Tallgrass Energy Partners 10-Q 3 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 03, 2018
Document and Entity Information [Line Items]
Entity Registrant Name	TALLGRASS ENERGY PARTNERS, LP
Entity Central Index Key	1,569,134
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	Q1
Trading Symbol	TEP
Amendment Flag	false
Common Units
Document and Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		73,199,753
General Partner Units
Document and Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		834,391

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 4,065	$ 1,809
Accounts receivable, net	131,401	118,615
Receivable from related parties	4,472	1,340
Gas imbalances	822	1,990
Inventories	32,147	21,609
Derivative assets	306	0
Prepayments and other current assets	10,946	11,175
Total Current Assets	184,159	156,538
Property, plant and equipment, net	2,498,715	2,394,337
Goodwill	404,838	404,838
Intangible assets, net	136,554	97,731
Unconsolidated investments	950,587	909,531
Deferred financing costs, net	11,008	11,684
Deferred charges and other assets	5,018	2,694
Total Assets	4,190,879	3,977,353
Current Liabilities:
Accounts payable	119,932	98,882
Accounts payable to related parties	64	5,461
Gas imbalances	1,616	1,663
Derivative liabilities	0	2,368
Accrued taxes	24,181	19,272
Accrued liabilities	36,894	35,659
Deferred revenue	99,922	88,471
Other current liabilities	7,816	7,171
Total Current Liabilities	290,425	258,947
Long-term debt, net	2,302,014	2,146,993
Other long-term liabilities and deferred credits	19,628	18,965
Total Long-term Liabilities	2,321,642	2,165,958
Commitments and Contingencies
Equity:
Limited partners (73,199,753 common units outstanding at March 31, 2018 and December 31, 2017)	2,152,036	2,109,316
General partner (834,391 units outstanding at March 31, 2018 and December 31, 2017)	(640,536)	(625,537)
Total Partners' Equity	1,511,500	1,483,779
Noncontrolling interests	67,312	68,669
Total Equity	1,578,812	1,552,448
Total Liabilities and Equity	$ 4,190,879	$ 3,977,353

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
General Partner Units Issued (in units)	834,391	834,391
General Partner Units	834,391	834,391
Limited Partner Units Issued (in units)	73,199,753	73,199,753
Limited Partner Units Outstanding (in units)	73,199,753	73,199,753

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues:
Crude oil transportation services	$ 84,738	$ 84,331
Natural gas transportation services	32,196	31,685
Sales of natural gas, NGLs, and crude oil	38,145	15,381
Processing and other revenues	24,015	13,003
Total Revenues	179,094	144,400
Operating Costs and Expenses:
Cost of sales	26,351	12,370
Cost of transportation services	10,420	13,503
Operations and maintenance	16,399	12,903
Depreciation and amortization	26,123	21,403
General and administrative	16,367	13,663
Taxes, other than income taxes	8,879	8,226
Gain on disposal of assets	(9,417)	(1,448)
Total Operating Costs and Expenses	95,122	80,620
Operating Income	83,972	63,780
Other Income (Expense):
Equity in earnings of unconsolidated investments	53,406	20,738
Interest expense, net	(28,184)	(14,689)
Other income, net	451	1,955
Total Other Income (Expense)	25,673	8,004
Net income	109,645	71,784
Net income attributable to noncontrolling interests	(1,761)	(879)
Net income attributable to partners	107,884	70,905
Allocation of income to the limited partners:
General partner interest in net income	(41,032)	(30,583)
Net income available to common unitholders	$ 66,852	$ 40,322
Basic net income per common unit	$ 0.91	$ 0.56
Diluted net income per common unit	$ 0.91	$ 0.55
Basic average number of common units outstanding	73,200	72,544
Diluted average number of common units outstanding	73,675	73,580

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash Flows from Operating Activities:
Net income	$ 109,645	$ 71,784
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	27,502	23,575
Equity in earnings of unconsolidated investments	(53,406)	(20,738)
Distributions from unconsolidated investments	52,064	20,740
Gain on disposal of assets	(9,417)	(1,448)
Other noncash items, net	148	(1,674)
Changes in components of working capital:
Accounts receivable and other	(12,015)	2,450
Accounts payable and accrued liabilities	14,775	(5,691)
Deferred revenue	10,750	16,202
Other current assets and liabilities	(1,596)	(819)
Other operating, net	108	(140)
Net Cash Provided by Operating Activities	138,558	104,241
Cash Flows from Investing Activities:
Acquisition of BNN North Dakota, net of cash acquired	(95,000)
Capital expenditures	(58,760)	(26,769)
Sale of Tallgrass Crude Gathering	50,046
Acquisition of 38% membership interest in Deeprock North	(19,500)
Distributions from unconsolidated investments in excess of cumulative earnings	13,793	10,079
Acquisition of Rockies Express membership interest	0	(400,000)
Acquisition of Terminals and NatGas	0	(140,000)
Other investing, net	(19,616)	(5,352)
Net Cash Used in Investing Activities	(129,037)	(562,042)
Net Cash (Used in) Provided by Financing Activities
Borrowings under revolving credit facility, net	155,000	552,000
Distributions to unitholders	(111,014)	(88,159)
Acquisition of Pony Express membership interest	(50,000)	0
Proceeds from public offering, net of offering costs	0	99,373
Payments for Repurchase of Common Stock	0	(35,335)
Other financing, net	(1,251)	1,628
Net Cash (Used in) Provided by Financing Activities	(7,265)	457,126
Net Change in Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents	2,256	(675)
Cash and Cash Equivalents, beginning of period	1,809	1,873
Cash and Cash Equivalents, end of period	4,065	1,198
Supplemental Cash Flow Disclosures
Contribution of 38% membership interest in Deeprock North to Deeprock Development	(19,500)
Issuance of noncontrolling interests in Deeprock Development in exchange for 62% membership interest in Deeprock North	(31,843)
Increase in accrual for payment of property, plant and equipment	1,336	0
Equity Option
Net Cash (Used in) Provided by Financing Activities
Payments for Repurchase of Common Stock	$ 0	$ (72,381)

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	Total	Total Partner Equity Excluding Portion Attributable to Noncontrolling Interest	Total Partner Equity Excluding Portion Attributable to Noncontrolling InterestRockies Express Pipeline LLC	Total Partner Equity Excluding Portion Attributable to Noncontrolling InterestPony Express Pipeline	Total Partner Equity Excluding Portion Attributable to Noncontrolling InterestDeeprock North, LLC	Total Partner Equity Excluding Portion Attributable to Noncontrolling InterestTerminals and NatGas	Noncontrolling Interest	Noncontrolling InterestRockies Express Pipeline LLC	Noncontrolling InterestPony Express Pipeline	Noncontrolling InterestDeeprock North, LLC	Noncontrolling InterestTerminals and NatGas	Total Partner Equity Including Portion Attributable to Noncontrolling Interest	Total Partner Equity Including Portion Attributable to Noncontrolling InterestRockies Express Pipeline LLC	Total Partner Equity Including Portion Attributable to Noncontrolling InterestPony Express Pipeline	Total Partner Equity Including Portion Attributable to Noncontrolling InterestDeeprock North, LLC	Total Partner Equity Including Portion Attributable to Noncontrolling InterestTerminals and NatGas	Predecessor Equity	Predecessor EquityRockies Express Pipeline LLC	Predecessor EquityPony Express Pipeline	Predecessor EquityDeeprock North, LLC	Predecessor EquityTerminals and NatGas	Limited Partner	Limited PartnerRockies Express Pipeline LLC	Limited PartnerPony Express Pipeline	Limited PartnerDeeprock North, LLC	Limited PartnerTerminals and NatGas	General Partner	General PartnerRockies Express Pipeline LLC	General PartnerPony Express Pipeline	General PartnerDeeprock North, LLC	General PartnerTerminals and NatGas
Total Equity		$ 1,520,451					$ 33,965					$ 1,554,416					$ 82,295					$ 2,070,495					$ (632,339)
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	$ 71,784	70,905					879					71,784					0					40,322					30,583
Issuance of units to public, net of offering costs		99,373					0					99,373					0					99,373					0
Distributions to unitholders		(88,159)					0					(88,159)					0					(58,793)					(29,366)
Noncash compensation expense		1,882					0					1,882					0					1,882					0
Acquisitions			$ 63,681			$ (140,000)		$ 0			$ 0		$ 63,681			$ (140,000)		$ 0			$ (82,295)		$ 0			$ 0		$ 63,681			$ (57,705)
LTIP units tendered by employees to satisfy tax withholding obligations		(400)					0					(400)					0					(400)					0
Partial exercise of call option		(84,942)					0					(84,942)					0					72,381					12,561
Payments for Repurchase of Common Stock	35,335	(35,335)					0					(35,335)					0					(35,335)					0
Contributions from TD		2,301										2,301					0										2,301
Contributions from noncontrolling interests		0					710					710					0					0					0
Distributions to noncontrolling interest	0	0					1,418					1,418					0					0					0
Total Equity		1,409,757					34,136					1,443,893					0					2,045,163					(635,406)
Total Equity	1,552,448	1,483,779					68,669					1,552,448					0					2,109,316					(625,537)
Cumulative effect of ASC 606 implementation | Accounting Standards Update 2014-09			$ 44,131					$ 0					$ 44,131					$ 0					$ 43,634					$ 497
Net income	109,645	107,884					1,761					109,645					0					66,852					41,032
Issuance of units to public, net of offering costs		(45)					0					(45)					0					(45)					0
Distributions to unitholders		(111,014)					0					(111,014)					0					(70,638)					(40,376)
Noncash compensation expense		2,917					0					2,917					0					2,917					0
Acquisitions				$ 16,152					$ 33,848					$ 50,000					$ 0					$ 0					$ 16,152
Consolidation of Deeprock North					$ 0					$ 31,843					$ 31,843					$ 0					$ 0					$ 0
Payments for Repurchase of Common Stock	0
Contributions from noncontrolling interests		0					183					183					0					0					0
Distributions to noncontrolling interest	50,000	0					1,296					1,296					0					0					0
Total Equity	$ 1,578,812	$ 1,511,500					$ 67,312					$ 1,578,812					$ 0					$ 2,152,036					$ (640,536)

