,760

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

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Natural Gas Transportation Segment (1)
Operating income	$	17,372		$	17,016		$	53,638		$	49,910
Add:
Depreciation and amortization expense (2)	4,861			1,350			8,199			4,068
Distributions from unconsolidated investment (2)	98,503			38,922			194,907			64,291
Other, net (2)	697			455			1,744			807
Less:
Adjusted EBITDA attributable to noncontrolling interests	—			10,922			(5,319		)	14,493
Non-cash gain related to derivative instruments (2)	—			—			—			(33		)
Tallgrass Equity Segment Adjusted EBITDA	$	121,433		$	68,665		$	253,169		$	133,536
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Crude Oil Transportation Segment (1)
Operating income	$	69,295		$	51,478		$	181,536		$	145,462
Add:
Depreciation and amortization expense (2)	13,627			3,669			22,928			11,230
Deficiency payments, net (2)	4,645			1,414			6,893			7,280
Less:
Adjusted EBITDA attributable to noncontrolling interests	—			(19,193		)	(60,414		)	(58,065		)
Non-cash loss (gain) related to derivative instruments (2)	—			57			—			(123		)
Tallgrass Equity Segment Adjusted EBITDA	$	87,567		$	37,425		$	150,943		$	105,784
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Gathering, Processing & Terminalling Segment (1)
Operating income	$	9,680		$	9,045		$	38,707		$	20,928
Add:
Depreciation and amortization expense (2)	7,688			1,592			12,836			3,920
Non-cash (gain) loss related to derivative instruments (2)	(2,993		)	137			(3,306		)	216
Distributions from unconsolidated investments (2)	2,217			196			3,112			557
Deficiency payments, net (2)	(1,566		)	(769		)	(343		)	268
Other, net (2)	314			—			314			142
Less:
Gain on disposal of assets (2)	(279		)	—			(3,388		)	(376		)
Adjusted EBITDA attributable to noncontrolling interests	(1,382		)	(11,588		)	(17,930		)	(15,208		)
Tallgrass Equity Segment Adjusted EBITDA	$	13,679		$	(1,387	)	$	30,002		$	10,447
Total Tallgrass Equity Segment Adjusted EBITDA	$	222,679		$	104,703		$	434,114		$	249,767
Corporate general and administrative costs	(2,317		)	(9,890		)	(20,819		)	(25,631		)
Total Tallgrass Equity Adjusted EBITDA	$	220,362		$	94,813		$	413,295		$	224,136

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

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

Results of Operations

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Natural Gas Transportation Segment:
Gas transportation average firm contracted volumes (MMcf/d) (1)	1,519	1,646	1,640	1,737
Crude Oil Transportation Segment:
Crude oil transportation average contracted capacity (Bbls/d)	308,580	306,916	306,382	302,476
Crude oil transportation average throughput (Bbls/d)	340,283	269,585	326,266	268,435
Gathering, Processing & Terminalling Segment:
Natural gas processing inlet volumes (MMcf/d)	128	111	121	106
Freshwater average volumes (Bbls/d)	—	109,988	23,398	93,885
Produced water gathering and disposal average volumes (Bbls/d)	94,445	43,924	90,293	23,405

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

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Revenues:
Crude oil transportation services	$	100,226		$	86,180		$	286,130		$	260,366
Natural gas transportation services	30,953			30,256			94,623			91,370
Sales of natural gas, NGLs, and crude oil	44,072			32,215			119,467			70,514
Processing and other revenues	25,069			27,218			72,783			58,882
Total Revenues	200,320			175,869			573,003			481,132
Operating Costs and Expenses:
Cost of sales	28,556			26,984			82,601			58,740
Cost of transportation services	12,588			10,538			35,672			38,799
Operations and maintenance	18,011			17,412			52,850			45,569
Depreciation and amortization	27,595			23,782			81,408			67,276
General and administrative	16,015			16,489			53,526			46,040
Taxes, other than income taxes	7,750			6,661			25,091			21,799
Gain on disposal of assets	(279		)	—			(9,417		)	(1,264		)
Total Operating Costs and Expenses	110,236			101,866			321,731			276,959
Operating Income	90,084			74,003			251,272			204,173
Other Income (Expense):
Equity in earnings of unconsolidated investments	76,268			123,642			222,857			187,121
Interest expense, net	(34,019		)	(24,408		)	(95,062		)	(61,539		)
Other (expense) income, net	(1,624		)	10,182			(843		)	12,409
Total Other Income (Expense)	40,625			109,416			126,952			137,991
Net income before tax	130,709			183,419			378,224			342,164
Deferred income tax expense	(11,997		)	(12,642		)	(35,498		)	(24,982		)
Net income	118,712			170,777			342,726			317,182
Net income attributable to noncontrolling interests	(59,162		)	(154,911		)	(265,378		)	(280,534		)
Net income attributable to TGE	$	59,550		$	15,866		$	77,348		$	36,648

Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017

Revenues. Total revenues were $200.3 million for the three months ended September 30, 2018, compared to $175.9 million for the three months ended September 30, 2017, which represents an increase of $24.5 million, or 14%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $23.2 million and $13.9 million in the Crude Oil Transportation and Gathering, Processing & Terminalling segments, respectively, partially offset by decreased revenues of $2.0 million in the Natural Gas Transportation segment and a $10.6 million increase in eliminations of intersegment revenue, as discussed further below.

