Tallgrass Energy Partners 10-Q 3 May 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 03, 2017
Document 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, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	Q1
Trading Symbol	TEP
Amendment Flag	false
Common Units
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		72,437,886
General Partner Units
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		834,391

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and cash equivalents	$ 1,198	$ 1,873
Accounts receivable, net	57,274	59,536
Gas imbalances	636	1,597
Inventories	15,647	13,093
Derivative assets at fair value	304	10,967
Prepayments and other current assets	6,785	7,628
Total Current Assets	81,844	94,694
Property, plant and equipment, net	2,085,670	2,079,232
Goodwill	343,288	343,288
Intangible asset, net	92,764	93,522
Unconsolidated investments	935,918	475,625
Deferred financing costs, net	3,930	4,815
Deferred charges and other assets	9,242	11,037
Total Assets	3,552,656	3,102,213
Current Liabilities:
Accounts payable	22,050	24,122
Accounts payable to related parties	6,175	5,935
Gas imbalances	1,473	1,239
Derivative liabilities at fair value	0	556
Accrued taxes	21,857	16,996
Accrued liabilities	6,783	16,702
Deferred revenue	77,067	60,757
Other current liabilities	6,001	6,446
Total Current Liabilities	141,406	132,753
Long-term debt, net	1,960,232	1,407,981
Other long-term liabilities and deferred credits	7,125	7,063
Total Long-term Liabilities	1,967,357	1,415,044
Commitments and Contingencies
Equity:
Predecessor Equity	0	82,295
Limited partners (72,184,472 and 72,485,954 common units issued and outstanding at March 31, 2017 and December 31, 2016, respectively)	2,045,163	2,070,495
General partner (834,391 units issued and outstanding at March 31, 2017 and December 31, 2016)	(635,406)	(632,339)
Total Partners' Equity	1,409,757	1,520,451
Noncontrolling interests	34,136	33,965
Total Equity	1,443,893	1,554,416
Total Liabilities and Equity	$ 3,552,656	$ 3,102,213

CONDENSED CONSOLIDATED BALANC3

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - shares	Mar. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
General Partner Units Issued (in units)	834,391	834,391
General Partner Units Outstanding (in units)	834,391	834,391
Limited Partner Units Issued (in units)	72,184,472	72,485,954
Limited Partner Units Outstanding (in units)	72,184,472	72,485,954

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues:
Crude oil transportation services	$ 84,331	$ 94,572
Natural gas transportation services	31,685	29,280
Sales of natural gas, NGLs, and crude oil	15,381	13,926
Processing and other revenues	13,003	9,390
Total Revenues	144,400	147,168
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	12,370	13,568
Cost of transportation services (exclusive of depreciation and amortization shown below)	13,503	13,529
Operations and maintenance	12,903	12,958
Depreciation and amortization	21,403	22,007
General and administrative	13,663	13,490
Taxes, other than income taxes	8,226	7,650
Gain on disposal of assets	1,448	0
Total Operating Costs and Expenses	80,620	83,202
Operating Income	63,780	63,966
Other Income (Expense):
Interest expense, net	(14,689)	(7,499)
Unrealized gain (loss) on derivative instrument	1,885	(8,946)
Equity in earnings of unconsolidated investments	20,738	709
Other income, net	70	566
Total Other Income (Expense)	8,004	(15,170)
Net income	71,784	48,796
Net income attributable to noncontrolling interests	(879)	(1,041)
Net income attributable to partners	70,905	47,755
Allocation of income to the limited partners:
Predecessor operations interest in net income	0	3,685
General partner interest in net income	(30,583)	(20,353)
Common unitholders' interest in net income	$ 40,322	$ 23,717
Basic net income per common unit	$ 0.56	$ 0.35
Diluted net income per common unit	$ 0.55	$ 0.35
Basic average number of common units outstanding	72,544	66,967
Diluted average number of common units outstanding	73,580	67,807

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash Flows from Operating Activities:
Net income	$ 71,784	$ 48,796
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	23,575	23,385
Equity in earnings of unconsolidated investments	(20,738)	(709)
Distributions from unconsolidated investments	20,740	634
Noncash change in the fair value of derivative financial instruments	(2,454)	8,990
Changes in components of working capital:
Accounts receivable and other	2,450	6,072
Accounts payable and accrued liabilities	(5,691)	(2,175)
Deferred revenue	16,202	7,204
Other current assets and liabilities	(819)	10
Other operating, net	(808)	968
Net Cash Provided by Operating Activities	(104,241)	(93,175)
Cash Flows from Investing Activities:
Acquisition of Rockies Express membership interest	400,000	0
Acquisition of Terminals and NatGas	(140,000)	0
Capital expenditures	26,769	21,207
Distributions from unconsolidated investments in excess of cumulative earnings	10,079	0
Contributions to unconsolidated investments	(6,693)	(63)
Acquisition of Pony Express membership interest	0	49,118
Other investing, net	(1,341)	(25)
Net Cash Used in Investing Activities	(562,042)	(70,363)
Net Cash Provided by (Used in) Financing Activities
Borrowings under revolving credit facility, net	552,000	447,000
Proceeds from public offering, net of offering costs	99,373	12,636
Distributions to unitholders	88,159	59,040
Payments for Repurchase of Common Stock	(35,335)	0
Acquisition of Pony Express membership interest	0	(425,882)
Other financing, net	1,628	3,748
Net Cash Provided by (Used in) Financing Activities	457,126	(21,538)
Net Change in Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents	(675)	1,274
Cash and Cash Equivalents, beginning of period	1,873	1,611
Cash and Cash Equivalents, end of period	1,198	2,885
Equity Option
Net Cash Provided by (Used in) Financing Activities
Payments for Repurchase of Common Stock	$ (72,381)	$ 0

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED) - USD ($) $ in Thousands	Total	Total Partner Equity Excluding Portion Attributable to Noncontrolling Interest	Total Partner Equity Excluding Portion Attributable to Noncontrolling InterestTerminals and NatGas	Total Partner Equity Excluding Portion Attributable to Noncontrolling InterestRockies Express Pipeline LLC	Total Partner Equity Excluding Portion Attributable to Noncontrolling InterestPony Express Pipeline	Noncontrolling Interest	Noncontrolling InterestTerminals and NatGas	Noncontrolling InterestRockies Express Pipeline LLC	Noncontrolling InterestPony Express Pipeline	Total Partner Equity Including Portion Attributable to Noncontrolling Interest	Total Partner Equity Including Portion Attributable to Noncontrolling InterestTerminals and NatGas	Total Partner Equity Including Portion Attributable to Noncontrolling InterestRockies Express Pipeline LLC	Total Partner Equity Including Portion Attributable to Noncontrolling InterestPony Express Pipeline	Predecessor Equity	Predecessor EquityTerminals and NatGas	Predecessor EquityRockies Express Pipeline LLC	Predecessor EquityPony Express Pipeline	Limited Partner	Limited PartnerTerminals and NatGas	Limited PartnerRockies Express Pipeline LLC	Limited PartnerPony Express Pipeline	General Partner	General PartnerTerminals and NatGas	General PartnerRockies Express Pipeline LLC	General PartnerPony Express Pipeline
Total Equity		$ 1,341,489				$ 445,077				$ 1,786,566				$ 71,564				$ 1,618,766				$ (348,841)
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	$ 48,796	47,755				1,041				48,796				3,685				23,717				20,353
Issuance of units to public, net of offering costs		12,636				0				12,636				0				12,636				0
Distributions to unitholders		(59,040)				0				(59,040)				0				(42,984)				(16,056)
Noncash compensation expense		1,869				0				1,869				0				1,869				0
Payments for Repurchase of Common Stock	0
Acquisitions					$ (11,360)				$ (417,679)				$ (429,039)				$ 0				$ 268,607				$ (279,967)
Contributions from noncontrolling interests		0				7,152				7,152				0				0				0
Payments to Noncontrolling Interests	425,882	0				1,793				1,793				0				0				0
Distributions to Predecessor Entities, net		(693)				0				(693)				(693)				0				0
Contributions from TD																						20,000
Total Equity		1,332,656				33,798				1,366,454				74,556				1,882,611				(624,511)
Total Equity	1,554,416	1,520,451				33,965				1,554,416				82,295				2,070,495				(632,339)
Net income	71,784	70,905				879				71,784				0				40,322				30,583
Issuance of units to public, net of offering costs	99,400	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
Common units issued under LTIP, net of 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
Acquisitions			$ (140,000)	$ 63,681			$ 0	$ 0			$ (140,000)	$ 63,681			$ (82,295)	$ 0			$ 0	$ 0			$ (57,705)	$ 63,681
Contributions from TD		2,301				0				2,301				0				0				2,301
Contributions from noncontrolling interests		0				710				710				0				0				0
Payments to Noncontrolling Interests	0	0				1,418				1,418				0				0				0
Total Equity	$ 1,443,893	$ 1,409,757				$ 34,136				$ 1,443,893				$ 0				$ 2,045,163				$ (635,406)

Description of Business

Description of Business	3 Months Ended
	Mar. 31, 2017
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: • Crude Oil Transportation & Logistics—the ownership and operation of a FERC-regulated crude oil pipeline system and crude oil storage and terminalling facilities; • Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; and • Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, the provision of water business services primarily to the oil and gas exploration and production industry and the transportation of NGLs. Crude Oil Transportation & Logistics. We currently 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, which includes a lateral in Northeast Colorado commencing in Weld County, Colorado, and interconnecting with the pipeline just east of Sterling, Colorado (the "Pony Express System"). We also provide crude oil storage and terminalling services through our 100% membership interest in Tallgrass Terminals, LLC ("Terminals") acquired effective January 1, 2017, which owns and operates crude oil terminals near Sterling, Colorado (the "Sterling Terminal") and in Weld County, Colorado (the "Buckingham Terminal"). Terminals also owns a 20% membership interest in Deeprock Development, LLC ("Deeprock Development"), which owns a crude oil terminal in Cushing, Oklahoma (the "Cushing Terminal"). Natural Gas Transportation & Logistics. 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"), which includes the additional 24.99% membership interest acquired from Tallgrass Development, LP ("TD") effective March 31, 2017 as discussed in Note 3 – Acquisitions , and our 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas") acquired effective January 1, 2017, 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"). Processing & Logistics. We also provide services for customers in Wyoming at the Casper and Douglas natural gas processing facilities and the West Frenchie Draw natural gas treating facility (collectively, the "Midstream Facilities"), and NGL transportation services in Northeast Colorado and Wyoming. We perform water business services, including freshwater transportation and produced water gathering and disposal, in Colorado and Texas through BNN Water Solutions, LLC ("Water Solutions"). The table below summarizes our equity ownership as of March 31, 2017 : 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 (1) 46,565,254 — 64.51 % 63.77 % Tallgrass Equity, LLC 20,000,000 — 27.71 % 27.39 % Tallgrass Development, LP 5,619,218 — 7.78 % 7.70 % Tallgrass MLP GP, LLC (2) — 834,391 — % 1.14 % Total (3) 72,184,472 834,391 100.00 % 100.00 % (1) As discussed in Note 10 – Partnership Equity and Distributions , we issued and sold an additional 253,414 common units subsequent to March 31, 2017 . As of May 3, 2017 , there were 46,818,668 common units held by public unitholders outstanding. (2) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights. (3) As of May 3, 2017 , there were 73,272,277 total limited partner and general partner units outstanding. 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. For additional information regarding these acquisitions, see Note 3 – Acquisitions .

