Tallgrass Energy Partners 10-Q 9 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 09, 2016
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, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	Q1
Trading Symbol	TEP
Amendment Flag	false
Common Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		72,097,211
General Partner Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		834,391

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 2,885	$ 1,611
Accounts receivable, net	53,330	57,757
Gas imbalances	552	1,227
Inventories	13,739	13,793
Prepayments and other current assets	2,883	2,835
Total Current Assets	73,389	77,223
Property, plant and equipment, net	2,017,138	2,025,018
Goodwill	343,288	343,288
Intangible asset, net	95,795	96,546
Derivative asset at fair value	37,014	0
Deferred financing costs, net	6,102	5,105
Deferred charges and other assets	14,046	14,894
Total Assets	2,586,772	2,562,074
Current Liabilities:
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)	17,794	22,218
Accounts payable to related parties	4,435	7,852
Gas imbalances	935	1,605
Derivative liabilities at fair value	44	0
Accrued taxes	19,450	13,844
Accrued liabilities	6,520	10,019
Deferred revenue	33,823	26,511
Other current liabilities	6,969	6,880
Total Current Liabilities	89,970	88,929
Long-term debt	1,200,000	753,000
Other long-term liabilities and deferred credits	4,904	5,143
Total Long-term Liabilities	$ 1,204,904	$ 758,143
Commitments and Contingencies
Equity:
Common unitholders (67,499,543 and 60,644,232 units issued and outstanding at March 31, 2016 and December 31, 2015, respectively)	$ 1,882,611	$ 1,618,766
General partner (834,391 units issued and outstanding at March 31, 2016 and December 31, 2015)	(624,511)	(348,841)
Total Partners' Equity	1,258,100	1,269,925
Noncontrolling interests	33,798	445,077
Total Equity	1,291,898	1,715,002
Total Liabilities and Equity	$ 2,586,772	$ 2,562,074

CONDENSED CONSOLIDATED BALANC3

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)	$ 17,794,000	$ 22,218,000
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)	67,499,543	60,644,232
Limited Partner Units Outstanding (in units)	67,499,543	60,644,232
Variable Interest Entity, Primary Beneficiary
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)	$ 0	$ 10,554

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenues:
Crude oil transportation services	$ 94,572	$ 50,381
Natural gas transportation services	29,280	32,148
Sales of natural gas, NGLs, and crude oil	13,926	21,869
Processing and other revenues	7,627	10,277
Total Revenues	145,405	114,675
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	13,568	19,593
Cost of transportation services (exclusive of depreciation and amortization shown below)	16,156	10,715
Operations and maintenance	12,477	9,575
Depreciation and amortization	21,692	20,605
General and administrative	13,016	12,689
Taxes, other than income taxes	7,506	11,297
Loss on sale of assets	0	4,483
Total Operating Costs and Expenses	84,415	88,957
Operating Income	60,990	25,718
Other (Expense) Income:
Interest expense, net	(7,499)	(3,440)
Unrealized loss on derivative instrument	(8,946)	0
Other income, net	566	712
Total Other Expense	(15,879)	(2,728)
Net income	45,111	22,990
Net (income) loss attributable to noncontrolling interests	(1,041)	9,329
Net income attributable to partners	44,070	32,319
Net (income) loss attributable to noncontrolling interests
General partner interest in net income	(20,353)	(7,438)
Common and subordinated unitholders' interest in net income	$ 23,717	$ 24,881
Basic net income per common and subordinated unit	$ 0.35	$ 0.47
Diluted net income per common and subordinated unit	$ 0.35	$ 0.46
Basic average number of common and subordinated units outstanding	66,967	52,727
Diluted average number of common and subordinated units outstanding	67,807	53,994