Description of Business

Description of Business	3 Months Ended
	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business	Tallgrass Energy Partners, LP ("TEP" or the "Partnership") is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. "We," "us," "our" and similar terms refer to TEP together with its consolidated subsidiaries. Our operations 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 integrated natural gas storage facilities; • Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system; and • Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering and processing facilities; crude oil storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs. Natural Gas Transportation. We provide natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) our 49.99% 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, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a FERC-regulated crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma, and includes a lateral in Northeast Colorado commencing in Weld County, Colorado that interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). In the second quarter of 2018, Pony Express placed into service an extension of the system from a new origin near Platteville, Colorado to the Buckingham Terminal. Gathering, Processing & Terminalling. We provide natural gas gathering and processing services for customers in Wyoming through: (1) a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System"), (2) the Casper and Douglas natural gas processing facilities, and (3) the West Frenchie Draw natural gas treating facility. We also provide NGL transportation services in Northeast Colorado and Wyoming. We perform water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, Wyoming, and North Dakota through BNN Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through our 100% membership interest in Tallgrass Terminals, LLC ("Terminals"), which owns and operates crude oil terminals in Colorado, Oklahoma, and Kansas. The Gathering, Processing & Terminalling segment also includes Stanchion Energy, LLC ("Stanchion"), which transacts in crude oil. The table below summarizes our equity ownership as of March 31, 2018 : Unit holder Limited Partner Common Units General Partner Units Percentage of Outstanding Limited Partner Common Units Percentage of Outstanding Common and General Partner Units Public Unitholders 47,580,535 — 65.00 % 64.27 % Tallgrass Equity, LLC 25,619,218 — 35.00 % 34.60 % Tallgrass MLP GP, LLC (1) — 834,391 — % 1.13 % Total 73,199,753 834,391 100.00 % 100.00 % (1) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights. The term "Terminals Predecessor" refers to Terminals and the term "NatGas Predecessor" refers to NatGas prior to their acquisition by TEP on January 1, 2017. Terminals Predecessor and NatGas Predecessor are collectively referred to as the Predecessor Entities, as further discussed in Note 2 – Summary of Significant Accounting Policies . Financial results for all prior periods have been recast to reflect the operations of the Predecessor Entities. Predecessor Equity as presented in the condensed consolidated financial statements represents the capital account activity of Terminals Predecessor and NatGas Predecessor prior to January 1, 2017. TEGP Merger Agreement On March 26, 2018, we announced the execution of a definitive Agreement and Plan of Merger (the "Merger Agreement") pursuant to which Tallgrass Energy GP, LP ("TEGP") will acquire the approximately 47.6 million TEP common units held by the public in a share-for-unit merger transaction that is taxable to TEP unitholders for U.S. federal income tax purposes at a ratio of 2.0 TEGP Class A shares for each outstanding TEP common unit. As a result of the proposed transaction, our incentive distribution rights will be cancelled, our common units will no longer be publicly traded, and 100% of our equity interests will be owned by TEGP's subsidiary, Tallgrass Equity, LLC ("Tallgrass Equity") and its subsidiaries. Upon closing of the merger transaction, TEGP will change its name to Tallgrass Energy, LP ("Tallgrass Energy") and will trade on the New York Stock Exchange under the ticker symbol "TGE." Tallgrass Energy will continue to be taxed as a corporation for U.S. federal income tax purposes. The Merger Agreement has been unanimously approved by the board of directors of TEGP's general partner, the conflicts committee of the board of directors of our general partner, and the board of directors of our general partner. Subject to customary approvals and conditions, including the approval by holders of a majority of the outstanding TEP common units, the merger is expected to close by the end of the second quarter of 2018. In connection with the proposed transaction, TEGP filed with the Securities and Exchange Commission ("SEC") a registration statement on Form S-4 that included a preliminary proxy statement/prospectus for our unitholders. After the registration statement is declared effective, we will mail a definitive proxy statement/prospectus to our unitholders. The description of the proposed transaction above is not a substitute for the proxy statement/prospectus or registration statement or for any other document that TEGP or TEP may file with the SEC and send to TEGP’s and/or TEP’s shareholders or unitholders in connection with the proposed transaction. Investors and security holders of TEGP and TEP are urged to read the proxy statement/prospectus and other documents filed with the SEC carefully and in their entirety when they become available because they will contain important information. Investors and security holders will be able to obtain free copies of the proxy statement/prospectus and other documents filed with the SEC by TEGP or TEP through the website maintained by the SEC at http://www.sec.gov. Copies of the documents filed with the SEC by TEGP and TEP will be available free of charge on TEGP’s and TEP’s website at www.tallgrassenergylp.com, in the “Investor Relations” tab near the top of the page.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Basis of Presentation These condensed consolidated financial statements and related notes for the three months ended March 31, 2018 and 2017 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of accounting principles generally accepted in the United States of America ("GAAP") for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three months ended March 31, 2018 and 2017 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation. Our financial results for the three months ended March 31, 2018 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2018 . The accompanying condensed consolidated interim financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017 ("2017 Form 10-K") filed with the SEC on February 13, 2018. The condensed consolidated financial statements include the accounts of TEP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP and noncontrolling interests in accordance with the respective ownership interests. TEP 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. Use of Estimates Certain amounts included in or affecting these condensed consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts reported for assets, liabilities, revenues, and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Management evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from these estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Accounting Pronouncement Recently Adopted Revenue Recognition In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to members' equity. Consolidated revenues presented in the comparative consolidated financial statements for periods prior to January 1, 2018 will not be revised. On January 1, 2018, we recorded a cumulative effect adjustment to equity of $44.1 million , increased the carrying amount of our investment in Rockies Express by $42.8 million , and recognized a receivable from Rockies Express of $1.3 million . These adjustments relate to the cumulative effect adjustment recorded by Rockies Express of $125.2 million upon adoption of ASC 606. The cumulative effect adjustment at Rockies Express arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas during the periods prior to implementation. Through our review process, we also identified the following changes to our revenue recognition policies that did not result in a cumulative effect adjustment on January 1, 2018: • Gathering & Processing. We have determined that a number of our gathering & processing contracts at TMID do not represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of raw gas will be accounted for as supply arrangements pursuant to ASC 705. As a result, gathering & processing fees previously recognized in revenue will be reported as a reduction to cost of sales under ASC 606. • Pipeline Loss Allowance. We have determined that pipeline loss allowance, or PLA, collected under certain crude oil transportation arrangements is a component of the transaction price where the PLA both significantly exceeds actual losses and was negotiated with the intent of providing a revenue stream to TEP. Under ASC 606, PLA barrels retained from customers will be subject to the guidance for noncash consideration and recognized in revenue at their contract inception fair value. See Note 11 – Revenue from Contracts with Customers for revenue disclosures related to both the implementation and the additional requirements prescribed by the standard. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities. Accounting Pronouncements Not Yet Adopted ASU No. 2016-02, "Leases (Topic 842)" In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP. Management is currently evaluating the impact of our pending adoption of ASC 842. The status of our implementation is as follows: • Management has formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain contract types, and project status. • Management is in the process of gathering data and reviewing contracts in order to identify all impacted contracts. • Management is evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from its contract review process. • Management plans to provide internal training and awareness related to the revised guidance to the key stakeholders throughout its organization. The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. We are currently evaluating the impact of ASU 2016-02.

Acquisitions & Dispositions

Acquisitions & Dispositions	3 Months Ended
	Mar. 31, 2018
Business Combinations [Abstract]
Acquisitions & Dispositions	Sale of Tallgrass Crude Gathering In February 2018, we entered into an agreement with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to sell our 100% membership interest in Tallgrass Crude Gathering, LLC ("TCG"), which owns a 50 -mile crude oil gathering system in the Powder River Basin, for approximately $50.0 million . The sale of TCG closed on February 23, 2018. During the three months ended March 31, 2018 , we recognized a gain of $9.4 million on the sale which is presented in the line item "Gain on disposal of assets" in the condensed consolidated statements of income. Iron Horse Joint Venture In February 2018, we entered into an agreement with Silver Creek to form Iron Horse Pipeline, LLC ("Iron Horse"), a new joint venture pipeline to transport crude oil from the Powder River Basin. During the three months ended March 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. Our investment in Iron Horse is accounted for under the equity method of accounting and reported as "Unconsolidated investments" on the condensed consolidated balance sheets. Acquisition of Additional 2% Membership Interest in Pony Express In February 2018, we acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from Tallgrass Development, LP ("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. The transaction resulted in a deemed distribution to our general partner as discussed further in Note 10 – Partnership Equity and Distributions . 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, subject to working capital adjustments. BNN North Dakota owns a produced water gathering and disposal system in the Bakken basin with approximately 133,000 acres under dedication. The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805. The following represents the fair value of assets acquired and liabilities assumed (in thousands): Accounts receivable $ 2,457 Inventory 67 Property, plant and equipment 48,900 Intangible asset 46,800 (1) Accounts payable and accrued liabilities (3,224 ) Net identifiable assets acquired (excluding cash) $ 95,000 (1) The $46.8 million intangible asset acquired represents three major customer relationships. This intangible asset is amortized on a straight-line basis over a period of 8 - 14 years, the remaining terms of the underlying contracts at the time of acquisition. At March 31, 2018 , the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. We are in the process of identifying and measuring all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. Actual revenue and net income attributable to TEP from BNN North Dakota of $3.1 million and $1.7 million , respectively, was recognized in the accompanying condensed consolidated statements of income for the period from January 12, 2018 to March 31, 2018 . Pro Forma Financial Information Unaudited pro forma revenue and net income attributable to TEP for the three months ended March 31, 2018 and 2017 is presented below as if the acquisition of BNN North Dakota had been completed on January 1, 2017. Three Months Ended March 31, 2018 2017 (in thousands) Revenue $ 179,522 $ 146,716 Net income attributable to partners $ 108,116 $ 70,061 The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TEP would have been if the transaction had in fact occurred on the date or for the period indicated, nor does it purport to project the results of operations or financial position of TEP for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transaction or the costs to achieve these cost savings, operating synergies, and revenue enhancements. Acquisition of Deeprock North and Merger with Deeprock Development In January 2018, Terminals acquired an approximate 38% membership interest in Deeprock North, LLC ("Deeprock North") from Kinder Morgan Deeprock North Holdco LLC for cash consideration of $19.5 million . Immediately following the acquisition, Deeprock North was merged into Deeprock Development, LLC ("Deeprock Development"), and the members of Deeprock North and Deeprock Development received adjusted membership interests in the combined entity. As a result, Terminals 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, Terminals owns an approximate 60% membership interest in the combined entity.

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	As a result of our relationship with Tallgrass Energy Holdings, LLC ("Tallgrass Energy Holdings") and its affiliates, we have entered into a number of related party transactions. The following disclosure includes those related party transactions which are not otherwise disclosed in these notes to our condensed consolidated financial statements. We have no employees. In connection with the closing of our initial public offering on May 17, 2013, TEP and its general partner entered into an Omnibus Agreement with Tallgrass Energy Holdings and certain of its affiliates (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse Tallgrass Energy Holdings and its affiliates for all expenses they incur and payments they make on TEP's behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by Tallgrass Energy Holdings and its affiliates, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP. Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows: Three Months Ended March 31, 2018 2017 (in thousands) Processing and other revenues (1) $ 1,896 $ 1,632 Cost of transportation services (2) $ — $ 4,507 Charges to TEP: (3) Property, plant and equipment, net $ — $ 293 Operations and maintenance $ — $ 6,277 General and administrative $ — $ 9,377 (1) Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline. (2) Reflects rent expense for the crude oil storage at the Deeprock Terminal prior to our consolidation of Deeprock Development during the third quarter of 2017 . (3) Charges to TEP include indirectly charged wages and salaries, other compensation and benefits, and shared services for periods prior to January 1, 2018. Effective January 1, 2018, these costs are incurred by TEP directly and, in the case of certain employee compensation and benefits, paid on TEP's behalf by its affiliate, Tallgrass Management, LLC pursuant to the TEP Omnibus Agreement. Details of balances with affiliates included in "Receivable from related parties" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows: March 31, 2018 December 31, 2017 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 4,324 $ 1,340 Iron Horse Pipeline, LLC 148 — Total receivable from related parties $ 4,472 $ 1,340 Accounts payable to related parties: Tallgrass Operations, LLC (1) $ — $ 5,381 Tallgrass Equity, LLC 64 80 Total accounts payable to related parties $ 64 $ 5,461 (1) Reflects accounts payable for charges to TEP including indirectly charged wages and salaries, other compensation and benefits, and shared services prior to January 1, 2018 as discussed above. Gas imbalances with affiliated shippers are as follows: March 31, 2018 December 31, 2017 (in thousands) Affiliate gas imbalance receivables $ 13 $ 18 Affiliate gas imbalance payables $ 269 $ 442

Inventory

Inventory	3 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Inventory	The components of inventory at March 31, 2018 and December 31, 2017 consisted of the following: March 31, 2018 December 31, 2017 (in thousands) Crude oil $ 21,517 $ 12,792 Materials and supplies 5,914 5,891 Natural gas liquids 607 942 Gas in underground storage 4,109 1,984 Total inventory $ 32,147 $ 21,609

Property, Plant and Equipment

Property, Plant and Equipment	3 Months Ended
	Mar. 31, 2018
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	A summary of net property, plant and equipment by classification is as follows: March 31, 2018 December 31, 2017 (in thousands) Crude oil pipelines $ 1,252,262 $ 1,220,379 Gathering, processing and terminalling assets (1) 744,515 675,092 Natural gas pipelines 585,483 581,400 General and other 118,355 98,680 Construction work in progress 112,464 97,978 Accumulated depreciation and amortization (314,364 ) (279,192 ) Total property, plant and equipment, net $ 2,498,715 $ 2,394,337 (1) Includes approximately $46.2 million and $40.1 million of assets associated with the acquisitions of Deeprock North and BNN North Dakota, respectively, in January 2018.

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates Investments in Unconsolidated Affiliates	3 Months Ended
	Mar. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our condensed consolidated balance sheets. During the three months ended March 31, 2018, we recognized equity in earnings associated with our 49.99% membership interest in Rockies Express of $52.1 million , inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $65.9 million and $2.4 million , respectively. Summarized financial information for Rockies Express is as follows: Three Months Ended March 31, 2018 2017 (in thousands) Revenue $ 230,058 $ 201,338 Operating income $ 128,678 $ 107,369 Net income to Members $ 90,968 $ 66,250

Risk Management

Risk Management	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management	We enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs. Fair Value of Derivative Contracts The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets: Balance Sheet March 31, 2018 December 31, 2017 (in thousands) Crude oil derivative contracts (1) Current assets $ 306 $ — Crude oil derivative contracts (1) Current liabilities $ — $ 2,368 (1) As of March 31, 2018 , the fair value shown for crude oil derivative contracts represents the forward sale of 242,000 barrels which will settle throughout the second quarter of 2018. As of December 31, 2017 , the fair value shown for crude oil derivative contracts represents the forward sale of 356,000 barrels of crude oil which settled in the first quarter of 2018. Effect of Derivative Contracts in the Statements of Income The following table summarizes the impact of derivative contracts not designated as hedging contracts for the three months ended March 31, 2018 and 2017 : Location of gain recognized Amount of gain recognized in income on derivatives Three Months Ended March 31, 2018 2017 (in thousands) Derivatives not designated as hedging contracts: Crude oil derivative contracts Sales of natural gas, NGLs, and crude oil $ 4,295 $ 663 Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ — $ 173 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 us an 18 month call option at an exercise price of $42.50 per common unit covering the 6,518,000 common units issued to TD as a portion of the consideration. On February 1, 2017 , we exercised the remainder of the call option covering an additional 1,703,094 common units for a cash payment of $72.4 million . 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. The counterparty to our call option derivative was TD. Our derivative contracts are entered into with counterparties through central trading organizations such as futures, options or stock exchanges or counterparties outside of central trading organizations. While we typically enter into derivative transactions with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. The maximum potential exposure to credit losses on our crude oil derivative contracts at March 31, 2018 was: Asset Position (in thousands) Gross $ 306 Netting agreement impact — Cash collateral held — Net exposure $ 306 As of March 31, 2018 and December 31, 2017 , we had $0.8 million and $3.0 million , respectively, of cash in margin accounts and outstanding letters of credit in support of our commodity derivative contracts. Fair Value Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). OTC commodity derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy. The call option granted by TD was valued using a Black-Scholes option pricing model. Key inputs to the valuation model included the term of the option, risk free rate, the exercise price and current market price, expected volatility and expected distribution yield of the underlying units. The call option valuation was classified within Level 2 of the fair value hierarchy as the value was based on significant observable inputs. The following table summarizes the fair value measurements of our derivative contracts as of March 31, 2018 and December 31, 2017 , based on the fair value hierarchy: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of March 31, 2018: Crude oil derivative contracts $ 306 $ — $ 306 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2017: Crude oil derivative contracts $ 2,368 $ — $ 2,368 $ —