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2017
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, 2017 and 2016 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of generally accepted accounting principles 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, 2017 and 2016 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, 2017 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2017. 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, 2016 ("2016 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 15, 2017. 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. As further discussed in Note 3 – Acquisitions , TEP closed the acquisition of Terminals and NatGas on 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. Net equity distributions of the Predecessor Entities included in the condensed consolidated financial statements represent transfers of cash as a result of TD's centralized cash management system prior to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the subsidiaries of TD. These loans were then periodically recorded as equity distributions. The accompanying condensed consolidated financial statements of TEP include historical cost-basis accounts of the assets and liabilities of the Predecessor Entities for the periods prior to January 1, 2017, the date TEP acquired Terminals and NatGas from TD, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. TEP and the Predecessor Entities are all considered "entities under common control" as defined under GAAP and, as such, the transfers between the entities of the assets and liabilities have been recorded by TEP at historical cost. 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 ASU No. 2016-09, "Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting" In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Among other changes, ASU 2016-09 allows an entity to make an entity-wide accounting policy election to either estimate the number of awards expected to vest (consistent with current GAAP) or account for forfeitures when they occur. The amendments in ASU 2016-09 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We adopted the guidance in ASU 2016-09 effective January 1, 2017 and made a policy election to account for forfeitures when they occur. The adoption of ASU 2016-09 did not have a material impact on our consolidated financial statements. Accounting Pronouncements Not Yet 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. Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact of our pending adoption of the revised guidance. The status of our implementation is as follows: • We have formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain revenue contract types, and project status. • We are currently reviewing contracts for each revenue stream identified within each of our business segments. Through this process, we are determining and documenting expected changes in revenue recognition upon adoption of the revised guidance. • We plan to evaluate the potential information technology and internal control changes that will be required for adoption based on the findings from our contract review process. • We plan to provide internal training and awareness related to the revised guidance to the key stakeholders throughout our organization. Through the contract review process currently underway, management has identified several areas of potential impact, including the accounting for non-cash consideration, particularly in our Crude Oil Transportation & Logistics and Processing & Logistics segments, and the timing of revenue recognition with respect to deficiency payments received in our Crude Oil Transportation & Logistics segment. We will continue to conduct our contract review process throughout 2017 and, as a result, additional areas of impact may be identified. We are in the process of quantifying the impact of adoption but cannot reasonably estimate such amount at this time. We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. 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 equity. Consolidated revenues presented in our comparative financial statements for periods prior to January 1, 2018 would not be revised. 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. 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. ASU No. 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. The ASU also narrows the definition of the term "output" so that the term is consistent with how outputs are described under the revenue recognition guidance in Topic 606. The amendments in ASU 2017-01 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2017. Early adoption is permitted in certain circumstances. We are currently evaluating the impact of ASU 2017-01, but do not anticipate a material impact on our consolidated financial statements. ASU No. 2017-04, "Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment" In January 2017, the FASB issued ASU No. 2017-04, which simplifies the subsequent measurement of goodwill by eliminating "Step 2" from the goodwill impairment test, which involved calculating the implied fair value of goodwill by determining the fair value at the impairment testing date of a reporting unit's assets and liabilities. Instead, under the simplified test approach, an entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The amendments in ASU 2017-04 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We are currently evaluating the impact of ASU 2017-04.

Acquisitions

Acquisitions	3 Months Ended
	Mar. 31, 2017
Business Combinations [Abstract]
Acquisitions	Acquisition of an Additional 24.99% Membership Interest in Rockies Express On March 31, 2017, TEP, TD, and Rockies Express Holdings, LLC, entered into a definitive Purchase and Sale Agreement, pursuant to which TEP acquired an additional 24.99% membership interest in Rockies Express from TD in exchange for cash consideration of $400 million . Together with the 25% membership interest in Rockies Express that TEP acquired from a unit of Sempra U.S. Gas and Power on May 6, 2016, this transaction increases TEP’s aggregate membership interest in Rockies Express to 49.99% . The transfer of the Rockies Express membership interest between TD and the Partnership is considered a transaction between entities under common control, but does not represent a change in reporting entity. 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. As a result of the common control nature of the transaction, the 24.99% membership interest in Rockies Express was transferred to the Partnership at TD's historical carrying amount, including the remaining unamortized basis difference driven by the difference between the fair value of the investment and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD. For additional information, see Note 7 – Investments in Unconsolidated Affiliates . As of March 31, 2017, the negative basis difference carried over from TD was approximately $386.8 million . The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years , which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. The basis difference associated with the recently acquired 24.99% membership interest in Rockies Express at March 31, 2017 was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 19,504 2 - 25 years Property, plant and equipment (406,301 ) 35 years Total basis difference $ (386,797 ) Acquisition of Tallgrass Terminals, LLC and Tallgrass NatGas Operator, LLC Effective January 1, 2017, we acquired 100% of the issued and outstanding membership interests in Terminals and 100% of the issued and outstanding membership interests in NatGas from TD for total cash consideration of $140 million . These acquisitions are considered transactions between entities under common control, and a change in reporting entity. Terminals owns several fully operational assets providing storage capacity and additional injection points for the Pony Express System, including the Sterling Terminal near Sterling, Colorado, the Buckingham Terminal in northeast Colorado, and a 20% interest in the Deeprock Development Terminal in Cushing, Oklahoma. The 20% interest in Deeprock Development is recorded under the equity method of accounting and reported as "Unconsolidated investments" on our condensed consolidated balance sheets. Terminals also owns acreage in Cushing, Oklahoma and Guernsey, Wyoming, which is under development to provide additional storage capacity, and other potential opportunities. NatGas is the operator of the Rockies Express Pipeline and receives a fee from Rockies Express as compensation for its services. Historical Financial Information The results of our acquisitions of Terminals and NatGas are included in the condensed consolidated balance sheets as of March 31, 2017 and December 31, 2016 . The following table presents our previously reported December 31, 2016 condensed consolidated balance sheet, adjusted for the acquisitions of Terminals and NatGas: December 31, 2016 TEP (As previously reported) Consolidate Terminals Consolidate NatGas TEP (As currently reported) (in thousands) ASSETS Current Assets: Cash and cash equivalents $ 1,873 $ — $ — $ 1,873 Accounts receivable, net 59,469 38 29 59,536 Gas imbalances 1,597 — — 1,597 Inventories 12,805 288 — 13,093 Derivative assets at fair value 10,967 — — 10,967 Prepayments and other current assets 6,820 808 — 7,628 Total Current Assets 93,531 1,134 29 94,694 Property, plant and equipment, net 2,012,263 66,969 — 2,079,232 Goodwill 343,288 — — 343,288 Intangible asset, net 93,522 — — 93,522 Unconsolidated investments 461,915 13,710 — 475,625 Deferred financing costs, net 4,815 — — 4,815 Deferred charges and other assets 9,637 1,400 — 11,037 Total Assets $ 3,018,971 $ 83,213 $ 29 $ 3,102,213 LIABILITIES AND EQUITY Current Liabilities: Accounts payable $ 24,076 $ 46 $ — $ 24,122 Accounts payable to related parties 5,879 56 — 5,935 Gas imbalances 1,239 — — 1,239 Derivative liabilities at fair value 556 — — 556 Accrued taxes 16,328 668 — 16,996 Accrued liabilities 16,525 177 — 16,702 Deferred revenue 60,757 — — 60,757 Other current liabilities 6,446 — — 6,446 Total Current Liabilities 131,806 947 — 132,753 Long-term debt, net 1,407,981 — — 1,407,981 Other long-term liabilities and deferred credits 7,063 — — 7,063 Total Long-term Liabilities 1,415,044 — — 1,415,044 Equity: Net Equity 1,472,121 82,266 29 1,554,416 Total Equity 1,472,121 82,266 29 1,554,416 Total Liabilities and Equity $ 3,018,971 $ 83,213 $ 29 $ 3,102,213 The results of our acquisitions of Terminals and NatGas are included in the condensed consolidated statements of income for the three months ended March 31, 2017 and 2016 . The following tables present the previously reported condensed consolidated statements of income for the three months ended March 31, 2016 , adjusted for the acquisitions of Terminals and NatGas: Three Months Ended March 31, 2016 TEP (As previously reported) Consolidate Terminals Consolidate NatGas Elimination (1) TEP (As currently reported) (in thousands) Revenues: Crude oil transportation services $ 94,572 $ — $ — $ — $ 94,572 Natural gas transportation services 29,280 — — — 29,280 Sales of natural gas, NGLs, and crude oil 13,926 — — — 13,926 Processing and other revenues 7,627 2,909 1,681 (2,827 ) 9,390 Total Revenues 145,405 2,909 1,681 (2,827 ) 147,168 Operating Costs and Expenses: Cost of sales (exclusive of depreciation and amortization shown below) 13,568 — — — 13,568 Cost of transportation services (exclusive of depreciation and amortization shown below) 16,156 200 — (2,827 ) 13,529 Operations and maintenance 12,477 481 — — 12,958 Depreciation and amortization 21,692 315 — — 22,007 General and administrative 13,016 474 — — 13,490 Taxes, other than income taxes 7,506 144 — — 7,650 Total Operating Costs and Expenses 84,415 1,614 — (2,827 ) 83,202 Operating Income 60,990 1,295 1,681 — 63,966 Other Income (Expense): Interest expense, net (7,499 ) — — — (7,499 ) Unrealized loss on derivative instrument (8,946 ) — — — (8,946 ) Equity in earnings of unconsolidated investments — 709 — — 709 Other income, net 566 — — — 566 Total Other (Expense) Income (15,879 ) 709 — — (15,170 ) Net income 45,111 2,004 1,681 — 48,796 Net income attributable to noncontrolling interests (1,041 ) — — — (1,041 ) Net income attributable to partners $ 44,070 $ 2,004 $ 1,681 $ — $ 47,755 (1) Represents the elimination of revenue and cost of transportation services associated with the lease of the Sterling Terminal facilities by Pony Express.

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	As a result of our relationship with TD and its affiliates, we have entered into a number of related party transactions. The following disclosure includes those related party disclosures 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 TD and certain of its affiliates, including Tallgrass Operations, LLC (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse TD 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 TD, 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, 2017 2016 (in thousands) Cost of transportation services (1) $ 4,507 $ 4,429 Charges to TEP: (2) Property, plant and equipment, net $ 293 $ 918 Operations and maintenance $ 6,277 $ 6,184 General and administrative $ 9,377 $ 9,212 (1) Reflects rent expense for the crude oil storage at the Deeprock Terminal. (2) Charges to TEP include directly charged wages and salaries, other compensation and benefits, and shared services. Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows: March 31, 2017 December 31, 2016 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 1,266 $ 590 Total receivable from related parties $ 1,266 $ 590 Accounts payable to related parties: Tallgrass Operations, LLC $ 6,088 $ 5,854 Tallgrass Equity, LLC 67 68 Tallgrass Management, LLC 20 — Deeprock Development, LLC — 13 Total accounts payable to related parties $ 6,175 $ 5,935 Gas imbalances with affiliated shippers are as follows: March 31, 2017 December 31, 2016 (in thousands) Affiliate gas imbalance receivables $ — $ 177 Affiliate gas imbalance payables $ 73 $ —

Inventory

Inventory	3 Months Ended
	Mar. 31, 2017
Inventory Disclosure [Abstract]
Inventory	The components of inventory at March 31, 2017 and December 31, 2016 consisted of the following: March 31, 2017 December 31, 2016 (in thousands) Crude oil $ 6,903 $ 5,462 Materials and supplies 6,455 6,383 Natural gas liquids 573 265 Gas in underground storage 1,716 983 Total inventory $ 15,647 $ 13,093

Property, Plant and Equipment

Property, Plant and Equipment	3 Months Ended
	Mar. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	A summary of net property, plant and equipment by classification is as follows: March 31, 2017 December 31, 2016 (in thousands) Crude oil pipelines $ 1,207,727 $ 1,202,125 Natural gas pipelines 575,536 572,150 Processing and treating assets 262,447 256,901 General and other 225,243 223,310 Construction work in progress 29,770 20,606 Accumulated depreciation and amortization (215,053 ) (195,860 ) Total property, plant and equipment, net $ 2,085,670 $ 2,079,232

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates (Notes)	3 Months Ended
	Mar. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Rockies Express 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, 2017 , we recognized equity in earnings associated with our previously acquired 25% membership interest in Rockies Express of $20.0 million , inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $30.1 million and $6.7 million , respectively. As discussed in Note 3 – Acquisitions , we acquired an additional 24.99% membership interest in Rockies Express from TD on March 31, 2017. Summarized financial information for Rockies Express is as follows: Three Months Ended March 31, 2017 Revenue $ 201,338 Operating income $ 107,369 Net income to Members $ 66,250 Deeprock Development See Note 3 – Acquisitions for additional information regarding our recently acquired 20% membership interest in Deeprock Development.