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash Flows from Operating Activities:
Net income	$ 45,111	$ 22,990
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	22,870	21,557
Noncash compensation expense	1,166	1,527
Noncash change in fair value of derivative financial instruments	8,990	(90)
Loss on sale of assets	0	(4,483)
Changes in components of working capital:
Accounts receivable and other	5,800	(5,678)
Gas imbalances	566	143
Inventories	(508)	(2,754)
Accounts payable and accrued liabilities	(2,196)	6,546
Deferred revenue	7,204	106
Other operating, net	(246)	(191)
Net Cash Provided by Operating Activities	(88,757)	(48,639)
Cash Flows from Investing Activities:
Capital expenditures	(17,545)	(13,300)
Payments to Acquire Additional Interest in Subsidiaries	49,118	700,000
Other investing, net	25	(311)
Net Cash Used in Investing Activities	66,638	713,611
Net Cash (Used in) Provided by Financing Activities
Distributions to unitholders	(59,040)	(28,294)
Distributions to noncontrolling interests	1,793	1,416
Contributions from noncontrolling interests	7,152	2,379
Borrowings under revolving credit facility, net	447,000	139,000
Proceeds from public offering, net of offering costs	12,636	551,949
Other financing, net	(918)	1,363
Net Cash (Used in) Provided by Financing Activities	(20,845)	664,981
Net Change in Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents	1,274	9
Cash and Cash Equivalents, beginning of period	1,611	867
Cash and Cash Equivalents, end of period	2,885	876
Supplemental Disclosures:
Property, plant and equipment acquired via the cash management agreement with Tallgrass Development, LP	0	72,407
Pony Express Pipeline
Cash Flows from Investing Activities:
Payments to Acquire Additional Interest in Subsidiaries	49,118
Net Cash (Used in) Provided by Financing Activities
Distributions to noncontrolling interests	$ 425,882	$ 0

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED) - USD ($) $ in Thousands	Total	General Partner	Common unitholdersLimited Partner	Subordinated UnitsLimited Partner	Total Partner Equity Excluding Portion Attributable to Noncontrolling Interest	Noncontrolling Interest	Total Partner Equity Including Portion Attributable to Noncontrolling Interest	Pony Express Pipeline	Pony Express PipelineGeneral Partner	Pony Express PipelineCommon unitholdersLimited Partner	Pony Express PipelineSubordinated UnitsLimited Partner	Pony Express PipelineTotal Partner Equity Excluding Portion Attributable to Noncontrolling Interest	Pony Express PipelineNoncontrolling Interest	Pony Express PipelineTotal Partner Equity Including Portion Attributable to Noncontrolling Interest
Partners' Capital, Including Portion Attributable to Noncontrolling Interest		$ (35,743)	$ 800,333	$ 274,133	$ 1,038,723	$ 756,428	$ 1,795,151
Increase (Decrease) in Partners' Capital [Roll Forward]
Net income	$ 22,990	7,438	19,701	5,180	32,319	(9,329)	22,990
Issuance of units to public, net of offering costs		0	551,949	0	551,949	0	551,949
Noncash compensation expense		0	2,933	0	2,933	0	2,933
Distributions to unitholders		(4,512)	(15,925)	(7,857)	(28,294)	0	(28,294)
Contributions from noncontrolling interests	2,379	0	0	0	0	2,379	2,379
Distributions to noncontrolling interests	1,416	0	0	0	0	2,156	2,156	$ 0
Acquisitions									$ (324,328)	$ 0	$ 0	$ (324,328)	$ (375,672)	$ (700,000)
Conversion of subordinated units		0	(271,456)	271,456	0	0	0
Partners' Capital, Including Portion Attributable to Noncontrolling Interest		(357,145)	1,630,447	0	1,273,302	371,650	1,644,952
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	1,715,002	(348,841)	1,618,766	0	1,269,925	445,077	1,715,002
Net income	45,111	20,353	23,717	0	44,070	1,041	45,111
Issuance of units to public, net of offering costs	12,600	0	12,636	0	12,636	0	12,636
Noncash compensation expense		0	1,869	0	1,869	0	1,869
Distributions to unitholders		(16,056)	(42,984)	0	(59,040)	0	(59,040)
Contributions from noncontrolling interests	7,152	0	0	0	0	7,152	7,152
Distributions to noncontrolling interests	1,793	0	0	0	0	1,793	1,793	$ 425,882
Acquisitions									$ (279,967)	$ 268,607	$ 0	$ (11,360)	$ (417,679)	$ (429,039)
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	$ 1,291,898	$ (624,511)	$ 1,882,611	$ 0	$ 1,258,100	$ 33,798	$ 1,291,898

