TGE 10-Q Quarterly Report Sept. 30, 2019

TALLGRASS ENERGY, LP

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Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



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

For the Quarterly Period Ended September 30, 2019



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

Commission file number 001-37365

Tallgrass Energy, LP

(Exact name of registrant as specified in its charter)

( 913 ) 928-6060

(Registrant's Telephone Number, Including Area Code)



Delaware		47-3159268
(State or other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification Number)

4200 W. 115th Street, Suite 350
Leawood,	Kansas	66211
(Address of Principal Executive Offices)		(Zip Code)



Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of each exchange on which registered
Class A Shares Representing Limited Partner Interests	TGE	New York Stock Exchange

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

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

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



Large accelerated filer	x	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	☐

		Emerging growth company	☐

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

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

On October 30, 2019 , the Registrant had 179,197,416 Class A shares and 102,136,875 Class B shares outstanding.

TALLGRASS ENERGY, LP

TABLE OF CONTENTS



PART 1—FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
CONDENSED CONSOLIDATED BALANCE SHEETS	1
CONDENSED CONSOLIDATED STATEMENTS OF INCOME	2
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY	3
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS	5
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	7
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.

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

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

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

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

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

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

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

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

TBtu: one trillion British Thermal Units.

Tcf: one trillion cubic feet.

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

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

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

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

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

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

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

PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)



	September 30, 2019		December 31, 2018
	(in thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	15,967	$	9,596
Accounts receivable, net	246,293		236,097
Inventories	41,028		34,316
Prepayments and other current assets	14,785		11,816
Total Current Assets	318,073		291,825
Property, plant and equipment, net	2,865,107		2,802,429
Goodwill	441,361		421,983
Intangible assets, net	246,684		227,103
Unconsolidated investments	1,964,949		1,861,686
Deferred tax asset	334,970		273,531
Deferred charges and other assets	31,753		14,952
Total Assets	$	6,202,897	$	5,893,509
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable	$	196,033	$	201,512
Accrued taxes	28,427		20,734
Accrued interest	24,012		39,217
Accrued liabilities	21,795		23,287
Deferred revenue	125,198		111,095
Other current liabilities	41,759		42,910
Total Current Liabilities	437,224		438,755
Long-term debt, net	3,451,268		3,205,958
Other long-term liabilities and deferred credits	53,357		31,688
Total Long-term Liabilities	3,504,625		3,237,646
Commitments and Contingencies
Equity:
Class A Shareholders (179,197,416 and 156,311,986 shares outstanding at September 30, 2019 and December 31, 2018, respectively)	1,848,872		1,725,537
Class B Shareholders (102,136,875 and 123,887,893 shares outstanding at September 30, 2019 and December 31, 2018, respectively)	—		—
Total Partners' Equity	1,848,872		1,725,537
Noncontrolling interests ^(a)	412,176		491,571
Total Equity	2,261,048		2,217,108
Total Liabilities and Equity	$	6,202,897	$	5,893,509


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

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

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands, except per unit amounts)
Revenues:
Crude oil transportation services	$	112,126		$	100,226		$	306,738		$	286,130
Natural gas transportation services	30,312			30,953			96,173			94,623
Sales of natural gas, NGLs, and crude oil	39,902			44,072			116,609			119,467
Processing and other revenues	44,369			25,069			116,065			72,783
Total Revenues	226,709			200,320			635,585			573,003
Operating Costs and Expenses:
Cost of sales	17,664			28,556			56,217			82,601
Cost of transportation services	19,103			12,588			53,929			35,672
Operations and maintenance	22,657			18,011			64,175			52,850
Depreciation and amortization	31,797			27,595			95,778			81,408
General and administrative	21,439			16,015			72,426			53,526
Taxes, other than income taxes	8,183			7,750			26,892			25,091
(Gain) loss on disposal of assets	—			( 279		)	242			( 9,417		)
Total Operating Costs and Expenses	120,843			110,236			369,659			321,731
Operating Income	105,866			90,084			265,926			251,272
Other Income (Expense):
Equity in earnings of unconsolidated investments	86,349			76,268			273,883			222,857
Interest expense, net	( 41,625		)	( 34,019		)	( 121,925		)	( 95,062		)
Other income (expense), net	476			( 1,624		)	851			( 843		)
Total Other Income (Expense)	45,200			40,625			152,809			126,952
Net income before tax	151,066			130,709			418,735			378,224
Income tax expense	( 22,577		)	( 11,997		)	( 61,624		)	( 35,498		)
Net income	128,489			118,712			357,111			342,726
Net income attributable to noncontrolling interests	( 55,965		)	( 59,162		)	( 162,381		)	( 265,378		)
Net income attributable to TGE	$	72,524		$	59,550		$	194,730		$	77,348
Net income per Class A share:
Basic net income per Class A share	$	0.40		$	0.38		$	1.12		$	0.85
Diluted net income per Class A share	$	0.40		$	0.38		$	1.12		$	0.85
Basic average number of Class A shares outstanding	179,197			155,001			173,322			91,183
Diluted average number of Class A shares outstanding	180,155			156,088			174,756			92,661

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

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)



	Partners' Capital					Noncontrolling Interests			Total Equity
	Class A Shares			Class B Shares		Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2019	$	1,725,537		$	—	$	491,571		$	2,217,108
Net income	50,587			—		51,805			102,392
Dividends paid to Class A shareholders	( 81,304		)	—		—			( 81,304		)
Distributions to noncontrolling interests	—			—		( 66,625		)	( 66,625		)
Contributions from noncontrolling interests	—			—		1,282			1,282
Noncash compensation expense	17,120			—		—			17,120
TGE LTIP shares tendered by employees to satisfy tax withholding obligations	( 13,260		)	—		—			( 13,260		)
Deferred tax asset	123,051			—		—			123,051
Conversion of Class B shares to Class A shares	68,614			—		( 68,614		)	—
Balance at March 31, 2019	$	1,890,345		$	—	$	409,419		$	2,299,764
Net income	71,619			—		54,611			126,230
Dividends paid to Class A shareholders	( 94,975		)	—		—			( 94,975		)
Distributions to noncontrolling interests	—			—		( 55,870		)	( 55,870		)
Noncash compensation expense	3,450			—		—			3,450
Acquisition of CES	—			—		3,400			3,400
Balance at June 30, 2019	$	1,870,439		$	—	$	411,560		$	2,281,999
Net income	72,524			—		55,965			128,489
Dividends paid to Class A shareholders	( 96,767		)	—		—			( 96,767		)
Distributions to noncontrolling interests	—			—		( 56,390		)	( 56,390		)
Noncash compensation expense	2,676			—		—			2,676
Contributions from noncontrolling interests	—			—		1,041			1,041
Balance at September 30, 2019	$	1,848,872		$	—	$	412,176		$	2,261,048

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



	Partners' Capital					Noncontrolling Interests			Total Equity
	Class A Shares			Class B Shares		Noncontrolling Interests			Total Equity
	(in thousands)
Balance at January 1, 2018	$	48,613		$	—	$	1,672,566		$	1,721,179
Cumulative effect of ASC 606 implementation	4,588			—		39,543			44,131
Net income	16,735			—		97,578			114,313
Issuance of TEP units to the public, net of offering costs	( 5		)	—		( 40		)	( 45		)
Dividends paid to Class A shareholders	( 21,346		)	—		—			( 21,346		)
Noncash compensation expense	405			—		2,917			3,322
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 additional 2% membership interest in Pony Express	( 5,268		)	—		( 44,732		)	( 50,000		)
Acquisition of 25.01% membership interest in Rockies Express	34,116			—		74,421			108,537
Consolidation of Deeprock North	—			—		31,843			31,843
Contributions from noncontrolling interests	—			—		183			183
Distributions to noncontrolling interests	—			—		( 89,073		)	( 89,073		)
Balance at March 31, 2018	$	15,615		$	—	$	2,240,468		$	2,256,083
Net income	1,063			—		108,638			109,701
Issuance of TEP units to the public, net of offering costs	( 22		)	—		( 181		)	( 203		)
Dividends paid to Class A shareholders	( 28,316		)	—		—			( 28,316		)
Noncash compensation expense	( 74		)	—		280			206
TEP LTIP units tendered by employees to satisfy tax withholding obligations	( 190		)	—		( 1,531		)	( 1,721		)
Conversion of Class B shares to Class A shares	( 13,402		)	—		13,402			—
Distributions to noncontrolling interests	—			—		( 109,764		)	( 109,764		)
Deferred tax asset	7,664			—		—			7,664
Acquisition of additional TEP common units	( 351,431		)	—		( 1,762,327		)	( 2,113,758		)
Issuance of Class A shares	2,113,758			—		—			2,113,758
Balance at June 30, 2018	$	1,744,665		$	—	$	488,985		$	2,233,650
Net income	59,550			—		59,162			118,712
Issuance of TEP units to the public, net of offering costs	( 71		)	—		( 58		)	( 129		)
Dividends paid to Class A shareholders	( 77,052		)	—		—			( 77,052		)
Noncash compensation expense	2,047			—		—			2,047
Distributions to noncontrolling interests	—			—		( 64,019		)	( 64,019		)
Deferred tax asset	5,839			—		—			5,839
Conversion of Class B shares to Class A shares	3,267			—		( 3,267		)	—
Balance at September 30, 2018	$	1,738,245		$	—	$	480,803		$	2,219,048

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

TALLGRASS ENERGY, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Nine Months Ended September 30,
	2019			2018
	(in thousands)
Cash Flows from Operating Activities:
Net income	$	357,111		$	342,726
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	100,818			86,121
Equity in earnings of unconsolidated investments	( 273,883		)	( 222,857		)
Distributions from unconsolidated investments	274,511			222,082
Deferred income tax expense	61,386			35,498
Noncash compensation expense	23,246			6,770
Other noncash items, net	107			( 11,451		)
Changes in components of working capital:
Accounts receivable and other	( 12,406		)	( 115,330		)
Accounts payable and accrued liabilities	( 8,287		)	104,920
Deferred revenue	14,139			14,265
Other current assets and liabilities	( 9,136		)	1,682
Other operating, net	( 9,398		)	1,965
Net Cash Provided by Operating Activities	518,208			466,391
Cash Flows from Investing Activities:
Capital expenditures	( 225,462		)	( 265,073		)
Distributions from unconsolidated investments in excess of cumulative earnings	95,179			60,720
Contributions to unconsolidated investments	( 75,179		)	( 444,788		)
Acquisition of CES, net of cash acquired	( 48,416		)	—
Formation of Powder River Gateway joint venture	( 37,000		)	—
Acquisition of BNN North Dakota, net of cash acquired	—			( 95,000		)
Sale of Tallgrass Crude Gathering	—			50,046
Acquisition of Pawnee Terminal	—			( 30,600		)
Acquisition of 38% membership interest in Deeprock North	—			( 19,500		)
Other investing, net	( 42		)	( 12,304		)
Net Cash Used in Investing Activities	( 290,920		)	( 756,499		)
Cash Flows from Financing Activities:
Dividends paid to Class A shareholders	( 273,046		)	( 126,714		)
Borrowings under revolving credit facilities, net	243,000			244,000
Distributions to noncontrolling interests	( 178,885		)	( 262,856		)
TGE LTIP shares tendered by employees to satisfy tax withholding obligations	( 13,260		)	—
Proceeds from issuance of long-term debt	—			500,000
Acquisition of Pony Express membership interest	—			( 50,000		)
Other financing, net	1,274			( 11,394		)
Net Cash Used in Financing Activities	( 220,917		)	293,036
Net Change in Cash and Cash Equivalents	6,371			2,928
Cash and Cash Equivalents, beginning of period	9,596			2,593
Cash and Cash Equivalents, end of period	$	15,967		$	5,521

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



	Nine Months Ended September 30,
	2019			2018
	(in thousands)
Schedule of Noncash Investing and Financing Activities:
Contribution of assets to Powder River Gateway joint venture	$	( 122,504	)	$	—
Accruals for property, plant and equipment	$	13,134		$	8,517
Right-of-use assets obtained in exchange for operating lease obligations	$	10,045		$	—
Acquisition of additional TEP common units ^(a)(b)	$	—		$	( 2,365,501	)
Issuance of Class A shares ^(a)	$	—		$	2,113,758
Issuance of Tallgrass Equity units ^(b)	$	—		$	644,782
Acquisition of Rockies Express membership interest ^(b)	$	—		$	( 393,039	)
Issuance of noncontrolling interests in Deeprock Development in exchange for 62% membership interest in Deeprock North	$	—		$	( 31,843	)
Contribution of 38% membership interest in Deeprock North to Deeprock Development	$	—		$	( 19,500	)


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


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

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

TALLGRASS ENERGY, LP

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. Description of Business

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

Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity, LLC ("Tallgrass Equity"), in which we directly own an approximate 63.70 % membership interest as of September 30, 2019 , and Tallgrass Energy Partners, LP ("TEP"), a wholly-owned subsidiary of Tallgrass Equity and its subsidiaries. We are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations.