Risk Management

Risk Management	3 Months Ended
	Mar. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management	We occasionally enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs. Fair Value of Derivative Contracts The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets: Balance Sheet March 31, 2017 December 31, 2016 (in thousands) Call option derivative (1) Current assets $ — $ 10,676 Crude oil derivative contracts (2) Current assets $ 223 $ — Natural gas derivative contracts (3) Current assets $ 81 $ 291 Crude oil derivative contracts (2) Current liabilities $ — $ 440 Natural gas derivative contracts (3) Current liabilities $ — $ 116 (1) As discussed below, in conjunction with our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option covering the 6,518,000 common units issued to TD. As of February 1, 2017, no common units remained subject to the call option. (2) As of March 31, 2017 and December 31, 2016 , the fair value shown for crude oil derivative contracts represents the sale of 125,000 barrels of crude oil which will settle throughout 2017. (3) As of March 31, 2017 , the fair value shown for natural gas derivative contracts was comprised of derivative volumes for long natural gas fixed-price swaps totaling 0.3 Bcf. As of December 31, 2016 , the fair value shown for natural gas derivative contracts was comprised of derivative volumes for short and long natural gas fixed-price swaps totaling 0.3 Bcf and 0.4 Bcf, respectively. Effect of Derivative Contracts in the Statements of Income The following table summarizes the impact of derivative contracts for the three months ended March 31, 2017 and 2016 : Location of gain (loss) recognized Amount of gain (loss) recognized in income on derivatives Three Months Ended March 31, 2017 2016 (in thousands) Derivatives not designated as hedging contracts: Call option derivative Unrealized gain (loss) on derivative instrument $ 1,885 $ (8,946 ) Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ 173 $ (44 ) Crude oil derivative contracts Sales of natural gas, NGLs, and crude oil $ 663 $ — 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. In July 2016 and October 2016, we partially exercised the call option covering 3,563,146 and 1,251,760 common units, respectively, for cash payments of $151.4 million and $53.2 million , respectively. 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 crude oil and natural gas derivatives consist of 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 over-the-counter swaps are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with financial institutions with investment grade credit ratings. While we enter into derivative transactions principally 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 and natural gas derivative contracts at March 31, 2017 was: Asset Position (in thousands) Gross $ 304 Netting agreement impact — Cash collateral held — Net exposure $ 304 As of March 31, 2017 and December 31, 2016 , we did not have any outstanding letters of credit or cash in margin accounts in support of our hedging of commodity price risks associated with our commodity derivative contracts nor did we have any margin deposits with counterparties associated with 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"). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. We value exchange-traded derivative contracts using quoted market prices for identical securities. 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 include 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. Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management's best estimate is used. The following table summarizes the fair value measurements of our derivative contracts as of March 31, 2017 and December 31, 2016 based on the fair value hierarchy established by the Codification: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of March 31, 2017: Crude oil derivative contracts $ 223 $ — $ 223 $ — Natural gas derivative contracts $ 81 $ — $ 81 $ — As of December 31, 2016: Call option derivative $ 10,676 $ — $ 10,676 $ — Natural gas derivative contracts $ 291 $ — $ 291 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2016: Crude oil derivative contracts $ 440 $ — $ 440 $ — Natural gas derivative contracts $ 116 $ — $ 116 $ —

Long-term Debt

Long-term Debt	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Long-term Debt	Long-term debt consisted of the following at March 31, 2017 and December 31, 2016 : March 31, 2017 December 31, 2016 (in thousands) Revolving credit facility $ 1,567,000 $ 1,015,000 5.50% senior notes due September 15, 2024 400,000 400,000 Less: Deferred financing costs, net (1) (6,768 ) (7,019 ) Total long-term debt, net $ 1,960,232 $ 1,407,981 (1) Deferred financing costs, net as presented above relate solely to the 2024 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our condensed consolidated balance sheets. Senior Unsecured Notes On September 1, 2016, 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 1, 2016 (the "Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). The 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, 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, 2017 , 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, 2017 and December 31, 2016 : March 31, 2017 December 31, 2016 (in thousands) Total capacity under the revolving credit facility $ 1,750,000 $ 1,750,000 Less: Outstanding borrowings under the revolving credit facility (1,567,000 ) (1,015,000 ) Available capacity under the revolving credit facility $ 183,000 $ 735,000 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 from making such a distribution), 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 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of March 31, 2017 , we are 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 0.300% to 0.500% , based on our total leverage ratio. As of March 31, 2017 , the weighted average interest rate on outstanding borrowings under the revolving credit facility was 2.95% . During the three months ended March 31, 2017 , 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 3.12% . 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, 2017 and December 31, 2016 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of March 31, 2017: Revolving credit facility $ — $ 1,567,000 $ — $ 1,567,000 $ 1,567,000 2024 Notes $ — $ 403,252 $ — $ 403,252 $ 393,232 As of December 31, 2016: Revolving credit facility $ — $ 1,015,000 $ — $ 1,015,000 $ 1,015,000 2024 Notes $ — $ 398,000 $ — $ 398,000 $ 392,981 The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of March 31, 2017 and December 31, 2016 , 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 Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the 2024 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, 2017 .

Partnership Equity and Distribu

Partnership Equity and Distributions	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Partnership Equity and Distributions	Equity Distribution Agreements As of March 31, 2017 , we had 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, 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). During the period from April 1, 2017 to May 3, 2017 , we issued and sold an additional 253,414 common units with a weighted average sales price of $53.65 per unit under our equity distribution agreements for net cash proceeds of approximately $13.5 million (net of approximately $0.1 million in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes as described above. 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 Limited Partner General Partner Distributions Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) March 31, 2017 May 15, 2017 (1) $ 60,486 $ 29,840 $ 1,040 $ 91,366 $ 0.8350 December 31, 2016 February 14, 2017 58,793 28,358 1,008 88,159 0.8150 September 30, 2016 November 14, 2016 57,332 26,987 976 85,295 0.7950 June 30, 2016 August 12, 2016 54,442 24,262 911 79,615 0.7550 March 31, 2016 May 13, 2016 48,238 19,816 830 68,884 0.7050 (1) The distribution announced on April 17, 2017 for the first quarter of 2017 will be paid on May 15, 2017 to unitholders of record at the close of business on April 28, 2017 . Other Contributions and Distributions During the three months ended March 31, 2017 , TEP was deemed to have made noncash capital distributions of $57.7 million and $12.6 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 and the derecognition of a portion of the derivative asset associated with the partial exercise of the call option, respectively. During the three months ended March 31, 2017 , 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. During the three months ended March 31, 2017 , TEP also 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 13 – Legal and Environmental Matters . During the three months ended March 31, 2017 , 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. During the three months ended March 31, 2016 , TEP was deemed to have made a noncash capital distribution of $280.0 million to the general partner, which represents the excess purchase price over the carrying value of the additional 31.3% membership interest in Pony Express acquired effective January 1, 2016. During the three months ended March 31, 2016 , TEP also recognized contributions from and distributions to noncontrolling interests of $7.2 million and $1.8 million , respectively, which primarily consisted of activity associated with TD's 2% noncontrolling interest in Pony Express.

Net Income per Limited Partner

Net Income per Limited Partner Unit	3 Months Ended
	Mar. 31, 2017
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. Basic and diluted net income per limited partner unit is calculated by dividing limited partners' interest in net income, less general partner incentive distributions, by the weighted average number of outstanding limited partner units during the period. 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. All net income or loss from Terminals and NatGas prior to its acquisition on January 1, 2017 is allocated to predecessor operations in the table below. Historical earnings of transferred businesses for periods prior to the date of those common control transactions are solely those of the general partner, and therefore we have appropriately excluded any allocation to the limited partner units when determining net income available to common unitholders. We present the financial results of any transferred business prior to the transaction date in the line item "Predecessor operations interest in net income" in the table below. The following table illustrates the Partnership's calculation of net income per common unit for the three months ended March 31, 2017 and 2016 : Three Months Ended March 31, 2017 2016 (in thousands, except per unit amounts) Net income $ 71,784 $ 48,796 Net income attributable to noncontrolling interests (879 ) (1,041 ) Net income attributable to partners 70,905 47,755 Predecessor operations interest in net income — (3,685 ) General partner interest in net income (30,583 ) (20,353 ) Net income available to common unitholders $ 40,322 $ 23,717 Basic net income per common unit $ 0.56 $ 0.35 Diluted net income per common unit $ 0.55 $ 0.35 Basic average number of common units outstanding 72,544 66,967 Equity Participation Unit equivalent units 1,036 840 Diluted average number of common units outstanding 73,580 67,807

Regulatory Matters

Regulatory Matters	3 Months Ended
	Mar. 31, 2017
Regulatory Matters [Abstract]
Regulatory Matters	There are no regulatory proceedings challenging the transportation rates of Pony Express, Rockies Express, Tallgrass Interstate Gas Transmission, LLC ("TIGT") or Trailblazer Pipeline Company LLC ("Trailblazer"). We have certain regulatory filings currently pending with the FERC, including the following: 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 0.8 Bcf/d on January 6, 2017. 2016 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP16-702 and RP17-240 On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702. The FERC issued an order accepting the filing on March 25, 2016. On December 1, 2016, Rockies Express made an interim fuel tracker filing with a proposed effective date of January 1, 2017 in Docket No. RP17-240. The FERC issued an order accepting the filing on December 29, 2016. 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 FERC Fuel Tracking Filing - FERC Docket No. RP17-401-000 On February 13, 2017, in Docket No. RP17-401-000, 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. TIGT General Rate Case Filing - FERC Docket No. RP16-137-000, et seq. On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to Section 4 of the National Gas Act ("NGA"). The rate case proposed, among other things, a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT, certain changes to the transportation rate design of its system, a fixed fuel and lost and unaccounted for ("FL&U") and power cost tracker, and certain pro forma tariff records reflecting revisions to TIGT's Tariff. On June 8, 2016, TIGT filed an Offer of Settlement (the "TIGT Rate Case Settlement") with the FERC, which resolved all issues the FERC had set for hearing. Following certification by the Administrative Law Judge and approval by the FERC, TIGT filed revised tariff records to implement the TIGT Rate Case Settlement, which the FERC subsequently approved on December 23, 2016. Per the terms of the TIGT Rate Case 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). On February 3, 2017, the FERC accepted TIGT’s pro forma tariff records, subject to conditions, and directed TIGT to file the actual tariff records within 30 days. TIGT subsequently submitted a compliance filing to implement the actual tariff records and restate its tariff to be effective April 1, 2017 and also filed to cancel its existing tariff (which was ultimately superseded by the new tariff). On March 16, 2017, the FERC accepted both filings. 2017 Annual Fuel Tracker Filing - FERC Docket No. RP17-428-000 On February 27, 2017, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2017 in Docket No. RP17-428-000. 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. Trailblazer 2017 Annual Fuel Tracker Filing - FERC Docket No. RP17-549-000 On March 22, 2017, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2017 in Docket No. RP15-549. This filing incorporates the revised fuel tracker and power cost tracker mechanisms agreed to in the Stipulation and Agreement, which resolved all outstanding issues related to Trailblazer fuel recoveries. The FERC accepted the filing on April 19, 2017.