Description of Business

Description of Business	3 Months Ended
	Mar. 31, 2016
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. 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 crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). We provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through 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 a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). As discussed in Note 14 – Subsequent Events , we recently acquired a membership interest in Rockies Express Pipeline LLC ("REX"), a Delaware limited liability company engaged in the ownership and operation of the Rockies Express Pipeline, a FERC-regulated natural gas pipeline transportation system, traversing an area from the Rocky Mountain Region to the Appalachian Mountain Region. 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. We perform water business services in Colorado and Texas through BNN Water Solutions, LLC ("Water Solutions"). Our operations are strategically 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 and Bakken shale formations. Our reportable business segments are: • Crude Oil Transportation & Logistics—the ownership and operation of a crude oil pipeline system; • 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. The table below summarizes our equity ownership as of March 31, 2016 : 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 34,626,063 — 51.30 % 50.67 % Tallgrass Equity, LLC 20,000,000 — 29.63 % 29.27 % Tallgrass Development, LP 12,873,480 — 19.07 % 18.84 % Tallgrass MLP GP, LLC (1) — 834,391 — 1.22 % Total 67,499,543 834,391 100.00 % 100.00 % (1) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2016
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, 2016 and 2015 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, 2016 and 2015 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, 2016 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2016. 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, 2015 ("2015 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 17, 2016. 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. Prior to January 1, 2016, Pony Express participated in a cash management agreement with Tallgrass Development, LP ("TD"), which currently holds a 2.0% common membership interest in Pony Express, under which cash balances were swept periodically and recorded as loans from Pony Express to TD. Effective January 1, 2016, Pony Express entered into a cash management agreement with TEP. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP and noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the allocation of cash distributions and may not follow the respective ownership percentages held by TEP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Pony Express effective September 1, 2014, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million (prorated to approximately $5.4 million for the quarter ended September 30, 2014) through the quarter ended September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ending December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 are attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests. A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. We have presented separately in our condensed consolidated balance sheets, to the extent material, the assets of our consolidated VIE that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of our consolidated VIE for which creditors do not have recourse to our general credit. Pony Express was considered to be a VIE under the applicable authoritative guidance prior to our acquisition of an additional 31.3% membership interest effective January 1, 2016. Effective January 1, 2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in Pony Express. 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. New Accounting Pronouncements Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers (Topic 606)" In May 2014, the FASB issued 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. The amendments in ASU 2014-09 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 ASU 2014-09. ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period" In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2014-12 did not have a material impact on our financial position and results of operations. ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis" In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis. ASU 2015-02 will change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 will modify the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminate the presumption that a general partner should consolidate a limited partnership, and change certain aspects of the consolidation analysis for reporting entities that are involved with VIEs, particularly for those with fee arrangements and related party relationships. The amendments in ASU 2015-02 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2015-02 did not have a material impact on our financial position and results of operations. ASU No. 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory" In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory. ASU 2015-11 establishes a "lower of cost and net realizable value" model for the measurement of most inventory balances. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The amendments in ASU 2015-11 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 are currently evaluating the impact of ASU 2015-11. ASU No. 2015-16, "Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments" In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. ASU 2015-16 simplifies the accounting for measurement-period adjustments for provisional amounts recognized in a business combination by eliminating the requirement for an acquirer to retrospectively account for measurement-period adjustments. Under the updated guidance, the acquirer must recognize adjustments in the reporting period in which the adjustment amounts are determined and the effect on earnings as a result of the change to the provisional amounts must be calculated as if the accounting had been completed at the acquisition date. The amendments in ASU 2015-16 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2015-16 did not have a material impact on our financial position and results of operations. 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. 2016-08, "Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)" In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). ASU 2016-08 provides further clarification of the guidance in ASU 2014-09 with respect to principal versus agent considerations and are intended to improve the operability and understandability of the implementation guidance provided in ASU 2014-09. The amendments in ASU 2016-08 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 ASU 2016-08. 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 are currently evaluating the impact of ASU 2016-09.