Our reportable business segments are:


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


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


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

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

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

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

Blackstone Acquisition

On March 11, 2019, pursuant to the terms of a previously announced definitive purchase agreement (the "Purchase Agreement"), dated January 30, 2019, entered into among acquisition vehicles controlled by affiliates of Blackstone Infrastructure Partners ("BIP" and, acquisition vehicles controlled by BIP, collectively, the "Sponsor Entities"), affiliates of Kelso & Co., affiliates of The Energy & Minerals Group, Tallgrass KC, LLC, an entity owned by certain members of our management, and the other sellers named therein (collectively, the "Sellers"), certain of the Sponsor Entities acquired from the Sellers (i) 100 % of the membership interests in our general partner, (ii) 21,751,018 Class A shares representing limited partner interests ("Class A shares") in us, (iii) 100,655,121 units representing limited liability company interests ("TE Units") in Tallgrass Equity, and (iv) 100,655,121 Class B shares representing limited partner interests ("Class B shares") in us, in exchange for aggregate consideration of approximately $ 3.2 billion in cash, which was paid to the Sellers (the "Blackstone Acquisition").

As a result of the Blackstone Acquisition, BIP effectively controls our business and affairs through the ownership of 100 % of the membership interests in our general partner and the exercise of the rights of such sole member. Additionally, the Sponsor Entities collectively held an approximate 44.2 % economic interest in us as of September 30, 2019 .

Take Private Proposal

On August 27, 2019, the board of directors of our general partner received a non-binding preliminary proposal letter from the Sponsor Entities to acquire all of our outstanding Class A shares not already owned by the Sponsor Entities for $ 19.50 per Class A share (the "Proposal"). The Proposal continues to be reviewed, evaluated and negotiated by members of an independent conflicts committee of the board of directors of our general partner.

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, 2019 and 2018 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of accounting principles generally accepted in the United States of America ("GAAP") for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three and nine months ended September 30, 2019 and 2018 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC.

Our financial results for the three and nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019 . The accompanying condensed consolidated interim financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2018 ("2018 Form 10-K") filed with the SEC on February 8, 2019.

The condensed consolidated financial statements include the accounts of TGE and its subsidiaries and controlled affiliates. Intra-entity items have been eliminated in the presentation. Net income or loss from consolidated subsidiaries that are not wholly-owned by TGE is attributed to TGE and noncontrolling interests in accordance with the respective ownership interests. We have no elements of other comprehensive income for the periods presented.

Use of Estimates

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

Income Taxes

During the nine months ended September 30, 2019 , we recognized an additional deferred tax asset of $ 123.1 million upon exercise of the Exchange Right, as discussed in Note 11 – Partnership Equity , with respect to 21,751,018 Class B shares to Class A shares in connection with the Blackstone Acquisition discussed in Note 1 – Description of Business .

As a result of the increased income allocated to TGE resulting from our increased ownership in TEP following the merger transaction effective June 30, 2018 and the exercise of the Exchange Right effective March 11, 2019, our annual effective tax rate increased from 9.02 % for the nine months ended September 30, 2018 to 14.79 % for the nine months ended September 30, 2019 .

As discussed in Note 3 – Acquisitions , a newly formed indirect subsidiary of TGE acquired the outstanding stock of an entity classified as a C corporation for U.S. federal income tax purposes effective May 1, 2019. As a result, we recognized approximately $ 237,000 of current income taxes during the three months ended September 30, 2019 .

Accounting Pronouncement Recently Adopted

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

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

Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2019. This approach allows us to (i) initially apply ASC 842 at the adoption date, January 1, 2019 and (ii) continue reporting comparative periods presented in the financial statements in the period of adoption under ASC 840. Accordingly, we will not recast comparative periods in the condensed consolidated financial statements. We have elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed us to carry forward the historical lease classification. We have also elected the following practical expedients: (a) the land easement practical expedient, allowing us to carry forward our accounting treatment for existing land easements as property, plant and equipment, (b) the practical expedient for short-term leases, allowing us to not recognize ROU assets or lease liabilities for leases with a term of 12 months or less, and (c) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease.

Excluding ROU assets and lease liabilities relating to agreements between consolidated subsidiaries, adoption of the new standard resulted in the recognition of ROU assets of approximately $ 2.3 million , and current and non-current lease liabilities of approximately $ 0.6 million and $ 1.7 million , respectively, for operating leases as of January 1, 2019. Our accounting for finance leases remained substantially unchanged. The adoption of this guidance had no impact to our cash flows from operating, investing, or financing activities. For additional information see Note 13 – Leases .

Accounting Pronouncements Not Yet Adopted

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

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments–Credit Losses (Topic 326). ASU 2016-13 amends current measurement techniques used to estimate credit losses for financial assets. The amendments in ASU 2016-13 are effective for financial statements issued for annual periods beginning after December 15, 2019, and interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact of ASU 2016-13 but do not anticipate a material impact on our consolidated financial statements.

3. Acquisitions

Acquisition of Central Environmental Services

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

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



	Preliminary			Adjustments			Final
	(in thousands)
Accounts receivable	$	1,391		$	—		$	1,391
Prepayments	67			—			67
Property, plant and equipment	6,900			4,400			11,300
Intangible asset	35,800			( 2,900		)	32,900			⁽¹⁾
Accounts payable and accrued liabilities	( 1,518		)	—			( 1,518		)	⁽²⁾
Deferred tax liability	( 8,557		)	( 189		)	( 8,746		)
Net identifiable assets acquired	34,083			1,311			35,394
Goodwill	17,734			( 1,311		)	16,423
Net assets acquired (excluding cash)	$	51,817		$	—		$	51,817


⁽¹⁾	The $ 32.9 million intangible asset acquired represents customer relationships and is amortized on a straight-line basis over a period of 8 years.


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

At June 30, 2019, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. During the three months ended September 30, 2019, the preliminary purchase price allocation was adjusted to reflect additional information obtained with respect to the property, plant and equipment acquired. The purchase price allocation was considered final as of September 30, 2019. The 7.65 % equity interest in BNN Eastern held by noncontrolling interests was recorded at its acquisition date fair value of $ 3.4 million . The fair value of the noncontrolling interests were determined using a discounted cash flow analysis and adjusted for lack of control. These fair value measurements are based on significant inputs, such as forecasted cash flows and discount rates, that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820. The goodwill recognized of $ 16.4 million is primarily attributed to synergies expected from combining the operations of TGE and CES. All the goodwill was assigned to our Gathering, Processing & Terminalling segment.

Actual revenue and net income attributable to TGE from CES of $ 2.4 million and $ 0.8 million , respectively, was recognized in the accompanying condensed consolidated statements of income for the three months ended September 30, 2019 . Actual revenue and net income attributable to TGE from CES of $ 4.5 million and $ 0.9 million , respectively, was recognized in the accompanying condensed consolidated statements of income for the period from May 1, 2019 to September 30, 2019 .

Pro Forma Financial Information

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Revenue	$	226,709	$	205,016	$	640,377	$	583,788
Net income attributable to TGE	$	72,524	$	60,641	$	195,565	$	78,695

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

Joint Venture with Silver Creek

In February 2018, we entered into an agreement with Silver Creek Midstream, LLC ("Silver Creek") to form Iron Horse Pipeline, LLC ("Iron Horse"), which owns the Iron Horse Pipeline. Effective January 1, 2019, the joint venture between us and Silver Creek was expanded through contributions to Powder River Gateway, a newly formed entity. We contributed our 75 % membership interest in Iron Horse with a carrying value of $ 35.6 million , $ 37 million in cash, and various other assets, including terminal facilities under construction in Guernsey, Wyoming, valued at $ 86.9 million . Silver Creek contributed the PRE Pipeline and related terminal facilities in Guernsey, Wyoming, as well as their 25 % membership interest in Iron Horse. Following the expansion of the joint venture, we own a 51 % membership interest in Powder River Gateway and continue to operate the joint venture, while Silver Creek owns a 49 % membership interest in Powder River Gateway. As Silver Creek retained certain participating rights with respect to Powder River Gateway, the 51 % membership interest does not represent a controlling interest in Powder River Gateway. Accordingly, our investment in Powder River Gateway is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the condensed consolidated balance sheets.

Consolidation of BNN Colorado Water

At December 31, 2018, the assets acquired and liabilities assumed as a result of the consolidation of BNN Colorado Water, LLC ("BNN Colorado") were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2019.

Acquisition of NGL Water Solutions Bakken

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

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



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

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

Acquisition of Plaquemines Liquids Terminal, LLC

In November 2018, we entered into a joint venture agreement with Drexel Hamilton Infrastructure Fund I, L.P. ("DHIF") to jointly own Plaquemines Liquids Terminal, LLC ("PLT"). PLT was formed with the intention of entering into agreements to develop a storage and terminalling facility. If developed, the facility is expected to be capable of offering up to 20 million barrels of storage for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers vessels for international delivery. In connection with our acquisition of a 100 % preferred membership interest and a 80 % common membership interest in PLT, we recognized liabilities related to DHIF's right to receive special distributions totaling $ 35 million , of which $ 25 million is included in "Other current liabilities" and the remaining $ 10 million is included in "Other long-term liabilities and deferred credits" in the condensed consolidated balance sheets. The special distributions are contingent upon PLT reaching certain milestones in the development and construction of the project facilities. Also in November 2018, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT expects to construct the facilities.

4. Related Party Transactions

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Processing and other revenues ⁽¹⁾	$	2,020	$	1,838	$	5,830	$	5,603
Cost of transportation services ⁽²⁾	$	210	$	—	$	730	$	—


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


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

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



	September 30, 2019		December 31, 2018
	(in thousands)
Receivable from related parties:
Rockies Express Pipeline LLC	$	2,900	$	3,447
Powder River Gateway, LLC	379		—
Pawnee Terminal, LLC	100		115
Iron Horse Pipeline, LLC	—		186
Total receivable from related parties	$	3,379	$	3,748

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



	September 30, 2019		December 31, 2018
	(in thousands)
Affiliate gas imbalance receivables	$	30	$	19
Affiliate gas imbalance payables	$	875	$	742

5. Inventory

The components of inventory at September 30, 2019 and December 31, 2018 consisted of the following:



	September 30, 2019		December 31, 2018
	(in thousands)
Crude oil	$	30,158	$	23,205
Materials and supplies	7,747		8,206
Gas in underground storage	2,650		2,740
Natural gas liquids	473		165
Total inventory	$	41,028	$	34,316

6. Property, Plant and Equipment

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



	September 30, 2019			December 31, 2018
	(in thousands)
Crude oil pipelines	$	1,365,353		$	1,313,976
Gathering, processing and terminalling assets	970,749			889,168
Natural gas pipelines	624,489			607,343
General and other ⁽¹⁾	172,708			180,299
Construction work in progress	188,320			191,994
Accumulated depreciation and amortization	( 456,512		)	( 380,351		)
Total property, plant and equipment, net	$	2,865,107		$	2,802,429


⁽¹⁾	Includes approximately $ 30.7 million of land associated with the PLT capital lease as discussed in Note 13 – Leases .

7. Investments in Unconsolidated Affiliates

Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our condensed consolidated balance sheets. During the nine months ended September 30, 2019 , we recognized equity in earnings associated with our 75 % membership interest in Rockies Express of $ 267.2 million , inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $ 361.2 million and $ 49.9 million , respectively.

Summarized financial information for Rockies Express is as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands)
Revenue	$	233,010	$	225,753	$	696,094	$	683,426
Operating income	$	130,908	$	127,119	$	397,629	$	385,831
Net income to Members	$	100,968	$	90,707	$	322,212	$	270,338

Rockies Express Senior Notes Offering

On April 12, 2019, Rockies Express and U.S. Bank, National Association, as trustee, entered into an Indenture pursuant to which Rockies Express issued $ 550 million in aggregate principal amount of 4.95 % senior notes due 2029. Substantially all of the net proceeds received by Rockies Express from the senior notes offering were used to repay Rockies Express' $ 525 million term loan facility.

8. Goodwill

Reconciliation of Goodwill

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



	Natural Gas Transportation		Gathering, Processing & Terminalling			Total
	(in thousands)
Balance at December 31, 2018	$	255,558	$	166,425		$	421,983
Goodwill acquired	—		16,423		⁽¹⁾	16,423
Other adjustments	—		2,955		⁽²⁾	2,955
Balance at September 30, 2019	$	255,558	$	185,803		$	441,361


⁽¹⁾	The $ 16.4 million of goodwill was recorded in connection with the acquisition of CES on May 1, 2019 as discussed further in Note 3 – Acquisitions .


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

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 according to the benefit received by the reporting unit at the date of acquisition. If we, after performing the qualitative assessment, determine it is "more likely than not" that the fair value of a reporting unit is greater than its carrying amount, then goodwill is not considered impaired. When goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the reporting unit's fair value, then the reporting unit should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.