Legal and Environmental Matters

Legal and Environmental Matters	3 Months Ended
	Mar. 31, 2017
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, 2017 or December 31, 2016 . 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's bankruptcy estate. In accordance with the settlement agreement, Ultra has agreed to make a cash payment to Rockies Express of $150 million no later than July 12, 2017, and Ultra has 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 , or approximately $26.8 million annually. The settlement was part of Ultra's Chapter 11 reorganization plan, which was confirmed by the U.S. Bankruptcy Court on March 14, 2017. On April 12, 2017, Ultra announced that it successfully completed its restructuring in the U.S. Bankruptcy Court and emerged from Chapter 11 bankruptcy. Michels Corporation On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due. On February 2, 2017, Rockies Express and Michels agreed to resolve Michels' claims for a $10 million cash payment by Rockies Express. The cash payment was inclusive of approximately $5.9 million that Rockies Express had been withholding from Michels. Subsequently, Rockies Express and Michels entered into a definitive agreement with respect to the settlement and Rockies Express made the $10 million cash payment to Michels on February 16, 2017. Environmental, Health and Safety We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We 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 $3.8 million and $4.0 million at March 31, 2017 and December 31, 2016 , respectively. 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 Mystery Bridge Superfund Site The Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed and we have requested that the portion of the site attributable to us be delisted from the National Priorities List. 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. Trailblazer Pipeline Integrity Management Program Trailblazer is currently operating at less than its current maximum allowable operating pressure ("MAOP"), public notice of which was first provided in June 2014. As a result of smart tool surveys in 2014, Trailblazer has identified approximately 25 - 35 miles of pipe that will likely need to be repaired or replaced in order for the pipeline to operate at its MAOP of 1,000 pounds per square inch across all segments of the Trailblazer Pipeline. Such repair or replacement will likely occur over a period of years, depending upon the remediation and repair plan implemented by Trailblazer. Segments of the Trailblazer Pipeline that require full replacement could cost as much as $2.7 million per mile and repair costs on sections of the pipeline that do not require full replacement are expected to be less on a per mile basis. The current pressure reduction is not expected to prevent Trailblazer from fulfilling its firm service obligations at existing subscription levels and to date it has not had a material adverse financial impact on us. With respect to the approximately 25 - 35 miles of pipe that has been identified, Trailblazer completed 32 excavation digs in 2015 at an aggregate cost of approximately $1.3 million . During 2016, Trailblazer completed additional excavation digs and replaced approximately 8 miles of pipe at an aggregate cost of approximately $19.0 million . In 2017, Trailblazer intends to complete final remediation and cleanup of the pipe replacement at an estimated cost of $2.5 million . Trailblazer is currently exploring all possible cost recovery options to recover such out of pocket costs, 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 the Trailblazer Pipeline, TD agreed to contractually indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions were necessitated by external corrosion caused by the pipeline's disbonded Hi-Melt CTE coating. The contractual indemnity provided by TD was capped at $20 million and was subject to a $1.5 million deductible. TEP has received $20 million from TD pursuant to the contractual indemnity as of March 31, 2017 . Pony Express Pipeline Integrity In connection with certain crack tool runs on the Pony Express System completed in 2015 and 2016, Pony Express completed approximately $9.8 million of remediation for anomalies identified on the Pony Express System associated with portions of the pipeline converted from natural gas to crude oil service, and expects to complete additional remediation in 2017 on the Pony Express System of approximately $9 million . Terminals System Failures In January 2017, approximately 10,000 bbls of crude oil were released at the Sterling Terminal as the result of a defective roof drain system on a storage tank. The release was restricted to the containment area designed for such purpose and approximately 9,000 bbls were recovered. We currently expect that the total cost to remediate the release will be less than $600,000 .

Reporting Segments

Reporting Segments	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Reporting Segments	Our operations are located in the United States. We are organized into three reportable segments: (1) Crude Oil Transportation & Logistics, (2) Natural Gas Transportation & Logistics, and (3) Processing & Logistics. Crude Oil Transportation & Logistics The Crude Oil Transportation & Logistics 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 mainline portion of the Pony Express System was placed in service in October 2014. 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 was placed in service in the second quarter of 2015. The Crude Oil Transportation & Logistics segment also includes our 100% membership interest in Terminals acquired effective January 1, 2017. Natural Gas Transportation & Logistics The Natural Gas Transportation & Logistics 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 & Logistics segment includes our 100% membership interest in NatGas acquired effective January 1, 2017 and our 49.99% membership interest in Rockies Express, including the additional 24.99% membership interest acquired effective March 31, 2017 . Processing & Logistics The Processing & Logistics segment is engaged in the ownership and operation of natural gas processing, treating and fractionation facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets, as well as water business services provided primarily to the oil and gas exploration and production industry and the transportation of NGLs. 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 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, 2017 Three Months Ended March 31, 2016 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 85,092 $ — $ 85,092 $ 94,654 $ — $ 94,654 Natural Gas Transportation & Logistics 36,428 (1,445 ) 34,983 32,668 (1,355 ) 31,313 Processing & Logistics 24,325 — 24,325 21,201 — 21,201 Corporate and Other — — — — — — Total revenue $ 145,845 $ (1,445 ) $ 144,400 $ 148,523 $ (1,355 ) $ 147,168 Three Months Ended March 31, 2017 Three Months Ended March 31, 2016 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 57,767 $ 1,344 $ 59,111 $ 66,985 $ 1,345 $ 68,330 Natural Gas Transportation & Logistics 53,030 (1,445 ) 51,585 18,833 (1,355 ) 17,478 Processing & Logistics 6,075 101 6,176 3,351 10 3,361 Corporate and Other (1,761 ) — (1,761 ) (1,352 ) — (1,352 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment 20,738 709 Gain on disposal of assets 1,448 — Less: Interest expense, net of noncontrolling interest (14,689 ) (7,499 ) Depreciation and amortization expense, net of noncontrolling interest (21,867 ) (22,482 ) Distributions from unconsolidated investment (30,819 ) (634 ) Non-cash gain (loss) related to derivative instruments, net of noncontrolling interests 2,441 (8,990 ) Non-cash compensation expense (1,458 ) (1,166 ) Net income attributable to partners $ 70,905 $ 47,755 Three Months Ended March 31, Capital Expenditures: 2017 2016 (in thousands) Crude Oil Transportation & Logistics $ 10,436 $ 15,973 Natural Gas Transportation & Logistics 4,655 2,133 Processing & Logistics 11,678 3,101 Corporate and Other — — Total capital expenditures $ 26,769 $ 21,207 Assets: March 31, 2017 December 31, 2016 (in thousands) Crude Oil Transportation & Logistics $ 1,492,333 $ 1,493,866 Natural Gas Transportation & Logistics 1,633,358 1,176,147 Processing & Logistics 418,479 411,999 Corporate and Other 8,486 20,201 Total assets $ 3,552,656 $ 3,102,213

Summary of Significant Accoun21

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These condensed consolidated financial statements and related notes for the three months ended March 31, 2017 and 2016 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of generally accepted accounting principles 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, 2017 and 2016 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, 2017 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2017. 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, 2016 ("2016 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 15, 2017.
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. As further discussed in Note 3 – Acquisitions , TEP closed the acquisition of Terminals and NatGas on 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. Net equity distributions of the Predecessor Entities included in the condensed consolidated financial statements represent transfers of cash as a result of TD's centralized cash management system prior to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the subsidiaries of TD. These loans were then periodically recorded as equity distributions. The accompanying condensed consolidated financial statements of TEP include historical cost-basis accounts of the assets and liabilities of the Predecessor Entities for the periods prior to January 1, 2017, the date TEP acquired Terminals and NatGas from TD, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. TEP and the Predecessor Entities are all considered "entities under common control" as defined under GAAP and, as such, the transfers between the entities of the assets and liabilities have been recorded by TEP at historical cost.
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.
Accounting Pronouncements	Accounting Pronouncement Recently Adopted ASU No. 2016-09, "Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting" In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Among other changes, ASU 2016-09 allows an entity to make an entity-wide accounting policy election to either estimate the number of awards expected to vest (consistent with current GAAP) or account for forfeitures when they occur. The amendments in ASU 2016-09 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We adopted the guidance in ASU 2016-09 effective January 1, 2017 and made a policy election to account for forfeitures when they occur. The adoption of ASU 2016-09 did not have a material impact on our consolidated financial statements. Accounting Pronouncements Not Yet 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. Throughout 2015 and 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, and ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, and ASU 2016-20 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact of our pending adoption of the revised guidance. The status of our implementation is as follows: • We have formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain revenue contract types, and project status. • We are currently reviewing contracts for each revenue stream identified within each of our business segments. Through this process, we are determining and documenting expected changes in revenue recognition upon adoption of the revised guidance. • We plan to evaluate the potential information technology and internal control changes that will be required for adoption based on the findings from our contract review process. • We plan to provide internal training and awareness related to the revised guidance to the key stakeholders throughout our organization. Through the contract review process currently underway, management has identified several areas of potential impact, including the accounting for non-cash consideration, particularly in our Crude Oil Transportation & Logistics and Processing & Logistics segments, and the timing of revenue recognition with respect to deficiency payments received in our Crude Oil Transportation & Logistics segment. We will continue to conduct our contract review process throughout 2017 and, as a result, additional areas of impact may be identified. We are in the process of quantifying the impact of adoption but cannot reasonably estimate such amount at this time. We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. 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 equity. Consolidated revenues presented in our comparative financial statements for periods prior to January 1, 2018 would not be revised. 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. 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. ASU No. 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. The ASU also narrows the definition of the term "output" so that the term is consistent with how outputs are described under the revenue recognition guidance in Topic 606. The amendments in ASU 2017-01 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2017. Early adoption is permitted in certain circumstances. We are currently evaluating the impact of ASU 2017-01, but do not anticipate a material impact on our consolidated financial statements. ASU No. 2017-04, "Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment" In January 2017, the FASB issued ASU No. 2017-04, which simplifies the subsequent measurement of goodwill by eliminating "Step 2" from the goodwill impairment test, which involved calculating the implied fair value of goodwill by determining the fair value at the impairment testing date of a reporting unit's assets and liabilities. Instead, under the simplified test approach, an entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The amendments in ASU 2017-04 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We are currently evaluating the impact of ASU 2017-04.

Acquisitions Equity Method Inve

Acquisitions Equity Method Investments (Policies)	3 Months Ended
	Mar. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments, Policy	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. As a result of the common control nature of the transaction, the 24.99% membership interest in Rockies Express was transferred to the Partnership at TD's historical carrying amount, including the remaining unamortized basis difference driven by the difference between the fair value of the investment and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD. For additional information, see Note 7 – Investments in Unconsolidated Affiliates . As of March 31, 2017, the negative basis difference carried over from TD was approximately $386.8 million . The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years , which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities.