Long-term Debt

Long-term Debt	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Long-term Debt	Long-term debt consisted of the following at March 31, 2018 and December 31, 2017 : March 31, 2018 December 31, 2017 (in thousands) Revolving credit facility $ 816,000 $ 661,000 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) (17,628 ) (17,737 ) Plus: Unamortized premium on 2028 Notes 3,642 3,730 Total long-term debt, net $ 2,302,014 $ 2,146,993 (1) Deferred financing costs, net as presented above relate solely to the 2024 and 2028 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our condensed consolidated balance sheets. Senior Unsecured Notes due 2028 On September 15, 2017, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 15, 2017 (the "2028 Indenture") pursuant to which the Issuers issued $500 million in aggregate principal amount of 5.50% senior notes due 2028 (the "2028 Notes"). On December 11, 2017, the Issuers issued an additional $250 million in aggregate principal amount of the 2028 Notes, which are also governed by the 2028 Indenture. The notes issued on September 15, 2017 and December 11, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date and offering price. The 2028 Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all TEP’s properties to, another person. As of March 31, 2018 , we were in compliance with the covenants required under the 2028 Notes. Senior Unsecured Notes due 2024 On September 1, 2016, the Issuers, the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016 (the "2024 Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). On May 16, 2017, the Issuers issued an additional $350 million in aggregate principal amount of the 2024 Notes which are also governed by the 2024 Indenture. The notes issued on September 1, 2016 and May 16, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date, offering price and first interest payment date. The 2024 Indenture 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. As of March 31, 2018 , we were in compliance with the covenants required under the 2024 Notes. Revolving Credit Facility The following table sets forth the available borrowing capacity under the revolving credit facility as of March 31, 2018 and December 31, 2017 : March 31, 2018 December 31, 2017 (in thousands) Total capacity under the revolving credit facility $ 1,750,000 $ 1,750,000 Less: Outstanding borrowings under the revolving credit facility (816,000 ) (661,000 ) Less: Letters of credit issued under the revolving credit facility (94 ) (94 ) Available capacity under the revolving credit facility $ 933,906 $ 1,088,906 The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict our ability (as well as the ability of our 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 our 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, we are required to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (which will be increased to 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions), 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 March 31, 2018 , we were in compliance with the covenants required under the revolving credit facility. The unused portion of the revolving credit facility is subject to a commitment fee, which ranges from 0.250% to 0.500% , based on our total leverage ratio. As of March 31, 2018 , the weighted average interest rate on outstanding borrowings under the revolving credit facility was 3.27% . During the three months ended March 31, 2018 , our weighted average effective interest rate, including the interest on outstanding borrowings under the revolving credit facility, commitment fees, and amortization of deferred financing costs, was 3.53% . Fair Value The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of March 31, 2018 and December 31, 2017 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of March 31, 2018: Revolving credit facility $ — $ 816,000 $ — $ 816,000 $ 816,000 2024 Notes $ — $ 767,063 $ — $ 767,063 $ 740,202 2028 Notes $ — $ 754,425 $ — $ 754,425 $ 745,812 As of December 31, 2017: Revolving credit facility $ — $ 661,000 $ — $ 661,000 $ 661,000 2024 Notes $ — $ 771,645 $ — $ 771,645 $ 739,824 2028 Notes $ — $ 758,168 $ — $ 758,168 $ 746,169 The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of March 31, 2018 and December 31, 2017 , the fair value of borrowings under the revolving credit facility approximates the carrying amount of the borrowings using a discounted cash flow analysis. The 2024 and 2028 Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the 2024 and 2028 Notes is based upon quoted market prices adjusted for illiquid markets. We are not aware of any factors that would significantly affect the estimated fair value subsequent to March 31, 2018 .

Partnership Equity and Distribu

Partnership Equity and Distributions	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Partnership Equity and Distributions	Equity Distribution Agreements We have active equity distribution agreements pursuant to which we may sell from time to time through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate offering price of up to $100.2 million and $657.5 million . Net cash proceeds from any sale of the common units may be used for general partnership purposes, which includes, among other things, the Partnership's exercise of the call option with respect to the 6,518,000 common units issued to TD in connection with the Partnership's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to working capital. During the three months ended March 31, 2018 , we did not issue any common units under our equity distribution agreements. During the three months ended March 31, 2017 , we issued and sold 2,087,647 common units with a weighted average sales price of $48.23 per unit under our equity distribution agreements for net cash proceeds of approximately $99.4 million (net of approximately $1.3 million in commissions and professional service expenses). Repurchase of Common Units Owned by TD Following an offer received from TD with respect to common units owned by TD not subject to the call option, we repurchased 736,262 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 our general partner. These common units were deemed canceled upon our purchase and as of such transaction date were no longer issued and outstanding. Distributions to Holders of Common Units, General Partner Units and Incentive Distribution Rights The following table shows the distributions for the periods indicated: Distributions Distribution Limited Partner 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 (1) $ 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 (1) The distribution announced on March 26, 2018 for the first quarter of 2018 will be paid on May 15, 2018 to unitholders of record at the close of business on April 30, 2018 . Other Contributions and Distributions During the three months ended March 31, 2018 , TEP recognized the following other contributions and distributions: • TEP was deemed to have made a noncash capital distribution of $16.2 million to the general partner, which represents the excess purchase price over the carrying value of the additional 2% membership interest in Pony Express acquired February 1, 2018; and • TEP recognized distributions to and contributions from noncontrolling interests of $1.3 million and $0.2 million , respectively. During the three months ended March 31, 2017 , TEP recognized the following other contributions and distributions: • TEP was deemed to have made a noncash capital distribution of $57.7 million to the general partner, which represents the excess purchase price over the carrying value of the Terminals and NatGas net assets acquired January 1, 2017; • TEP was deemed to have made a noncash capital distribution of $12.6 million to the general partner, which represents the derecognition of a portion of the derivative asset associated with the partial exercise of the call option; • TEP was deemed to have received a noncash capital contribution of $63.7 million from the general partner, 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; • 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 14 – Legal and Environmental Matters ; and • TEP recognized contributions from and distributions to noncontrolling interests of $0.7 million and $1.4 million , respectively, which primarily consisted of activity associated with TD's 2% noncontrolling interest in Pony Express.

Revenue from Contracts with Cus

Revenue from Contracts with Customers (Notes)	3 Months Ended
	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	Implementation of ASC Topic 606 As discussed in Note 2 – Summary of Significant Accounting Policies , we adopted the guidance in ASC Topic 606 effective January 1, 2018 using the modified retrospective method of adoption. As a result, revenue reported for the three months ended March 31, 2017 has not been revised. The following tables provide the impact of the guidance on our condensed consolidated balance sheet as of March 31, 2018 and the condensed consolidated statement of income for the three months ended March 31, 2018 : March 31, 2018 As currently reported Under previous guidance Impact of ASC Topic 606 (in thousands) Unconsolidated investments $ 950,587 $ 900,013 $ 50,574 (1) Three Months Ended March 31, 2018 As currently reported Under previous guidance Impact of ASC Topic 606 (in thousands) Revenues: Crude oil transportation services $ 84,738 $ 84,466 $ 272 (2) Sales of natural gas, NGLs, and crude oil $ 38,145 $ 39,245 $ (1,100 ) (3) Processing and other revenues $ 24,015 $ 25,525 $ (1,510 ) (1)(3) Cost of sales $ 26,351 $ 28,845 $ (2,494 ) (2)(3) Equity in earnings of unconsolidated investments $ 53,406 $ 45,698 $ 7,708 (1) Net income attributable to partners $ 107,884 $ 100,020 $ 7,864 Basic net income per common unit $ 0.91 $ 0.80 $ 0.11 Diluted net income per common unit $ 0.91 $ 0.80 $ 0.11 (1) Reflects the impact on our investment in Rockies Express and the management fee collected by NatGas of the cumulative effect adjustment at Rockies Express, which arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas. (2) Reflects the impact to revenue and cost of sales to value PLA barrels collected under certain crude oil transportation arrangements at their contract inception fair value in revenue and record an associated lower of cost or net realizable value adjustment in cost of sales. (3) Reflects the reclassification of certain gathering and processing fees collected under arrangements determined to be supply arrangements, rather than customer arrangements under ASC 606, to cost of sales and the reclassification of certain commodities retained as consideration for processing services to processing fee revenue. Disaggregated Revenue A summary of our revenue by line of business is as follows: Three Months Ended March 31, 2018 Natural Gas Transportation segment Crude Oil Transportation segment Gathering, Processing, & Terminalling segment Corporate and Other Total Revenue (in thousands) Crude oil transportation - committed shipper revenue $ — $ 84,738 $ — $ — $ 84,738 Natural gas transportation - firm service 33,334 — — (1,883 ) 31,451 Water business services — — 13,204 — 13,204 Natural gas gathering & processing fees — — 5,044 — 5,044 All other (1) 2,630 3,319 5,706 (6,088 ) 5,567 Total service revenue 35,964 88,057 23,954 (7,971 ) 140,004 Natural gas liquids sales — — 23,609 — 23,609 Natural gas sales 238 — 7,847 — 8,085 Crude oil sales — 1,909 247 — 2,156 Total commodity sales revenue 238 1,909 31,703 — 33,850 Total revenue from contracts with customers 36,202 89,966 55,657 (7,971 ) 173,854 Other revenue (2) — — 8,181 (2,941 ) 5,240 Total revenue (3) $ 36,202 $ 89,966 $ 63,838 $ (10,912 ) $ 179,094 (1) Includes revenue from crude oil 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 $230.1 million of revenue recognized at Rockies Express for the three months ended March 31, 2018 . See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express. Performance Obligations A performance obligation is a promise in a contract to transfer a distinct good or service to the customer, and is the unit of account in ASC Topic 606. A contract's transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. The majority of our contracts have a single performance obligation and are billed and collected monthly. All of our segments engage in commodity sales, in which our performance obligations include an obligation to deliver the specified volume of a commodity to the designated receipt point. Revenue from commodity sales is recognized at a point in time when the customer obtains control of the commodity, typically upon delivery to the designated delivery point when the customer accepts and takes possession of the commodity. In the Natural Gas Transportation segment, our performance obligations typically include an obligation to stand ready to provide natural gas transportation, storage, or an integrated transportation and storage service over the life of the contract, which is a series. These performance obligations are satisfied over time using each day of service to measure progress toward satisfaction of the performance obligation. In the Crude Oil Transportation segment, our performance obligations typically include an obligation to provide crude oil transportation services over the life of the contract, which is a series. These performance obligations are satisfied over time using barrels delivered to measure progress toward satisfaction of the performance obligation. 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 March 31, 2018 , we had $1.7 billion of remaining performance obligations at our consolidated subsidiaries, which we refer to as total backlog. Total backlog includes performance obligations under long-term crude oil transportation contracts with committed shippers, natural gas firm transportation and firm storage contracts, and certain water business service contracts with minimum volume commitments, and excludes variable consideration that is not estimated at contract inception, as discussed further below. We expect to recognize the total backlog during the remainder of 2018 and future periods as follows (in thousands): Year Estimated Revenue 2018 $ 387,826 2019 488,919 2020 317,235 2021 138,686 2022 129,548 Thereafter 271,311 Total $ 1,733,525 Contract Estimates Accounting for long-term contracts involves the use of various techniques to estimate total contract revenue. Contract estimates are based on various assumptions to project the outcome of future events that often span several years. These assumptions include the anticipated volumes of crude oil expected to be delivered by our customers for transport in future periods. The nature of our contracts gives rise to several types of variable consideration, including PLA, volumetric charges for actual volumes delivered, overrun charges, and other fees that are contingent on the actual volumes delivered by our customers. As the amount of variable consideration is allocable to each distinct performance obligation within the series of performance obligations that comprise the single performance obligation, we do not estimate the total variable consideration for the single overall performance obligation because the uncertainty related to the consideration is resolved each month as the distinct service is provided. Consequently, we are able to include in the transaction price each month the actual amount of variable consideration because no uncertainty exists surrounding the services provided that month. Certain of our contracts include provisions in which a portion of the consideration is noncash. In our Crude Oil Transportation segment, we collect PLA from our customers. As crude oil is transported, we earn, and take title to, a portion of the oil transported for our services. Any PLA that remains after replacing losses in transit can be sold. Where PLA is determined to be a component of compensation for the transportation services provided, crude oil retained is recognized in revenue at its contract inception fair value. In our Gathering, Processing & Terminalling segment, we retain commodity products as consideration under certain of our gathering and processing arrangements. Processing fee revenue is recorded when the performance obligation is completed based on the value of the product received at the time services are performed. At this time, the variability of the non-cash consideration related to both form (price) and other-than-form (volume and product mix), which are interrelated, is resolved. As a significant change in one or more of these estimates could affect the amount and timing of revenue recognized under our customer contracts, we review and update our contract-related estimates regularly. Contract Balances The timing of revenue recognition, billings, and cash collections may result in billed accounts receivable, unbilled receivables (contract assets), and deferred revenue (contract liabilities) on our condensed consolidated balance sheets. Revenue is generally billed and collected monthly based on services provided or commodity volumes sold. In our Crude Oil Transportation segment, we recognize shipper deficiencies, or deferred revenue, for barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers' agreed upon destination point. These shipper deficiencies are charged at the committed tariff rate per barrel and recorded as a contract liability until the barrels are physically transported and delivered, or when the likelihood that the customer will utilize the deficiency balance becomes remote. We also recognize contract liabilities, in the form of deferred revenue, under certain water business services contracts in the Gathering, Processing & Terminalling segment. Contract balances as of March 31, 2018 were as follows: March 31, 2018 January 1, 2018 (in thousands) Accounts receivable from contracts with customers $ 68,039 $ 61,888 Other accounts receivable 63,362 56,727 Accounts receivable, net $ 131,401 $ 118,615 Deferred revenue from contracts with customers (1) $ 99,922 $ 88,471 (1) Revenue recognized during the three months ended March 31, 2018 that was included in the deferred revenue balance at the beginning of the period was $3.1 million . This revenue primarily represented the utilization of shipper deficiencies at Pony Express.