Acquisitions

Acquisitions	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
Acquisitions	Acquisition of Additional 31.3% Membership Interest in Pony Express Effective January 1, 2016, TEP acquired an additional 31.3% membership interest in Pony Express in exchange for cash consideration of $475 million and 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of our common units) issued to TD, for total consideration of approximately $743.6 million . The transaction increased our aggregate membership interest in Pony Express to 98.0% . As part of the transaction, TD granted us an 18 month call option to repurchase the newly issued 6,518,000 common units at a price of $42.50 . On the effective date of the acquisition, the call option was valued at $46.0 million . The acquisition of the additional 31.3% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction have not been recast to reflect the additional 31.3% membership interest. The transaction resulted in a deemed distribution to our general partner as discussed further in Note 9 – Partnership Equity and Distributions . Cash outflows to acquire an additional noncontrolling interest in Pony Express are classified as an investing activity in the accompanying condensed consolidated statements of cash flows to the extent the consideration paid was used to directly fund the construction of the underlying assets by the noncontrolling member. Cash outflows to acquire an additional noncontrolling interest in excess of the cost to construct the underlying assets are classified as financing activities. For the three months ended March 31, 2016 , $49.1 million of the $475 million paid to acquire the additional 31.3% membership interest in Pony Express was classified as an investing activity and $425.9 million was classified as a financing activity. TEP Acquisition of BNN Western, LLC On December 16, 2015, Whiting Oil and Gas Corporation ("Whiting"), BNN Redtail, LLC ("Redtail"), and BNN Western, LLC ("Western"), a newly formed Delaware limited liability company, entered into a definitive Transfer, Purchase and Sale Agreement, pursuant to which Redtail acquired 100% of the outstanding membership interests of Western from Whiting in exchange for total cash consideration of $75 million . Western's assets consist of a fresh water delivery and storage system and produced water gathering and produced water disposal system, which together comprise 62 miles of pipeline along with associated fresh water ponds and disposal wells. As part of the transaction with Whiting, Whiting also executed a five -year fresh water service contract and a nine -year gathering and disposal contract. At December 31, 2015, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. The $75 million purchase price of the assets was allocated entirely to property, plant and equipment. TEP is in the process of obtaining additional information to identify and measure all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. TEP's unaudited pro forma revenue and net income attributable to partners for the three months ended March 31, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015: Three Months Ended March 31, 2015 (in thousands) Revenue $ 115,147 Net income attributable to partners $ 32,483 The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TEP would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project the results of operations or financial position of TEP for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The pro forma revenue and net income includes adjustments to give effect to TEP's consolidated interest in the estimated results of operations of Western for the periods presented.

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	We have no employees. TD, through its wholly-owned subsidiary Tallgrass Operations, LLC ("Tallgrass Operations"), provided and charged us for direct and indirect costs of services provided to us or incurred on our behalf including employee labor costs, information technology services, employee health and retirement benefits, and all other expenses necessary or appropriate to the conduct of our business. We recorded these costs on the accrual basis in the period in which TD incurred them. On May 17, 2013, in connection with the closing of TEP's initial public offering, TEP and its general partner entered into an Omnibus Agreement with TD and certain of its affiliates, including Tallgrass Operations (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. There was no interest income from TD recognized for the three months ended March 31, 2016 . During the three months ended March 31, 2015 we recognized interest income from TD of $0.4 million on the receivable balance under the Pony Express cash management agreement in effect through December 31, 2015. Totals of transactions with affiliated companies are as follows: Three Months Ended March 31, 2016 2015 (in thousands) Cost of transportation services $ 7,256 $ 4,358 Charges to TEP: (1) Property, plant and equipment, net $ 899 $ 1,307 Operation and maintenance $ 6,138 $ 5,423 General and administrative $ 8,966 $ 9,256 (1) Charges to TEP, inclusive of Pony Express, 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, 2016 December 31, 2015 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 31 $ 15 Total receivable from related parties $ 31 $ 15 Accounts payable to related parties: Tallgrass Operations, LLC $ 4,385 $ 7,792 Tallgrass Equity, LLC 41 36 Deeprock Development, LLC — 17 Rockies Express Pipeline LLC 9 7 Total accounts payable to related parties $ 4,435 $ 7,852 Balances of gas imbalances with affiliated shippers are as follows: March 31, 2016 December 31, 2015 (in thousands) Affiliate gas balance receivables $ 7 $ 92 Affiliate gas balance payables $ 102 $ 227

Inventory

Inventory	3 Months Ended
	Mar. 31, 2016
Inventory Disclosure [Abstract]
Inventory	The components of inventory at March 31, 2016 and December 31, 2015 consisted of the following: March 31, 2016 December 31, 2015 (in thousands) Crude oil $ 4,194 $ 2,661 Materials and supplies 6,741 8,581 Natural gas liquids 303 395 Gas in underground storage 2,501 2,156 Total inventory $ 13,739 $ 13,793

Property, Plant and Equipment

Property, Plant and Equipment	3 Months Ended
	Mar. 31, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	A summary of net property, plant and equipment by classification is as follows: March 31, 2016 December 31, 2015 (in thousands) Crude oil pipelines $ 1,177,790 $ 1,172,684 Natural gas pipelines 551,983 550,710 Processing and treating assets 255,663 254,073 Water business assets 82,608 81,098 General and other 80,660 69,181 Construction work in progress 21,255 30,699 Accumulated depreciation and amortization (152,821 ) (133,427 ) Total property, plant and equipment, net $ 2,017,138 $ 2,025,018

