TGE 10-K Fiscal year ended Dec. 31, 2019

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•	whether the proposed Take-Private Merger (as defined in Item 1.—Business, "Organizational Structure;") will be consummated before the end of the second quarter of 2020 or at all;

•	whether any of the conditions to the Take-Private Merger will be satisfied;

•	our ability to pay dividends to our Class A shareholders, which is impacted by, among other things, our agreement pursuant to the Take-Private Merger Agreement (as defined in Item 1.—Business, "Organizational Structure;") not to pay dividends during the pendency of the transactions contemplated by the Take-Private Merger Agreement;

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our expected receipt of, and amounts of, distributions from Tallgrass Equity, which is impacted by, among other things, our agreement pursuant to the Take-Private Merger Agreement not to permit Tallgrass Equity to pay distributions on the units representing limited liability company interests in Tallgrass Equity during the pendency of the transactions contemplated by the Take-Private Merger Agreement;

•	our ability to complete and integrate acquisitions, including integrating the acquisitions discussed in Item 1.—Business, "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 our services;

•	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;

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•	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, including litigation relating to the Take-Private Merger; and

•	certain factors discussed elsewhere in this Annual Report.

•	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.

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•	Zone 1 - 328 miles of mainline pipeline from the Meeker Hub in Northwest Colorado, across Southern Wyoming to the Cheyenne Hub in Weld County, Colorado capable of transporting 2.0 Bcf/d of natural gas from west-to-east;

•	Zone 2 - 714 miles of mainline pipeline from the Cheyenne Hub to an interconnect in Audrain County, Missouri capable of transporting 1.8 Bcf/d of natural gas from west-to-east; and

•	Zone 3 - 643 miles of mainline pipeline from Audrain County, Missouri to Clarington, Ohio, which is bi-directional and capable of transporting 1.8 Bcf/d of natural gas from west-to-east and 2.6 Bcf/d of natural gas from east-to-west.

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(1)	Reflects average total daily deliveries for the Rockies Express Pipeline, regardless of flow direction or distance traveled.

(2)	Reflects total capacity reserved under long-term firm fee contracts as of December 31, 2019 .

(3)	Weighted by contracted capacity as of December 31, 2019 .

(1)	Reflects total capacity reserved under long-term firm fee contracts, including backhaul service, as of December 31, 2019 .

(2)	Weighted by contracted capacity as of December 31, 2019 .

(3)	The FERC certificated working gas storage capacity.

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(1)	Includes additional capacity related to the ability to inject drag reducing agent, which is an additive that increases pipeline flow efficiency, and additional capacity related to expansion projects.

(2)	We are required to make no less than 10% of stated capacity available for non-contract, or "walk-up", shippers. Approximately 80% of the remaining design capacity (or available contractible capacity) is committed under contract.

(3)	Based on the average annual reservation capacity for each such contract's remaining life.

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(1)	Reflects approximate average gathering volumes subsequent to our acquisition of the Douglas Gathering System on June 5, 2017.

(2)	The West Frenchie Draw natural gas treating facility treats natural gas before it flows into the Casper and Douglas plants and therefore does not result in additional inlet capacity.

(1)	Represents design capacity at our BNN Redtail and BNN Colorado freshwater storage reservoir and supply pipeline.

(2)

Represents the combined daily disposal well injection capacity for the BNN Redtail produced water gathering and disposal system acquired in December 2015, the BNN West Texas produced water gathering and disposal system which commenced operations by Water Solutions in March 2016, the BNN North Dakota produced water gathering and disposal system acquired in January 2018 and produced water disposal system acquired in November 2018, and the BNN Eastern produced water disposal system acquired in May 2019.

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Acquisition of CES. In April 2019, we 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 CES. 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.

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Joint Venture with Silver Creek. In February 2018, we entered into an agreement with Silver Creek to form a joint venture to own the Iron Horse Pipeline. Effective January 1, 2019, the joint venture between us and Silver Creek was expanded through contributions to Powder River Gateway. The expanded joint venture operates under the name Powder River Gateway, LLC and owns the Iron Horse Pipeline, the Powder River Express Pipeline, and crude oil terminal facilities in Guernsey, Wyoming. Effective January 1, 2019, we own a 51% membership interest in Powder River Gateway and operate the joint venture.

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Cheyenne Connector Pipeline. In November 2019, we entered into a joint venture agreement with DCP Cheyenne Connector, LLC ("DCP") to jointly-own Cheyenne Connector, LLC ("Cheyenne Connector"). As of December 31, 2019 , we own a 50% membership interest in Cheyenne Connector, which is developing the Cheyenne Connector Pipeline, a new FERC-regulated pipeline lateral in Northeast Colorado that will transport natural gas from the DJ Basin in Weld County to the Rockies Express Pipeline's Cheyenne Hub, discussed below. The Cheyenne Connector Pipeline will be a large-diameter pipeline approximately 70 miles long, with an initial capacity of at least 600 mmcf/d. The Cheyenne Connector Pipeline is expected to be in-service in the first half of 2020.

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Cheyenne Hub Enhancement Project. The Rockies Express Pipeline's Cheyenne Hub is an existing natural gas facility owned and operated by Rockies Express Pipeline in northern Weld County. At the Cheyenne Hub, the existing Rockies Express Pipeline intersects and/or connects with numerous other natural gas pipelines. The Cheyenne Hub Enhancement Project consists of modifications to the Rockies Express Pipeline's Cheyenne Hub to accommodate firm receipt and delivery interconnectivity among multiple natural gas pipelines with various operating pressures and will provide customers significant diversity in terms of market access. The first phase of the Cheyenne Hub Enhancement Project is expected to be in-service in the first half of 2020.

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Plaquemines Liquids Terminal. In November 2018, we entered into a joint venture agreement with Drexel Hamilton Infrastructure Fund I, L.P. ("DHIF") to jointly-own Plaquemines Liquids Terminal, LLC ("PLT"). PLT was formed with the intention of developing storage and terminalling facilities for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers ("VLCC") vessels for international delivery on a site located on the Mississippi River in Plaquemines Parish, Louisiana. We made an initial cash contribution of $30.7 million in exchange for a 100% preferred membership interest and a 80% common membership interest. DHIF contributed any and all assets and rights related to the project in exchange for a 20% common membership interest and the right to receive certain special distributions. Also in November 2018, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT expects to construct the facilities. The project is currently under development.

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•	a decline in the price of our Class A shares due to the fact that the current price reflects a market assumption that the Take-Private Merger will be completed;

•	we may owe the Buyer a termination fee of $70 million under the terms and conditions of the Take-Private Merger Agreement;

•	we will have incurred certain significant costs relating to the Take-Private Merger; and

•	the attention of our management will have been diverted to the Take-Private Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

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•	the level of firm services we provide to customers pursuant to firm fee contracts and the volume of customer products we transport, store, process, gather, treat and dispose using our assets;

•	our ability to renew or replace expiring long-term firm fee contracts with other long-term firm fee contracts;

•	the creditworthiness of our customers, particularly customers who are subject to firm fee contracts;

•	our ability to source, complete and integrate acquisitions;

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

•	the actual and anticipated future prices, and the volatility thereof, of natural gas, crude oil and other commodities;

•	changes in the fees we charge for our services, including firm services and interruptible services;

•	our ability to identify, develop, and complete internal growth projects or expansion capital expenditures on favorable terms to improve optimization of our current assets;

•	regional, domestic and foreign supply and perceptions of supply of natural gas, crude oil and other hydrocarbons;

•	the level of demand and perceptions of demand in end-user markets we directly or indirectly serve;

•	applicable laws and regulations affecting our and our customers' business, including the market for natural gas, crude oil, other hydrocarbons and water, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility;

•	the effect of worldwide energy conservation measures;

•	prevailing economic conditions;

•	the effect of seasonal variations in temperature and climate on the amount of customer products we are able to transport, store, process, gather, treat and dispose using our assets;

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•	the realized pricing impacts on revenues and expenses that are directly related to commodity prices;

•	the level of competition from other midstream energy companies in our geographic markets;

•	the level of our operating and maintenance costs;

•	damage to our assets and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters or acts of terrorism;

•	outages in our assets;

•	the relationship between natural gas and NGL prices and resulting effect on processing margins; and

•	leaks or accidental releases of hazardous materials into the environment, whether as a result of human error or otherwise.

•	our ability to borrow funds and access capital markets;

•	the level, timing and characterization of capital expenditures we make;

•	the level of our general and administrative expenses, including reimbursements to our general partner and its affiliates, for services provided to us;

•	the cost of pursuing and completing acquisitions and capital expansion projects, if any;

•	our debt service requirements and other liabilities;

•	fluctuations in our working capital needs;

•	restrictions contained in our debt agreements;

•	the amount of cash reserves established by our general partner; and

•	other business risks affecting our cash levels.

•	the level of existing and new competition to provide competing services to our markets;

•	the macroeconomic factors affecting crude oil and natural gas economics for our current and potential customers;

•	the balance of supply and demand for natural gas, crude oil and other hydrocarbons, on a short-term, seasonal and long-term basis, in the markets we directly and indirectly serve;

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•	the extent to which the current and potential customers in our markets are willing to provide firm fee commitments on a long-term basis;

•	significant, prolonged low natural gas, crude oil, or other commodity prices, which could affect supply and demand for natural gas, crude oil and other hydrocarbons; and

•	the effects of federal, state or local laws or regulations on the contracting practices of us and our customers.

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•	mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;

•	an inability to maintain or secure adequate customer commitments to use the acquired systems or facilities;

•	an inability to successfully integrate the assets or businesses we acquire;

•	the assumption of unknown liabilities for which we are not indemnified or for which its indemnity is inadequate;

•	the diversion of management's and employees' attention from other business concerns;

•	unforeseen difficulties operating in new geographic areas or business lines; and

•	a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to finance an acquisition.

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•	denial or delay in issuing requisite regulatory approvals and/or permits, which for many of our projects includes a requirement to obtain a certificate from the FERC authorizing the project before construction can commence;

•	unplanned increases in the cost of construction materials or labor;

•	disruptions in transportation of modular components and/or construction materials;

•	adverse weather conditions, natural disasters, or other events (such as equipment malfunctions, explosions, fires, releases) out of our control that result in construction delays;

•	shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

•	changes in market conditions impacting long lead-time projects;

•	market-related increases in a project's debt or equity financing costs; and

•	nonperformance by, or disputes with, vendors, suppliers, contractors, or sub-contractors involved with a project.

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•	adverse changes in domestic laws and regulations;

•	adoption of various energy efficiency and conservation measures;

•	adverse changes in general global economic conditions;

•	technological advancements that may drive further increases in production and reduction in costs of developing crude oil and natural gas shale plays;

•	the price and availability of other forms of energy, including alternative energy which may benefit from government subsidies;

•	prices for natural gas, crude oil and NGLs;

•	decisions of the members of the Organization of the Petroleum Exporting Countries, or OPEC, regarding price and production controls;

•	increased costs to explore for, develop, produce, gather, process and transport natural gas or crude oil;

•	weather conditions, seasonal trends and hurricane disruptions;

•	the nature and extent of, and changes in, governmental regulation, for example regulation of GHGs and hydraulic fracturing;

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•	perceptions of customers on the availability and price volatility of our services and natural gas and crude oil prices, particularly customers' perceptions on the volatility of natural gas and crude oil prices over the long-term;

•	capacity and transportation service into, or out of, our markets; and

•	petrochemical demand for NGLs.

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•	rates, operating terms and conditions of service;

•	the form of tariffs governing service;

•	the types of services we may offer to our customers;

•	the certification and construction of new, or the expansion of existing, facilities;

•	the acquisition, extension, disposition or abandonment of facilities;

•	customer creditworthiness and credit support requirements;

•	the maintenance of accounts and records;

•	relationships among affiliated companies involved in certain aspects of the natural gas business;

•	depreciation and amortization policies; and

•	the initiation and discontinuation of services.

•	rates, rules and regulations of service;

•	the form of tariffs governing rates and service;

•	the maintenance of accounts and records; and

•	depreciation and amortization policies.

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•	damage to pipelines, facilities, equipment and surrounding properties caused by hurricanes, earthquakes, tornadoes, floods, fires or other adverse weather conditions and other natural disasters and acts of terrorism;

•	inadvertent damage from construction, vehicles, farm and utility equipment;

•	uncontrolled releases of crude oil, natural gas and other hydrocarbons or hazardous materials, including water from hydraulic fracturing;

•	leaks, migrations or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities;

•	outages at our facilities;

•	ruptures, fires, leaks and explosions; and

•	other hazards that could also result in personal injury and loss of life, pollution and other environmental risks, and suspension of operations.

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•	reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing additional safety requirements for newly constructed pipelines;

•	requiring PHMSA to adopt appropriate regulations within two years and requiring the use of automatic or remote- controlled shutoff valves on new or rebuilt pipeline facilities;

•	requiring operators of pipelines to verify MAOP and report exceedances within five days; and

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•	requiring studies of certain safety issues that could result in the adoption of new regulatory requirements for new and existing pipelines, including changes to integrity management requirements for HCAs, and expansion of those requirements to areas outside of HCAs.

•	empowers PHMSA to issue emergency orders to individual operators, groups of operators, or the industry upon a written finding that an unsafe condition or practice constitutes or is causing an imminent hazard;

•	requires PHMSA, in consultation with other federal agencies, to issue minimum safety standards for underground natural gas storage facilities within two years;

•	requires PHMSA to conduct post-inspection briefings outlining any concerns within 30 days and providing written preliminary findings within 90 days to the extent practicable;

•	requires liquid pipeline operators to provide safety data sheets on spilled product to the designated federal on-scene coordinator and appropriate state and local emergency responders within 6 hours of telephonic or electronic notice of an accident to the National Response Center; and

•	requires PHMSA to publish updates on its website every 90 days on the status of an outstanding final rule required by a statutory mandate.

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•	CAA and analogous state and local laws, which impose obligations related to air emissions and which the EPA has relied upon as authority for adopting climate change regulatory initiatives;

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•	CWA and analogous state and local laws, which regulate discharge of pollutants or fill material from our facilities to state and federal waters, including wetlands and which require compliance with state water quality standards;

•	CERCLA and analogous state and local laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;

•	RCRA and analogous state and local laws, which impose requirements for the handling and discharge of hazardous and nonhazardous solid waste from our facilities;

•	The SDWA, which ensures the quality of the nation's public drinking water through adoption of drinking water standards and controls the waste fluids from disposal wells into below-ground formations;

•	OSHA and analogous state and local laws, which establish workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures;

•	NEPA and analogous state and local laws, which require federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements that may be made available for public review and comment;

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The Migratory Bird Treaty Act, or MBTA, and analogous state and local laws, which implement various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful without a permit, thereby potentially requiring the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas;

•	ESA and analogous state and local laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species;

•	Bald and Golden Eagle Protection Act, or BGEPA, and analogous state and local laws, which prohibit anyone, without a permit issued by the Secretary of the Interior, from "taking" bald or golden eagles, including their parts, nests, or eggs, and defines "take" as "pursue, shoot, shoot at, poison, wound, kill, capture, trap, collect, molest or disturb;"

•	OPA and analogous state and local laws, which impose liability for discharges of oil into waters of the United States and requires facilities which could be reasonably expected to discharge oil into waters of the United States to maintain and implement appropriate spill contingency plans; and

•	National Historic Preservation Act, or NHPA, and analogous state and local laws, which are intended to preserve and protect historical and archeological sites.

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•	incur or guarantee additional indebtedness;

•	redeem or repurchase units or pay distributions under certain circumstances;

•	make certain investments and acquisitions;

•	incur certain liens or permit them to exist;

•	enter into certain types of transactions with affiliates;

•	merge or consolidate with another company; and

•	transfer, sell or otherwise dispose of assets.

•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

•	our funds available for operations, future business opportunities and dividends to Class A shareholders will be reduced by that portion of our cash flow required to make interest payments on our indebtedness;

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•	we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

•	our flexibility in responding to changing business and economic conditions may be limited.

•	make it more difficult for Rockies Express to satisfy its obligations with respect to its indebtedness;

•	increase the vulnerability of Rockies Express to general adverse economic and industry conditions;

•	limit the ability of Rockies Express to obtain additional financing for future working capital, capital expenditures and other general business purposes;

•	require Rockies Express to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of cash flow for operations and other purposes;

•	limit its flexibility in planning for, or reacting to, changes in its business and the industry in which Rockies Express operates;

•	place Rockies Express at a competitive disadvantage compared to its competitors that have less indebtedness; and

•	have a material adverse effect if Rockies Express fails to comply with the covenants in the indenture relating to its notes or in the instruments governing its other indebtedness.

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•	incurring secured indebtedness;

•	entering into mergers, consolidations and sales of assets;

•	granting liens;

•	entering into transactions with affiliates; and

•	making restricted payments.

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•	each shareholder's proportionate ownership interest in us may decrease;

•	the amount of cash available for dividends on each Class A share may decrease;

•	the relative voting strength of each previously outstanding Class A share may be diminished;

•	the date upon which we begin paying material U.S. federal income taxes, or upon which a material portion of our dividends constitute taxable dividend income for U.S. federal income tax purposes, could be accelerated; and

•	the market price of the Class A shares may decline.

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•	how to allocate business opportunities among us and its affiliates;

•	whether to exercise its limited call right;

•	whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;

•	how to exercise its voting rights with respect to the units it owns; and

•	whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to the partnership agreement.