We elected to apply the qualitative assessment option for one of our five reporting units during our 2019 annual goodwill impairment testing. In conducting the qualitative assessment we considered relevant factors and circumstances that affect the fair value or carrying amount of the reporting entity. Such factors included changes in discount rates, projected cash flows, macroeconomic considerations, industry and market considerations, overall financial performance, prior quantitative results, and entity and reporting unit specific events. For this reporting unit, the results of the qualitative assessment indicated that it was more likely than not that the fair value of the reporting units exceeds its book value. As such, we did not perform a quantitative impairment analysis, and we concluded that no impairment was indicated as of August 31, 2019.

For the remaining four reporting units, we did not elect to apply the qualitative assessment option and instead we proceeded directly to the quantitative impairment test. We compared the fair value of the reporting units with their respective book values, including goodwill, by using an income approach based on a discounted cash flow analysis. The fair value of the reporting units was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates, maintenance capital expenditures, and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For these reporting units, the results of the quantitative impairment test indicated no impairment as the fair value of each reporting unit was greater than its respective book value. As a result, in accordance with the Codification guidance, we did not record a goodwill impairment during the nine months ended September 30, 2019. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary.

Approximately $ 79.2 million of goodwill is allocated to the Midstream Facilities reporting unit, which is a component of our Gathering, Processing & Terminalling segment. As a result of current market conditions, certain producers from which the Midstream Facilities reporting unit receives natural gas for processing have recently indicated that they currently expect to deliver lower volumes than previously anticipated. The results of the Midstream Facilities reporting unit's impairment testing as of August 31, 2019 indicate that the fair value of the reporting unit exceeds the carrying value by approximately 17 % . As a result, no impairment charge was recorded, however our analysis includes assumptions of a gradual recovery of commodity prices and a corresponding increase in volumes over time. If our outlook is not realized, or our producers further decrease volumes, we may recognize an impairment in the future.

9. Risk Management

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

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

Fair Value of Derivative Contracts

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



	Balance Sheet Location	September 30, 2019		December 31, 2018
		(in thousands)
Crude oil derivative contracts	Prepayments and other current assets	$	4,015	$	3,526
Crude oil derivative contracts	Other current liabilities	$	454	$	1,642

As of September 30, 2019 , the amounts shown represent the fair value of crude oil derivative contracts for the forward purchase of 2,157,325 and the forward sale of 4,349,000 barrels of crude oil consisting of fixed price and floating price contracts, which will settle throughout 2019 and 2020. As of December 31, 2018 , the amounts shown represent the fair value of crude oil derivative contracts for the forward purchase of 2,105,146 and the forward sale of 1,274,500 barrels of crude oil consisting of fixed price and floating price contracts, which will settle throughout 2019.

Effect of Derivative Contracts in the Statements of Income

The following table summarizes the impact of derivative contracts not designated as hedging contracts for the three and nine months ended September 30, 2019 and 2018 :



	Location of gain recognized in income on derivatives	Amount of gain recognized in income on derivatives
		Three Months Ended September 30,				Nine Months Ended September 30,
		2019		2018		2019		2018
		(in thousands)
Crude oil derivative contracts	Sales of natural gas, NGLs, and crude oil	$	14,574	$	9,435	$	40,631	$	16,665

Credit Risk

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

Our derivative contracts are entered into with counterparties through central trading organizations such as futures, options or stock exchanges or counterparties outside of central trading organizations. While we typically enter into derivative transactions with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. The maximum potential exposure to credit losses on our crude oil derivative contracts at September 30, 2019 was:



	Asset Position
	(in thousands)
Gross	$	4,015
Netting agreement impact	—
Cash collateral held	—
Net exposure	$	4,015

As of September 30, 2019 , we had $ 0.5 million of cash in margin accounts in support of our commodity derivative contracts. As of December 31, 2018 , we did not have any cash in margin accounts in support of our commodity derivative contracts.

Fair Value

Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). OTC commodity derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy.

The following table summarizes the fair value measurements of our derivative contracts as of September 30, 2019 and December 31, 2018 , based on the fair value hierarchy:



			Asset Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of September 30, 2019:
Crude oil derivative contracts	$	4,015	$	—	$	4,015	$	—
As of December 31, 2018:
Crude oil derivative contracts	$	3,526	$	—	$	3,526	$	—
			Liability Fair Value Measurements Using
	Total		Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
	(in thousands)
As of September 30, 2019:
Crude oil derivative contracts	$	454	$	—	$	454	$	—
As of December 31, 2018:
Crude oil derivative contracts	$	1,642	$	—	$	1,642	$	—

10. Long-term Debt

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



	September 30, 2019			December 31, 2018
	(in thousands)
Revolving credit facility	$	1,467,000		$	1,224,000
4.75% senior notes due October 1, 2023	500,000			500,000
5.50% senior notes due September 15, 2024	750,000			750,000
5.50% senior notes due January 15, 2028	750,000			750,000
Less: Deferred financing costs, net ⁽¹⁾	( 18,848		)	( 21,421		)
Plus: Unamortized premium on 2028 Notes	3,116			3,379
Total long-term debt, net	$	3,451,268		$	3,205,958


⁽¹⁾	Deferred financing costs, net as presented above relate solely to the Senior Notes (as defined below). Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our condensed consolidated balance sheets.

Senior Unsecured Notes

On February 27, 2019, TEP and Tallgrass Energy Finance Corp. (together, the "Issuers"), together with the TEP subsidiary guarantors party thereto (the "Guarantors") and U.S. Bank National Association, as trustee (the "Trustee"), entered into supplemental indentures (the "Supplemental Indentures") to amend certain provisions of each of (i) the Indenture governing the 4.75 % senior notes due 2023 (the "2023 Notes"), dated as of September 26, 2018, among the Issuers, the Guarantors and Trustee, (ii) the Indenture governing the 5.50 % senior notes due 2024 (the "2024 Notes"), dated as of September 1, 2016, among the Issuers, the Guarantors and the Trustee, and (iii) the Indenture governing the 5.50 % senior notes due 2028 (the "2028 Notes"), dated as of September 15, 2017, among the Issuers, the Guarantors and the Trustee (collectively, the "Indentures"). The Supplemental Indentures (a) amended the defined term "Change of Control" in each Indenture to provide that the Blackstone Acquisition did not constitute a Change of Control under such Indenture, (b) changed the definition of "Qualifying Owners" in the applicable Indenture to provide that Blackstone Infrastructure Partners L.P., Vencap Holdings (1992) Pte. Ltd. and their respective affiliates, funds, holding companies and investment vehicles, among others, are Qualifying Owners under such Indenture, and (c) added to, amended, supplemented or changed certain other defined terms contained in each Indenture related to the foregoing.

The 2023 Notes, 2024 Notes, and 2028 Notes are together referred to as the "Senior Notes." As of September 30, 2019 , TEP was in compliance with the covenants required under the Indentures.

Revolving Credit Facility

The following table sets forth the available borrowing capacity under our revolving credit facility as of September 30, 2019 and December 31, 2018 :



	September 30, 2019			December 31, 2018
	(in thousands)
Total capacity under the revolving credit facility	$	2,250,000		$	2,250,000
Less: Outstanding borrowings under the revolving credit facility	( 1,467,000		)	( 1,224,000		)
Less: Letters of credit issued under the revolving credit facility	( 94		)	( 94		)
Available capacity under the revolving credit facility	$	782,906		$	1,025,906

On February 22, 2019, TEP and certain of its subsidiaries entered into a Consent and Amendment No. 2 to the Second Amended and Restated Credit Agreement (the "Consent and Amendment") with Wells Fargo Bank, National Association, as administrative agent, and the required lenders party thereto. The Consent and Amendment modified that certain Second Amended and Restated Credit Agreement dated as of June 2, 2017, as previously amended by that certain Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of July 26, 2018 (as amended, the "Credit Agreement"). The Credit Agreement governs our revolving credit facility.

In the Consent and Amendment, the required lenders under the Credit Agreement (i) consented to the Blackstone Acquisition pursuant to the terms and conditions of the Purchase Agreement, (ii) agreed that no Default (as defined in the Credit Agreement) under the Credit Agreement, if any, that may have resulted from a Change in Control (as defined in the Credit Agreement) caused by the consummation of the Blackstone Acquisition pursuant to the terms and conditions set forth in the Purchase Agreement will be deemed to have occurred, and (iii) agreed to modify the definition of "Permitted Holders" in Section 1.01 of the Credit Agreement (which is used in the definition of Change in Control) to reflect the change in ownership as a result of the Blackstone Acquisition.

As of September 30, 2019 , TEP was in compliance with the covenants required under its revolving credit facility. As of September 30, 2019 , the weighted average interest rate on outstanding borrowings under the revolving credit facility was 3.54 % . During the nine months ended September 30, 2019 , the weighted average effective interest rate under the revolving credit facility, including the interest on outstanding borrowings under the revolving credit facility, commitment fees, and amortization of deferred financing costs, was 4.35 % .

Fair Value

The following table sets forth the carrying amount and fair value of long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of September 30, 2019 and December 31, 2018 , but for which fair value is disclosed:



	Fair Value
	Quoted prices in active markets for identical assets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total		Carrying Amount
	(in thousands)
As of September 30, 2019:
Revolving credit facility	$	—	$	1,467,000	$	—	$	1,467,000	$	1,467,000
2023 Notes	$	—	$	502,135	$	—	$	502,135	$	495,466
2024 Notes	$	—	$	748,305	$	—	$	748,305	$	742,344
2028 Notes	$	—	$	735,998	$	—	$	735,998	$	746,458
As of December 31, 2018:
Revolving credit facility	$	—	$	1,224,000	$	—	$	1,224,000	$	1,224,000
2023 Notes	$	—	$	485,285	$	—	$	485,285	$	494,603
2024 Notes	$	—	$	737,745	$	—	$	737,745	$	741,196
2028 Notes	$	—	$	726,503	$	—	$	726,503	$	746,159

The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of September 30, 2019 and December 31, 2018 , the fair value of borrowings under the revolving credit facility approximates the carrying amount of the borrowings using a discounted cash flow analysis. The Senior Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the Senior Notes is based upon quoted market prices adjusted for illiquid markets. We are not aware of any factors that would significantly affect the estimated fair value subsequent to September 30, 2019 .

11. Partnership Equity

TGE Dividends to Holders of Class A Shares

The following table details the dividends for the periods indicated:



Three Months Ended	Date Paid	Dividends to Class A Shareholders		Dividends per Class A Share
		(in thousands, except per share amounts)
September 30, 2019	November 14, 2019 ⁽¹⁾	$	98,559	$	0.5500
June 30, 2019	August 14, 2019	96,767		0.5400
March 31, 2019	May 15, 2019	94,975		0.5300
December 31, 2018	February 14, 2019	81,304		0.5200
September 30, 2018	November 14, 2018	79,717		0.5100
June 30, 2018	August 14, 2018	77,052		0.4975
March 31, 2018	May 15, 2018	28,316		0.4875


⁽¹⁾	The dividend announced on October 10, 2019 for the third quarter of 2019 will be paid on November 14, 2019 to Class A shareholders of record at the close of business on October 31, 2019 .

Exchange Rights

Our current Class B shareholders (collectively, the "Exchange Right Holders") own an equal number of Tallgrass Equity units. The Exchange Right Holders, and any permitted transferees of their Tallgrass Equity units, each have the right to exchange all or a portion of their Tallgrass Equity units for Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us. Upon such exchange, we will cancel the Class B shares received from the exercising party. During the nine months ended September 30, 2019 , 21,751,018 Class A shares were issued and an equal number of Class B shares were cancelled as a result of the exercise of the Exchange Right.

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

Noncontrolling Interests

As of September 30, 2019 , noncontrolling interests in our subsidiaries consisted of a 36.30 % interest in Tallgrass Equity held by the Exchange Right Holders, as well as noncontrolling interests in certain subsidiaries held by unaffiliated third parties, including an approximate 40 % membership interest in Deeprock Development, LLC ("Deeprock Development"), an approximate 25 % membership interest in BNN West Texas, LLC ("BNN West Texas"), a 37 % membership interest in BNN Colorado, a 20 % common membership interest in PLT, and an approximate 8 % membership interest in BNN Eastern. During the nine months ended September 30, 2019 , we recognized contributions from and distributions to noncontrolling interests of $ 2.3 million and $ 178.9 million , respectively. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $ 173.7 million and distributions to Deeprock Development, BNN West Texas, and BNN Colorado noncontrolling interests of $ 5.2 million in the aggregate.

During the nine months ended September 30, 2018 , we recognized contributions from and made distributions to noncontrolling interests of $ 0.2 million and $ 262.9 million , respectively. 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 in the aggregate.

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;


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


•	TEP was deemed to have made a noncash capital distribution of $ 16.2 million , which represents the excess purchase price over the $ 33.8 million carrying value of the additional 2 % membership interest in Pony Express acquired as of February 1, 2018.