Operating costs and expenses. Operating costs and expenses were $110.2 million for the three months ended September 30, 2018 compared to $101.9 million for the three months ended September 30, 2017, which represents an increase of $8.4 million, or 8%. The overall increase in operating costs and expenses is driven by increased operating costs and expenses of $13.2 million and $5.4 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by decreased operating costs and expenses of $7.8 million and $2.4 million in the Corporate and Other and Natural Gas Transportation segments, respectively, as discussed further below. The decrease in Corporate and Other expenses was primarily driven by a $10.6 million increase in eliminations of intersegment operating costs and expenses, partially offset by a $1.6 million increase in corporate general and administrative costs and a $1.2 million increase in depreciation and amortization costs due to the administrative assets acquired from TD in February 2018.

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Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $76.3 million and $123.6 million for the three months ended September 30, 2018 and 2017, respectively. Equity in earnings of unconsolidated investments of $76.3 million for three months ended September 30, 2018 primarily reflects our portion of earnings and the $9.0 million of amortization of a negative basis difference associated with our aggregate 75% membership interest in Rockies Express, inclusive of the additional 25.01% membership interest acquired in February 2018, as well as $1.4 million of equity in earnings related to our 51% membership interest in Pawnee. Equity in earnings of unconsolidated investments of $123.6 million for the three months ended September 30, 2017 primarily reflects our portion of earnings and the $6.6 million of amortization of a negative basis difference associated with our 49.99% membership interest in Rockies Express. During the three months ended September 30, 2017, Rockies Express recognized a $150 million gain on settlement of the Ultra litigation as discussed in Note 15 – Legal and Environmental Matters.

Interest expense, net. Interest expense of $34.0 million for the three months ended September 30, 2018 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities and the Senior Notes. Interest expense of $24.4 million for the three months ended September 30, 2017 was primarily composed of interest and fees associated with TEP and Tallgrass Equity revolving credit facilities and the 2024 Notes issued on September 1, 2016 and May 16, 2017, and the 2028 Notes issued on September 15, 2017. The increase in interest and fees is primarily due to increased borrowings to fund a portion of our 2017 and 2018 acquisitions, as well as the higher borrowing rate on the Senior Notes, the proceeds of which were used to repay borrowings under TEP's revolving credit facility.

Other (expense) income, net. Other (expense) income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other expense for the three months ended September 30, 2018 was $1.6 million compared to $10.2 million of other income for the three months ended September 30, 2017. Other expense of $1.6 million for the three months ended September 30, 2018 included a $2.2 million loss on debt retirement associated with the write off of deferred financing costs associated with the Amendment to the TEP revolving credit facility and the termination of the Tallgrass Equity revolving credit facility. Other income of $10.2 million for the three months ended September 30, 2017 included a $9.7 million gain on remeasurement of unconsolidated investment related to the remeasurement to fair value of our existing 20% membership interest in Deeprock Development in connection with TEP's acquisition of a controlling financial interest in Deeprock Development in July 2017.

Deferred income tax expense. Deferred income tax expense for the three months ended September 30, 2018 was $12.0 million, compared to deferred income tax expense of $12.6 million for the three months ended September 30, 2017. The decrease in deferred income tax expense was primarily due to the increased equity in earnings during the three months ended September 30, 2017 associated with Rockies Express as a result of the Ultra settlement, partially offset by our increased ownership in TEP due to the TEP Merger and the resulting increase in income allocated to TGE.

Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

Revenues. Total revenues were $573.0 million for the nine months ended September 30, 2018, compared to $481.1 million for the nine months ended September 30, 2017, which represents an increase of $91.9 million, or 19%, in total revenues. The overall increase in revenue was largely driven by increased revenues of $77.6 million and $45.2 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by a $30.6 million increase in eliminations of intersegment revenue and decreased revenues of $0.4 million in the Natural Gas Transportation segment, as discussed further below.

Operating costs and expenses. Operating costs and expenses were $321.7 million for the nine months ended September 30, 2018 compared to $277.0 million for the nine months ended September 30, 2017, which represents an increase of $44.8 million, or 16%. The overall increase in operating costs and expenses is driven by increased operating costs and expenses of $59.9 million and $9.2 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by decreased operating costs and expenses of $20.2 million and $4.1 million in the Corporate and Other and Natural Gas Transportation segments, as discussed further below. The decrease in Corporate and Other expenses was primarily driven by a $30.6 million increase in eliminations of intersegment operating costs and expenses, partially offset by a $7.5 million increase in corporate general and administrative costs and a $2.9 million increase in depreciation and amortization costs due to the administrative assets acquired from TD in February 2018. The increase in corporate general and administrative costs was due to $7.2 million in expenses at TEP and Tallgrass Equity attributable to the Merger Agreement and the transactions contemplated by the Merger Agreement and Tallgrass Equity's acquisition of an additional 25.01% membership interest in Rockies Express and additional TEP common units.