Description of Business Schedul

Description of Business Schedule of Other Ownership Interests (Tables)	3 Months Ended
	Mar. 31, 2017
Schedule of Other Ownership Interests [Abstract]
Schedule of Ownership Interests	The table below summarizes our equity ownership as of March 31, 2017 : 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 (1) 46,565,254 — 64.51 % 63.77 % Tallgrass Equity, LLC 20,000,000 — 27.71 % 27.39 % Tallgrass Development, LP 5,619,218 — 7.78 % 7.70 % Tallgrass MLP GP, LLC (2) — 834,391 — % 1.14 % Total (3) 72,184,472 834,391 100.00 % 100.00 % (1) As discussed in Note 10 – Partnership Equity and Distributions , we issued and sold an additional 253,414 common units subsequent to March 31, 2017 . As of May 3, 2017 , there were 46,818,668 common units held by public unitholders outstanding. (2) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights. (3) As of May 3, 2017 , there were 73,272,277 total limited partner and general partner units outstanding.

Acquisitions Equity Method In24

Acquisitions Equity Method Investment (Tables)	3 Months Ended
	Mar. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	The basis difference associated with the recently acquired 24.99% membership interest in Rockies Express at March 31, 2017 was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 19,504 2 - 25 years Property, plant and equipment (406,301 ) 35 years Total basis difference $ (386,797 ) Summarized financial information for Rockies Express is as follows: Three Months Ended March 31, 2017 Revenue $ 201,338 Operating income $ 107,369 Net income to Members $ 66,250
Impact of Adjustments Related to Transaction Among Entities Under Common Control, Balance Sheet	The results of our acquisitions of Terminals and NatGas are included in the condensed consolidated balance sheets as of March 31, 2017 and December 31, 2016 . The following table presents our previously reported December 31, 2016 condensed consolidated balance sheet, adjusted for the acquisitions of Terminals and NatGas: December 31, 2016 TEP (As previously reported) Consolidate Terminals Consolidate NatGas TEP (As currently reported) (in thousands) ASSETS Current Assets: Cash and cash equivalents $ 1,873 $ — $ — $ 1,873 Accounts receivable, net 59,469 38 29 59,536 Gas imbalances 1,597 — — 1,597 Inventories 12,805 288 — 13,093 Derivative assets at fair value 10,967 — — 10,967 Prepayments and other current assets 6,820 808 — 7,628 Total Current Assets 93,531 1,134 29 94,694 Property, plant and equipment, net 2,012,263 66,969 — 2,079,232 Goodwill 343,288 — — 343,288 Intangible asset, net 93,522 — — 93,522 Unconsolidated investments 461,915 13,710 — 475,625 Deferred financing costs, net 4,815 — — 4,815 Deferred charges and other assets 9,637 1,400 — 11,037 Total Assets $ 3,018,971 $ 83,213 $ 29 $ 3,102,213 LIABILITIES AND EQUITY Current Liabilities: Accounts payable $ 24,076 $ 46 $ — $ 24,122 Accounts payable to related parties 5,879 56 — 5,935 Gas imbalances 1,239 — — 1,239 Derivative liabilities at fair value 556 — — 556 Accrued taxes 16,328 668 — 16,996 Accrued liabilities 16,525 177 — 16,702 Deferred revenue 60,757 — — 60,757 Other current liabilities 6,446 — — 6,446 Total Current Liabilities 131,806 947 — 132,753 Long-term debt, net 1,407,981 — — 1,407,981 Other long-term liabilities and deferred credits 7,063 — — 7,063 Total Long-term Liabilities 1,415,044 — — 1,415,044 Equity: Net Equity 1,472,121 82,266 29 1,554,416 Total Equity 1,472,121 82,266 29 1,554,416 Total Liabilities and Equity $ 3,018,971 $ 83,213 $ 29 $ 3,102,213
Impact of Adjustments Related to Transaction Among Entities Under Common Control, Income Statement	The results of our acquisitions of Terminals and NatGas are included in the condensed consolidated statements of income for the three months ended March 31, 2017 and 2016 . The following tables present the previously reported condensed consolidated statements of income for the three months ended March 31, 2016 , adjusted for the acquisitions of Terminals and NatGas: Three Months Ended March 31, 2016 TEP (As previously reported) Consolidate Terminals Consolidate NatGas Elimination (1) TEP (As currently reported) (in thousands) Revenues: Crude oil transportation services $ 94,572 $ — $ — $ — $ 94,572 Natural gas transportation services 29,280 — — — 29,280 Sales of natural gas, NGLs, and crude oil 13,926 — — — 13,926 Processing and other revenues 7,627 2,909 1,681 (2,827 ) 9,390 Total Revenues 145,405 2,909 1,681 (2,827 ) 147,168 Operating Costs and Expenses: Cost of sales (exclusive of depreciation and amortization shown below) 13,568 — — — 13,568 Cost of transportation services (exclusive of depreciation and amortization shown below) 16,156 200 — (2,827 ) 13,529 Operations and maintenance 12,477 481 — — 12,958 Depreciation and amortization 21,692 315 — — 22,007 General and administrative 13,016 474 — — 13,490 Taxes, other than income taxes 7,506 144 — — 7,650 Total Operating Costs and Expenses 84,415 1,614 — (2,827 ) 83,202 Operating Income 60,990 1,295 1,681 — 63,966 Other Income (Expense): Interest expense, net (7,499 ) — — — (7,499 ) Unrealized loss on derivative instrument (8,946 ) — — — (8,946 ) Equity in earnings of unconsolidated investments — 709 — — 709 Other income, net 566 — — — 566 Total Other (Expense) Income (15,879 ) 709 — — (15,170 ) Net income 45,111 2,004 1,681 — 48,796 Net income attributable to noncontrolling interests (1,041 ) — — — (1,041 ) Net income attributable to partners $ 44,070 $ 2,004 $ 1,681 $ — $ 47,755 (1) Represents the elimination of revenue and cost of transportation services associated with the lease of the Sterling Terminal facilities by Pony Express.

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2017
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, 2017 2016 (in thousands) Cost of transportation services (1) $ 4,507 $ 4,429 Charges to TEP: (2) Property, plant and equipment, net $ 293 $ 918 Operations and maintenance $ 6,277 $ 6,184 General and administrative $ 9,377 $ 9,212 (1) Reflects rent expense for the crude oil storage at the Deeprock Terminal. (2) Charges to TEP include directly charged wages and salaries, other compensation and benefits, and shared services.
Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets	Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows: March 31, 2017 December 31, 2016 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 1,266 $ 590 Total receivable from related parties $ 1,266 $ 590 Accounts payable to related parties: Tallgrass Operations, LLC $ 6,088 $ 5,854 Tallgrass Equity, LLC 67 68 Tallgrass Management, LLC 20 — Deeprock Development, LLC — 13 Total accounts payable to related parties $ 6,175 $ 5,935
Schedule of Balances of Gas Imbalance with Affiliated Shippers	Gas imbalances with affiliated shippers are as follows: March 31, 2017 December 31, 2016 (in thousands) Affiliate gas imbalance receivables $ — $ 177 Affiliate gas imbalance payables $ 73 $ —

Inventory (Tables)

Inventory (Tables)	3 Months Ended
	Mar. 31, 2017
Inventory Disclosure [Abstract]
Schedule of Components of Inventory	The components of inventory at March 31, 2017 and December 31, 2016 consisted of the following: March 31, 2017 December 31, 2016 (in thousands) Crude oil $ 6,903 $ 5,462 Materials and supplies 6,455 6,383 Natural gas liquids 573 265 Gas in underground storage 1,716 983 Total inventory $ 15,647 $ 13,093

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	3 Months Ended
	Mar. 31, 2017
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, 2017 December 31, 2016 (in thousands) Crude oil pipelines $ 1,207,727 $ 1,202,125 Natural gas pipelines 575,536 572,150 Processing and treating assets 262,447 256,901 General and other 225,243 223,310 Construction work in progress 29,770 20,606 Accumulated depreciation and amortization (215,053 ) (195,860 ) Total property, plant and equipment, net $ 2,085,670 $ 2,079,232

Investments in Unconsolidated28

Investments in Unconsolidated Affiliates (Tables)	3 Months Ended
	Mar. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	The basis difference associated with the recently acquired 24.99% membership interest in Rockies Express at March 31, 2017 was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 19,504 2 - 25 years Property, plant and equipment (406,301 ) 35 years Total basis difference $ (386,797 ) Summarized financial information for Rockies Express is as follows: Three Months Ended March 31, 2017 Revenue $ 201,338 Operating income $ 107,369 Net income to Members $ 66,250

Risk Management (Tables)

Risk Management (Tables)	3 Months Ended
	Mar. 31, 2017
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, 2017 December 31, 2016 (in thousands) Call option derivative (1) Current assets $ — $ 10,676 Crude oil derivative contracts (2) Current assets $ 223 $ — Natural gas derivative contracts (3) Current assets $ 81 $ 291 Crude oil derivative contracts (2) Current liabilities $ — $ 440 Natural gas derivative contracts (3) Current liabilities $ — $ 116 (1) As discussed below, in conjunction with our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option covering the 6,518,000 common units issued to TD. As of February 1, 2017, no common units remained subject to the call option. (2) As of March 31, 2017 and December 31, 2016 , the fair value shown for crude oil derivative contracts represents the sale of 125,000 barrels of crude oil which will settle throughout 2017. (3) As of March 31, 2017 , the fair value shown for natural gas derivative contracts was comprised of derivative volumes for long natural gas fixed-price swaps totaling 0.3 Bcf. As of December 31, 2016 , the fair value shown for natural gas derivative contracts was comprised of derivative volumes for short and long natural gas fixed-price swaps totaling 0.3 Bcf and 0.4 Bcf, respectively.
Derivative Contracts Included in Consolidated Statements of Income	The following table summarizes the impact of derivative contracts for the three months ended March 31, 2017 and 2016 : Location of gain (loss) recognized Amount of gain (loss) recognized in income on derivatives Three Months Ended March 31, 2017 2016 (in thousands) Derivatives not designated as hedging contracts: Call option derivative Unrealized gain (loss) on derivative instrument $ 1,885 $ (8,946 ) Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ 173 $ (44 ) Crude oil derivative contracts Sales of natural gas, NGLs, and crude oil $ 663 $ —
Derivative Instruments Maximum Potential Exposure to Credit Loss [Table Text Block]	The maximum potential exposure to credit losses on our crude oil and natural gas derivative contracts at March 31, 2017 was: Asset Position (in thousands) Gross $ 304 Netting agreement impact — Cash collateral held — Net exposure $ 304
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, 2017 and December 31, 2016 based on the fair value hierarchy established by the Codification: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of March 31, 2017: Crude oil derivative contracts $ 223 $ — $ 223 $ — Natural gas derivative contracts $ 81 $ — $ 81 $ — As of December 31, 2016: Call option derivative $ 10,676 $ — $ 10,676 $ — Natural gas derivative contracts $ 291 $ — $ 291 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2016: Crude oil derivative contracts $ 440 $ — $ 440 $ — Natural gas derivative contracts $ 116 $ — $ 116 $ —

Long-term Debt (Tables)