Share-Based Compensation

The Blackstone Acquisition discussed in Note 1 – Description of Business constituted a change in control event under certain Equity Participation Share agreements outstanding under the LTIP plan, resulting in the accelerated vesting of 1,092,637 Class A shares (net of tax withholding of approximately 543,909 Class A shares) with a weighted average grant date fair value of $ 18.82 . These Class A shares were issued in April 2019. The accelerated vesting resulted in the recognition of equity-based compensation costs of $ 12.5 million in "General and administrative" costs in the condensed consolidated statements of income during the nine months ended September 30, 2019 . In addition, 1,796,400 Equity Participation Shares with a weighted average grant date fair value of $ 15.19 were granted during the nine months ended September 30, 2019 .

12. Revenue from Contracts with Customers

Disaggregated Revenue

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



	Three Months Ended September 30, 2019
	Natural Gas Transportation segment		Crude Oil Transportation segment		Gathering, Processing, & Terminalling segment		Corporate and Other			Total Revenue
	(in thousands)
Crude oil transportation - committed shipper revenue	$	—	$	111,572	$	—	$	—		$	111,572
Natural gas transportation - firm service	30,066		—		—		( 490		)	29,576
Water business services	—		—		31,311		—			31,311
Natural gas gathering & processing fees	—		—		7,021		—			7,021
All other ⁽¹⁾	2,742		15,215		5,425		( 18,836		)	4,546
Total service revenue	32,808		126,787		43,757		( 19,326		)	184,026
Natural gas liquids sales	—		—		16,256		—			16,256
Natural gas sales	—		—		8,932		—			8,932
Crude oil sales	—		—		138		—			138
Total commodity sales revenue	—		—		25,326		—			25,326
Total revenue from contracts with customers	32,808		126,787		69,083		( 19,326		)	209,352
Other revenue ⁽²⁾	—		—		21,760		( 4,403		)	17,357
Total revenue ⁽³⁾	$	32,808	$	126,787	$	90,843	$	( 23,729	)	$	226,709



	Nine Months Ended September 30, 2019
	Natural Gas Transportation segment		Crude Oil Transportation segment		Gathering, Processing, & Terminalling segment		Corporate and Other			Total Revenue
	(in thousands)
Crude oil transportation - committed shipper revenue	$	—	$	306,288	$	—	$	—		$	306,288
Natural gas transportation - firm service	94,571		—		—		( 1,374		)	93,197
Water business services	—		—		80,896		—			80,896
Natural gas gathering & processing fees	—		—		18,431		—			18,431
All other ⁽¹⁾	8,831		45,723		12,689		( 54,584		)	12,659
Total service revenue	103,402		352,011		112,016		( 55,958		)	511,471
Natural gas liquids sales	—		—		46,303		—			46,303
Natural gas sales	119		—		24,441		—			24,560
Crude oil sales	—		4,730		384		—			5,114
Total commodity sales revenue	119		4,730		71,128		—			75,977
Total revenue from contracts with customers	103,521		356,741		183,144		( 55,958		)	587,448
Other revenue ⁽²⁾	—		—		62,495		( 14,358		)	48,137
Total revenue ⁽³⁾	$	103,521	$	356,741	$	245,639	$	( 70,316	)	$	635,585



	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



	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 terminal services, interruptible natural gas transportation and storage, and natural gas park and loan service.


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

⁽³⁾

Excludes revenue recognized at unconsolidated investments, including revenue recognized at Rockies Express of $ 233.0 million and $ 696.1 million for the three and nine months ended September 30, 2019 , respectively, and $ 225.8 million and $ 683.4 million 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

On September 30, 2019 , we had $ 1.4 billion of remaining performance obligations at our consolidated subsidiaries, which we refer to as total backlog. Total backlog includes performance obligations under long-term crude oil transportation contracts with committed shippers, natural gas firm transportation and firm storage contracts, and certain water business service contracts with minimum volume commitments, and excludes variable consideration that is not estimated at contract inception, as discussed further below. We expect to recognize the total backlog during the remainder of 2019 and future periods as follows (in thousands):



Year	Estimated Revenue
2019 – remaining	$	126,248
2020	407,639
2021	219,345
2022	213,821
2023	176,480
Thereafter	259,331
Total	$	1,402,864

Contract Estimates

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

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

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

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

Contract Balances

The timing of revenue recognition, billings, and cash collections may result in billed accounts receivable, unbilled receivables (contract assets), and deferred revenue (contract liabilities) on our condensed consolidated balance sheets. Revenue is generally billed and collected monthly based on services provided or commodity volumes sold.

In our Crude Oil Transportation segment, we recognize shipper deficiencies, or deferred revenue, for barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers' agreed upon destination point. These shipper deficiencies are charged at the committed tariff rate per barrel and recorded as a contract liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes remote.

We also recognize contract liabilities, in the form of deferred revenue, in the Gathering, Processing & Terminalling segment under certain water business services contracts subject to minimum volume commitments. We receive deficiency payments for volumes committed by the customer in a month but not physically delivered to the customer or received by us for disposal. These deficiencies are charged at the contracted rate per barrel and recorded as a contract liability until the barrels are received from the customer for disposal, or when the likelihood that the customer will utilize the deficiency balance becomes remote.

Contract balances at September 30, 2019 and December 31, 2018 were as follows:



	September 30, 2019		December 31, 2018
	(in thousands)
Accounts receivable from contracts with customers	$	83,712	$	80,935
Other accounts receivable ⁽¹⁾	159,202		151,414
Receivable from related parties	3,379		3,748
Accounts receivable, net	$	246,293	$	236,097

Deferred revenue from contracts with customers ⁽²⁾	$	125,198	$	111,095


⁽¹⁾	Other accounts receivable primarily consists of receivables under crude oil forward purchase and sale arrangements that are accounted for as derivatives under ASC 815.


⁽²⁾	Revenue recognized during the three and nine months ended September 30, 2019 that was included in the deferred revenue balance at the beginning of the period was $ 10.5 million and $ 17.0 million , respectively. This revenue primarily represented the utilization of shipper deficiencies at Pony Express.

13. Leases

We account for leases in accordance with ASC Topic 842, Leases, which we adopted on January 1, 2019, applying the modified retrospective transition approach as of the effective date of adoption. See Note 2 – Summary of Significant Accounting Policies for additional information regarding the impacts of adoption.

We enter into operating leases as lessee for certain office space and equipment. We also have a capital lease agreement to lease the land site on which PLT expects to construct storage and terminalling facilities. In November 2018, we entered into a joint venture agreement with DHIF to jointly own PLT, an entity formed with the intention of developing a storage and terminalling facility. At the same time, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT expects to construct the facilities.

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

Our leases have remaining terms of up to approximately 39 years . Certain of our lease agreements contain options to extend or early terminate the agreement. The lease term used to calculate the lease asset and liability at commencement includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. When determining whether it is reasonably certain that we will exercise an option at commencement, we consider various economic factors, including operating strategies, the nature, length, and underlying terms of the agreement, as well as the uncertainty of the condition of leased equipment at the end of the lease term. Based on these determinations, we generally determine that the exercise of renewal options would not be reasonably certain in determining the expected lease term.

For the three and nine months ended September 30, 2019 , operating lease cost was $ 0.5 million and $ 1.0 million , respectively. For the nine months ended September 30, 2019 , cash paid included in operating cash flows was $ 0.9 million . During these periods the existing finance lease did not have any lease payments or variable lease cost.

Supplemental information related to our existing leases as of September 30, 2019 was as follows:



	Balance Sheet Location	September 30, 2019
Operating Leases:		(in thousands, except lease term and discount rate)
Operating lease right-of-use assets	Deferred charges and other assets	$	11,673		⁽¹⁾
Current operating lease liabilities	Other current liabilities	$	1,239		⁽¹⁾
Non-current operating lease liabilities	Other long-term liabilities and deferred credits	$	10,496		⁽¹⁾

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

Weighted Average Remaining Lease Term:
Operating leases		15.6 years
Finance leases		39.2 years

Weighted Average Discount Rate:
Operating leases		5.88		%
Finance leases		7.01		%


⁽¹⁾	Includes right-of-use asset of approximately $ 9.0 million and current and non-current lease liabilities of $ 0.1 million and $ 8.9 million , respectively, related to Guernsey Terminal capacity that we lease from Powder River Gateway.


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

Maturities of lease liabilities as of September 30, 2019 were as follows:



Year	Operating Leases			Finance Leases ⁽¹⁾
	(in thousands)
2019 – remaining	$	481		$	449
2020	1,913			449
2021	1,315			449
2022	972			449
2023	895			449
Thereafter	13,385			17,770
Total lease payments	18,961			20,015
Less: discounting for present value and other adjustments	( 7,226		)	( 20,015		)
Present value of lease liabilities	$	11,735		$	—

⁽¹⁾

Future lease payments for finance leases consist of the annual payments under the PLT land site lease. At lease inception, the present value of the future lease payments exceeded the fair value of the leased property. As a result, the right of use asset and capital lease obligation were recorded at the $ 30.7 million fair value of land. On that date, PLT made a payment of $ 30.7 million , immediately relieving the capital lease obligation. As a result, PLT does not have an outstanding capital lease obligation or impute interest on the future minimum rental commitments and will recognize expense for the future lease payments in the period in which they are made.

Under various lease agreements, Tallgrass Midstream, LLC ("TMID"), as lessor, leases capacity on NGL pipelines that were constructed for third parties, and Deeprock Development, as lessor, leases capacity at certain of its storage facilities. Rental income for these arrangements was approximately $ 2.6 million and $ 7.3 million for the three and nine months ended September 30, 2019 , respectively, and was recorded as "Processing and other revenues" in the condensed consolidated statements of income. Under a lease agreement initially effective November 13, 2012, Tallgrass Interstate Gas Transmission, LLC ("TIGT"), as lessor, leases a portion of its office space to a third party. Rental income was approximately $ 0.1 million and $ 0.5 million for the three and nine months ended September 30, 2019 , respectively, and was recorded as "Other income, net" in the condensed consolidated statements of income.

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



Year	Total
	(in thousands)
2019 - remaining	$	2,374
2020	5,613
2021	3,773
2022	3,773
2023	3,773
Thereafter	7,353
Total	$	26,659

Information as of December 31, 2018 under historical lease accounting guidance:

At December 31, 2018 , our future minimum rental commitments under major, non-cancelable leases were as follows:



Year	Operating Leases		Capital Lease
	(in thousands)
2019	$	1,074	$	449
2020	922		449
2021	483		449
2022	240		449
2023	147		449
Thereafter	364		17,770
Total	$	3,230	$	20,015

14. Net Income per Class A Share

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

Diluted net income per Class A share is determined by dividing net income attributable to TGE by the weighted average number of outstanding diluted Class A shares during the period. For purposes of calculating diluted net income per Class A share, we considered the impact of possible future exercises of the Exchange Right by the Exchange Right Holders on both net income attributable to TGE and the diluted weighted average number of Class A shares outstanding. The Exchange Right Holders refers to the group of persons who collectively own all of TGE's outstanding Class B shares and an equivalent number of Tallgrass Equity units. The Exchange Right Holders are entitled to exercise the right to exchange their Tallgrass Equity units (together with an equivalent number of TGE Class B shares) for TGE Class A shares at an exchange ratio of one TGE Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. As of September 30, 2019 , the Exchange Right Holders primarily consist of certain of the Sponsor Entities and certain members of our management.

Pursuant to the TGE partnership agreement and the Tallgrass Equity limited liability company agreement, our capital structure and the capital structure of Tallgrass Equity will generally replicate one another in order to maintain the one-for-one exchange ratio between the Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other hand. As a result, the exchange of any Class B shares for Class A shares does not have a dilutive effect on basic net income per Class A share. However, for the three and nine months ended September 30, 2019 and 2018 , the assumed issuance of TGE Equity Participation Shares would have had a dilutive effect on basic net income per Class A share as shown in the table below.

The following table illustrates the calculation of net income per Class A share for the three and nine months ended September 30, 2019 and 2018 :



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
	(in thousands, except per unit amounts)
Basic Net Income per Class A Share
Net income attributable to TGE	$	72,524	$	59,550	$	194,730	$	77,348
Basic weighted average Class A Shares outstanding	179,197		155,001		173,322		91,183
Basic net income per Class A share	$	0.40	$	0.38	$	1.12	$	0.85
Diluted Net Income per Class A Share
Net income attributable to TGE	$	72,524	$	59,550	$	194,730	$	77,348
Incremental net income attributable to TGE including the effect of the assumed issuance of Equity Participation Shares	264		304		801		1,097
Net income attributable to TGE including incremental net income from assumed issuance of Equity Participation Shares	$	72,788	$	59,854	$	195,531	$	78,445
Basic weighted average Class A Shares outstanding	179,197		155,001		173,322		91,183
Equity Participation Shares equivalent shares	958		1,087		1,434		1,478
Diluted weighted average Class A Shares outstanding	180,155		156,088		174,756		92,661
Diluted net income per Class A Share	$	0.40	$	0.38	$	1.12	$	0.85

15. Regulatory Matters

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

Pony Express

Pony Express Local and Volume Incentive Rate Filing - FERC Docket No. IS20-3-000

On October 1, 2019, Pony Express filed with the FERC to establish three volume incentive programs that provide uncommitted shippers the ability to access lower rates depending on the volumes shipped. The establishment of the volume incentive programs caused a corresponding reduction in committed shipper rates from Guernsey, Wyoming to destinations in Kansas and Oklahoma. Pony Express proposed an effective date of November 1, 2019 for these changes.