Net Income per Limited Partner

Net Income per Limited Partner Unit	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Net Income per Limited Partner Unit	The Partnership's net income is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. We compute earnings per unit using the two-class method for Master Limited Partnerships as prescribed in the FASB guidance. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period. We calculate net income available to limited partners based on the distributions pertaining to the current period's net income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement and as further prescribed in the FASB guidance under the two-class method. The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights (which are currently held by our general partner), even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units. The following table illustrates the calculation of net income per common unit for the three months ended March 31, 2018 and 2017 : Three Months Ended March 31, 2018 2017 (in thousands, except per unit amounts) Net income $ 109,645 $ 71,784 Net income attributable to noncontrolling interests (1,761 ) (879 ) Net income attributable to partners 107,884 70,905 General partner interest in net income (41,032 ) (30,583 ) Net income available to common unitholders $ 66,852 $ 40,322 Basic net income per common unit $ 0.91 $ 0.56 Diluted net income per common unit $ 0.91 $ 0.55 Basic average number of common units outstanding 73,200 72,544 Equity Participation Unit equivalent units 475 1,036 Diluted average number of common units outstanding 73,675 73,580

Regulatory Matters

Regulatory Matters	3 Months Ended
	Mar. 31, 2018
Regulated Operations [Abstract]
Regulatory Matters	There are no regulatory proceedings challenging the rates of Pony Express, Rockies Express, Tallgrass Interstate Gas Transmission, LLC ("TIGT") or Trailblazer Pipeline Company LLC ("Trailblazer"). We have made certain regulatory filings with the FERC, including the following: Pony Express On May 22, 2017 and May 31, 2017, Pony Express made tariff filings with the FERC in Docket Nos. IS17-263-000, IS17-464-000, and IS17-465-000 to increase the contract and non-contract rates by an amount reflecting the most recent FERC annual index adjustment of approximately 0.2% , which became effective July 1, 2017. On November 30, 2017, Pony Express filed with the FERC in Docket No. IS18-60-000 certain changes to its tariffs to reflect the addition of two new destination points, which became effective January 1, 2018. On December 29, 2017, Pony Express filed with the FERC in Docket No. IS18-113-000 certain changes to its tariffs to reflect a new origin point in Rooks County, Kansas, which became effective on February 1, 2018. On February 28, 2018, Pony Express filed with the FERC in Docket No. IS18-199-000 certain changes to its tariffs to reflect a new origin point in Platteville, Colorado, which became effective on April 1, 2018. On March 1, 2018, Pony Express submitted proposed revisions to its Rules and Regulations Tariff in Docket No. IS18-204-000 to establish the right to accept "Specialty Batches" of oil that do not conform to the Quality Specifications reflected in the tariff, provided that the acceptance is operationally feasible. These tariff changes became effective on April 1, 2018. On April 11, 2018, Pony Express filed with the FERC in Docket No. IS18–267–000 certain changes to its tariffs to reflect additional contract rates from a new origin point in Platteville, Colorado, which are proposed to become effective on May 1, 2018. Rockies Express Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000 On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The facilities increased the Rockies Express Zone 3 east-to-west mainline capacity by 0.8 Bcf/d. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities. The project was placed in-service for the full 0.8 Bcf/d on January 6, 2017. Electric Power Charge Clarification - FERC Docket No. RP17-285 On December 21, 2016, in Docket No. RP17-285, Rockies Express proposed certain revisions to the General Terms and Conditions of its tariff to clarify that the electric power costs associated with the operation of gas coolers installed in association with the Zone 3 Capacity Enhancement Project at both electric and gas powered stations, will be included in the Power Cost Tracker. Several shippers submitted comments on the proposal. The FERC issued an order on January 19, 2017 accepting the proposed revisions permitting the recovery of electric power costs from the operation of both gas and electric powered compressor stations, subject to certain clarifications. 2017 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP17-401 and RP17-1064 On February 13, 2017, in Docket No. RP17-401, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2017. The FERC issued an order accepting the filing, including certain requested waivers, on March 21, 2017. On September 20, 2017, Rockies Express made its interim fuel tracker filing in Docket No. RP17-1064 with a proposed effective date of November 1, 2017. The FERC issued an order accepting the filing on October 18, 2017. Increased Frequency of FL&U and PCT Adjustments - FERC Docket No. RP18-228 On December 1, 2017, in Docket No. RP18-228, Rockies Express made a filing with the FERC to increase the frequency in which it may adjust fixed fuel and lost and unaccounted for retainages and power cost tracker charges during the year so that its recovery of fixed fuel and lost and unaccounted for charges and power costs more closely track usage. Rockies Express proposed an effective date of April 1, 2018. The comment period ended on December 13, 2017, and no parties opposed Rockies Express’ filing. On April 4, 2018, the FERC issued a letter order accepting Rockies Express’s proposal, subject to certain modifications. Rockies Express submitted a compliance filing reflecting the approved tariff provisions and requested modifications on April 10, 2018. No comments on the compliance filing were submitted by the comment deadline of April 16, 2018. On April 18, 2018, the FERC issued an order accepting Rockies Express’s compliance filing effective April 19, 2018. 2018 Annual FERC Fuel Tracking Filing - FERC Docket No. RP18-453 On February 20, 2018, in Docket No. RP18-453, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2018. The FERC issued an order accepting the filing on March 19, 2018. Cheyenne Hub Enhancement Project - FERC Docket CP18-103 On March 2, 2018, Rockies Express submitted an application pursuant to section 7(c) of the Natural Gas Act for a certificate of public convenience and necessity authorizing the construction and operation of certain booster compressor units and ancillary facilities located at the Cheyenne Hub in Weld County, Colorado that will enable Rockies Express to provide a new hub service allowing for firm receipts and deliveries between Rockies Express and certain other interconnected pipelines at the Cheyenne Hub. Rockies Express filed this certificate application in conjunction with a concurrently filed certificate application by Cheyenne Connector, LLC ("Cheyenne Connector") for the Cheyenne Connector Pipeline Project further described below. The comment period for the Cheyenne Hub Enhancement Project closed on April 9, 2018. To date, various comments have been filed by market participants regarding the proposed project. Cheyenne Connector Cheyenne Connector Pipeline Project - FERC Docket CP18-102 On March 2, 2018, Cheyenne Connector, an indirect wholly-owned subsidiary of TEP, submitted an application pursuant to section 7(c) of the Natural Gas Act 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’s Cheyenne Hub. The comment period for the Cheyenne Connector Pipeline Project closed on April 9, 2018. To date, various comments have been filed by market participants regarding the proposed project. TIGT General Rate Case Filing - FERC Docket No. RP16-137-000, et seq. On October 30, 2015, in Docket No. RP16-137-000, et seq. , TIGT filed a general rate case with the FERC pursuant to Section 4 of the National Gas Act ("NGA"). The general rate case was ultimately resolved via settlement, which the FERC approved on November 2, 2016, and a compliance filing that modernized TIGT's FERC Gas Tariff, consistent with prior FERC orders, which the FERC accepted on March 16, 2017. Per the terms of the settlement, TIGT is required to file a new general rate case on May 1, 2019 (provided that such rate case is not pre-empted by a pre-filing settlement). 2017 Annual Fuel Tracker Filing - FERC Docket No. RP17-428-000 On February 27, 2017, in Docket No. RP17-428-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2017. The filing incorporated the FL&U tracker and power cost tracker mechanisms agreed to in the TIGT Rate Case Settlement. The FERC accepted the filing on March 21, 2017. Electric Power Charge Clarification - FERC Docket No. RP17-1051-000 On September 15, 2017, in Docket No. RP17-1051-000, TIGT proposed certain revisions to its tariff to clarify, amongst other things, that the electric power costs associated with the operation of gas coolers at both electric and gas powered stations are properly included in the Power Cost Tracker. The FERC issued an order on October 3, 2017 accepting the proposed revisions. 2018 Annual Fuel Tracker Filing - FERC Docket No. RP18-533-000 On March 1, 2018, in Docket No. RP18-533-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2018. The FERC accepted the filing on March 22, 2018. Trailblazer 2017 Annual and Interim Fuel Tracker Filings - FERC Docket Nos. RP17-549-000 and RP17-1052-000 On March 22, 2017, in Docket No. RP17-549-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2017. The FERC accepted the filing on April 19, 2017. On September 15, 2017, Trailblazer made its interim fuel tracker filing in Docket No. RP17-1052-000 with a proposed effective date of November 1, 2017. The FERC accepted the filing on October 13, 2017. 2018 Annual Fuel Tracker Filing - FERC Docket No. RP18-580-000 On March 22, 2018, in Docket No. in Docket No. RP18-580-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2018. The FERC accepted the filing on April 20, 2018.

Legal and Environmental Matters

Legal and Environmental Matters	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Legal and Environmental Matters	Legal In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on our business, financial position, results of operations, or cash flows. We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, have recorded no reserve for legal claims as of March 31, 2018 or December 31, 2017 . Rockies Express Ultra Resources In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, seeking approximately $303 million in damages and other relief. On April 29, 2016, Ultra and certain of its debtor affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District of Texas, which operated as a stay of the Harris County state court proceeding. On January 12, 2017, Rockies Express and Ultra entered into an agreement to settle Rockies Express' approximately $303 million claim against Ultra. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37 per dth/d, or approximately $26.8 million annually. TEP received its proportionate distribution from the cash settlement payment in July 2017. 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 believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of $7.7 million at March 31, 2018 and December 31, 2017 . Rockies Express Seneca Lateral On January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations. The release required Rockies Express to shut off the flow through the segment until February 27, 2018, when temporary repairs were completed allowing the segment to be placed back into service. Total cost of remediation is expected to be approximately $4.8 million prior to any insurance recoveries. A root cause investigation is ongoing. TMID Casper Plant, EPA Notice of Violation In August 2011, the EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, Tallgrass Midstream, LLC ("TMID") received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including the expected inclusion of TIGT as a party to any possible settlement as a result of TIGT owning a compressor that is located adjacent to the Casper Gas Plant site. Casper Gas Plant On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing. TMG Archibald Booster Station Tallgrass Midstream Gathering, LLC ("TMG") is currently a party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Archibald Booster Station located in Campbell County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling, and quarterly recovery activities at monitoring wells. The facility is currently in compliance with the WDEQ under the remedy agreement. Irwin Booster Station TMG is also party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Irwin Booster Station located in Converse County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling. The facility is currently in compliance with the WDEQ under the remedy agreement. 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 intends to continue performing remediation to increase and maximize its operating capacity over the long-term and expects to spend in excess of $20 million during 2018 for this pipe replacement and remediation work. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms. In connection with our 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 is substantially complete as of March 31, 2018.