Long-term Debt (Tables)	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Schedule of Debt	Long-term debt consisted of the following at March 31, 2017 and December 31, 2016 : March 31, 2017 December 31, 2016 (in thousands) Revolving credit facility $ 1,567,000 $ 1,015,000 5.50% senior notes due September 15, 2024 400,000 400,000 Less: Deferred financing costs, net (1) (6,768 ) (7,019 ) Total long-term debt, net $ 1,960,232 $ 1,407,981 (1) Deferred financing costs, net as presented above relate solely to the 2024 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, 2017 and December 31, 2016 : March 31, 2017 December 31, 2016 (in thousands) Total capacity under the revolving credit facility $ 1,750,000 $ 1,750,000 Less: Outstanding borrowings under the revolving credit facility (1,567,000 ) (1,015,000 ) Available capacity under the revolving credit facility $ 183,000 $ 735,000
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, 2017 and December 31, 2016 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of March 31, 2017: Revolving credit facility $ — $ 1,567,000 $ — $ 1,567,000 $ 1,567,000 2024 Notes $ — $ 403,252 $ — $ 403,252 $ 393,232 As of December 31, 2016: Revolving credit facility $ — $ 1,015,000 $ — $ 1,015,000 $ 1,015,000 2024 Notes $ — $ 398,000 $ — $ 398,000 $ 392,981

Partnership Equity and Distri31

Partnership Equity and Distributions (Tables)	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Summary of Distributions	The following table shows the distributions for the periods indicated: Distributions Limited Partner General Partner Distributions Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) March 31, 2017 May 15, 2017 (1) $ 60,486 $ 29,840 $ 1,040 $ 91,366 $ 0.8350 December 31, 2016 February 14, 2017 58,793 28,358 1,008 88,159 0.8150 September 30, 2016 November 14, 2016 57,332 26,987 976 85,295 0.7950 June 30, 2016 August 12, 2016 54,442 24,262 911 79,615 0.7550 March 31, 2016 May 13, 2016 48,238 19,816 830 68,884 0.7050 (1) The distribution announced on April 17, 2017 for the first quarter of 2017 will be paid on May 15, 2017 to unitholders of record at the close of business on April 28, 2017 .

Net Income per Limited Partne32

Net Income per Limited Partner Unit (Tables)	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Summary of Net Income Per Limited Partner Unit	The following table illustrates the Partnership's calculation of net income per common unit for the three months ended March 31, 2017 and 2016 : Three Months Ended March 31, 2017 2016 (in thousands, except per unit amounts) Net income $ 71,784 $ 48,796 Net income attributable to noncontrolling interests (879 ) (1,041 ) Net income attributable to partners 70,905 47,755 Predecessor operations interest in net income — (3,685 ) General partner interest in net income (30,583 ) (20,353 ) Net income available to common unitholders $ 40,322 $ 23,717 Basic net income per common unit $ 0.56 $ 0.35 Diluted net income per common unit $ 0.55 $ 0.35 Basic average number of common units outstanding 72,544 66,967 Equity Participation Unit equivalent units 1,036 840 Diluted average number of common units outstanding 73,580 67,807

Reporting Segments (Tables)

Reporting Segments (Tables)	3 Months Ended
	Mar. 31, 2017
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, 2017 Three Months Ended March 31, 2016 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 85,092 $ — $ 85,092 $ 94,654 $ — $ 94,654 Natural Gas Transportation & Logistics 36,428 (1,445 ) 34,983 32,668 (1,355 ) 31,313 Processing & Logistics 24,325 — 24,325 21,201 — 21,201 Corporate and Other — — — — — — Total revenue $ 145,845 $ (1,445 ) $ 144,400 $ 148,523 $ (1,355 ) $ 147,168
Summary of TEP's Segment Information of Earnings	Three Months Ended March 31, 2017 Three Months Ended March 31, 2016 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 57,767 $ 1,344 $ 59,111 $ 66,985 $ 1,345 $ 68,330 Natural Gas Transportation & Logistics 53,030 (1,445 ) 51,585 18,833 (1,355 ) 17,478 Processing & Logistics 6,075 101 6,176 3,351 10 3,361 Corporate and Other (1,761 ) — (1,761 ) (1,352 ) — (1,352 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment 20,738 709 Gain on disposal of assets 1,448 — Less: Interest expense, net of noncontrolling interest (14,689 ) (7,499 ) Depreciation and amortization expense, net of noncontrolling interest (21,867 ) (22,482 ) Distributions from unconsolidated investment (30,819 ) (634 ) Non-cash gain (loss) related to derivative instruments, net of noncontrolling interests 2,441 (8,990 ) Non-cash compensation expense (1,458 ) (1,166 ) Net income attributable to partners $ 70,905 $ 47,755
Summary of TEP's Segment Capital Expenditures	Three Months Ended March 31, Capital Expenditures: 2017 2016 (in thousands) Crude Oil Transportation & Logistics $ 10,436 $ 15,973 Natural Gas Transportation & Logistics 4,655 2,133 Processing & Logistics 11,678 3,101 Corporate and Other — — Total capital expenditures $ 26,769 $ 21,207
Summary of TEP's Segment Information of Assets	Assets: March 31, 2017 December 31, 2016 (in thousands) Crude Oil Transportation & Logistics $ 1,492,333 $ 1,493,866 Natural Gas Transportation & Logistics 1,633,358 1,176,147 Processing & Logistics 418,479 411,999 Corporate and Other 8,486 20,201 Total assets $ 3,552,656 $ 3,102,213

Description of Business - Addit

Description of Business - Additional Information (Detail) - shares	1 Months Ended	3 Months Ended
	May 03, 2017	Mar. 31, 2017	Jan. 01, 2017	Dec. 31, 2016
Organization [Line Items]
Limited Partner Common Units		72,184,472		72,485,954
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%
Partners' Capital Account, Units, Sold in Public Offering		2,087,647
Ownership Interests Held By Public
Organization [Line Items]
Limited Partner Common Units		46,565,254
General Partner Units		0
Percentage of Outstanding Limited Partner Common Units		64.51%
Percentage of Outstanding Common and General Partner Units		63.77%
Ownership Interests Held By Tallgrass Equity, LLC
Organization [Line Items]
Limited Partner Common Units		20,000,000
General Partner Units		0
Percentage of Outstanding Limited Partner Common Units		27.71%
Percentage of Outstanding Common and General Partner Units		27.39%
Ownership Interests Held By Tallgrass Development , LP
Organization [Line Items]
Limited Partner Common Units		5,619,218
General Partner Units		0
Percentage of Outstanding Limited Partner Common Units		7.78%
Percentage of Outstanding Common and General Partner Units		7.70%
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		1.14%
Subsequent Event
Organization [Line Items]
Partners' Capital Account, Units, Sold in Public Offering	253,414
Capital Units, Outstanding	73,272,277
Subsequent Event | Ownership Interests Held By Public
Organization [Line Items]
Limited Partner Common Units	46,818,668
Deeprock Development, LLC
Organization [Line Items]
Equity Method Investment, Ownership Percentage			20.00%
Rockies Express Pipeline LLC
Organization [Line Items]
Equity Method Investment, Ownership Percentage		50.00%
Tallgrass Terminals, LLC
Organization [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			100.00%
Rockies Express Pipeline LLC | Tallgrass Development LP
Organization [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		24.99%
Tallgrass NatGas Operator, LLC
Organization [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			100.00%

Acquisitions Equity Method In35

Acquisitions Equity Method Investments (Details) - Rockies Express Pipeline LLC $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ (386,797)
Basis Difference, Amortization Period	35 years
Long-term Debt
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 19,504
Property, Plant and Equipment
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ (406,301)
Basis Difference, Amortization Period	35 years
Minimum | Long-term Debt
Schedule of Equity Method Investments [Line Items]
Basis Difference, Amortization Period	2 years
Maximum | Long-term Debt
Schedule of Equity Method Investments [Line Items]
Basis Difference, Amortization Period	25 years

Acquisitions Impact of Acquisit

Acquisitions Impact of Acquisition, Balance Sheet (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Cash and cash equivalents	$ 1,198	$ 1,873	$ 2,885	$ 1,611
Accounts receivable, net	57,274	59,536
Gas imbalances	636	1,597
Inventories	15,647	13,093
Derivative assets at fair value	304	10,967
Prepayments and other current assets	6,785	7,628
Total Current Assets	81,844	94,694
Property, plant and equipment, net	2,085,670	2,079,232
Goodwill	343,288	343,288
Intangible asset, net	92,764	93,522
Unconsolidated investments	935,918	475,625
Deferred financing costs, net	3,930	4,815
Deferred charges and other assets	9,242	11,037
Total Assets	3,552,656	3,102,213
Accounts payable	22,050	24,122
Accounts payable to related parties	6,175	5,935
Gas imbalances	1,473	1,239
Derivative liabilities at fair value	0	556
Accrued taxes	21,857	16,996
Accrued liabilities	6,783	16,702
Deferred revenue	77,067	60,757
Other current liabilities	6,001	6,446
Total Current Liabilities	141,406	132,753
Long-term debt, net	1,960,232	1,407,981
Other long-term liabilities and deferred credits	7,125	7,063
Total Long-term Liabilities	1,967,357	1,415,044
Total Equity	1,443,893	1,554,416
Total Liabilities and Equity	$ 3,552,656	3,102,213
Tallgrass Energy Partners
Business Acquisition [Line Items]
Cash and cash equivalents		1,873
Accounts receivable, net		59,469
Gas imbalances		1,597
Inventories		12,805
Derivative assets at fair value		10,967
Prepayments and other current assets		6,820
Total Current Assets		93,531
Property, plant and equipment, net		2,012,263
Goodwill		343,288
Intangible asset, net		93,522
Unconsolidated investments		461,915
Deferred financing costs, net		4,815
Deferred charges and other assets		9,637
Total Assets		3,018,971
Accounts payable		24,076
Accounts payable to related parties		5,879
Gas imbalances		1,239
Derivative liabilities at fair value		556
Accrued taxes		16,328
Accrued liabilities		16,525
Deferred revenue		60,757
Other current liabilities		6,446
Total Current Liabilities		131,806
Long-term debt, net		1,407,981
Other long-term liabilities and deferred credits		7,063
Total Long-term Liabilities		1,415,044
Total Equity		1,472,121
Total Liabilities and Equity		3,018,971
Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Cash and cash equivalents		0
Accounts receivable, net		38
Gas imbalances		0
Inventories		288
Derivative assets at fair value		0
Prepayments and other current assets		808
Total Current Assets		1,134
Property, plant and equipment, net		66,969
Goodwill		0
Intangible asset, net		0
Unconsolidated investments		13,710
Deferred financing costs, net		0
Deferred charges and other assets		1,400
Total Assets		83,213
Accounts payable		46
Accounts payable to related parties		56
Gas imbalances		0
Derivative liabilities at fair value		0
Accrued taxes		668
Accrued liabilities		177
Deferred revenue		0
Other current liabilities		0
Total Current Liabilities		947
Long-term debt, net		0
Other long-term liabilities and deferred credits		0
Total Long-term Liabilities		0
Total Equity		82,266
Total Liabilities and Equity		83,213
Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Cash and cash equivalents		0
Accounts receivable, net		29
Gas imbalances		0
Inventories		0
Derivative assets at fair value		0
Prepayments and other current assets		0
Total Current Assets		29
Property, plant and equipment, net		0
Goodwill		0
Intangible asset, net		0
Unconsolidated investments		0
Deferred financing costs, net		0
Deferred charges and other assets		0
Total Assets		29
Accounts payable		0
Accounts payable to related parties		0
Gas imbalances		0
Derivative liabilities at fair value		0
Accrued taxes		0
Accrued liabilities		0
Deferred revenue		0
Other current liabilities		0
Total Current Liabilities		0
Long-term debt, net		0
Other long-term liabilities and deferred credits		0
Total Long-term Liabilities		0
Total Equity		29
Total Liabilities and Equity		$ 29