Rockies Express

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

On March 2, 2018, Rockies Express submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub. Rockies Express filed this certificate application in conjunction with a concurrently filed certificate application by Cheyenne Connector, LLC ("Cheyenne Connector") for the Cheyenne Connector Pipeline Project further described below. The comment period for the Cheyenne Hub Enhancement Project closed on April 9, 2018. To date, various comments have been

filed by market participants and others regarding the proposed project. Rockies Express has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment. On September 20, 2019, the FERC issued an order approving the application. A notice to proceed with construction was issued on October 8, 2019.

Cheyenne Connector

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

On March 2, 2018, Cheyenne Connector, an indirect subsidiary of TGE, submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity to construct and operate a 70 -mile, 36 -inch pipeline to transport natural gas from multiple gas processing plants in Weld County, Colorado to Rockies Express' Cheyenne Hub. The comment period for the Cheyenne Connector Pipeline Project closed on April 9, 2018. To date, various comments have been filed by market participants and others regarding the proposed project. Cheyenne Connector has also responded to data requests from the FERC's relevant program offices. On October 11, 2018, the FERC issued a Notice of Schedule of Environmental Review setting December 18, 2018 as the date of issuance of the Environmental Assessment and March 18, 2019 as the deadline for decisions by other federal agencies on requests for authorizations for the proposed project. On December 18, 2018, the FERC issued the Environmental Assessment. On September 20, 2019, the FERC issued an order approving the application. A notice to proceed with construction was issued on October 8, 2019.

TIGT

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

On May 1, 2019, TIGT filed a contested pre-filing settlement that, consistent with Article II.B.1 of the 2016 rate case settlement approved in Docket No. RP16-137-000, satisfies TIGT's mandatory rate case filing requirement under Article II.B.1 of such settlement. The pre-filing settlement establishes, among other things, settlement rates reflecting an overall decrease to recourse rates, contract extensions for maximum recourse rate firm contracts through May 31, 2023, and a rate moratorium period through May 31, 2023. The settlement also requires that TIGT file a new NGA Section 4 general rate case on June 1, 2023, provided that TIGT has not preempted this mandatory filing requirement by filing on or before June 1, 2023 for approval of a new pre-filing settlement. TIGT has also requested that the FERC terminate the pending Form No. 501-G proceeding in Docket No. RP19-423-000 upon approval of the pre-filing settlement. On September 24, 2019, the FERC issued an order establishing settlement judge procedures to afford the parties an opportunity to resolve contested issues via settlement. On October 15, 2019, the party contesting the settlement notified the FERC that it no longer objects to the settlement, it has reached a mutually agreeable accommodation with TIGT, and settlement judge procedures are not required. Further action by the FERC on the settlement is pending.

Trailblazer

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

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

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 FERC also established a paper hearing to examine the extent to which Trailblazer is entitled to an income tax allowance. All remaining issues, including the proposed rate increases to Existing System Firm Transportation Service, were set for an administrative law judge hearing and accepted effective January 1, 2019, subject to refund. On December 31, 2018, Trailblazer filed a motion with FERC to move the suspended tariff records into effect as of January 1, 2019.

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

On February 21, 2019, the FERC issued an order following the paper hearing on the income tax allowance issue, making a preliminary finding that a double recovery appears to result from permitting an income tax allowance for the income tax liability attributable to certain private owners' ownership share in Trailblazer in addition to a discounted cash flow return on equity. The FERC also preliminarily found that no double recovery resulted from permitting an income tax allowance for the corporate income tax liability attributable to TGE's ownership share in Trailblazer in addition to a discounted cash flow return on equity. The FERC ordered that the income tax allowance be addressed at the administrative law judge hearing with the other remaining issues, and its initial findings may change based upon subsequent evidence and argument.

In March 2019, the Chief Administrative Law Judge terminated settlement judge procedures and established the procedural time standards for the administrative law judge hearing, with the hearing currently scheduled to begin in January 2020. On October 2, 2019, a settlement in principle was reached with all parties in the proceeding. The settlement in principle is subject to certification by the Presiding Administrative Law Judge and approval of the FERC.

16. 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, 2019 or December 31, 2018 .

Rockies Express

EM Energy Ohio, LLC

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

Ohio Public Utility Excise Tax

The Ohio Tax Commissioner has assessed Rockies Express a public utility excise tax on transactions concerning product that entered and exited Rockies Express within the state of Ohio. This tax applies to gross receipts from all business conducted within the state, but exempts all receipts derived wholly from interstate business. Rockies Express has disputed any obligation to pay Ohio's public utility excise tax, but has paid the taxes as assessed in order to preserve its right to appeal. The dispute is currently pending before the Ohio Supreme Court, with a final decision anticipated by early 2020. It is Rockies Express' position that the relevant statute exempts receipts derived wholly from interstate business from the public utility excise tax. The Ohio Supreme Court and the United States Supreme Court have both held that, once it enters an interstate pipeline, natural gas is moving in "interstate commerce" for the duration of its journey until it is delivered to a local distribution system.

As of September 30, 2019 , Rockies Express has paid public utility excise taxes to the state of Ohio totaling $ 7.1 million and has accrued an additional $ 7.1 million for amounts expected to be assessed for the period from May 1, 2018 through September 30, 2019 . While it is difficult to accurately predict how the Ohio Supreme Court will decide the case, Rockies Express is optimistic about the ultimate outcome and has recorded a $ 14.2 million asset representing the anticipated refund of the public utility excise taxes assessed.

Environmental, Health and Safety

We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We currently believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of $ 6.4 million and $ 7.4 million at September 30, 2019 and December 31, 2018 , respectively.

Rockies Express

Seneca Lateral

On January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations. The release required Rockies Express to shut off the flow through the segment until February 27, 2018, when temporary repairs were completed, allowing the segment to be placed back into service. Permanent repairs were completed in September 2018. Total cost of remediation was approximately $ 6.1 million , $ 5.1 million of which Rockies Express has recovered through insurance.

TMID and TIGT

Casper Plant, EPA Notice of Violation

In August 2011, the EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, TMID received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. TMID and TIGT entered into a Consent Agreement and Final Order to settle this matter with the EPA on February 21, 2019 and made an approximately $ 0.1 million penalty payment to the EPA.

Casper Gas Plant

On November 25, 2014, the WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. TMID and TIGT entered into a Consent Decree to settle this matter with the WDEQ on March 8, 2019 and made an approximately $ 0.1 million penalty payment to the WDEQ.

TMG

Archibald Booster Station

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

Irwin Booster Station

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

17. Reportable Segments

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

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

Crude Oil Transportation. The Crude Oil Transportation segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, and other nearby oil producing basins. The Crude Oil Transportation segment includes our 51 % membership interest in Powder River Gateway .

Gathering, Processing & Terminalling. The Gathering, Processing & Terminalling segment is engaged in the ownership and operation of natural gas gathering and processing facilities that produce NGLs and residue gas sold in local wholesale markets or delivered into pipelines for transportation to additional end markets; our crude oil terminal services; water business services provided primarily to the oil and gas exploration and production industry; the transportation of NGLs; and Stanchion. The Gathering, Processing & Terminalling segment includes our 51 % membership interest in Pawnee Terminal, LLC ("Pawnee Terminal").

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

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

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



	Three Months Ended September 30, 2019							Three Months Ended September 30, 2018
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Natural Gas Transportation	$	32,808	$	( 490	)	$	32,318	$	34,077	$	( 816	)	$	33,261
Crude Oil Transportation	126,787		( 14,415		)	112,372		116,250		( 13,579		)	102,671
Gathering, Processing & Terminalling	90,843		( 8,824		)	82,019		71,612		( 7,224		)	64,388
Corporate and Other	—		—			—		—		—			—
Total revenue	$	250,438	$	( 23,729	)	$	226,709	$	221,939	$	( 21,619	)	$	200,320



	Nine Months Ended September 30, 2019							Nine Months Ended September 30, 2018
Revenue:	Total Revenue		Inter- Segment			External Revenue		Total Revenue		Inter- Segment			External Revenue
	(in thousands)
Natural Gas Transportation	$	103,521	$	( 1,391	)	$	102,130	$	105,208	$	( 4,136	)	$	101,072
Crude Oil Transportation	356,741		( 44,774		)	311,967		319,008		( 26,323		)	292,685
Gathering, Processing & Terminalling	245,639		( 24,151		)	221,488		199,062		( 19,816		)	179,246
Corporate and Other	—		—			—		—		—			—
Total revenue	$	705,901	$	( 70,316	)	$	635,585	$	623,278	$	( 50,275	)	$	573,003



	Three Months Ended September 30, 2019									Three Months Ended September 30, 2018
Tallgrass Equity Adjusted EBITDA:	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA
	(in thousands)
Natural Gas Transportation	$	142,158		$	( 1,163	)	$	140,995		$	121,433		$	( 1,460	)	$	119,973
Crude Oil Transportation	88,202			( 4,527		)	83,675			87,567			( 5,008		)	82,559
Gathering, Processing & Terminalling	35,611			5,690			41,301			13,679			6,468			20,147
Corporate and Other	( 2,203		)	—			( 2,203		)	( 2,317		)	—			( 2,317		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investments ⁽¹⁾							86,349									76,268
Non-cash gain related to derivative instruments ⁽¹⁾							1,928									2,993
Gain on disposal of assets ⁽¹⁾							—									279
Less:
Interest expense, net ⁽¹⁾							( 41,630		)							( 34,019		)
Depreciation and amortization expense ⁽¹⁾							( 31,500		)							( 27,356		)
Distributions from unconsolidated investments ⁽¹⁾							( 129,122		)							( 100,720		)
Non-cash compensation expense ⁽¹⁾							( 2,951		)							( 2,767		)
Deficiency payments, net ⁽¹⁾							2,329									( 3,468		)
Loss on debt retirement							—									( 2,245		)
Income tax expense ⁽¹⁾							( 22,563		)							( 11,997		)
Net income attributable to Exchange Right Holders							( 54,084		)							( 57,780		)
Net income attributable to TGE							$	72,524								$	59,550



	Nine Months Ended September 30, 2019									Nine Months Ended September 30, 2018
Tallgrass Equity Adjusted EBITDA:	Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA			Total Adjusted EBITDA			Inter- Segment			External Adjusted EBITDA
	(in thousands)
Natural Gas Transportation	$	425,286		$	( 3,253	)	$	422,033		$	253,169		$	( 2,940	)	$	250,229
Crude Oil Transportation	258,900			( 17,681		)	241,219			150,943			( 3,857		)	147,086
Gathering, Processing & Terminalling	87,380			20,934			108,314			30,002			6,797			36,799
Corporate and Other	( 7,771		)	—			( 7,771		)	( 20,819		)	—			( 20,819		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investments ⁽¹⁾							273,883									153,235
Non-cash gain related to derivative instruments ⁽¹⁾							899									3,306
Gain on disposal of assets ⁽¹⁾							—									3,388
Less:
Interest expense, net ⁽¹⁾							( 121,941		)							( 57,208		)
Depreciation and amortization expense ⁽¹⁾							( 94,819		)							( 45,794		)
Distributions from unconsolidated investments ⁽¹⁾							( 369,690		)							( 198,019		)
Non-cash compensation expense ⁽¹⁾							( 23,521		)							( 4,738		)
Deficiency payments, net ⁽¹⁾							( 14,241		)							( 7,205		)
Loss on debt retirement							—									( 2,245		)
Income tax expense ⁽¹⁾							( 61,606		)							( 35,498		)
Net income attributable to Exchange Right Holders							( 158,029		)							( 145,169		)
Net income attributable to TGE							$	194,730								$	77,348


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



	Nine Months Ended September 30,
Capital Expenditures:	2019		2018
	(in thousands)
Natural Gas Transportation	$	75,478	$	96,290
Crude Oil Transportation	78,379		39,847
Gathering, Processing & Terminalling	66,411		125,866
Corporate and Other	5,194		3,070
Total capital expenditures	$	225,462	$	265,073



Assets:	September 30, 2019		December 31, 2018
	(in thousands)
Natural Gas Transportation	$	2,624,490	$	2,606,696
Crude Oil Transportation	1,758,450		1,423,740
Gathering, Processing & Terminalling	1,580,752		1,522,559
Corporate and Other	239,205		340,514
Total assets	$	6,202,897	$	5,893,509

18. Subsequent Events

Cheyenne Connector

On October 28, 2019, a subsidiary of DCP Midstream, LP ("DCP") exercised its option to purchase a 50 % membership interest in Cheyenne Connector, which is currently developing the Cheyenne Connector Pipeline Project as discussed in Note 15 – Regulatory Matters . The closing of DCP's option is expected in the fourth quarter of 2019, subject to certain closing conditions. Following the closing, we will own a 50 % membership interest and continue to operate the Cheyenne Connector joint venture.