Reporting Segments

Reporting Segments	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Reporting Segments	Our operations are located in the United States. We are organized into three reportable segments: (1) Natural Gas Transportation, (2) Crude Oil Transportation, and (3) Gathering, Processing & Terminalling. 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 49.99% 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 Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado, and an extension of the system from a new origin near Platteville, Colorado ending at the Buckingham Terminal. 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. Corporate and Other 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 2024 and 2028 Notes, public company costs, and equity-based compensation expense. 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 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, a non-GAAP measure, 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. The following tables set forth our segment information for the periods indicated: Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Revenue: Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 36,202 $ (1,858 ) $ 34,344 $ 36,428 $ (1,445 ) $ 34,983 Crude Oil Transportation 89,966 (3,319 ) 86,647 84,994 — 84,994 Gathering, Processing & Terminalling 63,838 (5,735 ) 58,103 27,307 (2,884 ) 24,423 Corporate and Other — — — — — — Total revenue $ 190,006 $ (10,912 ) $ 179,094 $ 148,729 $ (4,329 ) $ 144,400 Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 90,519 $ (2,255 ) $ 88,264 $ 53,030 $ (1,445 ) $ 51,585 Crude Oil Transportation 59,456 4,150 63,606 55,491 4,228 59,719 Gathering, Processing & Terminalling 16,915 (1,895 ) 15,020 8,351 (2,783 ) 5,568 Corporate and Other (1,853 ) — (1,853 ) (1,761 ) — (1,761 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investments 53,406 20,738 Non-cash gain related to derivative instruments, net of noncontrolling interests 2,674 2,441 Gain on disposal of assets 9,417 1,448 Less: Interest expense, net (28,184 ) (14,689 ) Depreciation and amortization expense, net of noncontrolling interest (25,854 ) (21,867 ) Distributions from unconsolidated investments (65,857 ) (30,819 ) Non-cash compensation expense (2,755 ) (1,458 ) Net income attributable to partners $ 107,884 $ 70,905 Three Months Ended March 31, Capital Expenditures: 2018 2017 (in thousands) Natural Gas Transportation $ 9,885 $ 4,655 Crude Oil Transportation 16,952 7,343 Gathering, Processing & Terminalling 31,139 14,771 Corporate and Other 784 — Total capital expenditures $ 58,760 $ 26,769 Assets: March 31, 2018 December 31, 2017 (in thousands) Natural Gas Transportation $ 1,648,241 $ 1,606,666 Crude Oil Transportation 1,412,650 1,407,758 Gathering, Processing & Terminalling 1,095,410 943,340 Corporate and Other 34,578 19,589 Total assets $ 4,190,879 $ 3,977,353

Subsequent Events (Notes)

Subsequent Events (Notes)	3 Months Ended
	Mar. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Pawnee Terminal On January 2, 2018, Terminals entered into an agreement to acquire a 51% membership interest in the Pawnee, Colorado crude oil terminal ("Pawnee Terminal") from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $31 million . The transaction closed on April 1, 2018.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These condensed consolidated financial statements and related notes for the three months ended March 31, 2018 and 2017 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of accounting principles generally accepted in the United States of America ("GAAP") for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP for annual periods. The condensed consolidated financial statements for the three months ended March 31, 2018 and 2017 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair statement of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Certain prior period amounts have been reclassified to conform to the current presentation. Our financial results for the three months ended March 31, 2018 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2018 . The accompanying condensed consolidated interim financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017 ("2017 Form 10-K") filed with the SEC on February 13, 2018.
Consolidation	The condensed consolidated financial statements include the accounts of TEP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP and noncontrolling interests in accordance with the respective ownership interests. TEP 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.
Use of Estimates	Use of Estimates Certain amounts included in or affecting these condensed consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts reported for assets, liabilities, revenues, and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Management evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from these estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.
Revenue Recognition, Policy	Accounting Pronouncement Recently Adopted Revenue Recognition In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five-step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to members' equity. Consolidated revenues presented in the comparative consolidated financial statements for periods prior to January 1, 2018 will not be revised. On January 1, 2018, we recorded a cumulative effect adjustment to equity of $44.1 million , increased the carrying amount of our investment in Rockies Express by $42.8 million , and recognized a receivable from Rockies Express of $1.3 million . These adjustments relate to the cumulative effect adjustment recorded by Rockies Express of $125.2 million upon adoption of ASC 606. The cumulative effect adjustment at Rockies Express arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas during the periods prior to implementation. Through our review process, we also identified the following changes to our revenue recognition policies that did not result in a cumulative effect adjustment on January 1, 2018: • Gathering & Processing. We have determined that a number of our gathering & processing contracts at TMID do not represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of raw gas will be accounted for as supply arrangements pursuant to ASC 705. As a result, gathering & processing fees previously recognized in revenue will be reported as a reduction to cost of sales under ASC 606. • Pipeline Loss Allowance. We have determined that pipeline loss allowance, or PLA, collected under certain crude oil transportation arrangements is a component of the transaction price where the PLA both significantly exceeds actual losses and was negotiated with the intent of providing a revenue stream to TEP. Under ASC 606, PLA barrels retained from customers will be subject to the guidance for noncash consideration and recognized in revenue at their contract inception fair value. See Note 11 – Revenue from Contracts with Customers for revenue disclosures related to both the implementation and the additional requirements prescribed by the standard. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities.
Accounting Pronouncements	Accounting Pronouncements Not Yet Adopted ASU No. 2016-02, "Leases (Topic 842)" In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP. Management is currently evaluating the impact of our pending adoption of ASC 842. The status of our implementation is as follows: • Management has formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain contract types, and project status. • Management is in the process of gathering data and reviewing contracts in order to identify all impacted contracts. • Management is evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from its contract review process. • Management plans to provide internal training and awareness related to the revised guidance to the key stakeholders throughout its organization. The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. We are currently evaluating the impact of ASU 2016-02.

Description of Business Descrip

Description of Business Description of Business - Schedule of Ownership Interests (Tables)	3 Months Ended
	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Other Ownership Interests	The table below summarizes our equity ownership as of March 31, 2018 : Unit holder Limited Partner Common Units General Partner Units Percentage of Outstanding Limited Partner Common Units Percentage of Outstanding Common and General Partner Units Public Unitholders 47,580,535 — 65.00 % 64.27 % Tallgrass Equity, LLC 25,619,218 — 35.00 % 34.60 % Tallgrass MLP GP, LLC (1) — 834,391 — % 1.13 % Total 73,199,753 834,391 100.00 % 100.00 % (1) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights.

Acquisitions & Dispositions - B

Acquisitions & Dispositions - Business Combinations (Tables)	3 Months Ended
	Mar. 31, 2018
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information	Pro Forma Financial Information Unaudited pro forma revenue and net income attributable to TEP for the three months ended March 31, 2018 and 2017 is presented below as if the acquisition of BNN North Dakota had been completed on January 1, 2017. Three Months Ended March 31, 2018 2017 (in thousands) Revenue $ 179,522 $ 146,716 Net income attributable to partners $ 108,116 $ 70,061
BNN North Dakota
Business Acquisition [Line Items]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following represents the fair value of assets acquired and liabilities assumed (in thousands): Accounts receivable $ 2,457 Inventory 67 Property, plant and equipment 48,900 Intangible asset 46,800 (1) Accounts payable and accrued liabilities (3,224 ) Net identifiable assets acquired (excluding cash) $ 95,000 (1) The $46.8 million intangible asset acquired represents three major customer relationships. This intangible asset is amortized on a straight-line basis over a period of 8 - 14 years, the remaining terms of the underlying contracts at the time of acquisition.

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2018
Related Party Transactions [Abstract]
Schedule of Transactions with Affiliated Companies	Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows: Three Months Ended March 31, 2018 2017 (in thousands) Processing and other revenues (1) $ 1,896 $ 1,632 Cost of transportation services (2) $ — $ 4,507 Charges to TEP: (3) Property, plant and equipment, net $ — $ 293 Operations and maintenance $ — $ 6,277 General and administrative $ — $ 9,377 (1) Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline. (2) Reflects rent expense for the crude oil storage at the Deeprock Terminal prior to our consolidation of Deeprock Development during the third quarter of 2017 . (3) Charges to TEP include indirectly charged wages and salaries, other compensation and benefits, and shared services for periods prior to January 1, 2018. Effective January 1, 2018, these costs are incurred by TEP directly and, in the case of certain employee compensation and benefits, paid on TEP's behalf by its affiliate, Tallgrass Management, LLC pursuant to the TEP Omnibus Agreement.
Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets	Details of balances with affiliates included in "Receivable from related parties" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows: March 31, 2018 December 31, 2017 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 4,324 $ 1,340 Iron Horse Pipeline, LLC 148 — Total receivable from related parties $ 4,472 $ 1,340 Accounts payable to related parties: Tallgrass Operations, LLC (1) $ — $ 5,381 Tallgrass Equity, LLC 64 80 Total accounts payable to related parties $ 64 $ 5,461 (1) Reflects accounts payable for charges to TEP including indirectly charged wages and salaries, other compensation and benefits, and shared services prior to January 1, 2018 as discussed above.
Schedule of Balances of Gas Imbalance with Affiliated Shippers	Gas imbalances with affiliated shippers are as follows: March 31, 2018 December 31, 2017 (in thousands) Affiliate gas imbalance receivables $ 13 $ 18 Affiliate gas imbalance payables $ 269 $ 442

Inventory (Tables)

Inventory (Tables)	3 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Schedule of Components of Inventory	The components of inventory at March 31, 2018 and December 31, 2017 consisted of the following: March 31, 2018 December 31, 2017 (in thousands) Crude oil $ 21,517 $ 12,792 Materials and supplies 5,914 5,891 Natural gas liquids 607 942 Gas in underground storage 4,109 1,984 Total inventory $ 32,147 $ 21,609

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	3 Months Ended
	Mar. 31, 2018
Property, Plant and Equipment [Abstract]
Components of Property Plant and Equipment	A summary of net property, plant and equipment by classification is as follows: March 31, 2018 December 31, 2017 (in thousands) Crude oil pipelines $ 1,252,262 $ 1,220,379 Gathering, processing and terminalling assets (1) 744,515 675,092 Natural gas pipelines 585,483 581,400 General and other 118,355 98,680 Construction work in progress 112,464 97,978 Accumulated depreciation and amortization (314,364 ) (279,192 ) Total property, plant and equipment, net $ 2,498,715 $ 2,394,337 (1) Includes approximately $46.2 million and $40.1 million of assets associated with the acquisitions of Deeprock North and BNN North Dakota, respectively, in January 2018.

Investments in Unconsolidated29

Investments in Unconsolidated Affiliates Investments in Unconsolidated Affiliates (Tables)	3 Months Ended
	Mar. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Summarized financial information for Rockies Express is as follows: Three Months Ended March 31, 2018 2017 (in thousands) Revenue $ 230,058 $ 201,338 Operating income $ 128,678 $ 107,369 Net income to Members $ 90,968 $ 66,250

Risk Management (Tables)

Risk Management (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Fair Value of Derivative Contracts	The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets: Balance Sheet March 31, 2018 December 31, 2017 (in thousands) Crude oil derivative contracts (1) Current assets $ 306 $ — Crude oil derivative contracts (1) Current liabilities $ — $ 2,368 (1) As of March 31, 2018 , the fair value shown for crude oil derivative contracts represents the forward sale of 242,000 barrels which will settle throughout the second quarter of 2018. As of December 31, 2017 , the fair value shown for crude oil derivative contracts represents the forward sale of 356,000 barrels of crude oil which settled in the first quarter of 2018.
Derivative Contracts Included in Consolidated Statements of Income	The following table summarizes the impact of derivative contracts not designated as hedging contracts for the three months ended March 31, 2018 and 2017 : Location of gain recognized Amount of gain recognized in income on derivatives Three Months Ended March 31, 2018 2017 (in thousands) Derivatives not designated as hedging contracts: Crude oil derivative contracts Sales of natural gas, NGLs, and crude oil $ 4,295 $ 663 Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ — $ 173 Call option derivative Other income, net $ — $ 1,885
Derivative Instruments Maximum Potential Exposure to Credit Loss	The maximum potential exposure to credit losses on our crude oil derivative contracts at March 31, 2018 was: Asset Position (in thousands) Gross $ 306 Netting agreement impact — Cash collateral held — Net exposure $ 306
Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification	The following table summarizes the fair value measurements of our derivative contracts as of March 31, 2018 and December 31, 2017 , based on the fair value hierarchy: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of March 31, 2018: Crude oil derivative contracts $ 306 $ — $ 306 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2017: Crude oil derivative contracts $ 2,368 $ — $ 2,368 $ —

Long-term Debt (Tables)

Long-term Debt (Tables)	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Schedule of Debt	Long-term debt consisted of the following at March 31, 2018 and December 31, 2017 : March 31, 2018 December 31, 2017 (in thousands) Revolving credit facility $ 816,000 $ 661,000 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) (17,628 ) (17,737 ) Plus: Unamortized premium on 2028 Notes 3,642 3,730 Total long-term debt, net $ 2,302,014 $ 2,146,993 (1) Deferred financing costs, net as presented above relate solely to the 2024 and 2028 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our condensed consolidated balance sheets.
Schedule of Line of Credit Facilities	The following table sets forth the available borrowing capacity under the revolving credit facility as of March 31, 2018 and December 31, 2017 : March 31, 2018 December 31, 2017 (in thousands) Total capacity under the revolving credit facility $ 1,750,000 $ 1,750,000 Less: Outstanding borrowings under the revolving credit facility (816,000 ) (661,000 ) Less: Letters of credit issued under the revolving credit facility (94 ) (94 ) Available capacity under the revolving credit facility $ 933,906 $ 1,088,906
Carrying Amount and Fair Value of TEP's Long-term Debt	The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of March 31, 2018 and December 31, 2017 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of March 31, 2018: Revolving credit facility $ — $ 816,000 $ — $ 816,000 $ 816,000 2024 Notes $ — $ 767,063 $ — $ 767,063 $ 740,202 2028 Notes $ — $ 754,425 $ — $ 754,425 $ 745,812 As of December 31, 2017: Revolving credit facility $ — $ 661,000 $ — $ 661,000 $ 661,000 2024 Notes $ — $ 771,645 $ — $ 771,645 $ 739,824 2028 Notes $ — $ 758,168 $ — $ 758,168 $ 746,169

Partnership Equity and Distri32

Partnership Equity and Distributions (Tables)	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Summary of Distributions	The following table shows the distributions for the periods indicated: Distributions Distribution Limited Partner 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 (1) $ 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 (1) The distribution announced on March 26, 2018 for the first quarter of 2018 will be paid on May 15, 2018 to unitholders of record at the close of business on April 30, 2018 .