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Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $222.9 million and $187.1 million for the nine months ended September 30, 2018 and 2017, respectively. Equity in earnings of unconsolidated investments of $222.9 million for nine months ended September 30, 2018 primarily reflects our portion of earnings and the $27.1 million of amortization of a negative basis difference associated with our aggregate 75% membership interest in Rockies Express, inclusive of the additional 25.01% membership interest acquired in February 2018, as well as $2.7 million of equity in earnings related to our 51% membership interest in Pawnee. Equity in earnings of unconsolidated investments of $187.1 million for the nine months ended September 30, 2017 primarily reflects our portion of earnings and the $16.7 million of amortization of a negative basis difference associated with our 49.99% membership interest in Rockies Express, as well as $1.5 million of equity in earnings related to our 20% membership interest in Deeprock Development prior to our acquisition of a controlling financial interest in Deeprock Development in July 2017. During the nine months ended September 30, 2017, Rockies Express recognized a $150 million gain on settlement of the Ultra litigation as discussed in Note 15 – Legal and Environmental Matters.

Interest expense, net. Interest expense of $95.1 million for the nine months ended September 30, 2018 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities and the Senior Notes. Interest expense of $61.5 million for the nine months ended September 30, 2017 was primarily composed of interest and fees associated with TEP and Tallgrass Equity revolving credit facilities and the 2024 Notes issued on September 1, 2016 and May 16, 2017, and the 2028 Notes issued on September 15, 2017. The increase in interest and fees is primarily due to increased borrowings to fund a portion of our 2017 and 2018 acquisitions, as well as the higher borrowing rate on the Senior Notes, the proceeds of which were used to repay borrowings under TEP's revolving credit facility.

Other (expense) income, net. Other (expense) income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other expense for the nine months ended September 30, 2018 was $0.8 million compared to $12.4 million of other income for the nine months ended September 30, 2017. Other expense of $0.8 million for the nine months ended September 30, 2018 included a $2.2 million loss on debt retirement associated with the write off of deferred financing costs associated with the Amendment to the TEP revolving credit facility and the termination of the Tallgrass Equity revolving credit facility. Other income of $12.4 million for the nine months ended September 30, 2017 included a $9.7 million gain on remeasurement of unconsolidated investment related to the remeasurement to fair value of our existing 20% membership interest in Deeprock Development in connection with TEP's acquisition of a controlling financial interest in Deeprock Development in July 2017 and a $1.9 million unrealized gain on derivative instrument related to the change in fair value of the call option received from TD as part of the acquisition of an additional 31.3% membership interest in Pony Express as discussed further in Note 9 – Risk Management.

Deferred income tax expense. Deferred income tax expense for the nine months ended September 30, 2018 was $35.5 million, compared to deferred income tax expense of $25.0 million for the nine months ended September 30, 2017. The increase in deferred income tax expense was a result of our increased ownership in TEP due to the TEP Merger and the resulting increase in income allocated to TGE.

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

Segment Financial Data - Natural Gas Transportation (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
Revenues:
Natural gas transportation services	$	31,769	$	32,139	$	98,759	$	96,140
Sales of natural gas, NGLs, and crude oil	457		603		802		2,793
Processing and other revenues	1,851		3,342		5,647		6,689
Total revenues	34,077		36,084		105,208		105,622
Operating costs and expenses:
Cost of sales	439		586		870		2,177
Cost of transportation services	845		1,489		1,799		2,731
Operations and maintenance	6,362		7,114		19,849		21,502
Depreciation and amortization	4,861		4,794		14,539		14,369
General and administrative	3,248		4,180		11,139		11,534
Taxes, other than income taxes	950		905		3,374		3,399
Total operating costs and expenses	16,705		19,068		51,570		55,712
Operating income	$	17,372	$	17,016	$	53,638	$	49,910

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

Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017

Revenues. Natural Gas Transportation segment revenues were $34.1 million for the three months ended September 30, 2018, compared to $36.1 million for the three months ended September 30, 2017, which represents a decrease of $2.0 million, or 6%, in segment revenues due to a $1.5 million decrease in other revenues and a $0.4 million decrease in natural gas transportation services. The $1.5 million decrease in other revenues was driven by a decrease in the management fee that NatGas receives as the operator of the Rockies Express Pipeline attributable to the Ultra settlement recognized during the three months ended September 30, 2017, as discussed in Note 15 – Legal and Environmental Matters.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $16.7 million for the three months ended September 30, 2018, compared to $19.1 million for the three months ended September 30, 2017, which represents a decrease of $2.4 million, or 12%. The overall decrease in operating costs and expenses was primarily driven by a $0.9 million decrease in general and administrative costs, a $0.8 million decrease in operations and maintenance costs driven by the timing of pipeline integrity work, and a $0.6 million decrease in cost of transportation services.

Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

Revenues. Natural Gas Transportation segment revenues were $105.2 million for the nine months ended September 30, 2018, compared to $105.6 million for the nine months ended September 30, 2017, which represents a decrease of $0.4 million, in segment revenues due to a $2.0 milliondecrease in sales of natural gas driven by decreased volumes sold, a $1.0 million decrease in other revenues driven by a decrease in the management fee that NatGas receives as the operator of the Rockies Express Pipeline attributable to the Ultra Settlement discussed above, partially offset by a $2.6 millionincrease in natural gas transportation services due to increased revenue associated with increased throughput and contracted capacity in the second quarter of 2018 and colder weather in the first quarter of 2018, both resulting in higher volumes transported during the first half of 2018.

Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were $51.6 million for the nine months ended September 30, 2018, compared to $55.7 million for the nine months ended September 30, 2017, which represents a decrease of $4.1 million, or 7%. The overall decrease in operating costs and expenses was primarily due to a $1.7 million decrease in operations and maintenance costs driven by the timing of pipeline integrity work, a $1.3 million decrease in cost of sales driven by decreased volumes of natural gas sold, and a $0.9 million decrease in cost of transportation services.

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

Segment Financial Data - Crude Oil Transportation (1)	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
Revenues:
Crude oil transportation services	$	113,805	$	90,113	$	312,453	$	264,299
Sales of natural gas, NGLs, and crude oil	2,314		2,916		6,289		9,469
Processing and other revenues	131		—		266		—
Total revenues	116,250		93,029		319,008		273,768
Operating costs and expenses:
Cost of sales	2,127		2,819		6,122		8,154
Cost of transportation services	17,374		11,957		49,408		39,708
Operations and maintenance	3,453		2,976		9,333		9,048
Depreciation and amortization	13,628		13,127		40,587		39,230
General and administrative	4,610		5,320		13,422		15,318
Taxes, other than income taxes	5,763		5,352		18,600		16,848
Total operating costs and expenses	46,955		41,551		137,472		128,306
Operating income	$	69,295	$	51,478	$	181,536	$	145,462

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

Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017

Revenues. Crude Oil Transportation segment revenues were $116.3 million for the three months ended September 30, 2018, compared to $93.0 million for the three months ended September 30, 2017, which represents an increase of $23.2 million, or 25%, in segment revenues driven by a $23.7 millionincrease in crude oil transportation services. The increase in crude oil transportation services revenue was primarily driven by a $15.0 million increase in committed volume shipments, a $9.3 million increase in walk-up barrels shipped during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, and a $3.0 million increase due to the FERC annual index adjustment effective July 1, 2018. These increases were partially offset by a $5.9 million net decrease in revenue from a committed shipper that extended its contract during the fourth quarter of 2017, thereby paying a lower tariff rate, which was partially offset by increased volumes shipped.

Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $47.0 million for the three months ended September 30, 2018 compared to $41.6 million for the three months ended September 30, 2017, which represents an increase of $5.4 million, or 13%. The overall increase in operating costs and expenses was primarily driven by a $5.4 million increase in cost of transportation services driven by higher throughput volumes during the three months ended September 30, 2018 compared to the three months ended September 30, 2017, a $0.5 million increase in depreciation and amortization costs due to assets placed into service in 2018, and a $0.5 million increase in operations and maintenance costs driven by the timing of pipeline integrity work, partially offset by a $0.7 million decrease in general and administrative costs.

Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

Revenues. Crude Oil Transportation segment revenues were $319.0 million for the nine months ended September 30, 2018, compared to $273.8 million for the nine months ended September 30, 2017, which represents an increase of $45.2 million, or 17%, in segment revenues driven by a $48.2 millionincrease in crude oil transportation services, partially offset by a $3.2 million decrease in sales of crude oil primarily due to decreased volumes sold during the nine months ended September 30, 2018. The increase in crude oil transportation services revenue was primarily driven by a $33.2 million increase in committed volume shipments, a $21.9 million increase in walk-up barrels shipped during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, a $4.6 million increase in PLA revenue, and a $3.9 million increase due to the FERC annual index adjustments effective July 1, 2018. These increases were partially offset by a $18.7 million net decrease in revenue from a committed shipper that extended its contract during the fourth quarter of 2017, thereby paying a lower tariff rate, which was partially offset by increased volumes shipped.

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Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were $137.5 million for the nine months ended September 30, 2018 compared to $128.3 million for the nine months ended September 30, 2017, which represents an increase of $9.2 million, or 7%. The overall increase in operating costs and expenses was primarily driven by a $9.7 million increase in cost of transportation services driven by higher throughput volumes during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, a $1.8 million increase in taxes, other than income taxes driven by an increase in property tax assessment estimates, and a $1.4 million increase in depreciation and amortization costs due to assets placed into service in 2018. These increases were partially offset by a $2.0 million decrease in cost of sales driven by decreased volumes sold and a $1.9 million decrease in general and administrative costs.

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

Segment Financial Data - Gathering, Processing & Terminalling (1)	Three Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2018			2017
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	41,301		$	28,696	$	112,376		$	58,252
Processing and other revenues	30,311			29,040		86,686			63,163
Total revenues	71,612			57,736		199,062			121,415
Operating costs and expenses:
Cost of sales	26,103			24,120		76,367			49,148
Cost of transportation services	15,875			7,531		33,982			15,294
Operations and maintenance	8,196			7,322		23,668			15,019
Depreciation and amortization	7,926			5,861		23,290			13,677
General and administrative	3,074			3,453		9,348			7,061
Taxes, other than income taxes	1,037			404		3,117			1,552
(Gain) loss on disposal of assets	(279		)	—		(9,417		)	(1,264		)
Total operating costs and expenses	61,932			48,691		160,355			100,487
Operating income	$	9,680		$	9,045	$	38,707		$	20,928

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

Three Months Ended September 30, 2018 Compared to the Three Months Ended September 30, 2017