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

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

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

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

Cautionary Statement Regarding Forward-Looking Statements

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

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


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


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


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


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


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


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


•	our ability to successfully implement our business plan;


•	changes in general economic conditions;


•	competitive conditions in our industry;


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


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


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


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


•	the price and availability of debt and equity financing;


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


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


•	competition from the same and alternative energy sources;


•	energy efficiency and technology trends;


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


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


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


•	interest rates;


•	labor relations;


•	changes in tax laws, regulations and status;


•	the effects of existing and future litigation; and


•	certain factors discussed elsewhere in this Quarterly Report.

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

Overview

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

Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity in which we directly own an approximate 63.70% membership interest as of October 30, 2019 . We are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations.

Our reportable business segments are:


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


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


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

Recent Developments

TGE Dividend Announced

On October 10, 2019 , the Board of Directors of our general partner declared a cash dividend for the quarter ended September 30, 2019 of $0.5500 per Class A share. The distribution will be paid on November 14, 2019 , to Class A shareholders of record on October 31, 2019 .

Cheyenne Connector

On October 28, 2019, a subsidiary of DCP Midstream, LP ("DCP") exercised its option to purchase a 50% membership interest in Cheyenne Connector, which is currently developing the Cheyenne Connector Pipeline Project as discussed in Note 15 – Regulatory Matters . The closing of DCP's option is expected in the fourth quarter of 2019, subject to certain closing conditions. Following the closing, we will own a 50% membership interest and continue to operate the Cheyenne Connector joint venture.

How We Evaluate Our Operations

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

Contract Profile and Volumes

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

Operating Costs and Expenses

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

Adjusted EBITDA and Cash Available for Dividends

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


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


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


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


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

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

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

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

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands)
Reconciliation of Tallgrass Equity Adjusted EBITDA to Net income attributable to TGE
Net income attributable to TGE	$	72,524		$	59,550		$	194,730		$	77,348
Add:
Interest expense, net ⁽¹⁾	41,630			34,019			121,941			57,208
Depreciation and amortization expense ⁽¹⁾	31,500			27,356			94,819			45,794
Distributions from unconsolidated investments ⁽¹⁾	129,122			100,720			369,690			198,019
Non-cash compensation expense ⁽¹⁾⁽²⁾	2,951			2,767			23,521			4,738
Income tax expense ⁽¹⁾	22,563			11,997			61,606			35,498
Net income attributable to Exchange Right Holders	54,084			57,780			158,029			145,169
Loss on extinguishment of debt ⁽¹⁾	—			2,245			—			2,245
Less:
Equity in earnings of unconsolidated investments ⁽¹⁾	(86,349		)	(76,268		)	(273,883		)	(153,235		)
Deficiency payments, net ⁽¹⁾	(2,329		)	3,468			14,241			7,205
Non-cash gain related to derivative instruments ⁽¹⁾	(1,928		)	(2,993		)	(899		)	(3,306		)
Gain on disposal of assets ⁽¹⁾	—			(279		)	—			(3,388		)
Tallgrass Equity Adjusted EBITDA	$	263,768		$	220,362		$	763,795		$	413,295
Reconciliation of Tallgrass Equity Adjusted EBITDA and Cash Available for Dividends to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	187,794		$	135,131		$	518,208		$	466,391
Add:
Interest expense, net ⁽¹⁾	41,630			34,019			121,941			57,208
Other, including changes in operating working capital ⁽¹⁾	34,344			51,212			123,646			(110,304		)
Tallgrass Equity Adjusted EBITDA	$	263,768		$	220,362		$	763,795		$	413,295
Less:
Cash interest cost ⁽¹⁾	(40,065		)	(32,728		)	(117,264		)	(54,909		)
Maintenance capital expenditures, net ⁽¹⁾	(13,017		)	(4,638		)	(30,410		)	(8,409		)
Current income tax expense ⁽¹⁾	(170		)	—			(219		)	—
Tallgrass Equity Cash Available for Dividends	$	210,516		$	182,996		$	615,902		$	349,977


⁽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 .

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,
	2019			2018			2019			2018
	(in thousands)
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Natural Gas Transportation Segment ⁽¹⁾
Operating income	$	13,674		$	17,372		$	50,580		$	53,638
Add:
Depreciation and amortization expense ⁽²⁾	5,004			4,861			14,911			8,199
Distributions from unconsolidated investment ⁽²⁾	126,124			98,503			361,221			194,907
Less:
Other, net ⁽²⁾	(2,644		)	697			(1,426		)	1,744
Adjusted EBITDA attributable to noncontrolling interests	—			—			—			(5,319		)
Tallgrass Equity Segment Adjusted EBITDA	$	142,158		$	121,433		$	425,286		$	253,169
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Crude Oil Transportation Segment ⁽¹⁾
Operating income	$	74,428		$	69,295		$	204,828		$	181,536
Add:
Depreciation and amortization expense ⁽²⁾	13,997			13,627			41,440			22,928
Distributions from unconsolidated investment	1,328			—			3,439			—
Less:
Deficiency payments, net ⁽²⁾	(1,551		)	4,645			9,193			6,893
Adjusted EBITDA attributable to noncontrolling interests	—			—			—			(60,414		)
Tallgrass Equity Segment Adjusted EBITDA	$	88,202		$	87,567		$	258,900		$	150,943
Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Gathering, Processing & Terminalling Segment ⁽¹⁾
Operating income	$	23,703		$	9,680		$	44,309		$	38,707
Add:
Depreciation and amortization expense ⁽²⁾	11,714			7,688			35,969			12,836
Distributions from unconsolidated investments ⁽²⁾	1,670			2,217			5,030			3,112
Deficiency payments, net ⁽²⁾	2,103			(1,566		)	7,150			(343		)
Other, net ⁽²⁾	239			314			175			314
Less:
Non-cash gain related to derivative instruments ⁽²⁾	(1,928		)	(2,993		)	(899		)	(3,306		)
Adjusted EBITDA attributable to noncontrolling interests	(1,890		)	(1,382		)	(4,354		)	(17,930		)
Gain on disposal of assets ⁽²⁾	—			(279		)	—			(3,388		)
Tallgrass Equity Segment Adjusted EBITDA	$	35,611		$	13,679		$	87,380		$	30,002
Total Tallgrass Equity Segment Adjusted EBITDA	$	265,971		$	222,679		$	771,566		$	434,114
Corporate general and administrative costs	(2,203		)	(2,317		)	(7,771		)	(20,819		)
Total Tallgrass Equity Adjusted EBITDA	$	263,768		$	220,362		$	763,795		$	413,295


⁽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 17 – Reportable Segments .


⁽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 average daily operating metrics for the periods indicated:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018
Natural Gas Transportation Segment:
TIGT and Trailblazer average firm contracted volumes (MMcf/d) ⁽¹⁾	1,809	1,519	1,835	1,640
Rockies Express average firm contracted volumes (MMcf/d) ⁽²⁾	4,154	4,099	4,184	4,102
Crude Oil Transportation Segment:
Pony Express average contracted capacity (Bbls/d)	310,172	308,580	310,234	306,382
Pony Express average throughput (Bbls/d)	365,342	340,283	349,660	326,266
Gathering, Processing & Terminalling Segment:
Natural gas processing inlet volumes (MMcf/d)	130	128	115	121
Freshwater average volumes (Bbls/d)	90,100	—	69,789	23,398
Produced water gathering and disposal average volumes (Bbls/d)	203,254	94,445	184,550	90,293


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


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

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,
	2019			2018			2019			2018
	(in thousands)
Revenues:
Crude oil transportation services	$	112,126		$	100,226		$	306,738		$	286,130
Natural gas transportation services	30,312			30,953			96,173			94,623
Sales of natural gas, NGLs, and crude oil	39,902			44,072			116,609			119,467
Processing and other revenues	44,369			25,069			116,065			72,783
Total Revenues	226,709			200,320			635,585			573,003
Operating Costs and Expenses:
Cost of sales	17,664			28,556			56,217			82,601
Cost of transportation services	19,103			12,588			53,929			35,672
Operations and maintenance	22,657			18,011			64,175			52,850
Depreciation and amortization	31,797			27,595			95,778			81,408
General and administrative	21,439			16,015			72,426			53,526
Taxes, other than income taxes	8,183			7,750			26,892			25,091
(Gain) loss on disposal of assets	—			(279		)	242			(9,417		)
Total Operating Costs and Expenses	120,843			110,236			369,659			321,731
Operating Income	105,866			90,084			265,926			251,272
Other Income (Expense):
Equity in earnings of unconsolidated investments	86,349			76,268			273,883			222,857
Interest expense, net	(41,625		)	(34,019		)	(121,925		)	(95,062		)
Other income (expense), net	476			(1,624		)	851			(843		)
Total Other Income (Expense)	45,200			40,625			152,809			126,952
Net income before tax	151,066			130,709			418,735			378,224
Income tax expense	(22,577		)	(11,997		)	(61,624		)	(35,498		)
Net income	128,489			118,712			357,111			342,726
Net income attributable to noncontrolling interests	(55,965		)	(59,162		)	(162,381		)	(265,378		)
Net income attributable to TGE	$	72,524		$	59,550		$	194,730		$	77,348

Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018

Revenues. Total revenues were $226.7 million for the three months ended September 30, 2019 , compared to $200.3 million for the three months ended September 30, 2018 , which represents an increase of $26.4 million , or 13% , in total revenues. The overall increase was largely driven by increased revenues of $19.2 million and $10.5 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by a $2.1 million increase in eliminations of intersegment revenue and decreased revenues of $1.3 million in the Natural Gas Transportation segment, as discussed further below.

Operating costs and expenses . Operating costs and expenses were $120.8 million for the three months ended September 30, 2019 compared to $110.2 million for the three months ended September 30, 2018 , which represents an increase of $10.6 million , or 10% . The overall increase in operating costs and expenses is driven by increased operating costs and expenses of $5.4 million , $5.2 million , and $2.4 million in the Crude Oil Transportation, Gathering, Processing & Terminalling and Natural Gas Transportation segments, respectively, partially offset by decreased operating costs and expenses of $2.4 million in the Corporate and Other segment, as discussed further below. The decrease in Corporate and Other expenses was primarily driven by a $2.1 million increase in eliminations of intersegment operating costs and expenses.

Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $86.3 million and $76.3 million for the three months ended September 30, 2019 and 2018 , respectively. Equity in earnings of unconsolidated investments of $86.3 million for the three months ended September 30, 2019 primarily reflects our portion of earnings and the $8.5 million of amortization of a negative basis difference associated with our aggregate 75% membership interest in Rockies Express, as well as equity in earnings related to our 51% membership interests in Pawnee Terminal and Powder River Gateway of $1.6 million and $0.6 million , respectively. Equity in earnings of unconsolidated investments of $76.3 million for the 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, as well as $1.4 million of equity in earnings related to our 51% membership interest in Pawnee Terminal. The overall increase was primarily driven by a $7.2 million increase in equity in earnings from Rockies Express primarily due to increased west-end and east-end incremental revenue and lower interest expense due to the refinancing of Rockies Express' $525 million of 6.00% senior notes due January 15, 2019.

Interest expense, net. Interest expense of $41.6 million for the three months ended September 30, 2019 was primarily composed of interest and fees associated with the TEP revolving credit facility and Senior Notes. 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 2024 Notes and 2028 Notes. The increase in interest and fees is primarily due to increased borrowings to fund a portion of our 2018 and 2019 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 income, net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income for the three months ended September 30, 2019 was $0.5 million . 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 an amendment to the TEP revolving credit facility and the termination of the Tallgrass Equity revolving credit facility.

Income tax expense. Income tax expense for the three months ended September 30, 2019 was $22.6 million , compared to income tax expense of $12.0 million for the three months ended September 30, 2018 . The increase in income tax expense was primarily due to the exercise of the Exchange Right effective March 11, 2019 and the resulting increase in income allocated to TGE.

Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018

Revenues. Total revenues were $635.6 million for the nine months ended September 30, 2019 , compared to $573.0 million for the nine months ended September 30, 2018 , which represents an increase of $62.6 million , or 11% , in total revenues. The overall increase in revenue was largely driven by increased revenues of $46.6 million and $37.7 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by a $20.0 million increase in eliminations of intersegment revenue and decreased revenues of $1.7 million in the Natural Gas Transportation segment, as discussed further below.