Risk Management

Risk Management	3 Months Ended
	Mar. 31, 2016
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 natural gas include, among others (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. As discussed in Note 3 – Acquisitions , 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 to repurchase the newly issued 6,518,000 common units at a price of $42.50 . 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, 2016 December 31, 2015 (in thousands) Call option derivative Noncurrent assets $ 37,014 $ — Energy commodity derivative contracts Current liabilities $ 44 $ — As of March 31, 2016 , the fair value shown for commodity contracts was comprised of derivative volumes for short natural gas fixed-price swaps totaling 0.4 Bcf. As of December 31, 2015 there were no derivative contracts outstanding. 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, 2016 and 2015 : Location of gain (loss) recognized Amount of gain (loss) recognized in income on derivatives Three Months Ended March 31, 2016 2015 (in thousands) Derivatives not designated as hedging contracts: Call option derivative Unrealized loss on derivative instrument $ (8,946 ) $ — Energy commodity derivative contracts Sales of natural gas, NGLs, and crude oil $ (44 ) $ 90 Credit Risk We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our energy commodity 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 is TD. Settlement of the call option derivative, if exercised, will require TEP to make a cash payment to TD in exchange for return of the common units. 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. As of March 31, 2016 , the fair value of our commodity derivative contracts was a liability, resulting in no credit exposure from TEP's counterparties as of that date. As of March 31, 2016 and December 31, 2015 , 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 the sale of natural gas nor did we have any margin deposits with counterparties associated with energy commodity contract positions. 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 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. 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 call option granted by TD is 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 is classified within Level 2 of the fair value hierarchy as the value is based on significant observable inputs. The following table summarizes the fair value measurements of our derivative contracts as of March 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, 2016 Call option derivative $ 37,014 $ — $ 37,014 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of March 31, 2016 Energy commodity derivative contracts $ 44 $ — $ 44 $ —

Long-term Debt

Long-term Debt	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Long-term Debt	Revolving Credit Facility Effective January 4, 2016, in connection with the acquisition of an additional 31.3% membership interest in Pony Express, TEP exercised the committed accordion feature to increase the total capacity of the revolving credit facility from $1.1 billion to $1.5 billion . As discussed in Note 14 – Subsequent Events , effective May 6, 2016 we amended the revolving credit facility to increase the total capacity to $1.75 billion . The following table sets forth the available borrowing capacity under our revolving credit facility as of March 31, 2016 and December 31, 2015 : March 31, 2016 December 31, 2015 (in thousands) Total capacity under the revolving credit facility $ 1,500,000 $ 1,100,000 Less: Outstanding borrowings under the revolving credit facility (1,200,000 ) (753,000 ) Available capacity under the revolving credit facility $ 300,000 $ 347,000 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, 2016 , 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, 2016 , the weighted average interest rate on outstanding borrowings was 2.20% . During the three months ended March 31, 2016 , our weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 2.48% . 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, 2016 and December 31, 2015 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) March 31, 2016 $ — $ 1,200,000 $ — $ 1,200,000 $ 1,200,000 December 31, 2015 $ — $ 753,000 $ — $ 753,000 $ 753,000 The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of March 31, 2016 and December 31, 2015 , the fair value approximates the carrying amount for the borrowings under the revolving credit facility using a discounted cash flow analysis. We are not aware of any factors that would significantly affect the estimated fair value subsequent to March 31, 2016 .