Revenue from Contracts with C33

Revenue from Contracts with Customers Revenue from Contract with Customer (Tables)	3 Months Ended
	Mar. 31, 2018
Revenue from Contract with Customer [Abstract]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	The following tables provide the impact of the guidance on our condensed consolidated balance sheet as of March 31, 2018 and the condensed consolidated statement of income for the three months ended March 31, 2018 : March 31, 2018 As currently reported Under previous guidance Impact of ASC Topic 606 (in thousands) Unconsolidated investments $ 950,587 $ 900,013 $ 50,574 (1) Three Months Ended March 31, 2018 As currently reported Under previous guidance Impact of ASC Topic 606 (in thousands) Revenues: Crude oil transportation services $ 84,738 $ 84,466 $ 272 (2) Sales of natural gas, NGLs, and crude oil $ 38,145 $ 39,245 $ (1,100 ) (3) Processing and other revenues $ 24,015 $ 25,525 $ (1,510 ) (1)(3) Cost of sales $ 26,351 $ 28,845 $ (2,494 ) (2)(3) Equity in earnings of unconsolidated investments $ 53,406 $ 45,698 $ 7,708 (1) Net income attributable to partners $ 107,884 $ 100,020 $ 7,864 Basic net income per common unit $ 0.91 $ 0.80 $ 0.11 Diluted net income per common unit $ 0.91 $ 0.80 $ 0.11 (1) Reflects the impact on our investment in Rockies Express and the management fee collected by NatGas of the cumulative effect adjustment at Rockies Express, which arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas. (2) Reflects the impact to revenue and cost of sales to value PLA barrels collected under certain crude oil transportation arrangements at their contract inception fair value in revenue and record an associated lower of cost or net realizable value adjustment in cost of sales. (3) Reflects the reclassification of certain gathering and processing fees collected under arrangements determined to be supply arrangements, rather than customer arrangements under ASC 606, to cost of sales and the reclassification of certain commodities retained as consideration for processing services to processing fee revenue.
Disaggregation of Revenue	A summary of our revenue by line of business is as follows: Three Months Ended March 31, 2018 Natural Gas Transportation segment Crude Oil Transportation segment Gathering, Processing, & Terminalling segment Corporate and Other Total Revenue (in thousands) Crude oil transportation - committed shipper revenue $ — $ 84,738 $ — $ — $ 84,738 Natural gas transportation - firm service 33,334 — — (1,883 ) 31,451 Water business services — — 13,204 — 13,204 Natural gas gathering & processing fees — — 5,044 — 5,044 All other (1) 2,630 3,319 5,706 (6,088 ) 5,567 Total service revenue 35,964 88,057 23,954 (7,971 ) 140,004 Natural gas liquids sales — — 23,609 — 23,609 Natural gas sales 238 — 7,847 — 8,085 Crude oil sales — 1,909 247 — 2,156 Total commodity sales revenue 238 1,909 31,703 — 33,850 Total revenue from contracts with customers 36,202 89,966 55,657 (7,971 ) 173,854 Other revenue (2) — — 8,181 (2,941 ) 5,240 Total revenue (3) $ 36,202 $ 89,966 $ 63,838 $ (10,912 ) $ 179,094 (1) Includes revenue from crude oil 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 $230.1 million of revenue recognized at Rockies Express for the three months ended March 31, 2018 . See Note 7 – Investments in Unconsolidated Affiliates for additional information about our investment in Rockies Express.
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	We expect to recognize the total backlog during the remainder of 2018 and future periods as follows (in thousands): Year Estimated Revenue 2018 $ 387,826 2019 488,919 2020 317,235 2021 138,686 2022 129,548 Thereafter 271,311 Total $ 1,733,525
Contract with Customer, Asset and Liability	Contract balances as of March 31, 2018 were as follows: March 31, 2018 January 1, 2018 (in thousands) Accounts receivable from contracts with customers $ 68,039 $ 61,888 Other accounts receivable 63,362 56,727 Accounts receivable, net $ 131,401 $ 118,615 Deferred revenue from contracts with customers (1) $ 99,922 $ 88,471 (1) Revenue recognized during the three months ended March 31, 2018 that was included in the deferred revenue balance at the beginning of the period was $3.1 million . This revenue primarily represented the utilization of shipper deficiencies at Pony Express.

Net Income per Limited Partne34

Net Income per Limited Partner Unit (Tables)	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Summary of Net Income Per Limited Partner Unit	The following table illustrates the calculation of net income per common unit for the three months ended March 31, 2018 and 2017 : Three Months Ended March 31, 2018 2017 (in thousands, except per unit amounts) Net income $ 109,645 $ 71,784 Net income attributable to noncontrolling interests (1,761 ) (879 ) Net income attributable to partners 107,884 70,905 General partner interest in net income (41,032 ) (30,583 ) Net income available to common unitholders $ 66,852 $ 40,322 Basic net income per common unit $ 0.91 $ 0.56 Diluted net income per common unit $ 0.91 $ 0.55 Basic average number of common units outstanding 73,200 72,544 Equity Participation Unit equivalent units 475 1,036 Diluted average number of common units outstanding 73,675 73,580

Reporting Segments (Tables)

Reporting Segments (Tables)	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Summary of TEP's Segment Information of Revenue	The following tables set forth our segment information for the periods indicated: Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Revenue: Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 36,202 $ (1,858 ) $ 34,344 $ 36,428 $ (1,445 ) $ 34,983 Crude Oil Transportation 89,966 (3,319 ) 86,647 84,994 — 84,994 Gathering, Processing & Terminalling 63,838 (5,735 ) 58,103 27,307 (2,884 ) 24,423 Corporate and Other — — — — — — Total revenue $ 190,006 $ (10,912 ) $ 179,094 $ 148,729 $ (4,329 ) $ 144,400
Summary of TEP's Segment Information of Earnings	Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 90,519 $ (2,255 ) $ 88,264 $ 53,030 $ (1,445 ) $ 51,585 Crude Oil Transportation 59,456 4,150 63,606 55,491 4,228 59,719 Gathering, Processing & Terminalling 16,915 (1,895 ) 15,020 8,351 (2,783 ) 5,568 Corporate and Other (1,853 ) — (1,853 ) (1,761 ) — (1,761 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investments 53,406 20,738 Non-cash gain related to derivative instruments, net of noncontrolling interests 2,674 2,441 Gain on disposal of assets 9,417 1,448 Less: Interest expense, net (28,184 ) (14,689 ) Depreciation and amortization expense, net of noncontrolling interest (25,854 ) (21,867 ) Distributions from unconsolidated investments (65,857 ) (30,819 ) Non-cash compensation expense (2,755 ) (1,458 ) Net income attributable to partners $ 107,884 $ 70,905
Summary of TEP's Segment Capital Expenditures	Three Months Ended March 31, Capital Expenditures: 2018 2017 (in thousands) Natural Gas Transportation $ 9,885 $ 4,655 Crude Oil Transportation 16,952 7,343 Gathering, Processing & Terminalling 31,139 14,771 Corporate and Other 784 — Total capital expenditures $ 58,760 $ 26,769
Summary of TEP's Segment Information of Assets	Assets: March 31, 2018 December 31, 2017 (in thousands) Natural Gas Transportation $ 1,648,241 $ 1,606,666 Crude Oil Transportation 1,412,650 1,407,758 Gathering, Processing & Terminalling 1,095,410 943,340 Corporate and Other 34,578 19,589 Total assets $ 4,190,879 $ 3,977,353

Description of Business Descr36

Description of Business Description of Business - Schedule of Ownership Interests (Details) - shares	Mar. 31, 2018	Dec. 31, 2017
Organization [Line Items]
Limited Partner Common Units	73,199,753	73,199,753
General Partner Units	834,391	834,391
Percentage of Outstanding Limited Partner Common Units	100.00%
Percentage of Outstanding Common and General Partner Units	100.00%
Ownership Interests Held By Public
Organization [Line Items]
Limited Partner Common Units	47,580,535
General Partner Units	0
Percentage of Outstanding Limited Partner Common Units	65.00%
Percentage of Outstanding Common and General Partner Units	64.27%
Ownership Interests Held By Tallgrass Equity, LLC
Organization [Line Items]
Limited Partner Common Units	25,619,218
General Partner Units	0
Percentage of Outstanding Limited Partner Common Units	35.00%
Percentage of Outstanding Common and General Partner Units	34.60%
Ownership Interests Held By Tallgrass MLP GP, LLC
Organization [Line Items]
Limited Partner Common Units	0
General Partner Units	834,391
Percentage of Outstanding Limited Partner Common Units	0.00%
Percentage of Outstanding Common and General Partner Units	1.13%

Description of Business - Addit

Description of Business - Additional Information (Detail)	Mar. 26, 2018	Mar. 31, 2018shares	Dec. 31, 2017shares	Jan. 01, 2017
Organization [Line Items]
Limited Partner Common Units		73,199,753	73,199,753
Stockholders' Equity Note, Stock Split, Conversion Ratio	0
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units		100.00%
Tallgrass NatGas Operator, LLC
Organization [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				100.00%
Tallgrass Terminals, LLC
Organization [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				100.00%
Tallgrass Energy Partners
Organization [Line Items]
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units	100.00%
Ownership Interests Held By Public
Organization [Line Items]
Limited Partner Common Units		47,580,535
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units		64.27%
Rockies Express Pipeline LLC
Organization [Line Items]
Equity Method Investment, Ownership Percentage		49.99%
Rockies Express Pipeline LLC | Tallgrass Energy Partners
Organization [Line Items]
Equity Method Investment, Ownership Percentage		49.99%

Summary of Significant Accoun38

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of ASC 606 implementation		$ 44,100
Unconsolidated investments	$ 950,587		$ 909,531
Accounts receivable, net	$ 131,401		$ 118,615
Rockies Express Pipeline LLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Unconsolidated investments		42,800
Tallgrass NatGas Operator, LLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Accounts receivable, net		1,300
Rockies Express Pipeline LLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cumulative effect of ASC 606 implementation		$ 125,200

Acquisitions & Dispositions -39

Acquisitions & Dispositions - BNN North Dakota Acquisition, Assets Acquired & Liabilities Assumed (Details) - USD ($) $ in Thousands	Jan. 12, 2018	Mar. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Inventories		$ 32,147	$ 21,609
Property, plant and equipment, net		2,498,715	2,394,337
Intangible assets, net		$ 136,554	$ 97,731
BNN North Dakota
Business Acquisition [Line Items]
Accounts receivable	$ 2,457
Inventories	67
Property, plant and equipment, net	48,900
Intangible assets, net	46,800
Accounts payable and accrued liabilities	(3,224)
Net identifiable assets acquired (excluding cash)	$ 95,000
Minimum
Business Acquisition [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	8 years
Maximum
Business Acquisition [Line Items]
Finite-Lived Intangible Assets, Remaining Amortization Period	14 years

Acquisitions & Dispositions - P

Acquisitions & Dispositions - Pro Forma Revenue & Net Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Business Combinations [Abstract]
Pro Forma Revenue	$ 179,522	$ 146,716
Pro Forma Net income attributable to partners	$ 108,116	$ 70,061

Acquisitons & Dispositions - Ad

Acquisitons & Dispositions - Additional Information (Details) $ in Thousands	Feb. 23, 2018USD ($)	Feb. 06, 2018USD ($)mi	Feb. 01, 2018USD ($)	Jan. 12, 2018USD ($)a	Jan. 02, 2018USD ($)	Mar. 31, 2018USD ($)	Mar. 31, 2018USD ($)	Mar. 31, 2017USD ($)	Jan. 01, 2016
Business Acquisition [Line Items]
Sale of Tallgrass Crude Gathering							$ 50,046
Payments to Acquire Interest in Subsidiaries and Affiliates							0	$ 400,000
Acquisition of BNN North Dakota, net of cash acquired							95,000
Payments to Acquire Equity Method Investments							19,500
Issuance of Noncontrolling Interest in Subsidiary in Exchange for Membership Interest							$ 31,843
Iron Horse Pipeline, LLC
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage	75.00%
Payments to Acquire Equity Method Investments	$ 3,500
Deeprock North, LLC
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage					38.00%
Tallgrass Crude Gathering, LLC
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Miles of gathering pipeline | mi		50
Sale of Tallgrass Crude Gathering		$ 50,000
Gain on disposal of assets		$ (9,400)
Tallgrass Energy Partners | Deeprock North, LLC
Business Acquisition [Line Items]
Payments to Acquire Equity Method Investments					$ 19,500
BNN North Dakota
Business Acquisition [Line Items]
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual						$ 3,100
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual						$ 1,700
Pony Express Pipeline
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest			100.00%
Business Acquisition, Percentage of Voting Interests Acquired			2.00%						31.30%
Pony Express Pipeline | Tallgrass Energy Partners
Business Acquisition [Line Items]
Payments to Acquire Interest in Subsidiaries and Affiliates			$ 60,000
BNN North Dakota
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				100.00%
Acres for Water Gathering and Disposal System | a				133,000
BNN North Dakota | Tallgrass Energy Partners
Business Acquisition [Line Items]
Acquisition of BNN North Dakota, net of cash acquired				$ 95,000
Deeprock Development, LLC
Business Acquisition [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest					60.00%