Revenues. Gathering, Processing & Terminalling segment revenues were $71.6 million for the three months ended September 30, 2018, compared to $57.7 million for the three months ended September 30, 2017, which represents a $13.9 million, or 24%, increase in segment revenues. The increase in segment revenues was primarily due to a $12.6 million increase in sales of natural gas, NGLs, and crude oil and a $1.3 million increase in processing and other revenues. The increase in sales of natural gas, NGLs, and crude oil was driven by (i) increased sales of crude oil of $9.1 million at Stanchion and (ii) increased sales of NGLs of $5.3 million, primarily due to higher throughput volumes, increased volumes sold, and higher NGL prices; partially offset by (iii) decreased sales of residue gas of $1.8 million driven by a 26% decrease in natural gas prices. The increase in processing and other revenues was driven by (i) increased terminal services revenue of $4.6 million driven by the acquisition of Deeprock North in January 2018 and the acquisition of a controlling interest in and subsequent consolidation of Deeprock Development in July 2017 and (ii) increased processing fee income of $1.3 million primarily driven by changes in the accounting treatment of certain commodities retained as consideration for processing services to processing fee revenue beginning January 1, 2018 as discussed further in Note 12 – Revenue from Contracts with Customers; partially offset by (iii) decreased water business services revenue of $4.2 million driven by decreased fresh water transportation volumes, partially offset by increased produced water disposal volumes.

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Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $61.9 million for the three months ended September 30, 2018 compared to $48.7 million for the three months ended September 30, 2017, which represents an increase of $13.2 million, or 27%. The increase in operating costs and expenses was primarily driven by (i) an increase of $8.3 million in cost of transportation services due to crude oil transportation fees paid by Stanchion, partially offset by decreased fresh water transportation volumes, (ii) an increase of $2.1 million in depreciation and amortization costs, primarily driven by the 2018 acquisition of BNN North Dakota and assets placed into service at Terminals, (iii) a $2.0 million increase in cost of sales primarily driven by higher prices, higher producer settlements, and higher NGL sales as discussed above, and (iv) an increase of $0.9 million in operations and maintenance costs, primarily driven by the 2018 acquisition of BNN North Dakota.

Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

Revenues. Gathering, Processing & Terminalling segment revenues were $199.1 million for the nine months ended September 30, 2018, compared to $121.4 million for the nine months ended September 30, 2017, which represents a $77.6 million, or 64%, increase in segment revenues. The increase in segment revenues was primarily due to a $54.1 million increase in sales of natural gas, NGLs, and crude oil and a $23.5 million increase in processing and other revenues. The increase in sales of natural gas, NGLs, and crude oil was driven by (i) increased sales of NGLs of $28.9 million primarily due to higher throughput volumes and increased volumes sold driven by the Douglas Gathering System acquisition in June 2017 and higher NGL prices, (ii) increased crude oil sales of $16.4 million at Stanchion, and (iii) increased sales of natural gas of $8.6 million due to sales of residue gas from the Douglas Gathering System. The increase in processing and other revenues was driven by (i) increased terminal services revenue of $16.9 million driven by the acquisition of Deeprock North in January 2018 and the acquisition of a controlling interest in and subsequent consolidation of Deeprock Development in July 2017, (ii) increased processing fee income of $4.6 million primarily driven by changes in the accounting treatment of certain commodities retained as consideration for processing services to processing fee revenue beginning January 1, 2018 as discussed further in Note 12 – Revenue from Contracts with Customers, and (iii) increased water business services revenue of $2.6 million driven by the acquisition of BNN North Dakota in January 2018 and increased produced water disposal volumes, partially offset by decreased fresh water transportation volumes.

Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were $160.4 million for the nine months ended September 30, 2018 compared to $100.5 million for the nine months ended September 30, 2017, which represents an increase of $59.9 million, or 60%. The increase in operating costs and expenses was primarily driven by (i) a $27.2 million increase in cost of sales primarily due to higher NGL prices, higher throughput volumes, and increased volumes sold driven by the Douglas Gathering System acquisition as discussed above, (ii) an increase of $18.7 million in cost of transportation services due to crude oil transportation fees paid by Stanchion, partially offset by decreased fresh water transportation volumes, and (iii) increases of $9.6 million, $8.6 million, and $2.3 million in depreciation and amortization, operations and maintenance costs, and general and administrative costs, respectively, all primarily driven by the 2018 acquisitions of BNN North Dakota and Deeprock North and the 2017 acquisitions of the Douglas Gathering System and Deeprock Development. The increase in operating costs and expenses was partially offset by the $9.4 million gain on the disposal of TCG during the nine months ended September 30, 2018, compared to the $1.3 million gain on disposal of assets during the nine months ended September 30, 2017.

Liquidity and Capital Resources Overview

Our primary sources of liquidity for the three months ended September 30, 2018 were proceeds from the issuance of senior notes, borrowings under TEP's revolving credit facility, and cash generated from operations. We expect our sources of liquidity in the future to include:

• cash generated from our operations;

• borrowing capacity available under TEP's revolving credit facility; and

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

We believe that cash on hand, cash generated from operations, and availability under TEP's revolving credit facility will be adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements, and our planned cash dividends to shareholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of cash generated from operations, borrowings under TEP's revolving credit facility and issuances of debt and/or equity securities. For additional information regarding our revolving credit facilities and senior unsecured notes, see Note 10 – Long-term Debt. For additional information regarding our equity transactions, see Note 11 – Partnership Equity.