Acquisitions Impact of Acquis37

Acquisitions Impact of Acquisition, Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Business Acquisition [Line Items]
Crude oil transportation services	$ 84,331	$ 94,572
Natural gas transportation services	31,685	29,280
Sales of natural gas, NGLs, and crude oil	15,381	13,926
Processing and other revenues	13,003	9,390
Total Revenues	144,400	147,168
Cost of sales (exclusive of depreciation and amortization shown below)	12,370	13,568
Cost of transportation services (exclusive of depreciation and amortization shown below)	13,503	13,529
Operations and maintenance	12,903	12,958
Depreciation and amortization	21,403	22,007
General and administrative	13,663	13,490
Taxes, other than income taxes	8,226	7,650
Total Operating Costs and Expenses	80,620	83,202
Operating Income	63,780	63,966
Interest expense, net	(14,689)	(7,499)
Unrealized gain (loss) on derivative instrument	1,885	(8,946)
Equity in earnings of unconsolidated investments	20,738	709
Other income, net	70	566
Total Other Income (Expense)	8,004	(15,170)
Net income	71,784	48,796
Net income attributable to noncontrolling interests	(879)	(1,041)
Net income attributable to partners	$ 70,905	47,755
Consolidation, Eliminations
Business Acquisition [Line Items]
Crude oil transportation services		0
Natural gas transportation services		0
Sales of natural gas, NGLs, and crude oil		0
Processing and other revenues		(2,827)
Total Revenues		(2,827)
Cost of sales (exclusive of depreciation and amortization shown below)		0
Cost of transportation services (exclusive of depreciation and amortization shown below)		(2,827)
Operations and maintenance		0
Depreciation and amortization		0
General and administrative		0
Taxes, other than income taxes		0
Total Operating Costs and Expenses		(2,827)
Operating Income		0
Interest expense, net		0
Unrealized gain (loss) on derivative instrument		0
Equity in earnings of unconsolidated investments		0
Other income, net		0
Total Other Income (Expense)		0
Net income		0
Net income attributable to noncontrolling interests		0
Net income attributable to partners		0
Tallgrass Energy Partners
Business Acquisition [Line Items]
Crude oil transportation services		94,572
Natural gas transportation services		29,280
Sales of natural gas, NGLs, and crude oil		13,926
Processing and other revenues		7,627
Total Revenues		145,405
Cost of sales (exclusive of depreciation and amortization shown below)		13,568
Cost of transportation services (exclusive of depreciation and amortization shown below)		16,156
Operations and maintenance		12,477
Depreciation and amortization		21,692
General and administrative		13,016
Taxes, other than income taxes		7,506
Total Operating Costs and Expenses		84,415
Operating Income		60,990
Interest expense, net		(7,499)
Unrealized gain (loss) on derivative instrument		(8,946)
Equity in earnings of unconsolidated investments		0
Other income, net		566
Total Other Income (Expense)		(15,879)
Net income		45,111
Net income attributable to noncontrolling interests		(1,041)
Net income attributable to partners		44,070
Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Crude oil transportation services		0
Natural gas transportation services		0
Sales of natural gas, NGLs, and crude oil		0
Processing and other revenues		2,909
Total Revenues		2,909
Cost of sales (exclusive of depreciation and amortization shown below)		0
Cost of transportation services (exclusive of depreciation and amortization shown below)		200
Operations and maintenance		481
Depreciation and amortization		315
General and administrative		474
Taxes, other than income taxes		144
Total Operating Costs and Expenses		1,614
Operating Income		1,295
Interest expense, net		0
Unrealized gain (loss) on derivative instrument		0
Equity in earnings of unconsolidated investments		709
Other income, net		0
Total Other Income (Expense)		709
Net income		2,004
Net income attributable to noncontrolling interests		0
Net income attributable to partners		2,004
Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Crude oil transportation services		0
Natural gas transportation services		0
Sales of natural gas, NGLs, and crude oil		0
Processing and other revenues		1,681
Total Revenues		1,681
Cost of sales (exclusive of depreciation and amortization shown below)		0
Cost of transportation services (exclusive of depreciation and amortization shown below)		0
Operations and maintenance		0
Depreciation and amortization		0
General and administrative		0
Taxes, other than income taxes		0
Total Operating Costs and Expenses		0
Operating Income		1,681
Interest expense, net		0
Unrealized gain (loss) on derivative instrument		0
Equity in earnings of unconsolidated investments		0
Other income, net		0
Total Other Income (Expense)		0
Net income		1,681
Net income attributable to noncontrolling interests		0
Net income attributable to partners		$ 1,681

Acquisitions (Details)

Acquisitions (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Jan. 01, 2017	Mar. 31, 2017	Mar. 31, 2016	May 06, 2016
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross			$ 140,000	$ 0
Tallgrass Terminals, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		100.00%
Tallgrass NatGas Operator, LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		100.00%
Tallgrass Development LP | Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	24.99%		24.99%
Sempra U.S. Gas and Power | Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					25.00%
Tallgrass Energy Partners | Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 400,000
Tallgrass Energy Partners | Terminals and NatGas
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 140,000
Deeprock Development, LLC
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage		20.00%
Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage	50.00%		50.00%
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ (386,797)		$ (386,797)
Basis Difference, Amortization Period			35 years
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service			2.86%
Rockies Express Pipeline LLC | Tallgrass Energy Partners
Business Acquisition [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 386,800		$ 386,800

Related Party Transactions - Sc

Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Related Party Transaction [Line Items]
Related Party Transactions, Cost of Sales and Transportation Services	$ 4,507	$ 4,429
Operation and maintenance
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	6,277	6,184
General and administrative
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	9,377	9,212
Property, Plant and Equipment
Related Party Transaction [Line Items]
Related Party Transaction Costs Capitalized From Transactions With Related Party	$ 293	$ 918

Related Party Transactions - 40

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, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Receivable from related parties	$ 1,266	$ 590
Accounts payable to related parties	6,175	5,935
Rockies Express Pipeline LLC
Related Party Transaction [Line Items]
Receivable from related parties	1,266	590
Tallgrass Operations, LLC
Related Party Transaction [Line Items]
Accounts payable to related parties	6,088	5,854
Tallgrass Equity, LLC
Related Party Transaction [Line Items]
Accounts payable to related parties	67	68
Tallgrass Management, LLC
Related Party Transaction [Line Items]
Accounts payable to related parties	20	0
Deeprock Development, LLC
Related Party Transaction [Line Items]
Accounts payable to related parties	$ 0	$ 13

Related Party Transactions - 41

Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Affiliate gas balance receivables	$ 0	$ 177
Affiliate gas balance payables	$ 73	$ 0

Inventory Inventory (Details)

Inventory Inventory (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Crude oil	$ 6,903	$ 5,462
Materials and supplies	6,455	6,383
Natural gas liquids	573	265
Gas in underground storage	1,716	983
Inventory, Net	$ 15,647	$ 13,093

Property Plant and Equipment -

Property Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Accumulated depreciation and amortization	$ (215,053)	$ (195,860)
Property, plant and equipment	2,085,670	2,079,232
Crude oil pipelines
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,207,727	1,202,125
Natural gas pipelines
Property, Plant and Equipment [Line Items]
Property, plant and equipment	575,536	572,150
Processing and treating assets
Property, Plant and Equipment [Line Items]
Property, plant and equipment	262,447	256,901
General and other
Property, Plant and Equipment [Line Items]
Property, plant and equipment	225,243	223,310
Construction work in progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 29,770	$ 20,606

Investments in Unconsolidated44

Investments in Unconsolidated Affiliates Equity Method Investments (Details) - Rockies Express Pipeline LLC $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Revenue	$ 201,338
Equity Method Investment Summarized Financial Information Operating Income	107,369
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	$ 66,250

Investments in Unconsolidated45

Investments in Unconsolidated Affiliates Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Jan. 01, 2017	May 06, 2016
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated investments	$ 20,738	$ 709
Payments to Acquire Equity Method Investments	6,693	$ 63
Rockies Express Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Equity in earnings of unconsolidated investments	20,046
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries	30,100
Payments to Acquire Equity Method Investments	$ 6,693
Equity Method Investment, Ownership Percentage	50.00%
Deeprock Development, LLC
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			20.00%
Rockies Express Pipeline LLC | Sempra U.S. Gas and Power
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				25.00%
Rockies Express Pipeline LLC | Tallgrass Development LP
Schedule of Equity Method Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	24.99%

Risk Management - Schedule of F

Risk Management - Schedule of Fair Value of Derivative Contracts (Detail) $ in Thousands	Jan. 01, 2016shares	Mar. 31, 2017USD ($)Bcfbbl	Dec. 31, 2016USD ($)Bcfbbl
Pony Express Pipeline
Derivatives, Fair Value [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	31.30%
Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value			$ 10,676
Equity Option | Pony Express Pipeline
Derivatives, Fair Value [Line Items]
Derivative, Term of Contract	18 months
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	6,518,000
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		$ 81	291
Derivative liabilities at fair value			$ 116
Energy commodity derivative contracts | Commodity | Long
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf		0.3	0.4
Energy commodity derivative contracts | Commodity | Short
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf			0.3
Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		$ 223
Derivative liabilities at fair value			$ 440
Energy Related Derivative | Commodity
Derivatives, Fair Value [Line Items]
Derivative, Nonmonetary Notional Amount | bbl		125,000	125,000
Other Current Assets | Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		$ 0	$ 10,676
Other Current Assets | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		81	291
Other Current Assets | Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		223	0
Other Current Liabilities | Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value		0	116
Other Current Liabilities | Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value		$ 0	$ 440

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, 2017	Mar. 31, 2016
Equity Option
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 1,885	$ (8,946)
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	173	(44)
Energy Related Derivative
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 663	$ 0

Risk Management Risk Management

Risk Management Risk Management - Derivative Instruments Maximum Potential Exposure to Credit Loss (Details) - Energy commodity derivative contracts $ in Thousands	Mar. 31, 2017USD ($)
Concentration Risk [Line Items]
Gross	$ 304
Netting agreement impact	0
Cash collateral held	0
Net exposure	$ 304

Risk Management - Schedule of E

Risk Management - Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification (Detail) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		$ 10,676
Equity Option | Quoted prices in active markets for identical assets (Level 1)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		0
Equity Option | Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		10,676
Equity Option | Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value		0
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 81	291
Derivative liabilities at fair value		116
Energy commodity derivative contracts | Quoted prices in active markets for identical assets (Level 1)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	0	0
Derivative liabilities at fair value		0
Energy commodity derivative contracts | Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	81	291
Derivative liabilities at fair value		116
Energy commodity derivative contracts | Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	0	0
Derivative liabilities at fair value		0
Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	223
Derivative liabilities at fair value		440
Energy Related Derivative | 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
Energy Related Derivative | Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	223
Derivative liabilities at fair value		440
Energy Related Derivative | 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 Manageme50

Risk Management Risk Management - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 01, 2017	Oct. 31, 2016	Jul. 21, 2016	Jan. 01, 2016	Mar. 31, 2017	Mar. 31, 2016
Derivative [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased	736,262
Partial exercise of call option	$ 35,300				$ 35,335	$ 0
Equity Option
Derivative [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased	1,703,094	1,251,760	3,563,146
Partial exercise of call option	$ 72,400	$ 53,200	$ 151,400		$ 72,381	$ 0
Pony Express Pipeline
Derivative [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				31.30%
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, 2017	Dec. 31, 2016
Revolving credit facility
Debt Instrument [Line Items]
Total long-term debt, net	$ 1,567,000	$ 1,015,000
Tallgrass Energy Partners
Debt Instrument [Line Items]
Less: Deferred financing costs, net (1)	(6,768)	(7,019)
Total long-term debt, net	1,960,232	1,407,981
Tallgrass Energy Partners | Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Gross	400,000	400,000
Tallgrass Energy Partners | Revolving credit facility
Debt Instrument [Line Items]
Long-term Debt, Gross	1,567,000	1,015,000
Total long-term debt, net	$ 1,567,000	$ 1,015,000