Related Party Transactions - Sc

Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Related Party Transaction [Line Items]
Revenue from related parties	$ 1,896	$ 1,632
Cost of transportation services from related parties	0	4,507
Operations and maintenance
Related Party Transaction [Line Items]
Expenses related to transactions with related parties	0	6,277
General and administrative
Related Party Transaction [Line Items]
Expenses related to transactions with related parties	0	9,377
Property, Plant and Equipment
Related Party Transaction [Line Items]
Costs capitalized from transactions with related parties	$ 0	$ 293

Related Party Transactions - 43

Related Party Transactions - Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Receivable from related parties	$ 4,472	$ 1,340
Accounts payable to related parties	64	5,461
Rockies Express Pipeline LLC
Related Party Transaction [Line Items]
Receivable from related parties	4,324	1,340
Iron Horse Pipeline, LLC
Related Party Transaction [Line Items]
Receivable from related parties	148	0
Tallgrass Operations, LLC
Related Party Transaction [Line Items]
Accounts payable to related parties	0	5,381
Tallgrass Equity, LLC
Related Party Transaction [Line Items]
Accounts payable to related parties	$ 64	$ 80

Related Party Transactions - 44

Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Affiliate gas imbalance receivables	$ 13	$ 18
Affiliate gas imbalance payables	$ 269	$ 442

Inventory Inventory (Details)

Inventory Inventory (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Crude oil	$ 21,517	$ 12,792
Materials and supplies	5,914	5,891
Natural gas liquids	607	942
Gas in underground storage	4,109	1,984
Inventory, Net	$ 32,147	$ 21,609

Property Plant and Equipment -

Property Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Accumulated depreciation and amortization	$ (314,364)	$ (279,192)
Property, plant and equipment, net	2,498,715	2,394,337
Crude oil pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	1,252,262	1,220,379
Gathering, processing and terminalling assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	744,515	675,092
Natural gas pipelines
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	585,483	581,400
General and other
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	118,355	98,680
Construction work in progress
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	112,464	$ 97,978
Deeprock North, LLC | Gathering, processing and terminalling assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	46,200
BNN North Dakota | Gathering, processing and terminalling assets
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 40,100

Investments in Unconsolidated47

Investments in Unconsolidated Affiliates Investments in Unconsolidated Affiliates - Equity Method Investments (Details) - Rockies Express Pipeline LLC - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Schedule of Equity Method Investments [Line Items]
Revenue	$ 230,058	$ 201,338
Operating income	128,678	107,369
Net income to Members	$ 90,968	$ 66,250

Investments in Unconsolidated48

Investments in Unconsolidated Affiliates Investments in Unconsolidated Affiliates - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated investments	$ 53,406	$ 20,738
Payments to Acquire Equity Method Investments	$ (19,500)
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	49.99%
Equity in earnings of unconsolidated investments	$ 52,063
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries	65,900
Payments to Acquire Equity Method Investments	$ (2,363)

Risk Management - Schedule of F

Risk Management - Schedule of Fair Value of Derivative Contracts (Detail) - Energy Related Derivative $ in Thousands	Mar. 31, 2018USD ($)bbl	Dec. 31, 2017USD ($)bbl
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 306
Derivative liabilities at fair value		$ 2,368
Commodity
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	242,000	356,000
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 306	$ 0
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	$ 0	$ 2,368

Risk Management - Derivative Co

Risk Management - Derivative Contracts Included in Consolidated Statement of Income (Detail) - Derivatives not designated as hedging contracts - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Energy Related Derivative
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 4,295	$ 663
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	0	173
Equity Option
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 0	$ 1,885

Risk Management Risk Management

Risk Management Risk Management - Derivative Instruments Maximum Potential Exposure to Credit Loss (Details) - Energy Related Derivative $ in Thousands	Mar. 31, 2018USD ($)
Concentration Risk [Line Items]
Derivative Asset, Securities Purchased under Agreements to Resell, Securities Borrowed, Gross	$ 306
Netting agreement impact	0
Cash Collateral for Borrowed Securities	0
Derivative Asset, Securities Purchased under Agreements to Resell, Securities Borrowed	$ 306

Risk Management - Schedule of E

Risk Management - Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification (Detail) - Energy Related Derivative - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 306
Derivative liabilities at fair value		$ 2,368
Quoted prices in active markets for identical assets (Level 1)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	0
Derivative liabilities at fair value		0
Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	306
Derivative liabilities at fair value		2,368
Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 0
Derivative liabilities at fair value		$ 0

Risk Management Risk Manageme53

Risk Management Risk Management - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Feb. 01, 2017	Jan. 01, 2016	Mar. 31, 2018	Mar. 31, 2017	Feb. 01, 2018
Derivative [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased			736,262
Payments for Repurchase of Common Stock			$ 35,300		$ 0	$ 35,335
Cash in Margin Accounts and Outstanding Letters of Credit	0.8	3
Equity Option
Derivative [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased			1,703,094
Payments for Repurchase of Common Stock			$ 72,400		$ 0	$ 72,381
Pony Express Pipeline
Derivative [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				31.30%			2.00%
Pony Express Pipeline | Equity Option
Derivative [Line Items]
Derivative, Term of Contract				18 months
Option Indexed to Issuer's Equity, Strike Price				$ 42.50
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares				6,518,000

Long-term Debt Schedule of Debt

Long-term Debt Schedule of Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
2024 Senior Notes
Debt Instrument [Line Items]
Total long-term debt, net	$ 740,202	$ 739,824
2028 Senior Notes
Debt Instrument [Line Items]
Total long-term debt, net	745,812	746,169
Revolving credit facility
Debt Instrument [Line Items]
Total long-term debt, net	816,000	661,000
Tallgrass Energy Partners
Debt Instrument [Line Items]
Less: Deferred financing costs, net (1)	(17,628)	(17,737)
Plus: Unamortized premium on 2028 Notes	3,642	3,730
Total long-term debt, net	2,302,014	2,146,993
Tallgrass Energy Partners | 2024 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Gross	750,000	750,000
Tallgrass Energy Partners | 2028 Senior Notes | Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Gross	750,000	750,000
Tallgrass Energy Partners | Revolving credit facility
Debt Instrument [Line Items]
Long-term Debt, Gross	816,000	661,000
Total long-term debt, net	$ 816,000	$ 661,000

Long-term Debt Capacity under R

Long-term Debt Capacity under Revolving Credit Facility (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Revolving credit facility
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility	$ (816,000,000)	$ (661,000,000)
Tallgrass Energy Partners
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility	(2,302,014,000)	(2,146,993,000)
Tallgrass Energy Partners | Revolving credit facility
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility	(816,000,000)	(661,000,000)
Less: Letters of credit issued under the revolving credit facility	(94,000)	(94,000)
Available capacity under the revolving credit facility	933,906,000	1,088,906,000
Tallgrass Energy Partners | Revolving credit facility | Wells Fargo Bank, National Association
Line of Credit Facility [Line Items]
Total capacity under the revolving credit facility	$ 1,750,000,000	$ 1,750,000,000

Long-term Debt - Carrying Amoun

Long-term Debt - Carrying Amount and Fair Value of TEP's Long-term Debt (Detail) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
2024 Senior Notes
Debt Instrument [Line Items]
Fair Value	$ 767,063	$ 771,645
Long-term debt	740,202	739,824
2028 Senior Notes
Debt Instrument [Line Items]
Fair Value	754,425	758,168
Long-term debt	745,812	746,169
Revolving credit facility
Debt Instrument [Line Items]
Fair Value	816,000	661,000
Long-term debt	816,000	661,000
Quoted prices in active markets for identical assets (Level 1) | 2024 Senior Notes
Debt Instrument [Line Items]
Fair Value	0	0
Quoted prices in active markets for identical assets (Level 1) | 2028 Senior Notes
Debt Instrument [Line Items]
Fair Value	0	0
Quoted prices in active markets for identical assets (Level 1) | Revolving credit facility
Debt Instrument [Line Items]
Fair Value	0	0
Significant other observable inputs (Level 2) | 2024 Senior Notes
Debt Instrument [Line Items]
Fair Value	767,063	771,645
Significant other observable inputs (Level 2) | 2028 Senior Notes
Debt Instrument [Line Items]
Fair Value	754,425	758,168
Significant other observable inputs (Level 2) | Revolving credit facility
Debt Instrument [Line Items]
Fair Value	816,000	661,000
Significant unobservable inputs (Level 3) | 2024 Senior Notes
Debt Instrument [Line Items]
Fair Value	0	0
Significant unobservable inputs (Level 3) | 2028 Senior Notes
Debt Instrument [Line Items]
Fair Value	0	0
Significant unobservable inputs (Level 3) | Revolving credit facility
Debt Instrument [Line Items]
Fair Value	$ 0	$ 0

Long-term Debt - Additional Inf

Long-term Debt - Additional Information (Detail)	Dec. 11, 2017USD ($)	Sep. 15, 2017USD ($)	May 16, 2017USD ($)	Sep. 01, 2016USD ($)	Mar. 31, 2018
Debt Instrument [Line Items]
Weighted average interest rate on outstanding borrowings					3.27%
Debt Instrument, Interest Rate, Effective Percentage					3.53%
Maximum
Debt Instrument [Line Items]
Credit facility commitment fee					0.50%
Minimum
Debt Instrument [Line Items]
Credit facility commitment fee					0.25%
Revolving credit facility | Maximum
Debt Instrument [Line Items]
Consolidated leverage ratio					5
Contingent Consolidated Leverage Ratio					5.50
Consolidated Senior Secured Leverage Ratio One					3.75
Revolving credit facility | Minimum
Debt Instrument [Line Items]
Consolidated interest coverage ratio					2.50
Senior Notes | Tallgrass Energy Partners
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					5.50%
2028 Senior Notes | Senior Notes | Tallgrass Energy Partners
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt	$ 250,000,000	$ 500,000,000
2024 Senior Notes | Senior Notes | Tallgrass Energy Partners
Debt Instrument [Line Items]
Proceeds from issuance of long-term debt			$ 350,000,000	$ 400,000,000

Partnership Equity and Distri58

Partnership Equity and Distributions - Summary of Distributions (Detail) - Tallgrass Energy Partners - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017
Distribution Made to Limited Partner [Line Items]
Limited Partner Common Distributions	$ 71,370	$ 70,638	$ 69,174	$ 67,671	$ 60,486
Incentive Distribution Rights Distributions	39,816	39,125	37,744	36,342	29,840
General Partner Distributions	1,267	1,251	1,219	1,186	1,040
Distributions Total	$ 112,453	$ 111,014	$ 108,137	$ 105,199	$ 91,366
Distributions per Limited Partner unit	$ 0.9750	$ 0.9650	$ 0.9450	$ 0.9250	$ 0.8350

Partnership Equity and Distri59

Partnership Equity and Distributions - Additional Information (Detail) - USD ($)	Feb. 01, 2017	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017	Feb. 01, 2018	May 17, 2016	Jan. 01, 2016	May 13, 2015
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Authorized Amount						$ 657,500,000		$ 100,200,000
Partners' Capital Account, Units, Treasury Units Purchased	736,262
Payments for Repurchase of Common Stock	$ 35,300,000	$ 0	$ 35,335,000
Treasury Stock Acquired, Average Cost Per Share	$ 47.99
Distributions to noncontrolling interest		50,000,000	0
Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Issuance of units to public, net of offering costs		0	0
Payments for Repurchase of Common Stock			0
Contributions from TD
Contributions from noncontrolling interests		183,000	710,000
Distributions to noncontrolling interest		$ 1,296,000	1,418,000
Partial exercise of call option			$ 0
Tallgrass Energy Partners
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Units, Sold in Public Offering			2,087,647
Shares Issued, Price Per Share			$ 48.23
Issuance of units to public, net of offering costs			$ 99,400,000
LimitedPartnerOfferingCosts			1,300,000
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		2.00%
Pony Express Pipeline | Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions		$ 33,848,000
Terminals and NatGas | Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions			0
Rockies Express Pipeline LLC | Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions			0
General Partner
Limited Partners' Capital Account [Line Items]
Issuance of units to public, net of offering costs		0	0
Payments for Repurchase of Common Stock			0
Contributions from TD			2,301,000	$ 20,000,000
Contributions from noncontrolling interests		0	0
Distributions to noncontrolling interest		0	0
Partial exercise of call option			12,561,000
General Partner | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions		$ 16,152,000
General Partner | Terminals and NatGas
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions			(57,705,000)
General Partner | Rockies Express Pipeline LLC
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions			$ 63,681,000
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					2.00%		31.30%
Rockies Express Pipeline LLC | Tallgrass Development LP
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			24.99%