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whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

•	our general partner will not have any liability to us or our shareholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

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our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•	our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our shareholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

◦	approved by the conflicts committee of the board of directors of our general partner (although our general partner is not obligated to seek such approval);

◦	approved by the vote of a majority of the outstanding voting shares, excluding any shares owned by our general partner and its affiliates;

◦	determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

◦	determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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•	comply with applicable law;

•	comply with any agreement binding upon us or our subsidiaries (exclusive of TEP and its subsidiaries);

•	provide for future capital expenditures, debt service and other credit needs as well as any federal, state, provincial or other income tax that may affect us in the future; or

•	otherwise provide for the proper conduct of our business.

•	the level of revenue Tallgrass Equity's subsidiaries and unconsolidated affiliates are able to generate from their respective businesses;

•	the level of capital expenditures Tallgrass Equity's subsidiaries and unconsolidated affiliates make;

•	the level of Tallgrass Equity's subsidiaries and unconsolidated affiliates' operating, maintenance and general and administrative expenses or related obligations;

•	the cost of acquisitions, if any;

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•	Tallgrass Equity's subsidiaries and unconsolidated affiliates' debt service requirements and other liabilities;

•	Tallgrass Equity's subsidiaries and unconsolidated affiliates' working capital needs;

•	restrictions on distributions contained in Tallgrass Equity's subsidiaries and unconsolidated affiliates' debt agreements and any future debt agreements;

•	Tallgrass Equity's subsidiaries and unconsolidated affiliates' ability to borrow under their existing revolving credit agreements to make distributions; and

•	the amount, if any, of cash reserves established by our general partner, in its sole discretion, for the proper conduct of our business.

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(1)	For more information see Note 7 – Investments in Unconsolidated Affiliates .

(2)	The net income attributed to TGE was based upon the number of days between the closing of the IPO on May 12, 2015 to December 31, 2015.

(3)	As a result of the Take-Private Merger Agreement discussed in Note 1 – Description of Business , TGE has agreed not to pay dividends during the pendency of the transaction contemplated by the agreement. Therefore, no dividends have been declared for the three months ended December 31, 2019.

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•	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.

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•	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.

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(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 Tallgrass Development prior to the TD Merger on February 7, 2018 .

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(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 21 – Reportable Segments to the accompanying consolidated financial statements.

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

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

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

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(1)	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 21 – Reportable Segments .

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(1)	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 21 – Reportable Segments .

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(1)	Segment results as presented represent total revenue and operating income, including intersegment activity. For reconciliations to the consolidated financial data, see Note 21 – Reportable Segments .

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•	cash generated from our operations;

•	borrowing capacity available under our revolving credit facility; and

•	future issuances of additional debt securities.

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

•	an increase in accounts receivable of $88.2 million primarily due to crude oil sales at Stanchion and related party receivables related to construction costs paid on behalf of joint ventures; and

•	an increase in inventories of $14.8 million primarily due to crude oil purchases at Stanchion.

•	an increase in accounts payable and accrued liabilities of $72.5 million prim arily due to crude oil purchases at Stanchion, an increase in employee compensation accruals, and an increase in the provision for rate refunds at Trailblazer, partially offset by lower capital accruals; and

•	an increase in deferred revenue of $16.8 million primarily from deficiency payments collected by Pony Express and Water Solutions.

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•	capital expenditures of $285.7 million , primarily due to Pony Express expansion projects, Cheyenne Connector prior to the deconsolidation of Cheyenne Connector in November 2019, and additional natural gas gathering infrastructure;

•	contributions to unconsolidated investments in the amount of $115.5 million , primarily to fund our share of capital projects at Rockies Express, Powder River Gateway, and Cheyenne Connector;

•	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.

•	$145.0 million of distributions received from unconsolidated investments in excess of cumulative earnings recognized, primarily from Rockies Express; and

•	$59.7 million from the sale of a 50% membership interest in Cheyenne Connector.

•	contributions to unconsolidated investments in the amount of $473.9 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;

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capital expenditures of $368.9 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 as discussed in Note 20 – Legal and Environmental Matters ;

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

•	cash outflows of $91.0 million for the acquisition of NGL Water Solutions Bakken;

•	cash outflows of $30.7 million for the initial capital contribution and formation of PLT;

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

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

•	$80.2 million of distributions received from unconsolidated affiliates in excess of cumulative earnings recognized, primarily from Rockies Express; and

•	$50.0 million from the sale of Tallgrass Crude Gathering.

•	dividends paid to Class A shareholders of $371.6 million ;

•	distributions to noncontrolling interests of $237.4 million , consisting of Tallgrass Equity distributions to the Exchange Right Holders of $229.9 million and distributions to Deeprock Development, BNN West Texas, and BNN Colorado noncontrolling interests of $7.5 million ; and

•	tax payments funded by shares tendered by employees to satisfy tax withholding obligations of $16.2 million related to the issuance of Class A shares under our LTIP plan.

•	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 $417.0 million .

•	distributions to noncontrolling interests of $327.6 million , which consisted of Tallgrass Equity distributions to the Exchange Right Holders of $223.7 million , distributions to TEP unitholders of $97.7 million , and distributions to Deeprock Development and Pony Express noncontrolling interests of $6.2 million ;

•	dividends paid to Class A shareholders of $206.4 million ; and

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

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

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

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(1)	Debt obligations at December 31, 2019 consisted of borrowings under the revolving credit facility and the Senior Notes. For additional information, see Note 10 – Long-term Debt .

(2)	Interest on debt obligations is estimated using current borrowings and interest rates as of December 31, 2019 . For additional information, see Note 10 – Long-term Debt .

(3)	Operating leases consist of leases for crude oil storage and terminalling, office space, and equipment. For additional information, see Note 13 – Leases .

(4)	Finance lease obligations consist of the PLT land site lease. For additional information, see Note 13 – Leases .

(5)	Other purchase commitments primarily relate to service contracts, right-of-way contracts, planned non-reimbursable capital expenditures, and operating and maintenance expenditures. For additional information, see Note 14 – Commitments & Contingent Liabilities .

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(1)	Represents the net forward sale of 593,000 barrels of crude oil in our Gathering, Processing & Terminalling segment which will settle throughout 2020.

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•	We tested the effectiveness of controls over management's goodwill impairment evaluation, including those over the assumptions used in selecting the weighted-average cost of capital.

•	With the assistance of our fair value specialists, we evaluated the reasonableness of the weighted-average cost of capital by:

•	Evaluating the appropriateness of the mathematical model used to develop the weighted-average cost of capital.

•	Recomputing the mathematical accuracy of the calculation of the weighted-average cost of capital.

•	Evaluating the guideline public companies selected by management and used in the selection of the weighted-average cost of capital considering the comparability of operations to MFRU.

•	Comparing the selected weighted-average cost of capital to weighted-average cost of capital estimates published by a third-party financial institution for subject entities within MFRU's industry.

•	Developing a range of independent estimates of the weighted-average cost of capital by independently obtaining data to estimate components of the weighted-average cost of capital, including the cost of debt capital, the cost of equity capital, and debt-to-equity ratio.

•	Comparing the weighted-average cost of capital selected by management with the range of independent estimates.

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

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

(b)	Represents the issuance of TE Units, as defined in Note 1 – Description of Business , associated with our acquisition of a 25.01 % membership interest in Rockies Express and an additional 5,619,218 TEP common units as discussed in Note 3 – Acquisitions and Dispositions .

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

Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity, LLC ("Tallgrass Equity"), in which we directly own an approximate 63.75 % membership interest as of December 31, 2019 , and Tallgrass Energy Partners, LP ("TEP"), a wholly-owned subsidiary of Tallgrass Equity and its subsidiaries. We are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations.

Our reportable business segments are:

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

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

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

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

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

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

Merger Agreement with Tallgrass Energy Partners, LP

TGE previously entered into a definitive Agreement and Plan of Merger, dated as of March 26, 2018 (the "TEP Merger Agreement"), with TEP, Tallgrass MLP GP, LLC, a Delaware limited liability company and the general partner of TEP ("TEP GP"), and Razor Merger Sub, LLC, a Delaware limited liability company. The merger transaction contemplated by the TEP Merger Agreement (the "TEP Merger") was completed effective June 30, 2018, and as a result, 47,693,097 TEP common units held by the public were converted into the right to receive Class A shares of TGE at an exchange ratio of 2.0 Class A shares for each outstanding TEP common unit, TEP's incentive distribution rights were cancelled, TEP's common units are no longer publicly traded, and 100 % of TEP's equity interests are now owned by Tallgrass Equity and its subsidiaries. The TEP Merger

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was accounted for as an acquisition of noncontrolling interest. Following consummation of the TEP Merger, TGE changed its name from "Tallgrass Energy GP, LP" to "Tallgrass Energy, LP" and began trading on the New York Stock Exchange under the ticker symbol "TGE" on July 2, 2018.

March 2019 Blackstone Acquisition

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

As a result of the March 2019 Blackstone Acquisition, BIP effectively controls our business and affairs through the exercise of the rights of the sole member of our general partner. Additionally, the March 2019 Acquirors, Prairie Secondary Acquiror LP, a Delaware limited partnership ("Prairie Secondary Acquiror 1"), and Prairie Secondary Acquiror E LP, a Delaware limited partnership ("Prairie Secondary Acquiror 2" and, together with Prairie Secondary Acquiror 1 and the March 2019 Acquirors, the "Sponsor Entities"), each of which are also controlled by BIP, collectively held an approximate 44.1 % economic interest in us as of December 31, 2019 .

Take-Private Merger

On December 16, 2019, we and our general partner entered into a definitive Agreement and Plan of Merger (the "Take-Private Merger Agreement") with Prairie Private Acquiror LP, a Delaware limited partnership ("Buyer"), and Prairie Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of Buyer ("Buyer Sub"). Buyer is an affiliate of the Sponsor Entities. Pursuant to the Take-Private Merger Agreement and subject to the satisfaction or waiver of certain conditions therein, Buyer will merge with and into TGE, with TGE surviving the merger and continuing to exist as a Delaware limited partnership (the "Take-Private Merger"). At the effective time of the Take-Private Merger (the "Effective Time"), each issued and outstanding Class A share other than the Class A shares owned by the Sponsor Entities and certain of their permitted transferees, will be converted into the right to receive $ 22.45 per Class A share in cash without any interest thereon. Through the Take-Private Merger, the Sponsor Entities and the limited partners of Buyer immediately prior to the Effective Time will become the owners of all of the outstanding Class A shares and the Class A shares will cease to be publicly traded upon closing of the Take-Private Merger.

The Take-Private Merger Agreement is subject to the satisfaction of customary conditions, including approval of the merger by holders of a majority of the outstanding Class A and Class B shares of TGE, voting together as a single class, inclusive of the approximately 44.1 % of the total Class A and Class B shares held by the Sponsors Entities as of December 31, 2019. As discussed in Note 11 – Partnership Equity , pursuant to the Take-Private Merger Agreement, TGE has agreed not to pay dividends during the pendency of the transactions contemplated by the Take-Private Merger Agreement.

Basis of Presentation

The accompanying consolidated financial statements and related notes were prepared in conformity with accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification ("ASC"), the single source of accounting principles generally accepted in the United States of America ("GAAP"). In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation.

As further discussed in Note 3 – Acquisitions and Dispositions , we closed the acquisition of Terminals and NatGas effective January 1, 2017. As the acquisitions of Terminals and NatGas are considered transactions between entities under common control, and a change in reporting entity, the financial information presented has been recast to include Terminals and NatGas for all periods presented. The term "Predecessor Entities" refers to Terminals and NatGas prior to their acquisition by TEP on January 1, 2017. Predecessor Equity as presented in the consolidated financial statements represents the capital account activity of the Predecessor Entities prior to January 1, 2017. For additional information regarding these acquisitions, see Note 3 – Acquisitions and Dispositions .

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

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

Use of Estimates

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

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are carried at their estimated collectible amounts. We make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and adjustments are recorded as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $ 0.7 million and $ 7.7 million at December 31, 2019 and 2018 , respectively.

Inventories

Inventories primarily consist of crude oil, materials and supplies, gas in underground storage, and natural gas liquids. A loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline loss allowance oil, or PLA, which we can then sell. As PLA oil is accumulated, it is recorded as inventory at the lower of historical cost and net realizable value using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for existence, physical deterioration, and obsolescence. Natural gas liquids and gas in underground storage, sometimes referred to as working gas, are recorded at the lower of historical cost and net realizable value using the average cost method. For additional information, see " Gas in Underground Storage " below.

Accounting for Regulatory Activities

Regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We recorded regulatory assets of approximately $ 2.6 million and $ 3.2 million included in "Prepayments and other current assets" and "Deferred charges and other assets" in the consolidated balance sheets at December 31, 2019 and 2018 , respectively. Regulatory assets at December 31, 2019 and December 31, 2018 were primarily attributable to costs associated with rate case filings and fuel tracker assets at our regulated natural gas pipelines. We recorded regulatory liabilities of approximately $ 3.0 million and $ 1.9 million included in "Other current liabilities" in the consolidated balance sheets at December 31, 2019 and 2018 , respectively, related to fuel tracker

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liabilities at our regulated natural gas pipelines. For further information regarding our rate case filings and fuel tracker balances, see Note 19 – Regulatory Matters .

Property, Plant and Equipment

Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs related to the construction of assets, including internal labor costs, interest and engineering costs.

Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation and/or the negative salvage liability discussed under "Depreciation and Amortization" below, as appropriate, with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred.

Intangible Assets

We establish identifiable intangible assets when they meet either the separability criterion or the contractual-legal criterion. Contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of TIGT's natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years , the period of expected future benefit. During 2018, we recognized additional intangible assets at Plaquemines Liquids Terminal, LLC ("PLT"), a newly formed subsidiary as discussed in Note 3 – Acquisitions and Dispositions , from the acquisition of permits, designs, and other work-product related to the development and construction of a crude oil terminal facility in Louisiana. These intangible assets will be amortized on a straight-line basis over a period of 35 years , the period of expected future benefit. We recognized intangible assets associated with customer relationships as part of our acquisitions of NGL Water Solutions Bakken, LLC ("NGL Water Solutions Bakken") and BNN Eastern, LLC ("BNN Eastern") in 2018 and 2019, respectively, as discussed in Note 3 – Acquisitions and Dispositions . The customer relationships are amortized on a straight-line basis over a period of 8 years. Other intangible assets include customer contracts amortized on a straight-line basis over a period of 2 - 14 years, based on the remaining term of the contracts at the time of acquisition.

Impairment of Long-Lived Assets

We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset or asset group's use and its eventual disposition are less than its carrying amount. We assess our long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset or asset group is tested for impairment whenever events or changes in circumstances indicate its carrying amount may not be recoverable.

Examples of long-lived asset impairment indicators include:

•	a significant decrease in the market value of a long-lived asset or asset group;

•	a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;

•	a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;

•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group;

•	a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and

•	a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

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When an impairment indicator is present, we first assess the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset or asset group to its carrying amount. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the asset or asset group is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized.

Gas in Underground Storage

Gas in underground storage represents the cost of base gas, which refers to the volumes necessary to maintain pressure and deliverability requirements in our storage facilities. We record base gas as a component of property, plant and equipment.

We maintain working gas in our underground storage facilities on behalf of certain third parties. We receive a fee for our storage services but do not reflect the value of third-party gas in the accompanying consolidated financial statements. We occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost and net realizable value.

Depreciation and Amortization

For non-regulated assets, we have elected to use the straight-line method of depreciation. For our regulated assets, we have elected to compute depreciation using a composite method employed by applying a single depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. The depreciation rates for our regulated natural gas pipeline assets include two components, one based on economic service life (capital recovery) and one based on net costs of removal (negative salvage). The accumulated liability related to negative salvage is classified as "Other long-term liabilities and deferred credits" in our consolidated balance sheets.

The rates of depreciation for the various classes of depreciable assets are as follows:

	Range of Depreciation Rates
Crude oil pipelines	2.8 %
Natural gas pipelines	0.7% - 5.0%
Gathering & processing assets	2.2% - 5.0%
Water business assets	2.3% - 20.0%
Terminal assets	1.8% - 4.0%
Replacement Gas Facilities (1)	10.0 %
General & other	2.9% - 25.0%

(1)	Represents costs incurred by TIGT, and reimbursed by Pony Express, for the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System after having sold approximately 433 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013.

Gas Imbalances

Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing and imbalance agreements. Gas imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements. Imbalances are valued at applicable average market index prices. Gas imbalances receivable and payable are included in "Prepayments and other current assets" and "Other current liabilities" in the consolidated balance sheets.

Deferred Financing Costs

Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method. Deferred financing costs associated with long-term debt are presented as a reduction to the corresponding debt in our consolidated balance sheets. Deferred financing costs associated with our revolving credit facility are presented as noncurrent assets in our consolidated balance sheets. During the year ended December 31, 2018, we recognized a $ 2.2 million loss on debt retirement, recorded as "Other income (expense), net" in the accompanying consolidated statements of income, associated with the write off of deferred financing costs associated with the Amendment to the TEP revolving credit facility and the termination of the Tallgrass Equity revolving credit facility as discussed further in Note 10 – Long-term Debt .