Partnership Equity and Distribu

Partnership Equity and Distributions	3 Months Ended
	Mar. 31, 2016
Equity [Abstract]
Partnership Equity and Distributions	Equity Distribution Agreement On October 31, 2014, we entered into an equity distribution agreement 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 $200 million . On May 13, 2015 the amount was subsequently amended to $100.2 million in order to account for follow-on equity offerings under our S-3 shelf registration statement. Sales of the common units, if any, will be made by means of ordinary brokers' transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by the Partnership and one or more of the managers. We intend to use the net cash proceeds from any sale of the units for general partnership purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt. During the three months ended March 31, 2016 , we issued and sold 337,311 common units with a weighted average sales price of $38.17 per unit under our equity distribution agreement for net cash proceeds of approximately $12.6 million (net of approximately $240,000 in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes. At March 31, 2016 , approximately $83.1 million in aggregate offering price remained available to be issued and sold under the equity distribution agreement. Subsequent to March 31, 2016, we issued and sold an additional 2,180,681 common units with a weighted average sales price of $37.93 per unit under our equity distribution agreement for net cash proceeds of approximately $81.9 million (net of approximately $830,000 in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes. Tallgrass Development Purchase Program On February 17, 2016, TEP and Tallgrass Energy GP, LP ("TEGP") announced that the Board of Directors of Tallgrass Energy Holdings, LLC, the sole member of TEGP's general partner and the general partner of TD, has authorized an equity purchase program under which TD may initially purchase up to an aggregate of $100 million of the outstanding Class A shares of TEGP or the outstanding common units of TEP. TD may purchase Class A shares or Common Units from time to time on the open market or in negotiated purchases. The timing and amounts of any such purchases will be subject to market conditions and other factors, and will be in accordance with applicable securities laws and other legal requirements. The purchase plan does not obligate TD to acquire any specific number of Class A shares or Common Units and may be discontinued at any time. No purchases were made under this program during the three months ended March 31, 2016 . Distributions to Holders of Common Units, Subordinated Units, General Partner Units and Incentive Distribution Rights Our partnership agreement requires us to distribute our available cash, as defined in the partnership agreement, to unitholders of record on the applicable record date within 45 days after the end of each quarter. The following table shows the distributions for the periods indicated: Distributions Limited Partners General Partner Distributions Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) March 31, 2016 May 13, 2016 (1) $ 48,238 $ 19,816 $ 830 $ 68,884 $ 0.7050 December 31, 2015 February 12, 2016 42,984 15,332 724 59,040 0.6400 September 30, 2015 November 13, 2015 36,347 11,567 660 48,574 0.6000 June 30, 2015 August 14, 2015 35,135 10,418 627 46,180 0.5800 March 31, 2015 May 14, 2015 31,322 6,934 530 38,786 0.5200 (1) The distribution announced on April 12, 2016 for the first quarter of 2016 will be paid on May 13, 2016 to unitholders of record at the close of business on April 21, 2016. Other Contributions and Distributions 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. See Note 3 - Acquisitions for additional information regarding the transaction. During the three months ended March 31, 2015 , TEP was deemed to have made a noncash capital distribution of $324.3 million to the general partner, which represents the excess purchase price over the carrying value of the additional 33.3% membership interest in Pony Express acquired effective March 1, 2015.

Net Income per Limited Partner

Net Income per Limited Partner Unit	3 Months Ended
	Mar. 31, 2016
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, including the holders of the subordinated units, 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. The following table illustrates the Partnership's calculation of net income per common and subordinated unit for the three months ended March 31, 2016 and 2015 : Three Months Ended March 31, 2016 2015 (in thousands, except per unit amounts) Net income $ 45,111 $ 22,990 Net (income) loss attributable to noncontrolling interests (1,041 ) 9,329 Net income attributable to partners 44,070 32,319 General partner interest in net income (20,353 ) (7,438 ) Net income available to common and subordinated unitholders $ 23,717 $ 24,881 Basic net income per common and subordinated unit $ 0.35 $ 0.47 Diluted net income per common and subordinated unit $ 0.35 $ 0.46 Basic average number of common and subordinated units outstanding 66,967 52,727 Equity Participation Unit equivalent units 840 1,267 Diluted average number of common and subordinated units outstanding 67,807 53,994