Our total liquidity as of September 30, 2018 and December 31, 2017 was as follows:

	September 30, 2018			December 31, 2017
	(in thousands)
Cash on hand	$	5,521		$	2,593
Total capacity under the TEP revolving credit facility (1)	2,250,000			1,750,000
Less: Outstanding borrowings under the TEP revolving credit facility	(1,051,000		)	(661,000		)
Less: Letters of credit issued under the TEP revolving credit facility	(94		)	(94		)
Available capacity under the TEP revolving credit facility	1,198,906			1,088,906
Total capacity under the Tallgrass Equity revolving credit facility	$	—		$	150,000
Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility (2)	—			(146,000		)
Available capacity under the Tallgrass Equity revolving credit facility	$	—		$	4,000
Total liquidity	$	1,204,427		$	1,095,499

⁽¹⁾  In July 2018, the TEP revolving credit facility was amended, increasing the total capacity to $2.25 billion. See Note 10 – Long-term Debt for additional information.

⁽²⁾  On July 26, 2018, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility.

Working Capital

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

As of September 30, 2018, we had a working capital deficit of $107.0 million compared to a working capital deficit of $101.6 million at December 31, 2017, which represents an increase in the working capital deficit of $5.4 million. The overall increase in the working capital deficit was primarily attributable to changes in the following components:

• an increase in accounts payable of $124.3 million primarily due to crude oil purchases at Stanchion, an increase in capital expenditures at Terminals, and payables related to BNN North Dakota acquired in January 2018, partially offset by a decrease in capital expenditures at Pony Express; and

• an increase in deferred revenue of $15.2 million primarily from deficiency payments collected by Pony Express and deferred revenue at BNN North Dakota, acquired in January 2018.

These working capital decreases were partially offset by:

• an increase in accounts receivable of $117.1 million primarily due to crude oil sales at Stanchion, as well as receivables related to BNN North Dakota acquired in January 2018;

• a decrease in accrued interest of $12.6 million primarily due to timing of interest payments; and

• an increase in inventory of $7.7 million primarily due to crude oil purchases at Stanchion.

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

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Cash Flows

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

	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Net cash provided by (used in):
Operating activities	$	466,391		$	450,377
Investing activities	$	(756,499	)	$	(852,941	)
Financing activities	$	293,036		$	403,384

Nine Months Ended September 30, 2018 Compared to the Nine Months Ended September 30, 2017

Operating Activities. Cash flows provided by operating activities were $466.4 million and $450.4 million for the nine months ended September 30, 2018 and 2017, respectively. The increase in net cash flows provided by operating activities of $16.0 million was primarily driven by the increase in operating results, as discussed above, and a $34.5 million increase in distributions received from unconsolidated affiliates, primarily Rockies Express, as a result of our increased membership interest effective March 31, 2017 and February 7, 2018. These increases were partially offset by a net decrease in cash flows from changes in working capital driven by a $81.1 million decrease in net cash inflows from accounts receivable, primarily due to crude oil sales at Stanchion and a $12.6 million decrease in net cash inflows from deferred revenue primarily at Pony Express, partially offset by a $62.2 million decrease in net cash outflows from accounts payable, primarily due to crude oil purchases at Stanchion.

Investing Activities. Cash flows used in investing activities were $756.5 million for the nine months ended September 30, 2018, primarily driven by:

• contributions to unconsolidated investments in the amount of $444.8 million, primarily to fund our portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018, as well as to fund our share of capital projects at Iron Horse and BNN Colorado Water, LLC ("BNN Colorado");

• capital expenditures of $265.1 million, primarily due to spending on the Cheyenne Connector, a new 70-mile natural gas pipeline located in Colorado, additional water gathering infrastructure located in North Dakota, a 55-mile extension on the Pony Express system, construction of the Buckingham Terminal expansion, construction of the Guernsey, Natoma, and Grasslands Terminals, and pipe replacement and remediation work on the Trailblazer Pipeline system as discussed in Note 15 – Legal and Environmental Matters;

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

• cash outflows of $30.6 million for the acquisition of a 51% membership interest in Pawnee; and

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

These cash outflows were partially offset by cash inflows of:

• $60.7 million of distributions received from unconsolidated affiliates in excess of cumulative earnings recognized, primarily Rockies Express; and

• $50.0 million from the sale of TCG.

Cash flows used in investing activities were $852.9 million for the nine months ended September 30, 2017, primarily driven by:

• cash outflows of $400.0 million for the acquisition of an additional 24.99% membership interest in Rockies Express;

• cash outflows of $140.0 million for the acquisition of Terminals and NatGas;

• cash outflows of $128.5 million for the acquisition of the Douglas Gathering System;

• capital expenditures of $88.1 million, primarily due to spending on an additional freshwater connection at Water Solutions and on a connection to a refinery complex and remediation digs on the Pony Express System as discussed in Note 15 – Legal and Environmental Matters;

• cash outflows of $57.2 million for the acquisition of an additional 40% membership interest in Deeprock Development;

• cash outflows of $36.0 million for the acquisition of the PRB Crude System; and

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• contributions to Rockies Express in the amount of $31.6 million, primarily to fund remaining costs associated with the Zone 3 Capacity Enhancement project at Rockies Express.