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Goodwill

We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. We evaluate goodwill for impairment at the reporting unit level, which is the same as, or one level below, an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or proceeding directly to the quantitative impairment test depending on facts and circumstances of the reporting unit. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units according to the benefit received by the reporting unit at the date of acquisition. If we, after performing the qualitative assessment, determine it is "more likely than not" that the fair value of a reporting unit is greater than its carrying amount, then goodwill is not considered impaired. When goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the reporting unit's fair value, then the reporting unit should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. See Note 8 – Goodwill and Other Intangible Assets for additional information regarding impairment testing performed during 2019 .

Investment in Unconsolidated Affiliates

We use the equity method to account for investments in 20 % or greater owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20 % owned affiliates where we have the ability to exercise significant influence.

We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary. See Note 7 – Investments in Unconsolidated Affiliates for additional information regarding our investment in unconsolidated affiliates.

Revenue Recognition

We adopted Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers" on January 1, 2018, using the modified retrospective method. For periods subsequent to adoption, we account for revenue from contracts with customers in accordance with the five-step model outlined in ASC Topic 606, "Revenue from Contracts with Customers ("ASC 606"). Under the five-step model, we identify the contract, identify the performance obligations, determine the transaction price, allocate the transaction price, and recognize revenue. Revenue is recognized when (or as) the performance obligations are satisfied. For additional information see Note 12 – Revenue from Contracts with Customers .

Commitments and Contingencies

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss.

Environmental Costs

We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action. Estimates of environmental liabilities are based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of other factors including our prior experience in remediating contaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information.

Fair Value

Fair value, as defined in the Codification, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. We apply the fair value measurement

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guidance to financial assets and liabilities in determining the fair value of derivative assets and liabilities, and to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill.

The fair value measurement accounting guidance requires that we make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments' fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity.

Fair value, where available, is based on observable market prices. Where observable market prices or inputs are not available, different valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments' complexity.

To increase consistency and enhance disclosure of fair value, the Codification creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability's level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows:

•	Level 1 Inputs-quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;

•	Level 2 Inputs-inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and

•	Level 3 Inputs-unobservable inputs for the asset or liability. These unobservable inputs reflect the entity's own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity's own data).

Any transfers between levels within the fair value hierarchy are recognized at the end of the reporting period. For information regarding financial instruments measured at fair value on a recurring basis, see Note 9 – Risk Management . For information regarding the fair value of financial instruments not measured at fair value in the consolidated balance sheets, see Note 10 – Long-term Debt .

Risk Management Activities

Our operations expose us to a variety of risks including, but not limited to, changes in the prices of commodities that we buy or sell. We manage these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including establishing and monitoring the adequacy of, and compliance with, exposure limits.

We record derivative contracts at their estimated fair values as of each reporting date and present profit and loss activity on a net basis in "Sales of natural gas, NGLs, and crude oil" in our consolidated statements of operations. For more information on our risk management activities, see Note 9 – Risk Management .

Equity-Based Compensation

Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. As discussed in Note 17 – Equity-Based Compensation , prior to February 2018 a portion of the expense recognized relating to equity-based compensation grants was charged to Tallgrass Development, LP (" TD").

Income Taxes

Although TGE is organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U.S. federal and state income taxes. TGE's consolidated subsidiaries consist primarily of entities that are flow-through entities for income tax purposes. We also own certain C corporation subsidiaries which have been formed for the purpose of potential pipeline construction and other investment purposes. In addition, Tallgrass

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Energy Finance Corp. is a wholly owned subsidiary of TEP that has no material assets and was formed for the sole purpose of being a co-issuer of TEP's senior notes as discussed in Note 10 – Long-term Debt . These C corporation subsidiaries have not commenced operations or generated any material income, and as a result no provision for federal or state income taxes for these entities has been recorded in our consolidated financial statements.

As discussed in Note 3 – Acquisitions and Dispositions , in April 2019, BNN Eastern, a newly formed indirect subsidiary of TGE, entered into a Stock Purchase Agreement to acquire all of the outstanding stock of CES Holding Company, Inc., which owns all of the issued and outstanding membership interests of K & H Partners LLC. CES Holding Company, Inc. is a C corporation for U.S. federal income tax purposes and is considered a taxable entity for such purposes.

Deferred income taxes are provided for temporary differences arising from differences between the consolidated financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates expected to be in effect when the related taxes are expected to be paid or recovered. A valuation allowance is established if it is more likely than not that a deferred tax asset will not be realized. In determining the appropriate valuation allowance, we consider projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies, and our overall deferred tax position.

Pursuant to the applicable guidance related to accounting for uncertainty in income taxes, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2019 , we had not recognized any material amounts in connection with uncertainty in income taxes.

Business Combinations

We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill or gain from a bargain purchase. For material or complex acquisitions, management typically engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, noncontrolling interest, if any, and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, we will record any material adjustments to the initial estimate based on new information obtained about facts and circumstances that existed as of the acquisition date. An income, market or cost valuation approach may be utilized to estimate the fair value of the assets acquired, liabilities assumed, and noncontrolling interest, if any, in a business combination. We typically use an income approach, such as the multi-period excess earnings method, to value intangible assets. The income approach requires management to estimate future cash flows: (i) discrete financial forecasts, which rely on management's estimates of gross margin and operating expenses; (ii) terminal growth rates; and (iii) appropriate discount rates. We typically use a cost approach to value property, plant and equipment. The cost approach is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. See Note 3 – Acquisitions and Dispositions for additional information regarding our business combinations.

Accounting Pronouncement Recently Adopted

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

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

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

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

Accounting Pronouncements Not Yet Adopted

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

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

ASU No. 2019-12, "Income Taxes (Topic 740)"

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740), which modifies ASC 740 to simplify the accounting for income taxes. The amendments in ASU 2019-12 are effective for financial statements issued for annual periods beginning after December 15, 2020, and interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the impact of ASU 2019-12.

Cheyenne Connector

In October 2019, a subsidiary of DCP Midstream, LP ("DCP") exercised its option to purchase a 50 % membership interest in Cheyenne Connector, LLC ("Cheyenne Connector"), which is currently developing and constructing the Cheyenne Connector Pipeline as discussed in Note 19 – Regulatory Matters . Effective November 4, 2019, we entered into a limited liability company agreement with DCP under which DCP made initial contributions of $ 59.7 million to Cheyenne Connector and entered into natural gas transportation agreements, in exchange for a 50 % membership interest in Cheyenne Connector. Upon closing of the transaction, we derecognized the assets and liabilities of Cheyenne Connector, which primarily consisted of construction work in progress of $ 134.4 million . No gain or loss was recognized on the deconsolidation as the carrying value was determined to approximate the fair value. We will account for our remaining 50 % membership interest in Cheyenne Connector under the equity method of accounting and will continue to operate the Cheyenne Connector joint venture.

Acquisition of Central Environmental Services

In April 2019, BNN Eastern, a newly formed indirect subsidiary of TGE, entered into a Stock Purchase Agreement to acquire all of the outstanding stock of CES Holding Company, Inc., which owns all of the issued and outstanding membership interests of K & H Partners LLC, a company doing business as Central Environmental Services ("CES"). CES Holding Company, Inc. is a C corporation for U.S. federal income tax purposes and is considered a taxable entity for such purposes. CES owns and operates a salt water disposal facility located in the Utica and Marcellus area of Ohio. On May 1, 2019, the acquisition closed for cash consideration of approximately $ 52 million paid at closing, and the issuance of a 7.65 % membership interest in BNN Eastern to one of the sellers in the transaction. In addition, the transaction included a potential earn out payment to the sellers of approximately $ 3 million based on the achievement of certain milestones during 2019, which was payable in cash or in additional membership interests in BNN Eastern. Because the milestones were not achieved, there will not be an earn out payment in connection with the transaction. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.

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

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

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

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

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

Actual revenue and net income attributable to TGE from CES of $ 6.4 million and $ 0.8 million , respectively, was recognized in the accompanying consolidated statements of income for the period from May 1, 2019 to December 31, 2019 .

Consolidation of BNN Colorado

Effective December 1, 2018, we obtained control of BNN Colorado Water, LLC ("BNN Colorado") through an amendment to the voting rights in BNN Colorado's limited liability company agreement. Prior to the amendment, we accounted for our interest in BNN Colorado under the equity method of accounting. The consolidation was accounted for as a business combination under ASC 805. No gain or loss was recognized on the remeasurement of our 63 % membership interest as of December 1, 2018, as the carrying value was determined to approximate the fair value. The 37 % equity interest in BNN Colorado held by noncontrolling interests was recorded at its acquisition date fair value of $ 10.1 million . These fair value measurements are based on significant inputs, such as forecasted cash flows and discount rates, that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820.

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

Accounts receivable	$	4,053
Property, plant and equipment	18,535
Intangible asset	7,922			(1)
Accounts payable and accrued liabilities	( 53		)
Deferred revenue	( 4,053		)
Net identifiable assets acquired (excluding cash)	$	26,404

(1)	The $ 7.9 million intangible asset acquired represents a customer contract. This intangible asset is amortized on a straight-line basis over a period of approximately 3 years, the remaining term of the underlying contract at the time of acquisition.

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At December 31, 2018, the assets acquired and liabilities assumed were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2019. Actual revenue and net loss attributable to TGE from BNN Colorado of less than $ 1.0 million was recognized in the accompanying consolidated statements of income for the period from December 1, 2018 to December 31, 2018 .

Acquisition of BNN North Dakota

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

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

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

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

At March 31, 2018, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of June 30, 2018. Actual revenue and net income attributable to TGE from BNN North Dakota of $ 18.8 million and $ 4.7 million , respectively, was recognized in the accompanying consolidated statements of income for the period from January 12, 2018 to December 31, 2018 .

Acquisition of NGL Water Solutions Bakken

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

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

	Preliminary				Adjustments				Final
	(in thousands)
Accounts receivable	$	3,599			$	( 3,599	)		$	—
Prepayments and other current assets	5				—				5
Property, plant and equipment	17,200				—				17,200
Intangible asset	54,000				—				54,000			(1)
Accounts payable and accrued liabilities	( 949		)		644				( 305		)
Net identifiable assets acquired	73,855				( 2,955		)		70,900
Goodwill	17,145				2,955				20,100
Net assets acquired	$	91,000			$	—			$	91,000

(1)	The $ 54.0 million intangible asset acquired represents customer relationships and a customer contract. This intangible asset is amortized on a straight-line basis over a period of 3 - 8 years.

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

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and liabilities assumed in the acquisition was considered final as of June 30, 2019. The goodwill recognized of $ 20.1 million is primarily attributed to synergies expected from combining the operations of TGE and NGL Water Solutions Bakken. All the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TGE from NGL Water Solutions Bakken of $ 1.4 million and $ 0.5 million , respectively, was recognized in the accompanying consolidated statements of income for the period from November 30, 2018 to December 31, 2018 .

Acquisition of Plaquemines Liquids Terminal, LLC

In November 2018, we entered into a joint venture agreement with Drexel Hamilton Infrastructure Fund I, L.P. ("DHIF") to jointly-own Plaquemines Liquids Terminal, LLC ("PLT"). PLT was formed with the intention of developing storage and terminalling facilities for both crude oil and refined products and export facilities capable of loading Suezmax and Very Large Crude Carriers vessels for international delivery on a site located on the Mississippi River in Plaquemines Parish, Louisiana. We made an initial cash contribution to PLT of $ 30.7 million in exchange for a 100 % preferred membership interest and a 80 % common membership interest in PLT. DHIF contributed any and all assets and rights related to PLT in exchange for a 20 % common membership interest and the right to receive certain special distributions. Our preferred and common membership interests are considered to be a controlling financial interest and PLT was consolidated accordingly. The transaction has been accounted for as an asset acquisition, with substantially all the fair value allocated to the assets and liabilities acquired based on their relative fair values. The intangible assets acquired, valued at approximately $ 35 million , relate to permits, designs, and other work-product related to the development and construction of a crude oil terminal facility in Louisiana. The liabilities recognized relate to DHIF's right to receive special distributions totaling $ 35 million , of which $ 25 million is included in "Other current liabilities" and the remaining $ 10 million is included in "Other long-term liabilities and deferred credits" in the consolidated balance sheets. The special distributions are contingent upon PLT reaching certain milestones in the development and construction of the project facilities. Also in November 2018, PLT entered into an agreement with the Plaquemines Port & Harbor Terminal District to lease the land site on which PLT expects to construct the facilities. The project is currently under development.

Acquisition of Pawnee Terminal

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

Acquisitions in Rockies Express and Additional TEP Common Units

In March 2017, TEP, TD, and Rockies Express Holdings, LLC, entered into a definitive Purchase and Sale Agreement, pursuant to which TEP acquired an additional 24.99 % membership interest in Rockies Express from TD in exchange for cash consideration of $ 400 million .

The 2017 transfer of the Rockies Express membership interest between TD and TEP is considered a transaction between entities under common control, but does not represent a change in reporting entity. As a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed contribution representing the excess carrying value of the 24.99 % membership interest in Rockies Express acquired over the fair value of the consideration paid. For further discussion, see Note 11 – Partnership Equity .

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

The 2018 transfer of the Rockies Express membership interest between TD and Tallgrass Equity is considered a transaction between entities under common control, but does not represent a change in reporting entity. As a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed contribution representing the excess carrying value of the 25.01 % membership interest in Rockies Express acquired over the fair value of the consideration paid. For further discussion, see Note 11 – Partnership Equity . As the aggregate 75 % membership interest does not represent a controlling interest in Rockies Express, TGE's investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our consolidated balance sheets. For additional information, see Note 7 – Investments in Unconsolidated Affiliates .

The acquisition of an additional 5,619,218 TEP common units is considered an acquisition of noncontrolling interest and resulted in the recognition of a noncash deemed distribution representing the excess purchase price over the $ 53.8 million

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carrying value of the 5,619,218 TEP common units acquired as of February 7, 2018. For further discussion, see Note 11 – Partnership Equity .

Acquisition and Sale of Outrigger Powder River Operating, LLC

In August 2017, we acquired 100 % of the membership interests of Outrigger Powder River Operating, LLC (subsequently renamed as Tallgrass Crude Gathering, LLC, "Tallgrass Crude Gathering"), which owns a crude oil gathering system in the Powder River Basin with approximately 34 miles of gathering lines as of the acquisition date and approximately 150,000 acres dedicated on a long-term fee-based contract (the "PRB Crude System"), for approximately $ 36 million . The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805.

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

Accounts receivable	$	117
Property, plant and equipment	29,306
Intangible asset	6,694			(1)
Accounts payable and accrued liabilities	( 87		)
Net identifiable assets acquired	$	36,030

(1)	The $ 6.7 million intangible asset acquired represents a major customer contract. This intangible asset is amortized on a straight-line basis over a period of 8 years, the remaining term of the contract at the time of acquisition.

At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of December 31, 2017. Actual revenue and net loss attributable to TGE from Tallgrass Crude Gathering of less than $ 1 million was recognized in the accompanying consolidated statements of income for the period from August 3, 2017 to December 31, 2017.

In February 2018, we entered into an agreement with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to sell our 100 % membership interest in Tallgrass Crude Gathering, for approximately $ 50.0 million . The sale of Tallgrass Crude Gathering closed on February 23, 2018. During the year ended December 31, 2018, we recognized a gain of $ 9.4 million on the sale which is presented in the line item "Loss (gain) on disposal of assets" in the consolidated statements of income.

Joint Venture with Silver Creek

In February 2018, we entered into an agreement with Silver Creek to form Iron Horse Pipeline, LLC ("Iron Horse"), to construct and own the Iron Horse Pipeline. During the year ended December 31, 2018, we contributed an initial $ 3.5 million and committed to funding our proportionate share of the remaining costs of construction in exchange for a 75 % membership interest in Iron Horse. As the 75 % membership interest does not represent a controlling interest in Iron Horse, our investment in Iron Horse is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the consolidated balance sheets.

In August 2018, we entered into an agreement with Silver Creek to expand the Iron Horse joint venture through the contribution by us and Silver Creek of cash and additional Powder River Basin assets. These additional contributions closed in January 2019. We contributed our 75 % membership interest in Iron Horse, $ 37 million in cash, and various other assets, including terminal facilities currently under construction in Guernsey, Wyoming. Silver Creek contributed the PRE Pipeline and their 25 % membership interest in Iron Horse. The expanded joint venture operates under the name Powder River Gateway, LLC ("Powder River Gateway"), and owns the Iron Horse Pipeline, the PRE Pipeline, a 70 -mile crude oil pipeline that transports crude oil from the Powder River Basin to Guernsey, Wyoming, and crude oil terminal facilities in Guernsey, Wyoming. Effective January 1, 2019, we own a 51 % membership interest in Powder River Gateway and continue to operate the joint venture, while Silver Creek owns a 49 % membership interest. As Silver Creek retained certain participating rights with respect to Powder River Gateway, the 51 % membership interest does not represent a controlling interest in Powder River Gateway. Accordingly, our investment in Powder River Gateway is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the consolidated balance sheets.

Acquisitions of Additional Interests in Deeprock Development, LLC

In July 2017, we acquired an additional 40 % membership interest in Deeprock Development, LLC ("Deeprock Development") from Kinder Morgan Cushing, LLC for cash consideration of approximately $ 57.2 million , net of cash acquired. We subsequently acquired an additional 9 % membership interest in Deeprock Development from Deeprock Energy Resources LLC ("DER") on July 21, 2017, as discussed further below.