Revenue from Contracts with C60

Revenue from Contracts with Customers Revenue from Contract with Customer - Impact of Adoption (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Unconsolidated investments	$ 950,587		$ 909,531
Crude oil transportation services	84,738	$ 84,331
Sales of natural gas, NGLs, and crude oil	(38,145)	(15,381)
Processing and other revenues	(24,015)	(13,003)
Cost of sales	26,351	12,370
Equity in earnings of unconsolidated investments	53,406	20,738
Net income attributable to partners	$ 107,884	$ 70,905
Basic net income per common unit	$ 0.91	$ 0.56
Diluted net income per common unit	$ 0.91	$ 0.55
Accounting Standards Update 2014-09 | Calculated under Revenue Guidance in Effect before Topic 606
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Unconsolidated investments	$ 900,013
Crude oil transportation services	84,466
Sales of natural gas, NGLs, and crude oil	(39,245)
Processing and other revenues	(25,525)
Cost of sales	28,845
Equity in earnings of unconsolidated investments	45,698
Net income attributable to partners	$ 100,020
Basic net income per common unit	$ 0.80
Diluted net income per common unit	$ 0.80
Accounting Standards Update 2014-09 | Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Unconsolidated investments	$ 50,574
Crude oil transportation services	272
Sales of natural gas, NGLs, and crude oil	(1,100)
Processing and other revenues	(1,510)
Cost of sales	(2,494)
Equity in earnings of unconsolidated investments	7,708
Net income attributable to partners	$ 7,864
Basic net income per common unit	$ 0.11
Diluted net income per common unit	$ 0.11

Revenue from Contracts with C61

Revenue from Contracts with Customers Revenue from Contract with Customer - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue, Net	$ 179,094
Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	84,738
Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	31,451
Water Business Services
Disaggregation of Revenue [Line Items]
Revenue, Net	13,204
Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue, Net	5,044
Other Service Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	5,567
Service Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	140,004
Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue, Net	23,609
Natural Gas
Disaggregation of Revenue [Line Items]
Revenue, Net	8,085
Crude Oil
Disaggregation of Revenue [Line Items]
Revenue, Net	2,156
Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	33,850
Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	173,854
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	5,240
Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	36,202
Natural Gas Transportation | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Natural Gas Transportation | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	33,334
Natural Gas Transportation | Water Business Services
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Natural Gas Transportation | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Natural Gas Transportation | Other Service Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	2,630
Natural Gas Transportation | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	35,964
Natural Gas Transportation | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Natural Gas Transportation | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue, Net	238
Natural Gas Transportation | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Natural Gas Transportation | Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	238
Natural Gas Transportation | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	36,202
Natural Gas Transportation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	89,966
Crude Oil Transportation | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	84,738
Crude Oil Transportation | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Crude Oil Transportation | Water Business Services
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Crude Oil Transportation | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Crude Oil Transportation | Other Service Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	3,319
Crude Oil Transportation | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	88,057
Crude Oil Transportation | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Crude Oil Transportation | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Crude Oil Transportation | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue, Net	1,909
Crude Oil Transportation | Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	1,909
Crude Oil Transportation | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	89,966
Crude Oil Transportation | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Gathering, Processing & Terminalling
Disaggregation of Revenue [Line Items]
Revenue, Net	63,838
Gathering, Processing & Terminalling | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Gathering, Processing & Terminalling | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Gathering, Processing & Terminalling | Water Business Services
Disaggregation of Revenue [Line Items]
Revenue, Net	13,204
Gathering, Processing & Terminalling | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue, Net	5,044
Gathering, Processing & Terminalling | Other Service Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	5,706
Gathering, Processing & Terminalling | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	23,954
Gathering, Processing & Terminalling | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue, Net	23,609
Gathering, Processing & Terminalling | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue, Net	7,847
Gathering, Processing & Terminalling | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue, Net	247
Gathering, Processing & Terminalling | Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	31,703
Gathering, Processing & Terminalling | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	55,657
Gathering, Processing & Terminalling | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	8,181
Corporate and Other
Disaggregation of Revenue [Line Items]
Revenue, Net	(10,912)
Corporate and Other | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Corporate and Other | Natural Gas Transportation
Disaggregation of Revenue [Line Items]
Revenue, Net	(1,883)
Corporate and Other | Water Business Services
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Corporate and Other | Natural Gas Gathering & Processing
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Corporate and Other | Other Service Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	(6,088)
Corporate and Other | Service Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	(7,971)
Corporate and Other | Natural Gas Liquids
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Corporate and Other | Natural Gas
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Corporate and Other | Crude Oil
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Corporate and Other | Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	0
Corporate and Other | Total Service and Commodity Sales Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	(7,971)
Corporate and Other | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue, Net	(2,941)
Rockies Express Pipeline LLC
Disaggregation of Revenue [Line Items]
Equity Method Investment, Summarized Financial Information, Revenue	$ 230,058	$ 201,338

Revenue from Contracts with C62

Revenue from Contracts with Customers Revenue from Contract with Customer - Remaining Performance Obligation (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized as of March 31, 2018	$ 387,826
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized as of March 31, 2018	$ 488,919
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized as of March 31, 2018	$ 317,235
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized as of March 31, 2018	$ 138,686
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized as of March 31, 2018	$ 129,548
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue expected to be recognized as of March 31, 2018	$ 1,733,525
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	15 years

Revenue from Contracts with C63

Revenue from Contracts with Customers Revenue from Contract with Customer - Contract with Customer, Asset and Liability (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Contract with Customer, Asset, Net, Current	$ 68,039	$ 61,888
Accounts and Other Receivables, Net, Current	63,362	56,727
Accounts receivable, net	131,401	118,615
Deferred revenue	99,922	$ 88,471
Contract with Customer, Liability, Revenue Recognized	$ 3,100

Net Income per Limited Partne64

Net Income per Limited Partner Unit (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share [Abstract]
Net income	$ 109,645	$ 71,784
Net income attributable to noncontrolling interests	(1,761)	(879)
Net income attributable to partners	107,884	70,905
General partner interest in net income	(41,032)	(30,583)
Net income available to common unitholders	$ 66,852	$ 40,322
Basic net income per common unit	$ 0.91	$ 0.56
Diluted net income per common unit	$ 0.91	$ 0.55
Basic average number of common units outstanding	73,200	72,544
Equity Participation Unit equivalent units	475	1,036
Diluted average number of common units outstanding	73,675	73,580

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters (Details)	3 Months Ended
	Mar. 31, 2018Bcf / dmi	Jul. 01, 2017
Public Utilities, General Disclosures [Line Items]
Capacity Enhancement | Bcf / d	0.8
Miles of Pipeline | mi	70
Size of Pipeline	36
Pony Express Pipeline
Public Utilities, General Disclosures [Line Items]
FERC Annual Index Adjustment		0.00%

Legal and Environmental Matte66

Legal and Environmental Matters - Additional Information (Detail)	Jul. 12, 2017USD ($)	Jan. 12, 2017USD ($)Bcf / d	Mar. 31, 2018USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2016Bcf / dmi	Dec. 31, 2015mi	Dec. 31, 2017USD ($)	Dec. 31, 2017USD ($)	Apr. 14, 2016USD ($)
Loss Contingencies [Line Items]
Estimated environmental liability			$ 7,700,000					$ 7,700,000	$ 7,700,000
Cost of Services, Environmental Remediation								21,800,000
Aggregate cost of crack tool runs									$ 18,000,000
Trailblazer
Loss Contingencies [Line Items]
Miles of natural gas pipeline needing repair or replacement | mi						8
Tallgrass Development LP
Loss Contingencies [Line Items]
Contractual indemnity provided to TEP by TD			20,000,000
Annual deductible			$ 1,500,000
General Partner
Loss Contingencies [Line Items]
Contributions from TD				$ 2,301,000				$ 20,000,000
Ultra Resources Complaint
Loss Contingencies [Line Items]
Firm transportation service agreement | Bcf / d		0.2				0.2
Gain Contingency, Unrecorded Amount										$ 303,000,000
Litigation Settlement, Amount Awarded from Other Party	$ 150,000,000
Firm Transportation Rate		$ 0.37
Anticipated Annual Revenue		$ 26,800,000
Minimum | Trailblazer
Loss Contingencies [Line Items]
Miles of natural gas pipeline needing repair or replacement | mi							25
Maximum | Trailblazer
Loss Contingencies [Line Items]
Miles of natural gas pipeline needing repair or replacement | mi							35
Subsequent Event
Loss Contingencies [Line Items]
Total Remediation costs					$ 4,800,000
Estimated pipeline replacement costs					$ 20,000,000

Reporting Segments - Summary of

Reporting Segments - Summary of TEP's Segment Information of Revenue (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Segment Reporting Information [Line Items]
Total Revenues	$ 179,094	$ 144,400
TEP
Segment Reporting Information [Line Items]
Total Revenues	179,094	144,400
TEP | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues	34,344	34,983
TEP | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues	86,647	84,994
TEP | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues	58,103	24,423
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues	0	0
TEP | Operating Segments
Segment Reporting Information [Line Items]
Total Revenues	190,006	148,729
TEP | Operating Segments | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues	36,202	36,428
TEP | Operating Segments | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues	89,966	84,994
TEP | Operating Segments | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues	63,838	27,307
TEP | Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues	0	0
TEP | Intersegment Eliminations
Segment Reporting Information [Line Items]
Total Revenues	(10,912)	(4,329)
TEP | Intersegment Eliminations | Natural Gas Transportation
Segment Reporting Information [Line Items]
Total Revenues	(1,858)	(1,445)
TEP | Intersegment Eliminations | Crude Oil Transportation
Segment Reporting Information [Line Items]
Total Revenues	(3,319)	0
TEP | Intersegment Eliminations | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Total Revenues	(5,735)	(2,884)
TEP | Intersegment Eliminations | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues	$ 0	$ 0

Reporting Segments - Summary 68

Reporting Segments - Summary of TEP's Segment Information of Earnings (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Reconciliation to Net Income:
Equity in earnings of unconsolidated investments	$ 53,406	$ 20,738
Gain on disposal of assets	9,417	1,448
Interest expense, net	28,184	14,689
Depreciation and amortization expense, net of noncontrolling interest	26,123	21,403
Distributions from unconsolidated investments	(52,064)	(20,740)
Net income attributable to partners	107,884	70,905
TEP
Reconciliation to Net Income:
Net income attributable to partners	107,884	70,905
TEP | Natural Gas Transportation
Segment Reporting Information [Line Items]
Adjusted EBITDA	88,264	51,585
TEP | Crude Oil Transportation
Segment Reporting Information [Line Items]
Adjusted EBITDA	63,606	59,719
TEP | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Adjusted EBITDA	15,020	5,568
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,853)	(1,761)
TEP | Operating Segments | Natural Gas Transportation
Segment Reporting Information [Line Items]
Adjusted EBITDA	90,519	53,030
TEP | Operating Segments | Crude Oil Transportation
Segment Reporting Information [Line Items]
Adjusted EBITDA	59,456	55,491
TEP | Operating Segments | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Adjusted EBITDA	16,915	8,351
TEP | Operating Segments | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,853)	(1,761)
TEP | Intersegment Eliminations | Natural Gas Transportation
Segment Reporting Information [Line Items]
Adjusted EBITDA	(2,255)	(1,445)
TEP | Intersegment Eliminations | Crude Oil Transportation
Segment Reporting Information [Line Items]
Adjusted EBITDA	4,150	4,228
TEP | Intersegment Eliminations | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,895)	(2,783)
TEP | Intersegment Eliminations | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	0	0
TEP | Segment Reconciling Items
Reconciliation to Net Income:
Equity in earnings of unconsolidated investments	53,406	20,738
Non-cash (loss) gain related to derivative instruments, net of noncontrolling interests	2,674	2,441
Gain on disposal of assets	9,417	1,448
Interest expense, net	(28,184)	(14,689)
Depreciation and amortization expense, net of noncontrolling interest	(25,854)	(21,867)
Distributions from unconsolidated investments	65,857	30,819
Noncash compensation expense	$ (2,755)	$ (1,458)

Reporting Segments Reporting Se

Reporting Segments Reporting Segments - Summary of TEP's Segment Capital Expenditures (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Segment Reporting Information [Line Items]
Capital expenditures	$ 58,760	$ 26,769
TEP
Segment Reporting Information [Line Items]
Capital expenditures	58,760	26,769
TEP | Natural Gas Transportation
Segment Reporting Information [Line Items]
Capital expenditures	9,885	4,655
TEP | Crude Oil Transportation
Segment Reporting Information [Line Items]
Capital expenditures	16,952	7,343
TEP | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Capital expenditures	31,139	14,771
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 784	$ 0

Reporting Segments - Summary 70

Reporting Segments - Summary of TEP's Segment Information of Assets (Detail) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Assets	$ 4,190,879	$ 3,977,353
TEP
Segment Reporting Information [Line Items]
Assets	4,190,879	3,977,353
TEP | Natural Gas Transportation
Segment Reporting Information [Line Items]
Assets	1,648,241	1,606,666
TEP | Crude Oil Transportation
Segment Reporting Information [Line Items]
Assets	1,412,650	1,407,758
TEP | Gathering, Processing & Terminalling
Segment Reporting Information [Line Items]
Assets	1,095,410	943,340
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Assets	$ 34,578	$ 19,589

Reporting Segments - Additional

Reporting Segments - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2018Segment
Segment Reporting Information [Line Items]
Number of Reportable Segments	3
Rockies Express Pipeline LLC
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	49.99%

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ in Thousands	Apr. 01, 2018	Mar. 31, 2018	Mar. 31, 2017
Subsequent Event [Line Items]
Payments to Acquire Businesses, Gross		$ 0	$ 140,000
Pawnee Terminal | Subsequent Event
Subsequent Event [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	51.00%
Tallgrass Energy Partners | Pawnee Terminal | Subsequent Event
Subsequent Event [Line Items]
Payments to Acquire Businesses, Gross	$ 31,000