Regulatory Matters

Regulatory Matters	3 Months Ended
	Mar. 31, 2016
Regulatory Matters [Abstract]
Regulatory Matters	There are currently no proceedings challenging the currently effective rates of Pony Express or Trailblazer Pipeline Company LLC ("Trailblazer"). On October 30, 2015, Tallgrass Interstate Gas Transmission, LLC ("TIGT") filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act ("NGA"), discussed in more detail below. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable law, to challenge the rates that we charge at our regulated entities. Further, applicable law governing service by Pony Express allows parties having standing to file complaints in regard to existing tariff rates and provisions. If the complaint is not resolved, the FERC may conduct a hearing and order a crude oil pipeline like the Pony Express System to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. We can provide no assurance that current rates will remain unchallenged. Any successful challenge could have a material, adverse effect on our future earnings and cash flows. TIGT General Rate Case Filing – FERC Docket RP16-137 On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to Section 4 of the NGA. The rate case proposed a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT. In addition, TIGT proposed certain changes to the transportation rate design of its system to replace the current rate zone structure with a single "postage stamp" rate. TIGT also proposed new incremental charges, including (i) a charge for deliveries made to points without certain electronic flow measurement equipment, and (ii) a Cost Recovery Mechanism ("CRM") charge to completely or partially reimburse TIGT for certain costs it incurred to maintain system safety, environmental compliance and reliability. TIGT also proposed to replace its fixed fuel and lost and unaccounted for ("FL&U") charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period's under/over collection and the forecasted FL&U expense for the upcoming period. TIGT also proposed to implement a power cost tracker to recover the actual power costs incurred by TIGT to power its compressors. Finally, TIGT proposed certain revisions to its FERC Gas Tariff addressing a number of other rate and non-rate matters. Under the NGA and the FERC's regulations, TIGT's shippers and other interested parties, including the FERC's Trial Staff, have a right to challenge any aspect of TIGT's rate case filing. Accordingly, numerous TIGT customers have protested aspects of TIGT's NGA Section 4 rate filing. On November 30, 2015, the FERC issued an order accepting and suspending the proposed rates and a majority of the proposed tariff records to be effective upon motion May 1, 2016, subject to refund, certain modifications to TIGT's proposed CRM charge, and the outcome of an evidentiary hearing before a FERC Administrative Law Judge (the "Suspension Order"). In the Suspension Order, the FERC also accepted two tariff records related to force majeure events and reservation charge crediting to be effective December 1, 2015, subject to certain modifications. On December 21, 2015, TIGT made a compliance filing with the FERC to modify TIGT's proposed CRM charge and update the tariff records related to force majeure events and reservation charge crediting as directed by the FERC in the Suspension Order. No comments or protests were filed in response to the compliance filing and FERC accepted the compliance filing on February 1, 2016. The FERC Administrative Law Judge assigned to the proceeding has issued an order establishing the procedural schedule and TIGT, the FERC's Trial Staff, and other participants that successfully intervened are actively participating in the litigated proceeding to address those rate and tariff matters set for hearing by the FERC in its Suspension Order. On March 22, 2016, a Settlement Judge was appointed in the case to assist the participants explore the possibility of settlement. On March 31, 2016, the FERC issued an order denying a request for rehearing with respect to its challenge of TIGT's proposed CRM. The FERC granted in part and denied in part a motion for technical conference, and denied a rehearing request made in the alternative on this issue, and retained for resolution through hearing the pro forma tariff records related to TIGT's proposed charge at delivery points lacking electronic flow measurement and removed from hearing the other issues related to the pro forma tariff records. Whether such issues will be resolved through technical conference is pending. The FERC also directed TIGT to provide additional information related to certain pro forma tariff records, which TIGT filed on April 14, 2016. TIGT has reached an agreement in principle with customers representing a majority of firm fee revenue on the TIGT System for the year ended December 31, 2015 to settle all rate related issues set for hearing in its existing FERC rate case, including the issues of a cost recovery mechanism and a non-Electronic Flow Measurement charge. The settlement remains subject to the final approval of the FERC. Trailblazer 2016 Annual Fuel Tracker Filing – FERC Docket RP16-814-000 On April 1, 2016, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2016 in Docket No. RP16-814-000. The FERC accepted this filing on April 18, 2016.

Legal and Environmental Matters

Legal and Environmental Matters	3 Months Ended
	Mar. 31, 2016
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, had no reserve for legal claims as of March 31, 2016 or December 31, 2015 . 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 $4.6 million and $4.8 million at March 31, 2016 and December 31, 2015 , 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 In 2014 and 2015, Trailblazer conducted smart tool surveys and preliminary analysis on segments of its natural gas pipeline to evaluate the growth rate of corrosion downstream of compressor stations. Trailblazer currently believes that approximately 25 - 35 miles of pipe will likely need to be repaired or replaced in order for the pipeline to operate at its maximum allowable operating pressure of 1,000 pounds per square inch. Such repair or replacement will likely occur over a period of years, depending upon final assessment of corrosion growth rates and the remediation and repair plan implemented by Trailblazer. Trailblazer is currently operating at less than its current maximum allowable operating pressure, public notice of which was first provided in June 2014. 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 TEP. During 2015, Trailblazer completed 32 excavation digs at an aggregate cost of approximately $1.3 million based on preliminary analysis of the smart tool surveys performed in 2014. Segments of the Trailblazer Pipeline that require full replacement are currently expected to cost in the range of approximately $2.2 million to $2.7 million per mile. Repair costs on sections of the pipeline that do not require full replacement are expected to be less on a per mile basis. Trailblazer is continuing to develop a remediation and repair plan, which involves, among other things, finalizing cost recovery options, establishing project scope and timing and setting an overall project budget. In 2016, Trailblazer intends to continue assessment and remediation activities, including the replacement of approximately 8 miles of pipe at an estimated cost of $21.5 million . Trailblazer is currently exploring all possible cost recovery options. It may not ultimately be able to recover any or all of such out of pocket costs unless and until Trailblazer recovers them through a general rate increase or other FERC-approved recovery mechanism, or through negotiated rate agreements with its customers. In connection with TEP's acquisition of the Trailblazer Pipeline, TD agreed to contractually indemnify TEP for any out of pocket costs incurred between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions are necessitated by external corrosion caused by the pipeline's disbonded Hi-Melt CTE coating. The contractual indemnity provided to TEP by TD is currently capped at $20 million and is subject to an annual $1.5 million deductible.