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Upon closing of the acquisition of the 40 % membership interest on July 20, 2017, we obtained a controlling financial interest in Deeprock Development and accordingly have accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, we remeasured our previously held 20 % equity interest in Deeprock Development to its fair value of $ 22.9 million , recognized a gain of $ 9.7 million in "Other income (expense), net" in the consolidated statements of income, and consolidated Deeprock Development in our consolidated financial statements. The 40 % equity interest in Deeprock Development held by noncontrolling interests was recorded at its acquisition date fair value of $ 45.9 million . The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow analysis and adjusted for lack of control. These fair value measurements are based on significant inputs, such as forecasted cash flows and discount rates, that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820.

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

Accounts receivable	$	968
Other current assets	598
Property, plant and equipment	70,148
Accounts payable	( 712		)
Deferred revenue	( 6,546		)
Net identifiable assets acquired	64,456
Goodwill	61,550
Net assets acquired (excluding cash)	$	126,006

At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of December 31, 2017. The goodwill recognized of $ 61.6 million is primarily attributed to synergies expected from combining our operations with the operations of Deeprock Development. All the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TGE from Deeprock Development of $ 10.5 million and $ 0.9 million , respectively, was recognized in the accompanying consolidated statements of income for the period from July 20, 2017 to December 31, 2017.

In July 2017, subsequent to the acquisition of an additional 40 % membership interest discussed above, we acquired an additional 9 % membership interest in Deeprock Development from DER for total consideration valued at approximately $ 13.1 million , consisting of approximately $ 6.4 million in cash and the issuance of 128,790 TEP common units (valued at approximately $ 6.7 million based on the July 20, 2017 closing price of TEP's common units), which was accounted for as an acquisition of noncontrolling interest. Subsequent to the closing of the transaction, our aggregate membership interest in Deeprock Development was 69 % .

Acquisition of Deeprock North and Merger with Deeprock Development

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

Acquisition of DCP Douglas, LLC

In June 2017, we acquired 100 % of the membership interests in DCP Douglas, LLC (subsequently renamed as Tallgrass Midstream Gathering, LLC), which owns the Douglas Gathering System, a natural gas gathering system in the Powder River Basin with approximately 1,500 miles of gathering pipeline connected to the Douglas processing plant, for approximately $ 128.5 million . The acquisition has been accounted for as an asset acquisition, with substantially all the fair value allocated to the long-lived assets acquired based on their relative fair values.

Acquisition of Tallgrass Terminals, LLC and Tallgrass NatGas Operator, LLC

In January 2017, we acquired 100 % of the issued and outstanding membership interests in Terminals and 100 % of the issued and outstanding membership interests in NatGas from TD for total cash consideration of $ 140 million . These acquisitions are considered transactions between entities under common control, and a change in reporting entity. As a result of the common control nature of the transaction, the acquisitions resulted in the recognition of a noncash deemed distribution

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representing the excess fair value of the consideration paid over the carrying value of Terminals and NatGas net assets acquired. For further discussion, see Note 11 – Partnership Equity .

Acquisition of Additional Interest in Pony Express

In February 2018, we acquired the remaining 2 % membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from TD for cash consideration of approximately $ 60 million , bringing our aggregate membership interest in Pony Express to 100 % . The acquisition of the remaining 2 % membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction has not been recast to reflect the additional 2 % membership interest. As a result of the common control nature of the transaction, the acquisition resulted in the recognition of a noncash deemed distribution representing the excess fair value of the consideration paid over the carrying value of the 2 % membership interest in Pony Express acquired. For further discussion, see Note 11 – Partnership Equity .

Pro Forma Financial Information

Unaudited pro forma revenue and net income attributable to TGE for the years ended December 31, 2019 and 2018 is presented below as if the acquisition of CES had been completed on January 1, 2018. Unaudited pro forma revenue and net income (loss) attributable to TGE for the years ended December 31, 2018 and 2017 is presented below as if the acquisitions of BNN North Dakota, NGL Water Solutions Bakken, and BNN Colorado had been completed on January 1, 2017. Unaudited pro forma revenue and net loss attributable to TGE for the year ended December 31, 2017 is presented below as if the acquisitions of Tallgrass Crude Gathering and Deeprock Development had been completed on January 1, 2016.

	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Revenue	$	873,340			$	827,998			$	686,803
Net income (loss) attributable to TGE	$	249,644			$	141,988			$	( 129,155	)

The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TGE would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project the results of operations or financial position of TGE for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The pro forma revenue and net income (loss) includes adjustments to give effect to the estimated results of operations of CES, BNN North Dakota, NGL Water Solutions Bakken, BNN Colorado, Tallgrass Crude Gathering, and Deeprock Development for the periods presented. The pro forma net income (loss) also includes adjustments to eliminate the equity in earnings and gain on remeasurement of unconsolidated investment associated with our previously held 20 % membership interest in Deeprock Development and to eliminate the equity in earnings associated with our 63 % membership interest in BNN Colorado which was previously accounted for as an equity method investment.

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

	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Processing and other revenues (1)	$	7,394			$	7,483			$	8,516
Cost of transportation services (2)	$	940			$	—			$	10,476
Charges to TGE: (3)
Property, plant and equipment, net	$	—			$	—			$	2,679
Other deferred charges	$	—			$	—			$	25
Operations and maintenance	$	—			$	—			$	29,881
General and administrative	$	—			$	—			$	41,676

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

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(2)	Reflects rent expense for crude oil storage and terminalling services provided by Powder River Gateway and at the Deeprock Terminal prior to our consolidation of Deeprock Development during the third quarter of 2017, as discussed in Note 3 – Acquisitions and Dispositions .

(3)

Charges to TGE, inclusive of Tallgrass Equity and TEP, include indirectly charged wages and salaries, other compensation and benefits, and shared services for periods prior to January 1, 2018 pursuant to an Omnibus Agreement entered into by TEP and TEP GP with Tallgrass Energy Holdings, LLC and certain of its affiliates in connection with the closing of our initial public offering on May 17, 2013. Effective January 1, 2018, these costs are incurred by TGE directly.

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

	December 31, 2019				December 31, 2018
	(in thousands)
Receivable from related parties:
Powder River Gateway, LLC	$	12,071			$	—
Rockies Express Pipeline LLC	3,998				3,447
Cheyenne Connector, LLC	575				—
Pawnee Terminal, LLC	125				115
Iron Horse Pipeline, LLC	—				186
Total receivable from related parties	$	16,769			$	3,748

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

	December 31, 2019				December 31, 2018
	(in thousands)
Affiliate gas imbalance receivables	$	74			$	19
Affiliate gas imbalance payables	$	991			$	742

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

	December 31, 2019				December 31, 2018
	(in thousands)
Crude oil	$	46,164			$	23,205
Gas in underground storage	1,772				2,740
Materials and supplies	650				8,206
Natural gas liquids	495				165
Total inventory	$	49,081			$	34,316

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

	December 31, 2019				December 31, 2018
	(in thousands)
Crude oil pipelines	$	1,375,036			$	1,313,976
Gathering, processing and terminalling assets	1,007,648				889,168
Natural gas pipelines	625,631				607,343
General and other (1)	175,537				180,299
Construction work in progress	72,842				191,994
Accumulated depreciation and amortization	( 482,176		)		( 380,351		)
Total property, plant and equipment, net (2)	$	2,774,518			$	2,802,429

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

(2)	Property, plant and equipment, net includes approximately $ 464.8 million of assets at our regulated natural gas pipelines at December 31, 2019 .

Depreciation expense was approximately $ 109.4 million , $ 102.7 million , and $ 86.9 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively. Capitalized interest was approximately $ 7.5 million , $ 5.2 million , and $ 1.1 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively.

The following table summarizes our investments in unconsolidated affiliates:

	Percentage Ownership at December 31, 2019			Carrying Value as of December 31,
				2019				2018
				(in thousands)
Rockies Express Pipeline LLC	75	%		$	1,714,857			$	1,794,987
Cheyenne Connector, LLC	50	%		96,194				—
Powder River Gateway, LLC	51	%		164,773				—
Pawnee Terminal, LLC	51	%		30,395				31,232
Iron Horse Pipeline, LLC	Not applicable			—				35,467
Total investments in unconsolidated affiliates				$	2,006,219			$	1,861,686

Cheyenne Connector

As discussed in Note 3 – Acquisitions and Dispositions , DCP exercised its option to purchase a 50 % membership interest in Cheyenne Connector. The transaction closed effective November 4, 2019 and we subsequently deconsolidated Cheyenne Connector's assets and liabilities and began accounting for our remaining 50 % membership interest under the equity method of accounting.

Powder River Gateway and Iron Horse Pipeline

As discussed in Note 3 – Acquisitions and Dispositions , effective January 1, 2019 we contributed our membership interest in Iron Horse along with cash and other assets under construction to Powder River Gateway, a joint venture with Silver Creek, in exchange for a 51 % membership interest in the joint venture.

BNN Colorado Water, LLC

As discussed in Note 3 – Acquisitions and Dispositions , we consolidated BNN Colorado effective December 1, 2018 and no longer account for our investment in BNN Colorado under the equity method of accounting.

Deeprock Development

As discussed in Note 3 – Acquisitions and Dispositions , on July 20, 2017, we acquired an additional 40 % membership interest in Deeprock Development. As a result of the acquisition, we consolidated Deeprock Development and effective July 20, 2017 we no longer account for our investment in Deeprock Development under the equity method of accounting.

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Rockies Express Basis Difference

Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our consolidated balance sheets. On May 6, 2016, TEP acquired a 25 % membership interest in Rockies Express. On that date, the difference between the fair value of our investment in Rockies Express of $ 436.0 million and the book value of the underlying net assets resulted in a negative basis difference of approximately $ 404.7 million . As discussed in Note 3 – Acquisitions and Dispositions , we acquired an additional 24.99 % and 25.01 % membership interest in Rockies Express from TD on March 31, 2017 and February 7, 2018, respectively. As of March 31, 2017, the negative basis difference carried over from TD from the transfer of the 24.99 % Rockies Express membership interest was approximately $ 386.8 million . As of February 7, 2018, the negative basis difference carried over from TD from the transfer of the 25.01 % Rockies Express membership interest was approximately $ 376.5 million . The transfer of the 24.99 % Rockies Express membership interest between TD and TEP and the 25.01 % Rockies Express membership interest between TD and Tallgrass Equity are considered transactions between entities under common control, but does not represent a change in reporting entity. As a result of the common control nature of the transactions, the 24.99 % and 25.01 % membership interests in Rockies Express were transferred to TEP and Tallgrass Equity, respectively, at TD's historical carrying amount, including the remaining unamortized basis difference driven by the difference between the fair value of the investments and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD.

The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years , which equates to the 2.86 % composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. At December 31, 2019 , the basis difference for our membership interests in Rockies Express was allocated as follows:

	Basis Difference				Amortization Period
	(in thousands)
Long-term debt	$	42,845			2 - 25 years
Property, plant and equipment	( 1,108,670		)		35 years
Total basis difference	$	( 1,065,825	)

During the year ended December 31, 2019 , we recognized equity in earnings associated with our 75 % membership interest in Rockies Express of $ 316.4 million , inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $ 458.7 million and $ 62.2 million , respectively.

Rockies Express Senior Notes Offerings

On January 31, 2020, Rockies Express issued $ 750 million in aggregate principal amount of senior notes. The issuance was composed of two tranches, $ 400 million of 3.60 % senior notes due 2025 and $ 350 million of 4.80 % senior notes due 2030. The proceeds of the issuance will be used to redeem the 5.625 % senior notes due April 15, 2020 in March 2020.

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

Summarized Financial Information of Unconsolidated Affiliates

The following tables summarize the combined financial information of our investments in unconsolidated affiliates during the periods in which we held a membership interest for the periods indicated:

	December 31,
	2019				2018
	(in thousands)
Current assets	$	201,621			$	132,213
Noncurrent assets	$	6,430,144			$	6,031,066
Current liabilities	$	216,596			$	694,951
Noncurrent liabilities	$	2,211,448			$	1,502,906
Members' equity	$	4,203,721			$	3,965,422

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	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Revenue	$	931,025			$	930,771			$	860,115
Operating income	$	499,493			$	524,607			$	480,337
Net income	$	394,725			$	376,934			$	465,592

Reconciliation of Goodwill

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

	Natural Gas Transportation				Gathering, Processing & Terminalling				Total
	(in thousands)
Balance at December 31, 2017	$	255,558			$	149,280			$	404,838
Goodwill acquired	—				17,145			(1)	17,145
Balance at December 31, 2018	255,558				166,425				421,983
Goodwill acquired	—				16,423			(2)	16,423
Other adjustments	—				2,955			(3)	2,955
Balance at December 31, 2019	$	255,558			$	185,803			$	441,361

(1)	The $ 17.1 million of goodwill was recorded in connection with the acquisition of NGL Water Solutions Bakken on November 30, 2018 as discussed further in Note 3 – Acquisitions and Dispositions .

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

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

Annual Goodwill Impairment Analysis

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

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

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

Other Intangible Assets

A summary of amortized intangible assets is as follows:

	December 31, 2019				December 31, 2018
	(in thousands)
Pony Express oil conversion use rights	$	105,973			$	105,973
Customer contracts	60,348				60,348
Customer relationships	85,950				52,100
Plaquemines Liquids Terminal use rights and permits	35,000				35,000
Accumulated amortization	( 45,719		)		( 26,318		)
Intangible assets, net	$	241,552			$	227,103

Amortization of intangible assets was approximately $ 19.4 million , $ 8.1 million , and $ 3.8 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively.

Estimated future amortization for the intangible assets is as follows (in thousands):

Year		Total
2020		$	20,527
2021		20,474
2022		17,324
2023		17,324
2024		17,324
Thereafter		113,579
Total (1)		$	206,552

(1)	Excludes the $ 35 million intangible asset at PLT, as discussed in Note 3 – Acquisitions and Dispositions , that will be amortized over 35 years beginning on the in-service date of the project facilities.

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

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

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Fair Value of Derivative Contracts

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

	Balance Sheet Location		December 31, 2019				December 31, 2018
			(in thousands)
Crude oil derivative contracts	Prepayments and other current assets		$	2,536			$	3,526
Crude oil derivative contracts	Other current liabilities		$	60			$	1,642

As of December 31, 2019 , the amounts shown represent the fair value of crude oil derivative contracts for the forward purchase of 2,394,002 and the forward sale of 5,913,554 barrels of crude oil consisting of fixed price and floating price contracts, which will settle throughout 2020. As of December 31, 2018 , the amounts shown represent the fair value of crude oil derivative contracts for the forward purchase of 2,105,146 and the forward sale of 1,274,500 barrels of crude oil, consisting of fixed price and floating price contracts, which settled throughout 2019.

Effect of Derivative Contracts in the Statements of Income

The following table summarizes the impact of derivative contracts not designated as hedging contracts for the years ended December 31, 2019 , 2018 and 2017 :

		Location of gain recognized in income on derivatives		Amount of gain recognized in income on derivatives
				Year Ended December 31,
				2019				2018				2017
				(in thousands)
Crude oil derivative contracts		Sales of natural gas, NGLs, and crude oil		$	55,562			$	29,510			$	39
Natural gas derivative contracts		Sales of natural gas, NGLs, and crude oil		$	—			$	—			$	75
Call option derivative		Other income, net		$	—			$	—			$	1,885

Call Option Derivative

As part of our acquisition of an additional 31.3 % membership interest in Pony Express effective January 1, 2016, TD granted TEP an 18 month call option at an exercise price of $ 42.50 per TEP common unit covering the 6,518,000 TEP common units issued to TD as a portion of the consideration. On February 1, 2017 , TEP exercised the remainder of the call option covering 1,703,094 common units for a cash payment of $ 72.4 million . As a result of the exercise, we derecognized the derivative asset balance, recognizing approximately $ 12.6 million through equity for the year ended December 31, 2017. These common units were deemed canceled upon the exercise of the call option and as of the applicable exercise date were no longer issued and outstanding.

Credit Risk

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

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Our derivative contracts are entered into with counterparties through central trading organizations such as futures, options or stock exchanges or counterparties outside of central trading organizations. While we typically enter into derivative transactions with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. The maximum potential exposure to credit losses on our crude oil derivative contracts at December 31, 2019 was:

	Asset Position
	(in thousands)
Gross	$	2,536
Netting agreement impact	—
Cash collateral held	—
Net exposure	$	2,536

As of December 31, 2019 , we had $ 2.6 million of cash in margin accounts in support of our commodity derivative contracts. As of December 31, 2018 , we did not have any cash in margin accounts in support of our commodity derivative contracts.