Operating costs and expenses . Operating costs and expenses were $369.7 million for the nine months ended September 30, 2019 compared to $321.7 million for the nine months ended September 30, 2018 , which represents an increase of $47.9 million , or 15% . The overall increase in operating costs and expenses is driven by increased operating costs and expenses of $41.0 million , $14.4 million , and $1.4 million in the Gathering, Processing & Terminalling, Crude Oil Transportation, and Natural Gas Transportation segments, respectively, partially offset by decreased operating costs and expenses of $8.9 million in the Corporate and Other segment, as discussed further below. The decrease in Corporate and Other expenses was primarily driven by a $20.0 million increase in eliminations of intersegment operating costs and expenses, partially offset by a $11.7 million increase in corporate general and administrative costs due to an increase in equity-based compensation costs related to the accelerated vesting of certain Equity Participation Shares as a result of the change in control triggered by the Blackstone Acquisition.

Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was $273.9 million and $222.9 million for the nine months ended September 30, 2019 and 2018 , respectively. Equity in earnings of unconsolidated investments of $273.9 million for the nine months ended September 30, 2019 primarily reflects our portion of earnings and the $25.5 million of amortization of a negative basis difference associated with our aggregate 75% membership interest in Rockies Express, as well as equity in earnings related to our 51% membership interests in Pawnee Terminal and Powder River Gateway of $4.4 million and $2.3 million , respectively. Equity in earnings of unconsolidated investments of $222.9 million for the 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 75% membership interest in Rockies Express, inclusive of Tallgrass Equity's 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 Terminal. The overall increase was primarily driven by a $46.8 million increase in equity in earnings from Rockies Express as a result of lower interest expense due to the repayment of Rockies Express' $550 million

of 6.85% senior notes due July 15, 2018 and the refinancing of Rockies Express' $525 million of 6.00% senior notes due January 15, 2019, the additional 25.01% membership interest acquired in February 2018, the proceeds from the contract termination discussed in Note 16 – Legal and Environmental Matters , as well as increased east-end incremental revenue.

Interest expense, net. Interest expense of $121.9 million for the nine months ended September 30, 2019 was primarily composed of interest and fees associated with the TEP revolving credit facility and Senior Notes. 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 2024 Notes and 2028 Notes. The increase in interest and fees is primarily due to increased borrowings to fund a portion of our 2018 and 2019 acquisitions and a special contribution to Rockies Express to fund our pro rata portion of the repayment of Rockies Express' $550 million of 6.85% senior notes due July 15, 2018, as well as the higher borrowing rate on the 2023 Notes, the proceeds of which were used to repay borrowings under the revolving credit facility.

Other income, net. Other income, net typically includes rental income and income earned from certain customers related to the capital costs we incurred to connect these customers to our system. Other income for the nine months ended September 30, 2019 was $0.9 million . 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.

Income tax expense. Income tax expense for the nine months ended September 30, 2019 was $61.6 million , compared to income tax expense of $35.5 million for the nine months ended September 30, 2018 . The increase in income tax expense was primarily due to our increased ownership in TEP effective June 30, 2018 as a result of the merger transaction with TEP and the exercise of the Exchange Right effective March 11, 2019 and the resulting increase in income allocated to TGE.

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



Segment Financial Data – Natural Gas Transportation ⁽¹⁾	Three Months Ended September 30,				Nine Months Ended September 30,
Segment Financial Data – Natural Gas Transportation ⁽¹⁾	2019		2018		2019		2018
	(in thousands)
Revenues:
Natural gas transportation services	$	30,802	$	31,769	$	97,564	$	98,759
Sales of natural gas, NGLs, and crude oil	—		457		119		802
Processing and other revenues	2,006		1,851		5,838		5,647
Total revenues	32,808		34,077		103,521		105,208
Operating costs and expenses:
Cost of sales	56		439		897		870
Cost of transportation services	1,036		845		1,368		1,799
Operations and maintenance	7,367		6,362		20,388		19,849
Depreciation and amortization	5,004		4,861		14,911		14,539
General and administrative	4,377		3,248		11,638		11,139
Taxes, other than income taxes	1,294		950		3,739		3,374
Total operating costs and expenses	19,134		16,705		52,941		51,570
Operating income	$	13,674	$	17,372	$	50,580	$	53,638


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 17 – Reportable Segments .

Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018

Revenues. Natural Gas Transportation segment revenues were $32.8 million for the three months ended September 30, 2019 , compared to $34.1 million for the three months ended September 30, 2018 , which represents a decrease of $1.3 million , or 4% , in segment revenues driven by a $1.0 million decrease in natural gas transportation services primarily due to an overall decrease to recourse rates at TIGT as a result of the pre-filing rate case settlement as discussed further in Note 15 – Regulatory Matters .

Operating costs and expenses . Operating costs and expenses in the Natural Gas Transportation segment were $19.1 million for the three months ended September 30, 2019 , compared to $16.7 million for the three months ended September 30, 2018 , which represents an increase of $2.4 million , or 15% . The overall increase in operating costs and expenses was primarily due to a $1.1 million increase in general and administrative costs and a $1.0 million increase in operations and maintenance costs driven by increased pipeline integrity work.

Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018

Revenues. Natural Gas Transportation segment revenues were $103.5 million for the nine months ended September 30, 2019 , compared to $105.2 million for the nine months ended September 30, 2018 , which represents a decrease of $1.7 million , or 2% , in segment revenues driven by a $1.2 million decrease in natural gas transportation services primarily due to an overall decrease to recourse rates at TIGT as a result of the pre-filing rate case settlement as discussed further in Note 15 – Regulatory Matters .

Operating costs and expenses . Operating costs and expenses in the Natural Gas Transportation segment were $52.9 million for the nine months ended September 30, 2019 , compared to $51.6 million for the nine months ended September 30, 2018 , which represents an increase of $1.4 million , or 3% . The overall increase in operating costs and expenses was primarily due to a $0.5 million increase in operations and maintenance costs driven by increased pipeline integrity work and a $0.5 million increase in general and administrative costs.

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,
Segment Financial Data – Crude Oil Transportation ⁽¹⁾	2019		2018		2019		2018
	(in thousands)
Revenues:
Crude oil transportation services	$	126,541	$	113,805	$	351,512	$	312,453
Sales of natural gas, NGLs, and crude oil	—		2,314		4,730		6,289
Processing and other revenues	246		131		499		266
Total revenues	126,787		116,250		356,741		319,008
Operating costs and expenses:
Cost of sales	615		2,127		5,224		6,122
Cost of transportation services	20,587		17,374		57,117		49,408
Operations and maintenance	4,190		3,453		11,034		9,333
Depreciation and amortization	13,997		13,628		41,440		40,587
General and administrative	6,598		4,610		16,528		13,422
Taxes, other than income taxes	6,372		5,763		20,570		18,600
Total operating costs and expenses	52,359		46,955		151,913		137,472
Operating income	$	74,428	$	69,295	$	204,828	$	181,536


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 17 – Reportable Segments .

Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018

Revenues. Crude Oil Transportation segment revenues were $126.8 million for the three months ended September 30, 2019 , compared to $116.3 million for the three months ended September 30, 2018 , which represents an increase of $10.5 million , or 9% , in segment revenues driven by a $12.7 million increase in crude oil transportation services and a $2.3 million decrease in sales of crude oil. The increase in crude oil transportation services revenue was primarily driven by a $9.8 million increase in committed shipper revenue and a $1.6 million increase in walk-up shipper revenue as a result of increased throughput volumes and the FERC annual index adjustments effective July 1, 2019.

Operating costs and expenses . Operating costs and expenses in the Crude Oil Transportation segment were $52.4 million for the three months ended September 30, 2019 compared to $47.0 million for the three months ended September 30, 2018 , which represents an increase of $5.4 million , or 12% . The overall increase in operating costs and expenses was primarily driven by a $3.2 million increase in cost of transportation services driven by higher throughput volumes during the three months ended September 30, 2019 compared to the three months ended September 30, 2018 resulting in higher costs for drag reducing agents and pump station electrical costs, as well as higher lease payments, and a $2.0 million increase in general and administrative costs, primarily due to insurance and labor costs.

Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018

Revenues. Crude Oil Transportation segment revenues were $356.7 million for the nine months ended September 30, 2019 , compared to $319.0 million for the nine months ended September 30, 2018 , which represents an increase of $37.7 million , or 12% , in segment revenues driven by a $39.1 million increase in crude oil transportation services, partially offset by a $1.6 million decrease in sales of crude oil due to decreased volumes sold and lower crude oil prices during the nine months ended September 30, 2019 . The increase in crude oil transportation services revenue was primarily driven by a $20.2 million increase in committed shipper revenues and a $18.5 million increase in walk-up shipper revenue as a result of increased throughput volumes and the FERC annual index adjustments effective July 1, 2018 and 2019.

Operating costs and expenses . Operating costs and expenses in the Crude Oil Transportation segment were $151.9 million for the nine months ended September 30, 2019 compared to $137.5 million for the nine months ended September 30, 2018 , which represents an increase of $14.4 million , or 11% . The overall increase in operating costs and expenses was primarily driven by a $7.7 million increase in cost of transportation services driven by higher throughput volumes during the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 resulting in higher costs for drag reducing agents and pump station electrical costs, as well as higher lease payments, a $3.1 million increase in general and administrative costs driven by an increase in insurance and labor costs, and a $2.0 million increase in taxes, other than income taxes driven by an increase in property tax assessment estimates.

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,
	2019		2018			2019		2018
	(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil	$	39,902	$	41,301		$	111,760	$	112,376
Processing and other revenues	50,941		30,311			133,879		86,686
Total revenues	90,843		71,612			245,639		199,062
Operating costs and expenses:
Cost of sales	17,091		26,103			50,404		76,367
Cost of transportation services	21,111		15,875			65,452		33,982
Operations and maintenance	11,100		8,196			32,753		23,668
Depreciation and amortization	12,011		7,926			36,928		23,290
General and administrative	5,310		3,074			12,968		9,348
Taxes, other than income taxes	517		1,037			2,583		3,117
(Gain) loss on disposal of assets	—		(279		)	242		(9,417		)
Total operating costs and expenses	67,140		61,932			201,330		160,355
Operating income	$	23,703	$	9,680		$	44,309	$	38,707


⁽¹⁾	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 17 – Reportable Segments .

Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2018

Revenues. Gathering, Processing & Terminalling segment revenues were $90.8 million for the three months ended September 30, 2019 , compared to $71.6 million for the three months ended September 30, 2018 , which represents a $19.2 million , or 27% , increase in segment revenues. The increase in segment revenues was due to a $20.6 million increase in processing and other revenues, partially offset by a $1.4 million decrease in sales of natural gas, NGLs, and crude oil. The increase in processing and other revenues was driven by (i) increased water business services revenue of $18.5 million driven by the consolidation of BNN Colorado in December 2018, the acquisitions of NGL Water Solutions Bakken in November 2018 and CES in May 2019, and increased produced water disposal and fresh water transportation volumes and (ii) increased terminal services revenue of $1.5 million driven by the Buckingham Terminal expansion, the Grasslands Terminal placed into service in August 2019, and increased throughput on the Pony Express System. The decrease in sales of natural gas, NGLs, and crude oil was driven by decreased sales of NGLs of $9.9 million , primarily due to lower NGL prices partially offset by higher volumes sold, partially offset by increased crude oil sales of $5.1 million at Stanchion and increased sales of natural gas of $3.4 million due to sales of residue gas from the Douglas Gathering System.

Operating costs and expenses . Operating costs and expenses in the Gathering, Processing & Terminalling segment were $67.1 million for the three months ended September 30, 2019 compared to $61.9 million for the three months ended September 30, 2018 , which represents an increase of $5.2 million , or 8% . The increase in operating costs and expenses was primarily driven by (i) an increase of $5.2 million in the cost of transportation services due to increased freshwater and water gathering and disposal volumes at Water Solutions and crude oil transportation fees and (ii) increases of $4.1 million , $2.9 million , and $2.2 million in depreciation and amortization, operations and maintenance, and general and administrative costs, respectively, each primarily due to acquisitions and assets placed into service in 2018 and 2019 at Water Solutions and Terminals. These increases were partially offset by a $9.0 million decrease in cost of sales primarily due to lower NGL prices, partially offset by higher volumes as discussed above.

Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018

Revenues. Gathering, Processing & Terminalling segment revenues were $245.6 million for the nine months ended September 30, 2019 , compared to $199.1 million for the nine months ended September 30, 2018 , which represents a $46.6 million , or 23% , increase in segment revenues. The increase in segment revenues was due to a $47.2 million increase in processing and other revenues, partially offset by a $0.6 million decrease in sales of natural gas, NGLs, and crude oil. The increase in processing and other revenues was driven by (i) increased water business services revenue of $42.6 million driven by the consolidation of BNN Colorado in December 2018, the acquisitions of NGL Water Solutions Bakken in November 2018 and CES in May 2019, and increased produced water disposal and fresh water transportation volumes and (ii) increased terminal services revenue of $3.8 million driven by the Buckingham Terminal expansion, the Natoma Terminal placed into service in April 2018, the Grasslands Terminal placed into service in August 2019, and increased throughput on the Pony Express System. The decrease in sales of natural gas, NGLs, and crude oil was driven by decreased sales of NGLs of $31.0 million , primarily due to lower NGL prices partially offset by higher volumes sold, partially offset by increased crude oil sales of $24.0 million at Stanchion and increased sales of natural gas of $6.5 million due to sales of residue gas from the Douglas Gathering System.

Operating costs and expenses . Operating costs and expenses in the Gathering, Processing & Terminalling segment were $201.3 million for the nine months ended September 30, 2019 compared to $160.4 million for the nine months ended September 30, 2018 , which represents an increase of $41.0 million , or 26% . The increase in operating costs and expenses was primarily driven by (i) an increase of $31.5 million in the cost of transportation services due to crude oil transportation fees and increased freshwater and water gathering and disposal volumes at Water Solutions, (ii) increases of $13.6 million , $9.1 million , and $3.6 million in depreciation and amortization, operations and maintenance, and general and administrative costs, respectively, each primarily due to acquisitions and assets placed into service in 2018 and 2019 at Water Solutions and Terminals, and (iii) $0.2 million loss on the disposal of assets during the nine months ended September 30, 2019 , compared to the $9.4 million gain on disposal of assets on the disposal of Tallgrass Crude Gathering, LLC ("Tallgrass Crude Gathering") during the nine months ended September 30, 2018 . These increases were partially offset by a $26.0 million decrease in cost of sales driven by lower NGL prices, partially offset by higher volumes processed and higher sales of residue gas from the Douglas Gathering System.

Liquidity and Capital Resources Overview

Our primary sources of liquidity for the three months ended September 30, 2019 were cash generated from operations and borrowings under our revolving credit facility. We expect our sources of liquidity in the future to include:


•	cash generated from our operations;


•	borrowing capacity available under our revolving credit facility; and


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

We believe that cash on hand, cash generated from operations, and availability under our revolving credit facility will be adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements, and our planned cash dividends to shareholders. We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of cash generated from operations, borrowings under our revolving credit facility and issuances of debt and/or equity securities. For additional information regarding our revolving credit facility 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, 2019 and December 31, 2018 was as follows:



	September 30, 2019			December 31, 2018
	(in thousands)
Cash on hand ⁽¹⁾	$	15,967		$	9,596
Total capacity under the revolving credit facility	2,250,000			2,250,000
Less: Outstanding borrowings under the revolving credit facility	(1,467,000		)	(1,224,000		)
Less: Letters of credit issued under the revolving credit facility	(94		)	(94		)
Available capacity under the revolving credit facility	782,906			1,025,906
Total liquidity	$	798,873		$	1,035,502


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

Working Capital

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

As of September 30, 2019 , we had a working capital deficit of $119.2 million compared to a working capital deficit of $146.9 million at December 31, 2018 , which represents an increase in working capital of $27.8 million . The overall increase in working capital was primarily attributable to changes in the following components:


•	a decrease in accrued interest $15.2 million primarily due to timing of interest payments;


•	an increase in accounts receivable of $10.2 million primarily due to crude oil sales at Stanchion, as well as receivables related to CES acquired during 2019;


•	an increase in inventories of $6.7 million primarily due to PLA barrels retained at Pony Express;


•	an increase in cash and cash equivalents of $6.4 million primarily due to the timing of payments and cash receipts; and


•	a decrease in accounts payable of $5.5 million primarily due to timing of payments, lower producer settlements at TMID, and lower capital accruals.

These working capital decreases were partially offset by


•	an increase in deferred revenue of $14.1 million primarily from deficiency payments collected by Pony Express and Water Solutions; and


•	an increase in accrued taxes of $7.7 million primarily due to the timing of property tax payments, partially offset by a decrease in property tax assessment estimates.

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

Cash Flows

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



	Nine Months Ended September 30,
	2019			2018
	(in thousands)
Net cash provided by (used in):
Operating activities	$	518,208		$	466,391
Investing activities	$	(290,920	)	$	(756,499	)
Financing activities	$	(220,917	)	$	293,036

Nine Months Ended September 30, 2019 Compared to the Nine Months Ended September 30, 2018

Operating Activities. Cash flows provided by operating activities were $518.2 million and $466.4 million for the nine months ended September 30, 2019 and 2018 , respectively. The increase in net cash flows provided by operating activities of $51.8 million was primarily driven by a $52.4 million increase in distributions received from unconsolidated affiliates, primarily Rockies Express, as well as the increase in operating results, as discussed above. These increases were partially offset by a net decrease in cash flows from changes in working capital driven by a $113.2 million increase in net cash outflows from accounts payable and accrued liabilities, primarily due to higher crude oil purchases at Stanchion, partially offset by a $102.9 million increase in net cash inflows from accounts receivable, primarily due to higher crude oil sales at Stanchion.

Investing Activities. Cash flows used in investing activities were $290.9 million for the nine months ended September 30, 2019 , primarily driven by:


•	capital expenditures of $225.5 million , primarily due to Pony Express expansion projects, Cheyenne Connector, and additional natural gas gathering infrastructure;


•	contributions to unconsolidated investments in the amount of $75.2 million , primarily to fund our share of capital projects at Rockies Express and Powder River Gateway;


•	net cash outflows of $48.4 million for the acquisition of CES; and


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

These cash outflows were partially offset by $95.2 million of distributions received from unconsolidated investments in excess of cumulative earnings recognized, primarily Rockies Express.

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;

•

capital expenditures of $265.1 million , primarily due to 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;


•	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 Terminal; and


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

These cash outflows were partially offset by cash inflows of:


•	$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 Tallgrass Crude Gathering.

Financing Activities. Cash flows used in financing activities were $220.9 million for the nine months ended September 30, 2019 , primarily driven by:


•	dividends paid to Class A shareholders of $273.0 million ;


•	distributions to noncontrolling interests of $178.9 million , consisting of Tallgrass Equity distributions to the Exchange Right Holders of $173.7 million and distributions to Deeprock Development, BNN West Texas, and BNN Colorado noncontrolling interests of $5.2 million ; and


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

These cash outflows were partially offset by net borrowings under the revolving credit facility of $243.0 million .

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 , which 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 ;


•	dividends paid to Class A shareholders of $126.7 million ; and


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

Dividends

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

Our dividend for the three months ended September 30, 2019 , in the amount of $0.55 per Class A share, or $98.6 million in the aggregate, was announced on October 10, 2019 and will be paid on November 14, 2019 to Class A shareholders of record on October 31, 2019 .

Capital Requirements

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


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


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

The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. We expect to incur approximately $254 million for expansion capital projects and approximately $42 million for maintenance capital expenditures in 2019 . The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities:



	Nine Months Ended September 30,
	2019		2018
	(in thousands)
Maintenance capital expenditures	$	30,537	$	15,189
Expansion capital expenditures	187,512		258,401
Total capital expenditures incurred	$	218,049	$	273,590

Capital expenditures incurred represent capital expenditures paid and accrued during the period. The increase in maintenance capital expenditures to $30.5 million for the nine months ended September 30, 2019 from $15.2 million for the nine months ended September 30, 2018 is primarily driven by increased expenditures in the Natural Gas Transportation, Gathering, Processing & Terminalling, and Corporate and Other segments. Maintenance capital expenditures for the nine months ended September 30, 2019 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 $187.5 million for the nine months ended September 30, 2019 compared to $258.4 million for the nine months ended September 30, 2018 . Expansion capital expenditures for the nine months ended September 30, 2019 consisted primarily of spending on the Pony Express expansion, Cheyenne Connector, and additional natural gas gathering infrastructure. Expansion capital expenditures of $258.4 million 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, and construction of the Guernsey, Natoma, and Grasslands Terminals.

During the nine months ended September 30, 2019 and 2018 , we invested cash of $75.2 million and $444.8 million , respectively, in unconsolidated affiliates, including Rockies Express, Powder River Gateway, Iron Horse, and BNN Colorado, prior to our consolidation of BNN Colorado in December 2018 and our contribution of Iron Horse to the Powder River Gateway joint venture in January 2019, 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. In addition, we have made commitments of approximately $38 million to fund our portion of capital costs at Cheyenne Connector subsequent to closing of the joint venture in the fourth quarter of 2019 as discussed in Note 18 – Subsequent Events .

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

Contractual Obligations

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

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

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

The majority of TMID's Adjusted EBITDA comes from volumetric fee or commodity sensitive contracts. The profitability of our commodity sensitive processing contracts that include keep whole or percent of proceeds components is affected by volatility in prevailing NGL and natural gas prices. During the nine months ended September 30, 2019 , TMID represented 3% 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, 2019 , assuming a parallel shift in the forward curve through the end of 2019:



	Fair Value			Effect of 10% Price Increase			Effect of 10% Price Decrease
	(in thousands)
Crude oil derivative contract assets ⁽¹⁾	$	4,015		$	(1,529	)	$	1,529
Crude oil derivative contract liabilities ⁽¹⁾	$	(454	)	$	—		$	—


⁽¹⁾	Represents the net forward sale of 283,000 barrels of crude oil in our Gathering, Processing & Terminalling segment which will settle throughout 2019.

Interest Rate Risk

As of September 30, 2019 , TEP has issued $2.0 billion of Senior Notes and has a $2.25 billion revolving credit facility with outstanding borrowings of $1.47 billion . Borrowings under TEP's revolving credit facility will bear interest, at our option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar Rate, plus, in each case, an applicable margin. The applicable margin ranges from 0.25% to 1.25% for base rate borrowings and 1.25% to 2.25% for reserve adjusted Eurodollar rate borrowings, based upon TEP's total leverage ratio.

We do not currently hedge the interest rate risk on TEP's borrowings under the revolving credit facility. However, in the future we may consider hedging the interest rate risk or may consider choosing longer Eurodollar borrowing terms in order to fix all or a portion of our borrowings for a period of time. We estimate that a 1% increase in interest rates would decrease the fair value of the debt by $0.8 million based on our outstanding debt under the revolving credit facility as of September 30, 2019 .

Credit Risk

We are exposed to credit risk. Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We manage our exposure to credit risk associated with customers to whom we extend credit through a credit approval process which includes credit analysis, the establishment of credit limits and ongoing monitoring procedures. We may request letters of credit, prepayments, guarantees or other 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, 2019 .

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

See Note 16 – Legal and Environmental Matters to the condensed consolidated financial statements included in Part I—Item 1.—Financial Statements of this Quarterly Report, which is incorporated herein by reference.

Item 1A. Risk Factors

Item 1A of our 2018 Form 10-K sets forth information relating to important risks and uncertainties that could materially adversely affect our business, financial condition or operating results. Those risk factors continue to be relevant to an understanding of our business, financial condition and operating results for the quarter ended September 30, 2019 . There have been no material changes to the risk factors contained in our 2018 Form 10-K.

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

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

10.1		Standstill Agreement, dated September 25, 2019, by and between the Conflicts Committee of the Board of Directors of Tallgrass Energy GP, LLC and Blackstone Infrastructure Advisors L.L.C. (incorporated by reference to Exhibit 10.1 to Tallgrass Energy, LP's Current Report on Form 8-K filed on September 26, 2019)
31.1*		Rule 13a-14(a)/15d-14(a) Certification of David G. Dehaemers, Jr.

31.2*		Rule 13a-14(a)/15d-14(a) Certification of Gary J. Brauchle.

32.1*		Section 1350 Certification of David G. Dehaemers, Jr.

32.2*		Section 1350 Certification of Gary J. Brauchle.

101.INS*		XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

104*		Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.


* -	filed herewith

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 30, 2019	By:	/s/ Gary J. Brauchle
			Name:	Gary J. Brauchle
			Title:	Executive Vice President and Chief Financial Officer
				(Duly Authorized Officer and Principal Financial Officer)

TABLE OF CONTENTS

Part 1 Financial Information Item 1. Financial Statements Item 2. Management's Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II - Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

Exhibits

10.1 Standstill Agreement, dated September 25, 2019, by and between the Conflicts Committee of the Board of Directors of Tallgrass Energy GP, LLC and Blackstone Infrastructure Advisors L.L.C. (incorporated by reference to Exhibit 10.1 to Tallgrass Energy, LP's Current Report on Form 8-K filed on September 26, 2019) 31.1* Rule 13a-14(a)/15d-14(a) Certification of David G. Dehaemers, Jr. 31.2* Rule 13a-14(a)/15d-14(a) Certification of Gary J. Brauchle. 32.1* Section 1350 Certification of David G. Dehaemers, Jr. 32.2* Section 1350 Certification of Gary J. Brauchle.

TGE 10-Q Quarter ended Sept. 30, 2019

Exhibits