These cash outflows were partially offset by $41.9 million of distributions from Rockies Express in excess of cumulative earnings recognized.

Financing Activities. Cash flows provided by financing activities were $293.0 million for the nine months ended September 30, 2018, primarily driven by:

• proceeds from TEP's issuance of $500.0 million in aggregate principal amount of 2023 Notes; and

• net borrowings under the revolving credit facilities of $244.0 million.

These cash inflows were partially offset by cash outflows of:

• distributions to noncontrolling interests of $262.9 million, consisting of distributions to the Exchange Right Holders of $160.6 million, distributions to TEP unitholders of $97.7 million, and distributions to Deeprock Development and Pony Express noncontrolling interests of $4.6 million;

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

•dividends paid to Class A shareholders of $126.7 million.

Cash flows provided by financing activities were $403.4 million for the nine months ended September 30, 2017, primarily driven by:

• proceeds from TEP's issuance of $850.0 million in aggregate principal amount of 2024 Notes and 2028 Notes; and

• net cash proceeds of $112.4 million from the issuance of 2,341,061 TEP common units under the Equity Distribution Agreements.

These financing cash inflows were partially offset by cash outflows of:

• distributions to noncontrolling interests of $229.7 million, which consisted of distributions to TEP unitholders of $135.4 million, Tallgrass Equity distributions to the Exchange Right Holders of $90.0 million, and distributions to Pony Express noncontrolling interests of $4.3 million;

• net repayments under the revolving credit facilities of $136.0 million;

• $72.4 million for TEP's partial exercise of the call option granted by TD covering 1,703,094 common units;

• dividends paid to Class A shareholders of $52.7 million; and

• $35.3 million for 736,262 TEP common units repurchased from TD.

Dividends

Dividends to our Class A shareholders. We distribute 100% of TGE's available cash at the end of each quarter to Class A shareholders of record beginning with the quarter ended June 30, 2015. Available cash at TGE is generally defined in our partnership agreement as all cash and cash equivalents on hand at the date of determination in respect of such quarter less reserves established in the discretion of our general partner for future requirements. For a discussion of factors and trends impacting our business, which in turn impacts our ability to pay dividends to our Class A shareholders, please see "—Factors and Trends Impacting Our Business" in our 2017 Form 10-K.

Our dividend for the three months ended September 30, 2018, in the amount of $0.5100 per Class A share, or $79.7 million in the aggregate, was announced on October 15, 2018 and will be paid on November 14, 2018 to Class A shareholders of record on October 31, 2018.

Capital Requirements

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

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

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

The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. We expect to incur approximately $343 million for expansion capital projects and approximately $22 million for maintenance capital expenditures in 2018. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities:

	Nine Months Ended September 30,
	2018		2017
	(in thousands)
Maintenance capital expenditures	$	15,189	$	7,746
Expansion capital expenditures	258,401		78,448
Total capital expenditures incurred	$	273,590	$	86,194

Capital expenditures incurred represent capital expenditures paid and accrued during the period. Capital expenditures are presented net of contributions and reimbursements received. The increase in maintenance capital expenditures to $15.2 million for the nine months ended September 30, 2018 from $7.7 million for the nine months ended September 30, 2017 is primarily driven by increased expenditures in the Natural Gas Transportation and Corporate and Other segments and contributions from TD to TEP in order to indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline during the nine months ended September 30, 2017, as discussed further in Note 15 – Legal and Environmental Matters. Maintenance capital expenditures for the nine months ended September 30, 2018 in the Corporate and Other segment consisted primarily of spending on information technology assets. Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from year to year and from quarter to quarter. Expansion capital expenditures were $258.4 million for the nine months ended September 30, 2018 compared to $78.4 million for the nine months ended September 30, 2017. Expansion capital expenditures for the nine months ended September 30, 2018 consisted primarily of spending on the Cheyenne Connector, additional water gathering infrastructure located in North Dakota, a 55-mile extension on the Pony Express system, construction of the Buckingham Terminal expansion, construction of the Guernsey, Natoma, and Grasslands Terminals, and pipe replacement and remediation work on the Trailblazer Pipeline system as discussed in Note 15 – Legal and Environmental Matters. Expansion capital expenditures of $78.4 million for the nine months ended September 30, 2017 consisted primarily of spending on an additional freshwater connection at Water Solutions and on a connection to a refinery complex and remediation digs on the Pony Express System, as discussed in Note 15 – Legal and Environmental Matters.

During the nine months ended September 30, 2018, TEP made an initial contribution of $3.5 million to Iron Horse, a newly formed unconsolidated affiliate. In connection with TEP's 75% membership interest in Iron Horse, TEP has made commitments to fund its proportionate share of the remaining cost to construct the pipeline, estimated at $82.1 million as of September 30, 2018. In addition, we invested cash in unconsolidated affiliates, including Rockies Express, Iron Horse, and BNN Colorado, of $444.8 million and $31.6 million during the nine months ended September 30, 2018 and 2017, respectively, to fund our share of capital projects, including a special contribution of approximately $412.5 million to fund our portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018.