Fair Value

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

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

					Asset Fair Value Measurements Using
	Total				Quoted prices in active markets for identical assets (Level 1)				Significant other observable inputs (Level 2)				Significant unobservable inputs (Level 3)
	(in thousands)
As of December 31, 2019:
Crude oil derivative contracts	$	2,536			$	—			$	2,536			$	—
As of December 31, 2018:
Crude oil derivative contracts	$	3,526			$	—			$	3,526			$	—
					Liability Fair Value Measurements Using
	Total				Quoted prices in active markets for identical assets (Level 1)				Significant other observable inputs (Level 2)				Significant unobservable inputs (Level 3)
	(in thousands)
As of December 31, 2019:
Crude oil derivative contracts	$	60			$	—			$	60			$	—
As of December 31, 2018:
Crude oil derivative contracts	$	1,642			$	—			$	1,642			$	—

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

	December 31, 2019				December 31, 2018
	(in thousands)
Revolving credit facility	$	1,456,000			$	1,224,000
4.75% senior notes due October 1, 2023	500,000				500,000
5.50% senior notes due September 15, 2024	750,000				750,000
5.50% senior notes due January 15, 2028	750,000				750,000
Less: Deferred financing costs, net (1)	( 18,004		)		( 21,421		)
Plus: Unamortized premium on 2028 Notes	3,028				3,379
Total long-term debt, net	$	3,441,024			$	3,205,958

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

Senior Unsecured Notes

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

The Issuers have previously issued $ 500 million in aggregate principal amount of 4.75 % senior notes due 2023 on September 26, 2018. The Indenture governing the 2023 Notes contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all TEP's properties to, another person.

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

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

The 2023 Notes, 2024 Notes, and 2028 Notes are together referred to as the "Senior Notes." As of December 31, 2019 , TEP was in compliance with the covenants required under the Indentures.

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Revolving Credit Facility

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

	December 31, 2019				December 31, 2018
	(in thousands)
Total capacity under the revolving credit facility	$	2,250,000			$	2,250,000
Less: Outstanding borrowings under the revolving credit facility	( 1,456,000		)		( 1,224,000		)
Less: Letters of credit issued under the revolving credit facility	( 94		)		( 94		)
Available capacity under the revolving credit facility	$	793,906			$	1,025,906

On February 22, 2019, TEP and certain of its subsidiaries entered into a Consent and Amendment No. 2 to the Second Amended and Restated Credit Agreement (the "Consent and Amendment") with Wells Fargo Bank, National Association, as administrative agent, and the required lenders party thereto. The Consent and Amendment modified that certain Second Amended and Restated Credit Agreement dated as of June 2, 2017, as previously amended by that certain Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of July 26, 2018 (as amended, the "Credit Agreement"). The Credit Agreement governs our revolving credit facility, which matures on June 2, 2022.

In the Consent and Amendment, the required lenders under the Credit Agreement (i) consented to the March 2019 Blackstone Acquisition pursuant to the terms and conditions of the Purchase Agreement, (ii) agreed that no Default (as defined in the Credit Agreement) under the Credit Agreement, if any, that may have resulted from a Change in Control (as defined in the Credit Agreement) caused by the consummation of the March 2019 Blackstone Acquisition pursuant to the terms and conditions set forth in the Purchase Agreement will be deemed to have occurred, and (iii) agreed to modify the definition of "Permitted Holders" in Section 1.01 of the Credit Agreement (which is used in the definition of Change in Control) to reflect the change in ownership as a result of the March 2019 Blackstone Acquisition.

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

The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP's ability (as well as the ability of its restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions, including distributions from available cash, if a default or event of default under the credit agreement then exists or would result therefrom, change the nature of its business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, TEP is required to maintain a consolidated leverage ratio of not more than 5.50 to 1.00, a consolidated senior secured leverage ratio of not more than 3.75 to 1.00 and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of December 31, 2019 , TEP was in compliance with the covenants required under its revolving credit facility.

The unused portion of the revolving credit facility is subject to a commitment fee, which ranges from 0.250 % to 0.375 % , based on TEP's total leverage ratio. As of December 31, 2019 , the weighted average interest rate on outstanding borrowings under the revolving credit facility was 3.13 % . During the year ended December 31, 2019 , the weighted average effective interest rate under the revolving credit facility, including the interest on outstanding borrowings under the revolving credit facility, commitment fees, and amortization of deferred financing costs, was 4.18 % .

Tallgrass Equity Revolving Credit Facility

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

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Fair Value

The following table sets forth the carrying amount and fair value of long-term debt, which is not measured at fair value in the consolidated balance sheets as of December 31, 2019 and 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 December 31, 2019:
Revolving credit facility	$	—			$	1,456,000			$	—			$	1,456,000			$	1,456,000
2023 Notes	$	—			$	500,065			$	—			$	500,065			$	495,750
2024 Notes	$	—			$	754,043			$	—			$	754,043			$	742,723
2028 Notes	$	—			$	735,375			$	—			$	735,375			$	746,551
As of December 31, 2018:
Revolving credit facility	$	—			$	1,224,000			$	—			$	1,224,000			$	1,224,000
2023 Notes	$	—			$	485,285			$	—			$	485,285			$	494,603
2024 Notes	$	—			$	737,745			$	—			$	737,745			$	741,196
2028 Notes	$	—			$	726,503			$	—			$	726,503			$	746,159

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

TGE Dividends to Holders of Class A Shares

The following table details the dividends for the periods indicated:

Three Months Ended		Date Paid		Dividends to Class A Shareholders				Dividends per Class A Share
				(in thousands, except per share amounts)
December 31, 2019		Not applicable		$	—			$	—
September 30, 2019		November 14, 2019		98,559				0.5500
June 30, 2019		August 14, 2019		96,767				0.5400
March 31, 2019		May 15, 2019		94,975				0.5300
December 31, 2018		February 14, 2019		81,304				0.5200
September 30, 2018		November 14, 2018		79,717				0.5100
June 30, 2018		August 14, 2018		77,052				0.4975
March 31, 2018		May 15, 2018		28,316				0.4875
December 31, 2017		February 14, 2018		21,346				0.3675
September 30, 2017		November 14, 2017		20,617				0.3550
June 30, 2017		August 14, 2017		19,891				0.3425
March 31, 2017		May 15, 2017		16,697				0.2875

As a result of the Take-Private Merger Agreement discussed in Note 1 – Description of Business , TGE has agreed to not pay dividends with respect to its Class A shares and to not permit Tallgrass Equity to pay any distributions on its TE Units during the pendency of the transactions contemplated by the Take-Private Merger Agreement, in each case, without the prior written consent of Buyer. Therefore, no dividends have been declared for the three months ended December 31, 2019. However, in the event the Take-Private Merger Agreement is terminated, the board of directors of our general partner will

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promptly fix a record date and declare and pay a dividend to the holders of Class A shares in an amount equal to the amount of dividends that otherwise would have been paid during the pendency of the transactions contemplated by the Take-Private Merger Agreement, all in accordance with our partnership agreement.

Subsidiary Distributions

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

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

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

Exchange Rights

Our current Class B shareholders (collectively, the "Exchange Right Holders") own an equal number of TE Units. The Exchange Right Holders, and any permitted transferees of their TE Units, each have the right to exchange all or a portion of their TE Units for Class A shares at an exchange ratio of one Class A share for each TE Unit exchanged, which we refer to as the Exchange Right. The Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us. Upon such exchange, we will cancel the Class B shares received from the exercising party. During the year ended December 31, 2019 , 21,751,018 Class A shares were issued and an equal number of Class B shares were cancelled as a result of the exercise of the Exchange Right. During the year ended December 31, 2018, 2,821,332 Class A shares were issued and an equal number of Class B shares were cancelled as a result of the exercise of the Exchange Right.

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

Equity Distribution Agreements

Neither TGE nor TEP currently have equity distribution agreements in place. TEP was previously a party to equity distribution agreements pursuant to which it sold from time to time through a group of managers, as its sales agents, TEP common units representing limited partner interests. Following the TEP Merger, these agreements were terminated effective July 2, 2018.

During the year ended December 31, 2018 , TEP did not issue any common units under its equity distribution agreements. During the year ended December 31, 2017 , TEP issued and sold 2,341,061 common units with a weighted average sales price of $ 48.82 per unit under its equity distribution agreements for net cash proceeds of approximately $ 112.4 million (net of approximately $ 1.9 million in commissions and professional service expenses). TEP used the net cash proceeds for general partnership purposes.

Repurchase of TEP Common Units Owned by TD

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

Noncontrolling Interests

As of December 31, 2019 , noncontrolling interests in our subsidiaries consisted of a 36.25 % interest in Tallgrass Equity held by the Exchange Right Holders, as well as noncontrolling interests in certain subsidiaries held by unaffiliated third parties,

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including an approximate 40 % membership interest in Deeprock Development, an approximate 25 % membership interest in BNN West Texas, LLC ("BNN West Texas"), a 37 % membership interest in BNN Colorado, a 20 % common membership interest in PLT, and an approximate 8 % membership interest in BNN Eastern. During the year ended December 31, 2019 , we recognized contributions from and distributions to noncontrolling interests of $ 2.3 million and $ 237.4 million , respectively. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $ 229.9 million and distributions to Deeprock Development, BNN West Texas, BNN Colorado, and BNN Eastern noncontrolling interests of $ 7.5 million in the aggregate.

During the year ended December 31, 2018 , we recognized contributions from and made distributions to noncontrolling interests of $ 1.8 million and $ 327.6 million , respectively. Distributions to noncontrolling interests consisted of Tallgrass Equity distributions to the Exchange Right Holders of $ 223.7 million , distributions to TEP unitholders of $ 97.7 million , and distributions to Pony Express and Deeprock Development noncontrolling interests of $ 6.2 million in the aggregate.

During the year ended December 31, 2017 , we recognized contributions from and made distributions to noncontrolling interests of $ 1.6 million and $ 317.1 million , respectively. Distributions to noncontrolling interests consisted of distributions to TEP unitholders of $ 185.7 million , Tallgrass Equity distributions to the Exchange Right Holders of $ 125.2 million , and distributions to Pony Express and Deeprock Development noncontrolling interests of $ 6.2 million in the aggregate.

Other Contributions and Distributions

During the year ended December 31, 2018 , TGE recognized the following other contributions and distributions:

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

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

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

During the year ended December 31, 2017 , TGE recognized the following other contributions and distributions:

•	TEP was deemed to have made a noncash capital distribution of $ 57.7 million , which represents the excess purchase price over the $ 82.3 million carrying value of the Terminals and NatGas net assets acquired January 1, 2017;

•	TEP was deemed to have received a noncash capital contribution of $ 63.7 million , which represents the excess carrying value of the additional 24.99 % membership interest in Rockies Express acquired March 31, 2017 over the fair value of the consideration paid; and

•	TEP received contributions from TD of $ 2.3 million primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 20 – Legal and Environmental Matters .

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Disaggregated Revenue

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

	Year Ended December 31, 2019
	Natural Gas Transportation segment				Crude Oil Transportation segment				Gathering, Processing, & Terminalling segment				Corporate and Other				Total Revenue
	(in thousands)
Crude oil transportation - committed shipper revenue	$	—			$	395,297			$	—			$	—			$	395,297
Natural gas transportation - firm service	125,170				—				—				( 2,161		)		123,009
Water business services	—				—				102,287				—				102,287
Natural gas gathering & processing fees	—				—				25,679				—				25,679
All other (1)	14,040				80,520				20,977				( 74,377		)		41,160
Total service revenue	139,210				475,817				148,943				( 76,538		)		687,432
Natural gas liquids sales	—				—				68,238				—				68,238
Natural gas sales	542				—				35,935				—				36,477
Crude oil sales	—				10,830				622				—				11,452
Total commodity sales revenue	542				10,830				104,795				—				116,167
Total revenue from contracts with customers	139,752				486,647				253,738				( 76,538		)		803,599
Other revenue (2)	—				—				82,157				( 17,208		)		64,949
Total revenue (3)	$	139,752			$	486,647			$	335,895			$	( 93,746	)		$	868,548

	Year Ended December 31, 2018
	Natural Gas Transportation segment				Crude Oil Transportation segment				Gathering, Processing, & Terminalling segment				Corporate and Other				Total Revenue
	(in thousands)
Crude oil transportation - committed shipper revenue	$	—			$	392,276			$	—			$	—			$	392,276
Natural gas transportation - firm service	128,041				—				—				( 4,585		)		123,456
Water business services	—				—				52,333				—				52,333
Natural gas gathering & processing fees	—				—				24,109				—				24,109
All other (1)	11,223				45,888				18,444				( 53,950		)		21,605
Total service revenue	139,264				438,164				94,886				( 58,535		)		613,779
Natural gas liquids sales	—				—				101,382				—				101,382
Natural gas sales	1,195				—				29,558				—				30,753
Crude oil sales	—				6,290				652				—				6,942
Total commodity sales revenue	1,195				6,290				131,592				—				139,077
Total revenue from contracts with customers	140,459				444,454				226,478				( 58,535		)		752,856
Other revenue (2)	—				—				53,187				( 12,784		)		40,403
Total revenue (3)	$	140,459			$	444,454			$	279,665			$	( 71,319	)		$	793,259

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

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

(3)	Excludes revenue recognized at unconsolidated investments of $ 931.0 million and $ 930.8 million for the years ended December 31, 2019 and 2018 , respectively. See Note 7 – Investments in Unconsolidated Affiliates for additional information.

Performance Obligations

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

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

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

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

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

On December 31, 2019 , we had $ 1.6 billion of remaining performance obligations at our consolidated subsidiaries, which we refer to as total backlog. Total backlog includes performance obligations under long-term crude oil transportation contracts with committed shippers, natural gas firm transportation and firm storage contracts, and certain water business service contracts with minimum volume commitments, and excludes variable consideration that is not estimated at contract inception, as discussed further below. We expect to recognize the total backlog during future periods as follows (in thousands):

Year		Estimated Revenue
2020		$	398,647
2021		287,026
2022		281,798
2023		245,006
2024		206,499
Thereafter		218,956
Total		$	1,637,932

Contract Estimates

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

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

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

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

Contract Balances

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

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

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

Balances associated with our contracts with customers were as follows:

		Contract Liabilities
		(in thousands)
Balance at January 1, 2018		$	88,471
Additions		34,613
Amounts recognized as revenue		( 11,989		)
Balance at December 31, 2018		111,095
Additions		35,923
Amounts recognized as revenue		( 19,086		)
Balance at December 31, 2019		$	127,932

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	December 31, 2019				December 31, 2018				January 1, 2018
	(in thousands)
Accounts receivable from contracts with customers	$	80,756			$	80,935			$	61,888
Other accounts receivable (1)	226,756				151,414				56,727
Receivable from related parties	16,769				3,748				1,340
Accounts receivable, net	$	324,281			$	236,097			$	119,955

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

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

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

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

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

For the years ended December 31, 2019 , 2018 , and 2017 operating lease cost was $ 1.6 million , $ 0.8 million , and $ 9.1 million , respectively. For the year ended December 31, 2019 , cash paid included in operating cash flows was $ 1.5 million . During these periods the existing finance lease did not have any lease payments.

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

	Balance Sheet Location		December 31, 2019
Operating Leases:			(in thousands, except lease term and discount rate)
Operating lease right-of-use assets	Deferred charges and other assets		$	12,629		(1)
Current operating lease liabilities	Other current liabilities		$	1,497		(1)
Non-current operating lease liabilities	Other long-term liabilities and deferred credits		$	11,231		(1)
Finance Leases:
Finance lease right-of-use asset (2)	Property, plant and equipment, net		$	30,704
Weighted Average Remaining Lease Term:
Operating leases			15.3 years
Finance leases			38.9 years
Weighted Average Discount Rate:
Operating leases			5.82		%
Finance leases			7.01		%

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

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

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

Year		Operating Leases				Finance Leases (1)
		(in thousands)
2020		$	2,247			$	449
2021		1,561				449
2022		1,021				449
2023		946				449
2024		910				467
Thereafter		13,644				17,303
Total lease payments		20,329				19,566
Less: discounting for present value and other adjustments		( 7,601		)		( 19,566		)
Present value of lease liabilities		$	12,728			$	—

(1)

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

Under various lease agreements, Tallgrass Midstream, LLC ("TMID"), as lessor, leases capacity on NGL pipelines that were constructed for third parties, and Deeprock Development, as lessor, leases capacity at certain of its storage facilities. Rental income for these arrangements was approximately $ 9.4 million , $ 10.9 million , and $ 3.8 million for the years ended December 31, 2019 , 2018 , and 2017 respectively, and was recorded as "Processing and other revenues" in the accompanying consolidated statements of income. Under a lease agreement initially effective November 13, 2012, Tallgrass Interstate Gas Transmission, LLC ("TIGT"), as lessor, leases a portion of its office space to a third party. Rental income was approximately

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$ 0.7 million , $ 0.8 million , and $ 0.8 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively, and was recorded as "Other income (expense), net" in the accompanying consolidated statements of income.

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

Year		Total
		(in thousands)
2020		$	5,613
2021		3,773
2022		3,773
2023		3,773
2024		3,773
Thereafter		3,580
Total		$	24,285

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

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

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

See Note 13 – Leases for discussion regarding obligations under operating and finance leases.

Other Purchase Obligations

At December 31, 2019 , future minimum commitments under long-term, non-cancelable contracts for service contracts, right of way ("ROW") agreements not accounted for as leases, and other purchase obligations were as follows (in thousands):

Year		Total
2020		$	16,260
2021		6,618
2022		5,753
2023		4,823
2024		2,141
Thereafter		20,255
Total		$	55,850

Capital Expenditures

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

Diluted net income per Class A share is determined by dividing net income attributable to TGE by the weighted average number of outstanding diluted Class A shares during the period. For purposes of calculating diluted net income per Class A share, we considered the impact of possible future exercises of the Exchange Right by the Exchange Right Holders on both net income attributable to TGE and the diluted weighted average number of Class A shares outstanding. The Exchange Right Holders refers to the group of persons who collectively own all of TGE's outstanding Class B shares and an equivalent number of TE Units. The Exchange Right Holders are entitled to exercise the right to exchange their TE Units (together with an equivalent number of Class B shares) for Class A shares at an exchange ratio of one Class A share for each TE Unit exchanged, which we refer to as the Exchange Right. As of December 31, 2019 , the Exchange Right Holders primarily consist of certain of the Sponsor Entities and certain current and former members of our management.