Long-term Debt Capacity under R

Long-term Debt Capacity under Revolving Credit Facility (Details) - USD ($)	Mar. 31, 2017	Dec. 31, 2016
Revolving credit facility
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility	$ (1,567,000,000)	$ (1,015,000,000)
Tallgrass Energy Partners
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility	(1,960,232,000)	(1,407,981,000)
Tallgrass Energy Partners | Revolving credit facility
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility	(1,567,000,000)	(1,015,000,000)
Available capacity under the revolving credit facility	183,000,000	735,000,000
Tallgrass Energy Partners | Barclays Bank
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, 2017	Dec. 31, 2016
Senior Notes
Debt Instrument [Line Items]
Fair Value	$ 403,252	$ 398,000
Total long-term debt, net	393,232	392,981
Revolving credit facility
Debt Instrument [Line Items]
Fair Value	1,567,000	1,015,000
Total long-term debt, net	1,567,000	1,015,000
Quoted prices in active markets for identical assets (Level 1) | 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) | Senior Notes
Debt Instrument [Line Items]
Fair Value	403,252	398,000
Significant other observable inputs (Level 2) | Revolving credit facility
Debt Instrument [Line Items]
Fair Value	1,567,000	1,015,000
Significant unobservable inputs (Level 3) | 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)	Sep. 01, 2016USD ($)	Mar. 31, 2017
Debt Instrument [Line Items]
Weighted average interest rate on outstanding borrowings		2.95%
Debt Instrument, Interest Rate, Effective Percentage		3.12%
Senior Notes | Tallgrass Energy Partners
Debt Instrument [Line Items]
Proceeds from Issuance of Senior Long-term Debt	$ 400,000,000
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Revolving credit facility | Maximum
Debt Instrument [Line Items]
Consolidated leverage ratio		4.75
Contingent Consolidated Leverage Ratio		5.25
Credit facility commitment fee		0.50%
Revolving credit facility | Minimum
Debt Instrument [Line Items]
Consolidated interest coverage ratio		2.50
Credit facility commitment fee		0.30%

Partnership Equity and Distri55

Partnership Equity and Distributions - Summary of Distributions (Detail) - Tallgrass Energy Partners - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016
Distribution Made to Limited Partner [Line Items]
Distributions Limited Partners Common	$ 60,486	$ 58,793	$ 57,332	$ 54,442	$ 48,238
Distributions General Partner Incentive	29,840	28,358	26,987	24,262	19,816
General Partner Distributions	1,040	1,008	976	911	830
Distributions Total	$ 91,366	$ 88,159	$ 85,295	$ 79,615	$ 68,884
Distributions per Limited Partner unit	$ 0.8350	$ 0.8150	$ 0.7950	$ 0.7550	$ 0.7050

Partnership Equity and Distri56

Partnership Equity and Distributions - Additional Information (Detail) - USD ($)	Feb. 01, 2017	May 03, 2017	Mar. 31, 2017	Mar. 31, 2016	Mar. 31, 2017	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, Sold in Public Offering			2,087,647
Shares Issued, Weighted Average Price Per Share			$ 48.23
Issuance of units to public, net of offering costs			$ 99,400,000
LimitedPartnerOfferingCosts			1,300,000
Partners' Capital Account, Units, Treasury Units Purchased	736,262
Payments for Repurchase of Common Stock	$ (35,300,000)		(35,335,000)	$ 0
Treasury Stock Acquired, Average Cost Per Share	$ 47.99
Payments to Noncontrolling Interests			0	425,882,000
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired							31.30%
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
Partial exercise of call option			12,561,000
Contributions from TD			2,301,000		$ 20,000,000
Contributions from noncontrolling interests			0	0
Payments to Noncontrolling Interests			0	0
General Partner | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions				(280,000,000)
Subsequent Event
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Units, Sold in Public Offering		253,414
Shares Issued, Weighted Average Price Per Share		$ 53.65
Issuance of units to public, net of offering costs		$ 13,500,000
LimitedPartnerOfferingCosts		$ 100,000
Total Partner Equity Including Portion Attributable to Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Issuance of units to public, net of offering costs			99,373,000	12,636,000
Payments for Repurchase of Common Stock			35,335,000
Partial exercise of call option			84,942,000
Contributions from TD			2,301,000
Contributions from noncontrolling interests			710,000	7,152,000
Payments to Noncontrolling Interests			$ 1,418,000	1,793,000
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners			2.00%		2.00%
Pony Express Pipeline | General Partner
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions				(279,967,000)
Pony Express Pipeline | Total Partner Equity Including Portion Attributable to Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions				$ (429,039,000)

Net Income per Limited Partne57

Net Income per Limited Partner Unit - Summary of Net Income Per Limited Partner Unit (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Net income	$ 71,784	$ 48,796
Net income attributable to noncontrolling interests	(879)	(1,041)
Net income attributable to partners	70,905	47,755
Predecessor operations interest in net (income) loss	0	(3,685)
General partner interest in net income	(30,583)	(20,353)
Net income available to common unitholders	$ 40,322	$ 23,717
Basic net income per common unit	$ 0.56	$ 0.35
Diluted net income per common unit	$ 0.55	$ 0.35
Basic average number of common units outstanding	72,544	66,967
Equity Participation Unit equivalent units	1,036	840
Diluted average number of common units outstanding	73,580	67,807

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters (Details) MMBTU / d in Thousands	Jan. 06, 2017MMBTU / d
Regulated Operations [Abstract]
Capacity Enhancement	0

Legal and Environmental Matte59

Legal and Environmental Matters - Additional Information (Detail)	Feb. 16, 2017USD ($)	Feb. 02, 2017USD ($)	Jan. 12, 2017USD ($)Bcf / d	Jan. 31, 2017bbl	Mar. 31, 2017USD ($)ft-lb	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)Bcf / dmi	Dec. 31, 2015USD ($)mi	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Apr. 14, 2016USD ($)
Loss Contingencies [Line Items]
Estimated environmental liability					$ 3,800,000		$ 4,000,000		$ 3,800,000	$ 4,000,000
Aggregate cost of crack tool runs										$ 9,800,000
Crude Oil Spilled or Leaked | bbl				10,000
Crude oil recovered | bbl				9,000
Trailblazer
Loss Contingencies [Line Items]
Miles of natural gas pipeline needing repair or replacement | mi							8
Maximum allowable operating pressure | ft-lb					144,000
Excavation digs								32
Aggregate cost of excavation digs								$ 1,300,000
Estimated pipeline replacement costs							$ 19,000,000
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
Subsequent Event
Loss Contingencies [Line Items]
Aggregate cost of crack tool runs						$ 9,000,000
Remediation costs, Anticipated costs						600,000
Subsequent Event | Trailblazer
Loss Contingencies [Line Items]
Estimated remediation and cleanup costs						$ 2,500,000
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
Pipeline replacement costs					2,700,000
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			$ 150,000,000
Firm Transportation Rate			0.37
Anticipated Annual Revenue			$ 26,800,000
Michels Corporation Complaint
Loss Contingencies [Line Items]
Litigation Settlement, Amount	$ 10,000,000	$ 10,000,000
Withholding for Liquidated Delay Damages and Excess Completion Costs	$ 5,900,000
Loss Contingency, Damages Sought, Value					$ 24,200,000

Reporting Segments - Summary of

Reporting Segments - Summary of TEP's Segment Information of Revenue (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Total Revenues	$ 144,400	$ 147,168
TEP
Segment Reporting Information [Line Items]
Total Revenues	144,400	147,168
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Total Revenues	85,092	94,654
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Total Revenues	34,983	31,313
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Total Revenues	24,325	21,201
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues	0	0
TEP | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	145,845	148,523
TEP | Operating Segments [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Total Revenues	85,092	94,654
TEP | Operating Segments [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Total Revenues	36,428	32,668
TEP | Operating Segments [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Total Revenues	24,325	21,201
TEP | Operating Segments [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues	0	0
TEP | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	(1,445)	(1,355)
TEP | Intersegment Eliminations [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Total Revenues	0	0
TEP | Intersegment Eliminations [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Total Revenues	(1,445)	(1,355)
TEP | Intersegment Eliminations [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Total Revenues	0	0
TEP | Intersegment Eliminations [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Total Revenues	$ 0	$ 0

Reporting Segments - Summary 61

Reporting Segments - Summary of TEP's Segment Information of Earnings (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Reconciliation to Net Income:
Equity in earnings of unconsolidated investments	$ 20,738	$ 709
Interest expense, net of noncontrolling interest	14,689	7,499
Depreciation and amortization expense, net of noncontrolling interest	(21,403)	(22,007)
Distributions from unconsolidated investments	(20,740)	(634)
Non-cash gain (loss) related to derivative instruments, net of noncontrolling interests	(1,885)	8,946
Net income attributable to partners	70,905	47,755
TEP
Reconciliation to Net Income:
Net income attributable to partners	70,905	47,755
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	59,111	68,330
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	51,585	17,478
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	6,176	3,361
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,761)	(1,352)
TEP | Operating Segments [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	57,767	66,985
TEP | Operating Segments [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	53,030	18,833
TEP | Operating Segments [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	6,075	3,351
TEP | Operating Segments [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,761)	(1,352)
TEP | Intersegment Eliminations [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	1,344	1,345
TEP | Intersegment Eliminations [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,445)	(1,355)
TEP | Intersegment Eliminations [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	101	10
TEP | Intersegment Eliminations [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	0	0
TEP | Segment Reconciling Items [Member]
Reconciliation to Net Income:
Equity in earnings of unconsolidated investments	20,738	709
Gain on disposal of assets	(1,448)	0
Interest expense, net of noncontrolling interest	(14,689)	(7,499)
Depreciation and amortization expense, net of noncontrolling interest	21,867	22,482
Distributions from unconsolidated investments	30,819	634
Non-cash gain (loss) related to derivative instruments, net of noncontrolling interests	2,441	(8,990)
Noncash compensation expense	$ 1,458	$ 1,166

Reporting Segments Reporting Se

Reporting Segments Reporting Segments - Summary of TEP's Segment Capital Expenditures (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Segment Reporting Information [Line Items]
Capital expenditures	$ 26,769	$ 21,207
TEP
Segment Reporting Information [Line Items]
Capital expenditures	26,769	21,207
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	10,436	15,973
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	4,655	2,133
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	11,678	3,101
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 0	$ 0

Reporting Segments - Summary 63

Reporting Segments - Summary of TEP's Segment Information of Assets (Detail) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Assets	$ 3,552,656	$ 3,102,213
TEP
Segment Reporting Information [Line Items]
Assets	3,552,656	3,102,213
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Assets	1,492,333	1,493,866
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Assets	1,633,358	1,176,147
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Assets	418,479	411,999
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Assets	$ 8,486	$ 20,201

Reporting Segments - Additional

Reporting Segments - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2017Segment
Segment Reporting Information [Line Items]
Number of Reportable Segments	3
Rockies Express Pipeline LLC | Tallgrass Development LP
Segment Reporting Information [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	24.99%
Rockies Express Pipeline LLC
Segment Reporting Information [Line Items]
Equity Method Investment, Ownership Percentage	50.00%