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

Contractual Obligations

There have been no material changes in our contractual obligations as reported in our 2017 Form 10-K.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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Critical Accounting Policies and Estimates

The critical accounting policies and estimates used in the preparation of our condensed consolidated financial statements are set forth in our 2017 Form 10-K for the year ended December 31, 2017 and have not changed, with the exception of the following addition related to our implementation of the guidance in ASC Topic 606, Revenue from Contracts with Customers, as discussed in Note 2 – Summary of Significant Accounting Policies.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Assumptions
Revenue Recognition
The majority of our revenue is derived from long-term contracts that can span several years. Accounting for long-term contracts involves the use of various techniques to estimate total contract revenue and determine the timing of revenue recognition. We periodically evaluate our estimates with respect to the probability of our customers exercising their rights and recognize revenue associated with contract liabilities when the probability becomes remote that the customer will exercise its remaining rights.	We review our deferred revenue (contract liabilities) at each balance sheet date to determine the probability that our customers will exercise their remaining rights. We recognize revenue when the probability becomes remote that the customer will exercise its remaining rights. Our evaluation requires management to apply judgment in estimating future system capacity and the ability of our customers to utilize that capacity.	If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, the timing of our revenue recognition with respect to deferred revenue could be impacted and we may experience material changes in revenue.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

The majority of TMID's Adjusted EBITDA comes from volumetric fee or commodity sensitive contracts. The profitability of our commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. During the nine months ended September 30, 2018, TMID represented 4% of our consolidated Adjusted EBITDA.

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

The following table summarizes our commodity derivatives and the change in fair value that would be expected from a 10% price increase or decrease as of September 30, 2018, assuming a parallel shift in the forward curve through the end of 2018:

	Fair Value		Effect of 10% Price Increase			Effect of 10% Price Decrease
	(in thousands)
Crude oil derivative contracts(1)	$	6,014	$	90		$	(90	)
Crude oil derivative contracts (2)	$	4,163	$	(1,525	)	$	1,525

⁽¹⁾  Represents the forward purchase of 3,565,000 barrels of crude oil in our Gathering, Processing & Terminalling segment which will settle throughout the fourth quarter of 2018 and 2019.

⁽²⁾  Represents the forward sale of 3,163,500 barrels of crude oil in our Gathering, Processing & Terminalling segment which will settle throughout the fourth quarter of 2018 and 2019.

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Interest Rate Risk

As described in Note 10 – Long-term Debt, on July 26, 2018, in connection with the Amendment to TEP's Credit Agreement, Tallgrass Equity repaid all outstanding borrowings and terminated its revolving credit facility.

As of September 30, 2018, TEP has issued $2.0 billion of Senior Notes and has a $2.25 billion revolving credit facility with borrowings of $1.051 billion. Borrowings under TEP's revolving credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. The applicable margin ranges from 0.25% to 1.25% for base rate borrowings (previously 0.50% to 1.50% prior to the Amendment) and 1.25% to 2.25% for reserve adjusted Eurodollar rate borrowings (previously 1.50% to 2.50% prior to the Amendment), based upon our total leverage ratio.

We do not currently hedge the interest rate risk on our borrowings under the revolving credit facilities. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the fair value of the debt by $0.5 million based on our outstanding debt under our revolving credit facilities as of September 30, 2018.

Credit Risk

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

A substantial majority of our revenue is produced under long-term firm fee contracts with high-quality customers. The customer base we currently serve under these contracts generally has a strong credit profile, with a majority of our revenues derived from customers who have BBB- or Baa3 and better credit ratings or are part of corporate families with such credit ratings as of September 30, 2018.

We also have indirect credit risk exposure with respect to our investment in Rockies Express. See Item 1A.—Risk Factors in our 2017 Form 10-K for additional information.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Item 1A of our 2017 Form 10-K sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition or operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results for the quarter ended September 30, 2018. There have been no material changes to the risk factors contained in our 2017 Form 10-K.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit No.	Description
4.1	Indenture, dated as of September 26, 2018, among Tallgrass Energy Partners, LP, Tallgrass Energy Finance Corp., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Tallgrass Energy, LP's Current Report on Form 8-K filed on September 26, 2018).
4.2	Form of 4.75% Senior Note (included as Exhibit A in Exhibit 4.1 which is incorporated by reference to Exhibit 4.1 to Tallgrass Energy, LP's Current Report on Form 8-K filed on September 26, 2018).
10.1	Amendment No. 1 to Second Amended and Restated Credit Agreement, dated July 26, 2018, (incorporated by reference to Exhibit 10.1 to Tallgrass Energy, LP's Current Report on Form 8-K filed on July 27, 2018).
12.1*	Computation of Ratio of Earnings to Fixed Charges
31.1*	Rule 13a-14(a)/15d-14(a) Certification of David G. Dehaemers, Jr.
31.2*	Rule 13a-14(a)/15d-14(a) Certification of Gary J. Brauchle.
32.1*	Section 1350 Certification of David G. Dehaemers, Jr.
32.2*	Section 1350 Certification of Gary J. Brauchle.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

* - filed herewith

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SIGNATURES

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

		Tallgrass Energy, LP
		(registrant)
		By:	Tallgrass Energy GP, LLC, its general partner
Date:	October 31, 2018	By:	/s/ Gary J. Brauchle
			Name:	Gary J. Brauchle
			Title:	Executive Vice President and Chief Financial Officer
				(Duly Authorized Officer and Principal Financial Officer)

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