Pursuant to the TGE partnership agreement and the Tallgrass Equity limited liability company agreement, our capital structure and the capital structure of Tallgrass Equity will generally replicate one another in order to maintain the one-for-one exchange ratio between the TE Units and Class B shares, on the one hand, and our Class A shares, on the other hand. As a result, the exchange of any Class B shares for Class A shares does not have a dilutive effect on basic net income per Class A share. However, for the years ended December 31, 2019 and 2018, the assumed issuance of TGE Equity Participation Shares would have had a dilutive effect on basic net income per Class A share as shown in the table below. The potential issuance of TGE Equity Participation Shares would not have had a dilutive effect on the basic net loss per Class A share for the year ended December 31, 2017.

The following table illustrates the calculation of net income per Class A share for the years ended December 31, 2019 , 2018 , and 2017 :

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

During the years ended December 31, 2019 , 2018 , and 2017 , one non-affiliated customer, Continental Resources, Inc. ("Continental Resources"), accounted for $ 85.4 million ( 10 % ), $ 81.9 million ( 10 % ), and $ 100.2 million ( 15 % ), of our total operating revenues, respectively. Revenues from Continental Resources for the years ended December 31, 2019 and 2018 were earned in our Crude Oil Transportation and Gathering, Processing & Terminalling segments. Revenues from Continental Resources for the year ended December 31, 2017 were earned in our Crude Oil Transportation segment.

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For the year ended December 31, 2019 , the percentage of segment revenues from the top ten non-affiliated customers for each segment was as follows:

		Percentage of Segment Revenue
Natural Gas Transportation		55 %
Crude Oil Transportation		80 %
Gathering, Processing & Terminalling		50 %

We attempt to mitigate credit risk by seeking credit support, such as letters of credit, prepayments or other financial guarantees from customers with specific credit concerns.

Long-term Incentive Plan

We have two long-term incentive plans. The Tallgrass Energy GP, LLC Long-Term Incentive Plan (f/k/a the TEGP Management, LLC Long-Term Incentive Plan), was originally adopted by our general partner effective as of May 1, 2015, and was amended and restated effective August 2, 2018 (as amended, the "TGE LTIP"). In addition, the Tallgrass MLP GP, LLC Long-Term Incentive Plan was originally adopted by TEP GP effective as of May 13, 2013, and was amended and restated effective August 2, 2018 (as amended, the "Legacy LTIP" and together with the TGE LTIP, the "Plans"). In connection with the completion of the TEP Merger effective June 30, 2018, the Legacy LTIP was assumed by our general partner.

Awards under the Plans may consist of, among others, unrestricted shares, restricted shares, equity participation shares, options and share appreciation rights which may be granted to (i) the employees of our general partner and its affiliates who perform services for us, (ii) the non-employee directors of our general partner and (iii) the consultants who perform services for us. The TGE LTIP limits the number of shares that may be delivered pursuant to awards to 3,144,589 Class A shares, and the Legacy LTIP limits the number of shares that may be delivered pursuant to awards under such plan to 20,000,000 Class A shares, subject in each case to any adjustment due to recapitalization, reorganization or a similar event permitted under the applicable Plan. Shares that are forfeited or withheld to satisfy exercise price or tax withholding obligations are available for delivery pursuant to other awards under the applicable Plan. The Plans are administered by the board of directors of our general partner or a committee thereof, which is referred to as the plan administrator.

Equity Participation Shares

Vesting of the Equity Participation Shares granted to date is contingent on certain service and, in some cases, performance conditions. The Equity Participation Shares are non-participating; as such participants are not entitled to receive any dividends with respect to the Equity Participation Shares unless the participant receives a separate grant of Distribution Equivalent Rights. At this time, no grants of Distribution Equivalent Rights have been made.

The Equity Participation Share grants under the Plans are measured at their grant date fair value. The Equity Participation Shares are non-participating; therefore, the grant date fair value is discounted from the grant date fair value of TGE's Class A shares for the present value of the expected future dividends during the vesting period. Effective June 30, 2018 with the completion of the TEP Merger, as discussed in Note 1 – Description of Business , TEP's outstanding Equity Participation Units were converted to Equity Participation Shares at a ratio of 2.0 Equity Participation Shares for each outstanding TEP Equity Participation Unit. Total equity-based compensation cost related to the Equity Participation Share grants was approximately $ 31.6 million , $ 7.6 million , and $ 1.6 million for the years ended December 31, 2019 , 2018 , and 2017 respectively, excluding costs associated with TEP's Equity Participation Units prior to the TEP Merger. As of December 31, 2019 , $ 60.0 million of total compensation cost related to non-vested Equity Participation Shares is expected to be recognized over a weighted-average period of 3.7 years .

The March 2019 Blackstone Acquisition discussed in Note 1 – Description of Business constituted a change in control event under certain Equity Participation Share agreements outstanding under the LTIP plan, resulting in the accelerated vesting of 1,092,637 Class A shares (net of tax withholding of approximately 543,909 Class A shares) with a weighted average grant date fair value of $ 18.82 . These Class A shares were issued in April 2019. The accelerated vesting resulted in the recognition of equity-based compensation costs of $ 12.5 million in "General and administrative" costs in the consolidated statements of income during the year ended December 31, 2019 .

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The following table summarizes the changes in the Equity Participation Shares outstanding for the years ended December 31, 2019 , 2018 and 2017 :

	Equity Participation Shares			Weighted Average Grant Date Fair Value
Outstanding at January 1, 2017	205,000			$	25.83
Granted	30,000			23.66
Vested	( 10,002	)		( 14.26		)
Outstanding at December 31, 2017	224,998			25.91
Granted	1,138,200			17.01
Converted (1)	1,786,310			18.20
Vested	( 20,664	)		( 19.19		)
Forfeited	( 79,200	)		( 20.62		)
Outstanding at December 31, 2018	3,049,644			18.25
Granted	3,204,850			18.14
Vested (2)	( 2,316,294	)		( 18.75		)
Forfeited	( 55,200	)		( 17.18		)
Outstanding at December 31, 2019	3,883,000			$	17.85

(1)	Reflects TEP's outstanding Equity Participation Units that were converted to Equity Participation Shares at a ratio of 2.0 Equity Participation Shares for each outstanding TEP Equity Participation Unit upon completion of the TEP Merger as discussed above.

(2)	Includes the accelerated vesting of 1,478,986 Class A shares (net of tax withholding of approximately 707,560 Class A shares) upon the change in control event as discussed above and other 2019 transactions.

Income tax expense is estimated using the tax rate in effect or to be in effect during the relevant periods in the jurisdictions in which we operate. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes and are stated at enacted tax rates expected to be in effect when taxes are actually paid or recovered. To the extent we do not consider it more likely than not that a deferred tax asset will be recovered, a valuation allowance is established. We record a valuation allowance to reduce our deferred tax assets to the amount we believe is more likely than not to be realized. In making these determinations we consider historical and projected taxable income, and ongoing prudent and feasible tax planning strategies, in assessing the appropriateness of a valuation allowance. Changes in tax legislation are included in the relevant computations in the period in which such changes are effective.

U.S. Federal and State Taxes

Although we are organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U.S. federal and state income taxes. We are projecting a loss for both U.S. federal and state income taxes for the tax year ended December 31, 2019 . As a result, TGE has no current provision for income taxes for the year ended December 31, 2019 , however, as discussed below one of our consolidated subsidiaries recognized current income tax expense during the year ended December 31, 2019 .

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Tax Components

Components of income tax expense are as follows:

	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Current income tax expense:
Federal income tax	$	728		(1)	$	—			$	—
Deferred income tax expense:
Federal income tax	65,009				41,585				200,787
State income tax	4,856				14,124				7,671
Total deferred income tax expense	69,865				55,709				208,458
Total income tax expense	$	70,593			$	55,709			$	208,458

(1)	As discussed in Note 3 – Acquisitions and Dispositions , a newly formed indirect subsidiary of TGE acquired the outstanding stock of an entity classified as a C corporation for U.S. federal income tax purposes effective May 1, 2019. As a result, we recognized approximately $ 0.7 million of current income taxes during the year ended December 31, 2019 .

The difference between tax expense based on the statuary federal income tax rate and our effective tax expense is summarized as follows:

	Year Ended December 31,
	2019				2018				2017
	(in thousands)
Net income before tax	$	519,148			$	523,380			$	432,443
Less: Net income attributable to noncontrolling interests	( 199,746		)		( 330,544		)		( 352,714		)
Net income subject to tax	$	319,402			$	192,836			$	79,729
Federal statutory income tax rate	21		%		21		%		35		%
Income tax at statutory rate	$	67,074			$	40,496			$	27,905
State income taxes, net of federal benefit	8,413				5,419				2,392
Change in state tax rate	1,214				8,705				1,353
Valuation allowance	( 4,771		)		—				3,926
Other	( 1,337		)		1,089				—
Total income tax expense before change in tax legislation	$	70,593			$	55,709			$	35,576
Impact of federal tax legislation on deferred tax asset	—				—				172,037
Impact of federal tax legislation on valuation allowance	—				—				845
Total income tax expense	$	70,593			$	55,709			$	208,458
Effective tax rate	13.6		%		10.6		%		48.2		%

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Deferred tax assets result from the following:

	December 31, 2019				December 31, 2018
	(in thousands)
Deferred tax assets:
Investment in partnerships	$	149,336			$	198,290
Net operating losses	168,866				80,012
Deferred tax assets before valuation allowance	$	318,202			$	278,302
Valuation allowance	—				( 4,771		)
Total deferred tax assets	$	318,202			$	273,531
Deferred tax liabilities:
Equity earnings adjustment pursuant to ASC 606	$	523			$	817
Property, plant & equipment in corporate subsidiary	8,207				—
Total deferred tax liabilities	$	8,730			$	817

On May 12, 2015, as a result of the transfer of the ownership interest in Tallgrass Equity as part of the Reorganization Transactions in connection with the TGE IPO, we recognized a deferred tax asset of $ 445.2 million . During 2018, a portion of the Exchange Right Holders exercised their Exchange Right as discussed in Note 11 – Partnership Equity . In connection with the resulting transfer of TE Units, we recognized an additional deferred tax asset of $ 15.4 million . During 2019, we recognized an additional deferred tax asset of $ 115.4 million upon exercise of the Exchange Right, as discussed in Note 11 – Partnership Equity , with respect to 21,751,018 Class B shares to Class A shares in connection with the March 2019 Blackstone Acquisition discussed in Note 1 – Description of Business . These transfers of ownership were accounted for at the historical carrying basis for GAAP accounting purposes, but recorded at the value of the consideration paid for U.S. federal income tax purposes. The tax rates that apply when the deferred tax balances ultimately reverse are inherent in the realization of the deferred tax balances. State tax rates can change from year to year based upon changes in both state apportionment percentages and state tax laws.

As of December 31, 2019 , we had a federal net operating loss carry forward of $ 697.6 million and various state net operating loss carry forwards. The determination of the state net operating loss carry forwards is dependent upon apportionment percentages and state laws that can change from year to year and impact the amount of such carry forwards. If not utilized, the federal net operating loss carry forward will expire between 2035 and 2037 (net operating losses generated in tax years beginning after December 31, 2017 can be carried forward indefinitely) and the state operating loss carry forwards will expire between 2025 and 2039. During the year ended December 31, 2019 , we released the previously recorded valuation allowance of $ 4.8 million , as it is more likely than not that the deferred tax assets related to federal and state net operating losses will be realized.

On December 22, 2017, legislation referred to as the "Tax Cuts and Jobs Act" ("TCJA") was signed into law. Substantially all provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes amendments to the Internal Revenue Code of 1986, that significantly change the taxation of individuals and business entities. Pursuant to ASC Topic 740, Income Taxes (ASC 740), we recognized the tax effect of the TCJA changes during the year ended December 31, 2017, the period in which the law was enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Accordingly, we remeasured our deferred tax asset based on the new tax rates, resulting in an increase to our tax provision of $ 172.9 million for the year ended December 31, 2017.

The 2016 through 2019 tax years are open to examination for federal and state income tax.

Ratemaking Process - Natural Gas Transportation & Storage

Transportation and storage services on interstate natural gas pipelines are contracted under one of three rate types: recourse, discount, or negotiated. Recourse rates are calculated based on the cost of service being provided and include an allowable rate of return for the pipeline. Recourse rates are established through a FERC rate proceeding and remain effective until a subsequent rate proceeding is filed and approved by the FERC. Discount rates are offered at a discount to the then-effective maximum recourse rate. Discount rates are typically effective for an established term and can vary based on movement of the underlying recourse rate. Negotiated rates can be higher or lower than the then-effective maximum recourse

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rate, subject to agreement between the pipeline and shipper and approval by the FERC. Negotiated rates are also entered into for a defined term but do not change based on adjustments in the applicable recourse rate for that type of service.

On May 1, 2019, TIGT filed with the FERC a pre–filing settlement in Docket No. RP19-423-001 that establishes, among other things, settlement rates reflecting an overall decrease to recourse rates, contract extensions for maximum recourse rate firm contracts through May 31, 2023, and a rate moratorium period through May 31, 2023. The settlement also requires that TIGT file a new general rate case pursuant to Section 4 of the Natural Gas Act ("NGA") on June 1, 2023, provided that TIGT has not preempted this mandatory filing requirement by filing on or before June 1, 2023 for approval of a new pre-filing settlement. The settlement also provided for contract extensions for maximum recourse rate firm contracts through May 31, 2023 and established a rate moratorium that will result in TIGT filing a new rate case or pre-filing settlement on or before June 1, 2023. TIGT's settlement was approved on November 8, 2019 in an order issued by the FERC.

On June 29, 2018, Trailblazer Pipeline filed a general rate case with the FERC pursuant to Section 4 of the NGA in Docket No. RP18-922-000. Trailblazer and its customers reached a settlement in principle on October 2, 2019. The settlement continues the bifurcated rate treatment for Trailblazer's "Existing System" and "Expansion System" and maintains the existing fuel retainage and revenue crediting mechanisms. Shippers with firm contracts on the Existing System were given the opportunity to convert their contracts to negotiated rate agreements that would terminate no earlier than December 31, 2026. A rate moratorium will be in effect through December 31, 2025. The settlement was filed with the FERC on December 20, 2019 and is currently awaiting approval from the FERC.

The majority of services provided by Rockies Express are contracted under negotiated rate agreements. Currently, there are no regulatory proceedings challenging the transportation rates of Rockies Express.

Ratemaking Process - Crude Oil Transportation

Pony Express has three types of transportation rates on its system. The first are contract rates, which are contractually agreed to and given in exchange for either commitments to ship on the pipeline or acreage dedications ("Contract Rates"). Contract Rates are generally honored by the FERC during the term of the relevant contracts. The majority of Pony Express' revenue is derived from Contract Rates. The second are indexed rates, which means they may be increased or decreased at any time provided they do not exceed the index ceiling ("Indexed Rates"). The index ceiling is calculated yearly by applying the FERC-approved inflationary adjustment, which may be positive or negative. These rates can be challenged on a cost-of-service basis. Pony Express last adjusted its Indexed Rates in Docket No. IS19-638-000 effective July 1, 2019. The third are volume incentive rates, which reflect a discount to the Indexed Rates and are available to all shippers without a contractual commitment to ship on the pipeline ("Volume Incentive Rates"). These discounts are discretionary and may not be challenged on a cost-of-service basis; however, should Pony Express' Indexed Rates be lowered due to a cost-of-service challenge, the Volume Incentive Rates would also be reduced if they are no longer below the Indexed Rates. Pony Express established its first Volume Incentive Rates effective November 1, 2019 in Docket No. IS20-3-000. Currently, there are no regulatory proceedings challenging transportation rates at Pony Express.

Powder River Gateway's crude oil pipeline systems operate with Contract Rates and Indexed Rates, which can be challenged on a cost-of-service basis. Currently, there are no regulatory proceedings challenging transportation rates at Powder River Gateway.

In 2020, the FERC will conduct its five-year index review to establish the new FERC approved adder, which will be in effect for the five-year period beginning July 1, 2021. The 2020 review will also consider, among other things, the effects of the Tax Cuts and Jobs Act of 2017 and any applicable impact on a crude oil pipeline's cost of service.

Other Regulatory Matters

In addition to the ratemaking proceedings discussed above, we have also made certain other regulatory filings with the FERC, including those further described below:

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

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

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

On March 2, 2018, Rockies Express submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub. Rockies Express filed this certificate application in conjunction with a concurrently filed certificate application by Cheyenne Connector, LLC ("Cheyenne Connector") for the Cheyenne Connector Pipeline further described below. On December 18, 2018, the FERC issued the Environmental Assessment. On September 20, 2019, the FERC issued an order approving the application. A notice to proceed with construction was issued on October 8, 2019.

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

On March 2, 2018, Cheyenne Connector submitted an application pursuant to section 7(c) of the NGA for a certificate of public convenience and necessity to construct and operate a 70 -mile, 36 -inch pipeline to transport natural gas from multiple gas processing plants in Weld County, Colorado to Rockies Express' Cheyenne Hub. On September 20, 2019, the FERC issued an order approving the application. A notice to proceed with construction was issued on October 8, 2019.

Legal

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

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

Rockies Express

EM Energy Ohio, LLC

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

Ohio Public Utility Excise Tax

The Ohio Tax Commissioner has assessed Rockies Express a public utility excise tax on transactions concerning product that entered and exited the Rockies Express Pipeline within the State of Ohio. This tax applies to gross receipts from all business conducted within the state, but exempts all receipts derived wholly from interstate business. Rockies Express disputed its obligation to pay Ohio's public utility excise tax under the relevant Ohio statute, but made payments in the amounts assessed in order to preserve its right to appeal. On February 11, 2020, the Ohio Supreme Court reached a final decision adverse to the position taken by Rockies Express.

As a result of this decision, Rockies Express no longer believes that the refund of prior payments is probable and accordingly has recognized expense totaling $ 15.8 million during the year ended December 31, 2019. The expense recognized represents payments made to the state of Ohio totaling $ 12.3 million and an additional $ 3.5 million for amounts expected to be assessed for the period from May 1, 2019 through December 31, 2019.

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Ultra Resources

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

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

Michels Corporation

On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $ 24.2 million as the amount due.

On February 2, 2017, Rockies Express and Michels agreed to resolve Michels' claims for a $ 10 million cash payment by Rockies Express. The cash payment was inclusive of approximately $ 5.9 million that Rockies Express had been withholding from Michels. Subsequently, Rockies Express and Michels entered into a definitive agreement with respect to the settlement and Rockies Express made the $ 10 million cash payment to Michels on February 16, 2017.

Environmental, Health and Safety

We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We currently believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of $ 6.3 million and $ 7.4 million at December 31, 2019 and 2018 , respectively.

Rockies Express

Seneca Lateral

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

TMID and TIGT

Casper Gas Plant, EPA Notice of Violation

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

Casper Gas Plant, WDEQ Notice of Violation

On November 25, 2014, the WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as

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well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. TMID and TIGT entered into a Consent Decree to settle this matter with the WDEQ on March 8, 2019 and made an approximately $ 0.1 million penalty payment to the WDEQ.

Trailblazer

Pipeline Integrity Management Program

Starting in 2014 Trailblazer's operating capacity was decreased as a result of smart tool surveys that identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred approximately $ 21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing subscription levels or had a material adverse financial impact on us. However, Trailblazer continued performing remediation to increase and maximize its operating capacity over the long-term and spent approximately $ 21 million during 2018 for this pipe replacement and remediation work. As of October 2018, the pipeline was returned to its maximum allowable operating capacity.

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

Pony Express

Pipeline Integrity

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

Terminals

System Failures

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").

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

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

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

	Year Ended December 31,
	2019												2018												2017
Revenue:	Total Revenue				Inter- Segment				External Revenue				Total Revenue				Inter- Segment				External Revenue				Total Revenue				Inter- Segment				External Revenue
	(in thousands)
Natural Gas Transportation	$	139,752			$	( 2,179	)		$	137,573			$	140,459			$	( 4,661	)		$	135,798			$	141,021			$	( 6,694	)		$	134,327
Crude Oil Transportation	486,647				( 57,881		)		428,766				444,454				( 39,319		)		405,135				364,574				( 10,676		)		353,898
Gathering, Processing & Terminalling	335,895				( 33,686		)		302,209				279,665				( 27,339		)		252,326				186,211				( 18,538		)		167,673
Corporate and Other	—				—				—				—				—				—				—				—				—
Total revenue	$	962,294			$	( 93,746	)		$	868,548			$	864,578			$	( 71,319	)		$	793,259			$	691,806			$	( 35,908	)		$	655,898

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	Year Ended December 31,
	2019												2018												2017
Tallgrass Equity Adjusted EBITDA:	Total Adjusted EBITDA				Inter- Segment				External Adjusted EBITDA				Total Adjusted EBITDA				Inter- Segment				External Adjusted EBITDA				Total Adjusted EBITDA				Inter- Segment				External Adjusted EBITDA
	(in thousands)
Natural Gas Transportation	$	543,507			$	( 4,707	)		$	538,800			$	377,224			$	( 4,251	)		$	372,973			$	180,978			$	( 2,176	)		$	178,802
Crude Oil Transportation	344,333				( 19,903		)		324,430				239,330				( 8,147		)		231,183				140,785				4,878				145,663
Gathering, Processing & Terminalling	121,159				24,610				145,769				59,203				12,398				71,601				16,083				( 2,702		)		13,381
Corporate and Other	( 12,666		)		—				( 12,666		)		( 21,321		)		—				( 21,321		)		( 37,591		)		—				( 37,591		)
Reconciliation to Net Income:
Add:
Equity in earnings of unconsolidated investments (1)									325,385												237,197												66,922
(Loss) gain on disposal of assets (1)									( 354		)										4,630												189
Non-cash (loss) gain related to derivative instruments (1)									( 272		)										3,340												( 64		)
Other non-cash gain									724												—												—
Gain on remeasurement of unconsolidated investment (1)									—												—												2,744
Less:
Interest expense, net (1)									( 161,429		)										( 95,465		)										( 29,403		)
Depreciation and amortization expense (1)									( 127,503		)										( 74,998		)										( 26,131		)
Distributions from unconsolidated investments (1)									( 470,981		)										( 302,364		)										( 86,551		)
Non-cash compensation expense (1)									( 31,563		)										( 8,634		)										( 2,682		)
Deficiency payments, net (1)									( 16,992		)										( 14,443		)										( 7,701		)
Loss on debt retirement									—												( 2,245		)										—
Income tax expense (1)									( 70,578		)										( 55,709		)										( 208,458		)
Net income attributable to Exchange Right Holders									( 193,961		)										( 208,618		)										( 137,849		)
Net income (loss) attributable to TGE									$	248,809											$	137,127											$	( 128,729	)

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

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	Year Ended December 31,
Capital Expenditures:	2019				2018				2017
	(in thousands)
Natural Gas Transportation	$	86,892			$	112,529			$	16,705
Crude Oil Transportation	94,363				65,745				57,022
Gathering, Processing & Terminalling	96,168				185,732				71,417
Corporate and Other	8,230				4,867				—
Total capital expenditures	$	285,653			$	368,873			$	145,144

Unconsolidated Investments:	December 31, 2019				December 31, 2018
	(in thousands)
Natural Gas Transportation	$	1,811,051			$	1,794,987
Crude Oil Transportation	164,773				35,467
Gathering, Processing & Terminalling	30,395				31,232
Total unconsolidated investments	$	2,006,219			$	1,861,686

Assets:	December 31, 2019				December 31, 2018
	(in thousands)
Natural Gas Transportation	$	2,554,513			$	2,606,696
Crude Oil Transportation	1,734,278				1,423,740
Gathering, Processing & Terminalling	1,693,474				1,522,559
Corporate and Other	231,821				340,514
Total assets	$	6,214,086			$	5,893,509

The following tables summarize our unaudited quarterly financial data for 2019 and 2018 :

	Quarter Ended 2019
	First				Second				Third				Fourth
	(in thousands, except per unit amounts)
Total revenues	$	197,352			$	211,524			$	226,709			$	232,963
Operating income	$	70,464			$	89,596			$	105,866			$	86,834
Net income	$	102,392			$	126,230			$	128,489			$	91,444
Net income allocable to noncontrolling interests	$	( 51,805	)		$	( 54,611	)		$	( 55,965	)		$	( 37,365	)
Net income attributable to TGE	$	50,587			$	71,619			$	72,524			$	54,079
Basic net income per Class A Share	$	0.31			$	0.40			$	0.40			$	0.30
Diluted net income per Class A Share	$	0.31			$	0.40			$	0.40			$	0.30

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	Quarter Ended 2018
	First				Second				Third				Fourth
	(in thousands, except per unit amounts)
Total revenues	$	179,094			$	193,589			$	200,320			$	220,256
Operating income	$	81,913			$	79,275			$	90,084			$	99,359
Net income	$	114,313			$	109,701			$	118,712			$	124,945
Net income allocable to noncontrolling interests	$	( 97,578	)		$	( 108,638	)		$	( 59,162	)		$	( 65,166	)
Net income attributable to TGE	$	16,735			$	1,063			$	59,550			$	59,779
Basic net income per Class A Share	$	0.29			$	0.02			$	0.38			$	0.38
Diluted net income per Class A Share	$	0.29			$	0.02			$	0.38			$	0.38

During the second quarter of 2018, we recognized increased deferred income tax expense as a result of our increased ownership in TEP due to the TEP Merger and the resulting increase in income allocated to TGE.

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(1)	Mr. Brauchle has informed the board of directors of our general partner of his resignation from his position as the Executive Vice President and Chief Financial Officer effective on February 14, 2020.

(2)	The board of directors of our general partner has appointed Mr. Watkins as Executive Vice President and Chief Financial Officer effective on February 14, 2020, in addition to Mr. Watkins' current role as Chief Accounting Officer of our general partner.

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The first category of awards was granted by TGE in October 2018 (the "2018 Grants") and will vest on the earliest date on or after November 1, 2022, on which the average compounded annual distribution growth rate, based upon the regular quarterly distribution paid by TGE on, or immediately prior to, such date is at least 5% over an annualized distribution rate of $1.99 per Class A share, as determined by the board of directors of our general partner (the "Distribution Hurdle Date") as long as such Named Executive Officer remains continuously employed by us through the vesting date. If the Distribution Hurdle Date has not occurred by October 19, 2025, such equity participation shares will expire and terminate and no vesting will occur. Following consummation of the Take-Private Merger, the outstanding awards in this category will vest on November 1, 2022 without regard to whether the Distribution Hurdle Date has occurred. Mr. Watkins is the only Named Executive Officer that has any outstanding granted equity participation shares in this category. See "Potential Payments upon Termination or Change-in-Control" for a description of the conditions that would accelerate vesting of the 2018 Grants.

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The second category of awards was granted by TGE in March 2019 (the "2019 Grants") and will vest on the dates and in the percentages set forth in the applicable award agreement as long as such Named Executive Officer remains continuously employed by us through the vesting date. Messrs. Moler, Brauchle, Jones, and Watkins were granted equity participation shares in this category. Mr. Moler's equity participation shares will vest one-half on October 31, 2022 and the remaining one-half on October 31, 2023. Mr. Brauchle's equity participation shares will vest in full on December 31, 2020. Messrs. Jones' and Watkins' equity participation shares will vest one-half on October 31, 2023 and the remaining one-half on October 31, 2024.

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10,623,673 Performance Awards with a per Performance Award value equal to (i) the lower of (a) the volume-weighted average price of a Class A share over the 60-day period beginning November 1, 2024 and (b) $36.04/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 10.5% rate of return, minus (ii) a per share price of $32.95/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 10.5% rate of return;

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4,756,377 Performance Awards with a per Performance Award value equal to (i) the lower of (a) the volume-weighted average price of a Class A share over the 60-day period beginning November 1, 2024 and (b) $40.23/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming an 12.5% rate of return, minus (ii) a per share price of $36.04/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 12.5% rate of return; and

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2,752,095 Performance Awards with a per Performance Award value equal to (i) the lower of (a) the volume-weighted average price of a Class A share over the 60-day period beginning November 1, 2024 and (b) $44.79/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 15.0% rate of return, minus (ii) a per share price of $40.23/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 15.0% rate of return.

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7,082,449 Performance Awards with a per Performance Award value equal to (i) the lower of (a) the volume-weighted average price of a Class A share over the 60-day period beginning November 1, 2024 and (b) $36.04/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 10.5% rate of return, minus (ii) a per share price of $32.95/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 10.5% rate of return;

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3,170,918 Performance Awards with a per Performance Award value equal to (i) the lower of (a) the volume-weighted average price of a Class A share over the 60-day period beginning November 1, 2024 and (b) $40.23/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 12.5% rate of return, minus (ii) a per share price of $36.04/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 12.5% rate of return; and

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1,834,730 Performance Awards with a per Performance Award value equal to (i) the lower of (a) the volume-weighted average price of a Class A share over the 60-day period beginning November 1, 2024 and (b) $44.79/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 15.0% rate of return, minus (ii) a per share price of $40.23/share, with such price to be reduced based on the future value of any dividends paid between January 1, 2020 and December 31, 2024, assuming a 15.0% rate of return.

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•	Adjusted EBITDA of $965 million - $1.035 billion for the year ended December 31, 2019;

•	Cash Available for Dividends of $760 - $835 million for the year ended December 31, 2019;

•	Dividend coverage of greater than 1.25x for the year ended December 31, 2019; and

•	Dividend growth of approximately 6 - 8% for TGE.

•	Our Adjusted EBITDA for the year ended December 31, 2019 was approximately $996.3 million ;

•	Our Cash Available for Dividends for the year ended December 31, 2019 was approximately $798.2 million ;

•	Our dividend coverage for the nine months ended September 30, 2019 was approximately 1.35x, which was the last period prior to entering into the Take-Private Merger Agreement; and

•	Our dividends on Class A shares in the third quarter of 2019, our last dividend prior to entering into the Take-Private Merger Agreement, represented a 7.8% increase from the third quarter of 2018.

•	The completion of the Iron Horse Pipeline project, Guernsey Terminal facilities, and Pony Express expansion projects;

•	The receipt of the FERC approval to the applications pursuant to section 7(c) of the NGA for the Cheyenne Connector Pipeline and the Cheyenne Hub Enhancement Project;

•	The pre-filing settlement with respect to TIGT rate case and the settlement in principle with respect to the Trailblazer Pipeline rate case;

•	Third-party acquisitions in 2019, including the acquisition of CES in May 2019;

•	The extension of the Rockies Express revolving credit facility in November 2019; and

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•	The senior note offerings by Rockies Express in April 2019 of $550 million in aggregate principal amount of 4.95% senior notes due 2029 and in January 2020 of $750 million in aggregate principal amount composed of two tranches, $400 million of 3.60% senior notes due 2025 and $350 million of 4.80% senior notes due 2030.

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(1)	Reflects actual salary received. Salary adjustments are typically implemented during February, which results in odd amounts actually received by the indicated Named Executive Officer.

(2)	Represents discretionary cash bonuses paid in 2020 , 2019 and 2018 based on performance in 2019 , 2018 and 2017 , respectively, as well as a bonus of $500 after tax that was paid to all employees in 2017.

(3)

The amounts in this column include equity participation shares granted pursuant to the Plans. Each of our Named Executive Officers, with the exception of Mr. Dehaemers and Mr. Sheehy, received grants under the Plans in 2019 and 2018. In addition, Mr. Moler, Mr. Brauchle, and Mr. Jones each received grants in January 2019 as a component of their 2018 bonuses. Mr. Jones and Mr. Watkins were the only Named Executive Officers to receive grants under the Plans during 2017. These amounts represent the aggregate grant date fair value determined in accordance with ASC Topic 718 for equity participation units, or EPUs, granted under the Legacy LTIP prior to June 30, 2018 and equity participation shares, or EPSs granted under the Plans. Pursuant to SEC rules, the amounts shown in the Summary Compensation Table for awards subject to performance conditions are based on the probable outcome as of the date of grant and exclude the impact of estimated forfeitures. The EPUs and EPSs are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TEP's common units or TGE's Class A shares, as appropriate, for the present value of the expected (but non-participating) future dividends during the vesting period. For additional information, see Note 17 – Equity-Based Compensation . These amounts do not correspond to the actual value that will be recognized by the executive.

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(4)

The amounts in the column include the following: contributions under the 401(k) savings plan (includes $28,000 for Mr. Moler, $28,000 for Mr. Dehaemers, $1,731 for Mr. Sheehy, $27,989 for Mr. Brauchle, $28,000 for Mr. Jones, and $25,000 for Mr. Watkins for the year ended December 31, 2019; $27,500 for Mr. Moler, $27,500 for Mr. Dehaemers, $27,307 for Mr. Brauchle, $27,500 for Mr. Jones, and $24,712 for Mr. Watkins for the year ended December 31, 2018; and $27,000 for Mr. Moler, $27,000 for Mr. Dehaemers, $26,804 for Mr. Brauchle, $26,640 for Mr. Jones, and $22,492 for Mr. Watkins for the year ended December 31, 2017) and the dollar value of premiums paid for group life, accidental death and dismemberment insurance.

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(1)

The amounts in this column represent the aggregate grant date fair value determined in accordance with ASC Topic 718 for equity participation shares, or EPSs, granted under the Plans. Pursuant to SEC rules, the amounts shown in this table for awards subject to performance conditions, if applicable, are based on the probable outcome as of the date of grant and exclude the impact of estimated forfeitures. The EPSs are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TGE's Class A shares for the present value of the expected (but non-participating) future dividends during the vesting period. For additional information, see Note 17 – Equity-Based Compensation . These amounts do not correspond to the actual value that will be recognized by the executive.

(2)	These awards were granted on January 31, 2019 as a component of the 2018 bonus and vested immediately. The recipients of these awards received the Class A shares as a result of such vesting on February 7, 2020.

(3)	Vesting of the EPSs will occur in two parts, with one-half vesting on October 31, 2022 and the remaining one-half vesting on October 31, 2023, as long as Mr. Moler remains continuously employed by us through the vesting date.

(4)	Vesting of the EPSs will occur on December 31, 2020, as long as Mr. Brauchle remains continuously employed by us through the vesting date.

(5)	Vesting of the EPSs will occur in two parts, with one-half vesting on October 31, 2023 and the remaining one-half vesting on October 31, 2024, as long as such Named Executive Officer remains continuously employed by us through the vesting date.

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(1)	The award agreements pursuant to which the equity participation shares set forth above were granted provide for the settlement of the equity participation shares in Class A shares.

(2)	Reflects the closing price of $22.10 per Class A share at December 31, 2019.

(3)	Messrs. Moler, Brauchle, and Jones hold equity participation shares granted under the 2019 Grants described under "Elements of Compensation" above.

(4)	Mr. Watkins holds 35,000 equity participation shares under the 2018 Grants and 150,000 equity participation shares granted under the 2019 Grants, each as described under "Elements of Compensation" above.

(1)

Represents the gross number of EPSs that vested during the year ended December 31, 2019 . The actual number of Class A shares delivered to the Named Executive Officers was, in some cases, less than the number shown in the above table due to the withholding of Class A shares otherwise deliverable under the applicable award agreement to satisfy the tax withholding obligations related to the vesting of such EPSs.

(2)	The stated value realized upon vesting is computed by multiplying the closing market price of TGE's Class A shares on the date they vested by the number of units that vested .

(3)

Includes 23,250 EPSs granted to each of Messrs. Moler, Brauchle and Jones on January 31, 2019, which vested immediately upon grant, as an additional component of their 2018 bonus. Messrs. Moler, Brauchle and Jones were issued the Class A shares in respect of those awards on February 7, 2020 net of the Class A shares withheld to satisfy the tax withholding obligations related to the vesting of such EPSs.

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"Cause" means (i) the applicable executive's conviction of, or plea of nolo contendere to, any crime or offense constituting a felony under applicable law, other than motor vehicle violations for which no custodial penalty is imposed; (ii) the applicable executive's commission of fraud or embezzlement against Tallgrass Management or certain of its affiliates; (iii) gross neglect by the applicable executive of, or gross or willful misconduct of the applicable executive in connection with the performance of, his duties; (iv) the applicable executive's willful failure or refusal to carry out the reasonable and lawful instructions of the person to whom h reports; (v) the applicable executive's failure to perform the duties and responsibilities of his office as his primary business activity; (vi) a judicial determination that the applicable executive has breached his fiduciary duties with respect to Tallgrass Management or certain of its affiliates; or (vii) the applicable executive's willful and material breach of his obligations under any agreement between him and certain affiliates of Tallgrass Management that he fails to cure, if curable, within 30 days following written notice.

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"Good reason" means (i) a material diminution of the applicable executive's duties and responsibilities to Tallgrass Management or certain of its affiliates to a level inconsistent with those of his position; (ii) a material reduction in his cash compensation or the aggregate welfare benefits provided to him (excluding any reduction that is not limited to him specifically); (iii) with respect to Messrs. Moler, Brauchle, Jones and Watkins, a willful or intentional breach of the applicable employment agreement by Tallgrass Management, and with respect to Mr. Sheehy, a material breach of the Sheehy Employment Agreement by Tallgrass Management; (iv) with respect to Messrs. Moler and Sheehy, relocation of his primary work location to a location that is not within 30 miles of Leawood, Kansas and with respect to Messrs. Jones and Watkins, relocation of his primary work location to a location that is not within 30 miles of either Leawood, Kansas or Lakewood, Colorado; (v) with respect to Mr. Moler, his removal as a member of the board of directors of our general partner; and (vi) with respect to Mr. Moler, a merger of Tallgrass Management with another company that results in a reduction in his title, role or responsibilities.

•	any Person or group, other than Tallgrass Energy Holdings or its affiliates, becomes the owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of (A) the combined voting power of the equity interests in our general partner or (B) the general partner interests in TGE;

•	the limited partners of TGE approve, in one or a series of transactions, a plan of complete liquidation of TGE; or

•	the sale or other disposition by TGE of all or substantially all of its assets in one or more transactions to any person other than our general partner an affiliate of our general partner.

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a person other than certain designated persons directly or indirectly acquires direct or indirect ownership or control of more than 50% of the voting interests in our general partner, the ownership of more than 50% of the general partner interests in TGE, or the ownership of such other rights or interests that grant to the owner or holder thereof the ability to direct the management or policies of TGE, whether through the ownership of voting rights, by contract, or otherwise, or if TGE becomes a corporation or limited liability company or if the limited partners of TGE become eligible to elect the members of the board of our general partner, the direct or indirect ability to appoint a majority of the board of directors of the corporation or limited liability company or the board of our general partner, as the case may be.

•	TGE's limited partners approve, in one or a series of transactions, a plan of complete liquidation of TGE; or

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•	the sale or other disposition by TGE of all or substantially all of its assets in one or more transactions to any person other than our general partner and its affiliates.

(1)	The stated value upon a change in control is computed by assuming that a triggering change of control event occurred on December 31, 2019 and multiplying the closing market price ( $22.10 ) of the Class A shares on such date by the number of Class A shares that would have vested.

•	Messrs. Moler and Sheehy have agreed not to compete with Tallgrass Management or certain of its affiliates and not to solicit Tallgrass Management's or certain of its affiliates' employees during the term of his employment and for a period of two years thereafter.

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Mr. Brauchle has agreed (i) not to compete with Tallgrass Management or certain of its affiliates through certain specified competitors or acquirors during the term of his employment and for a period of one year thereafter, or (ii) not to solicit Tallgrass Management's or any of its affiliates' employees or interfere with certain business relationships during the term of his employment and for a period of one year thereafter.

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Messrs. Jones and Watkins have agreed not to compete with Tallgrass Management or certain of its affiliates and not to solicit Tallgrass Management's or any of its affiliates' employees or interfere with certain business relationships during the term of their employment and (i) in the event employment terminates on or before December 31, 2020, for a period of two years thereafter or (ii) in the event employment terminates after December 31, 2020, until the later of December 31, 2022 and one year after such termination.

•	Mr. Dehaemers has agreed not to compete with Tallgrass Management or certain of its affiliates and not to solicit Tallgrass Management's or any of its affiliates' employees or interfere with certain business relationships during the term of his employment and service as a director of TGE GP and generally for three years thereafter.

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(1)

The amounts in this column include equity participation shares granted pursuant to the Plans. These amounts represent the aggregate grant date fair value determined in accordance with ASC Topic 718 for equity participation shares granted under the Plans. Pursuant to SEC rules, the amounts shown in the table above for awards subject to performance conditions are based on the probable outcome as of the date of grant and exclude the impact of estimated forfeitures. The EPSs are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TGE's Class A shares, as appropriate, for the present value of the expected (but non-participating) future dividends during the vesting period. For additional information, see Note 17 – Equity-Based Compensation . These amounts do not correspond to the actual value that will be recognized by the directors.

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•	each person who is known to us to beneficially own more than 5% of the Class A shares (calculated in accordance with Rule 13d-3);

•	the named executive officers of our general partner;

•	each of the directors of our general partner; and

•	all the directors and executive officers of our general partner as a group.

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*	Less than 1%.

(1)

Pursuant to Rule 13d-3 under the Exchange Act, a person has beneficial ownership of a security as to which that person, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares voting power and/or investment power of such security and as to which that person has the right to acquire beneficial ownership of such security within 60 days. In addition to Class A shares, this column includes Class B shares beneficially owned by such persons that are, together with a corresponding number of TE Units, exchangeable at any time and from time to time for Class A shares on a one-for-one basis (subject to the terms of the Tallgrass Equity limited liability company agreement and our partnership agreement). See "Certain Relationships and Related Transactions, and Director Independence-Exchange Right."

(2)

The Class A shares to be issued upon the exchange of Class B shares and TE Units as described in footnote (1) above are deemed to be outstanding and beneficially owned by the person holding the Class B shares for the purpose of computing the percentage of beneficial ownership of Class A shares for that person and any group of which that person is a member, but are not deemed outstanding for purpose of computing the percentage of beneficial ownership of any other person. As such, the percentage of Class A shares shown as being beneficially owned by each person is based on an assumption that each such person exchanged all of such person's Class B shares, together with a corresponding number of TE Units, for Class A shares and that no other person made a similar exchange.

(3)	Represents the percentage of voting power of the Class A shares and Class B shares held by such person voting together as a single class.

(4)

Amounts beneficially owned reflect 21,751,018 Class A shares directly held by Prairie Non-ECI Acquiror LP, a Delaware limited partnership ("Class A Acquiror"), 773,510 Class A shares directly held by Prairie Secondary Acquiror LP, a Delaware limited partnership ("Secondary Acquiror 1"), 1,127,935 Class A shares directly held by Prairie Secondary Acquiror E LP, a Delaware limited partnership ("Secondary Acquiror 2" and, together with Secondary Acquiror 1, the "Prairie Secondary Acquirors"), 92,778,793 Class B shares and TE Units directly held by Prairie ECI Acquiror LP, a Delaware limited partnership ("Up-C Acquiror 1"), and 7,876,328 Class B shares and TE Units directly held by Prairie VCOC Acquiror LP, a Delaware limited partnership ("Up-C Acquiror 2" and, together with Up-C Acquiror 1, the "Up-C Acquirors").

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(5)

Amounts beneficially owned reflect Class A shares and Class B shares reported in footnote (4) above. Pursuant to the Equityholders Agreement, the consent of Jasmine is required in certain circumstances for Holdings Manager to direct the voting and disposition of the securities held by the Class A Acquiror, Prairie Secondary Acquirors and Up-C Acquirors. Jasmine is controlled and managed by GIC Special Investments Pte. Ltd. ("GIC SI"), which is a wholly owned subsidiary of GIC Private Limited ("GIC"). In such capacities, each of GIC SI and GIC shares with Jasmine the power to vote and dispose of the Class A shares and Class B shares deemed to be beneficially owned by Jasmine. Each of Jasmine, GIC SI and GIC expressly disclaims beneficial ownership of any such Class A shares or Class B shares. The principal business address for each of Jasmine, GIC SI and GIC is 168, Robinson Road, #37-01 Capital Tower, Singapore 068912.

(6)

Amounts beneficially owned reflect Class A shares and Class B shares reported in footnote (4) above. Pursuant to the Equityholders Agreement, the consent of Enagás Holding USA, S.L.U. ("Enagás Spain") and Enagas U.S.A. LLC ("Enagas USA") is required in certain circumstances for Holdings Manager to direct the voting and disposition of the securities held by the Class A Acquiror, Prairie Secondary Acquirors and Up-C Acquirors. Enagás is the sole shareholder of Enagás Internacional, S.L.U. ("Enagás Internacional"), which is the sole shareholder of Enagás Spain, which is the sole member of Enagas USA. As a result, each of Enagás, Enagás Internacional, Enagás Spain and Enagas USA may be deemed to beneficially own the Class A shares, Class B shares and TE Units held by Class A Acquiror, the Prairie Secondary Acquirors and Up-C Acquirors. The principal business address of Enagas USA is 850 New Burton Road, Suite 201, Dover, DE 19904. The principal business address of each of Enagás, Enagás Internacional and Enagás Spain is Paseo de los Olmos, 19, 28005 Madrid, Spain.

(7)

As reported on Schedule 13G filed with the SEC on August 6, 2019. Tortoise Capital Advisors, L.L.C. ("TCA") acts as an investment advisor to certain investment companies registered under the Investment Company Act of 1940. TCA, by virtue of investment advisory agreements with these investment companies, has all investment and voting power over securities owned of record by these investment companies. However, despite their delegation of investment and voting power to TCA, these investment companies may be deemed to be the beneficial owners under Rule 13d-3 of the Act, of the securities they own of record because they have the right to acquire investment and voting power through termination of their investment advisory agreement with TCA. Thus, TCA has reported on the Schedule 13G that it shares voting power and dispositive power over the securities owned of record by these investment companies. TCA also acts as an investment adviser to certain managed accounts. Under contractual agreements with these managed account clients, TCA, with respect to the securities held in these client accounts, has investment and voting power with respect to certain of these client accounts, and has investment power but no voting power with respect to certain other of these client accounts. TCA has reported on the Schedule 13G that it shares voting and/or investment power over the securities held by these client managed accounts despite a delegation of voting and/or investment power to TCA because the clients have the right to acquire investment and voting power through termination of their agreements with TCA. TCA may be deemed the beneficial owner of the securities covered by the Schedule 13G under Rule 13d-3 of the Act that are held by its clients. The business address for this person is 11550 Ash Street, Suite 300, Leawood, Kansas 66211.

(8)	Consists of (i) 16,328 Class A shares held directly by Mr. Moler, and (ii) 1,499,288 Class A shares held indirectly by Mr. Moler through the William R. Moler Revocable Trust U.T.A. dated August 27, 2013, for which Mr. Moler serves as trustee. Mr. Moler disclaims beneficial ownership of such 1,499,288 Class A shares except to the extent of his pecuniary interest therein.

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(9)	Consists of (i) 16,258 Class A shares held directly by Mr. Brauchle, and (ii) 145,176.41 Class A shares and 545,909 Class B shares held indirectly by Mr. Brauchle under trust agreement dated April 10, 2014, for which Mr. Brauchle serves as the Trustee. Mr. Brauchle disclaims beneficial ownership of such Class B shares except to the extent of his pecuniary interest therein.

(10)	Consists of (i) 343,458 Class A shares held directly by Mr. Jones, and (ii) 103,983 Class B shares held indirectly by Mr. Jones through the Amended and Restated Christopher R. Jones Revocable Trust under Trust Indenture dated March 6, 2019. Mr. Jones disclaims beneficial ownership of such Class B shares except to the extent of his pecuniary interest therein.

(11)	Class A shares held indirectly by Mr. Dehaemers through the David G. Dehaemers, Jr. Revocable Trust, dated April 26, 2006, for which Mr. Dehaemers serves as trustee. Mr. Dehaemers disclaims beneficial ownership of such Class A shares except to the extent of his pecuniary interest therein.

(1)	Amounts shown represent EPS awards outstanding under the Plans as of December 31, 2019. The outstanding awards will be settled in Class A shares pursuant to the terms of the award agreements and are not subject to an exercise price.

(2)	There are no equity compensation plans in place pursuant to which Class A shares may be issued except for the Plans.

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•	Tallgrass Equity's obligation to reimburse Tallgrass Energy Holdings and its affiliates for expenses incurred (i) on our behalf, (ii) on behalf of our general partner and (iii) for any other purposes related to our business and activities or those of our general partner, including our public company expenses and general and administrative expenses; and

•	Our use of the name "Tallgrass" and any associated or related marks.

•	the provision by Tallgrass Energy Holdings to TEP of certain administrative services and TEP's agreement to reimburse it for such services;

•	the provision by Tallgrass Energy Holdings of such employees as may be necessary to operate and manage TEP's business, and TEP's agreement to reimburse it for the expenses associated with such employees;

•	certain indemnification obligations; and

•	TEP's use of the name "Tallgrass" and related marks.

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(1)

Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the integrated audit of our annual financial statements and internal control over financial reporting, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this Annual Report.

(2)	Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews of our financial statements and are not reported under audit fees.

(3)	Tax fees represent amounts we were billed by PricewaterhouseCoopers LLP in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning.

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•	Zone 1 - a 328-mile pipeline from the Meeker Hub in Northwest Colorado, across Southern Wyoming to the Cheyenne Hub in Weld County, Colorado capable of transporting 2.0 Bcf/d of natural gas from west to east;

•	Zone 2 - a 714-mile pipeline from the Cheyenne Hub to an interconnect in Audrain County, Missouri capable of transporting 1.8 Bcf/d of natural gas from west to east; and

•	Zone 3 - a 643-mile pipeline from Audrain County, Missouri to Clarington, Ohio, which is bi-directional and capable of transporting 1.8 Bcf/d of natural gas from west to east and 2.6 Bcf/d of natural gas from east to west.

•	75% - TEP REX Holdings, LLC ("TEP REX"), an indirect subsidiary of Tallgrass Energy, LP ("TGE"); and

•	25% - Phillips 66 Company, a wholly owned subsidiary of Phillips 66 and successor by merger to P66REX LLC.

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•	a significant decrease in the market value of a long-lived asset or group;

•	a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;

•	a significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;

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•	an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group;

•	a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and

•	a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

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(1)	As discussed further below, Rockies Express issued an additional $750.0 million of senior notes on January 31, 2020, the proceeds of which will be used to redeem the $750.0 million of senior notes due April 15, 2020 in March 2020.

(2)	Deferred financing costs as presented above relate to the Senior Notes. Deferred financing costs associated with Rockies Express revolving credit facility are presented in noncurrent assets in the accompanying balance sheets.

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(1)	As discussed further above, Rockies Express issued an additional $750.0 million of senior notes on January 31, 2020, the proceeds of which will be used to redeem the $750.0 million of senior notes due April 15, 2020 in March 2020.

•	incurring secured indebtedness;

•	entering into mergers, consolidations and sales of assets;

•	granting liens;

•	entering into transactions with affiliates; and

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•	making restricted payments.

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* -	filed herewith

† -	Management contract of compensatory plan or arrangement required to be filed as an exhibit to this Form 10-K pursuant to Item 15(b).

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