Reporting Segments

Reporting Segments	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Reporting Segments	Our operations are located in the United States. We are organized into three reporting 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 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. 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 integrated natural gas storage facilities that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. 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, 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, 2016 Three Months Ended March 31, 2015 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 94,572 $ — $ 94,572 $ 50,381 $ — $ 50,381 Natural Gas Transportation & Logistics 30,987 (1,355 ) 29,632 33,610 (1,346 ) 32,264 Processing & Logistics 21,201 — 21,201 32,030 — 32,030 Corporate and Other — — — — — — Total Revenue $ 146,760 $ (1,355 ) $ 145,405 $ 116,021 $ (1,346 ) $ 114,675 Three Months Ended March 31, 2016 Three Months Ended March 31, 2015 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 64,541 $ 1,345 $ 65,886 $ 25,506 $ 1,346 $ 26,852 Natural Gas Transportation & Logistics 17,152 (1,355 ) 15,797 19,246 (1,346 ) 17,900 Processing & Logistics 3,351 10 3,361 8,718 — 8,718 Corporate and Other (1,352 ) — (1,352 ) (635 ) — (635 ) Reconciliation to Net Income: Add: Non-cash loss allocated to noncontrolling interest — 9,377 Less: Interest expense, net of noncontrolling interest (7,499 ) (3,440 ) Depreciation and amortization expense, net of noncontrolling interest (21,967 ) (20,533 ) Non-cash (loss) gain related to derivative instruments (8,990 ) 90 Non-cash compensation expense (1,166 ) (1,527 ) Non-cash loss from asset sales — (4,483 ) Net income attributable to partners $ 44,070 $ 32,319 Three Months Ended March 31, Capital Expenditures: 2016 2015 (in thousands) Crude Oil Transportation & Logistics $ 12,311 $ 6,480 Natural Gas Transportation & Logistics 2,133 3,865 Processing & Logistics 3,101 2,955 Corporate and Other — — Total capital expenditures $ 17,545 $ 13,300 Assets: March 31, 2016 December 31, 2015 (in thousands) Crude Oil Transportation & Logistics $ 1,433,153 $ 1,439,418 Natural Gas Transportation & Logistics 698,745 706,576 Processing & Logistics 411,509 409,795 Corporate and Other 43,365 6,285 Total assets $ 2,586,772 $ 2,562,074

Subsequent Events Subsequent Ev

Subsequent Events Subsequent Events	3 Months Ended
	Mar. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Acquisition of a Membership Interest in Rockies Express Pipeline LLC On March 29, 2016, TD's indirect wholly owned subsidiary Rockies Express Holdings, LLC ("REX Holdings") signed a purchase agreement (the "Purchase Agreement") with a unit of Sempra U.S. Gas and Power ("Sempra") to acquire Sempra's 25% membership interest in Rockies Express Pipeline LLC ("REX") for cash consideration of $440 million , subject to adjustment under the Purchase Agreement. A subsidiary of Phillips 66, which owns a 25% membership interest in REX, has waived its right to purchase its proportionate share of Sempra's 25% membership interest being sold to REX Holdings (the "Right of First Refusal") in exchange for Sempra and REX Holdings agreeing to certain modifications to the REX Limited Liability Company Agreement. On April 28, 2016, we announced that TD offered us the right to assume the rights and obligations of REX Holdings under the Purchase Agreement. On May 6, 2016, TEP REX Holdings, LLC ("TEP REX"), an indirect wholly-owned subsidiary of the Partnership, and REX Holdings entered into an Assignment and Assumption Agreement pursuant to which REX Holdings assigned to TEP REX all of its rights under the Purchase Agreement and, in exchange, TEP REX assumed all of the rights and obligations of REX Holdings under the Purchase Agreement. Subsequently on May 6, 2016, TEP REX closed the purchase of a 25% membership interest in REX from Sempra pursuant to the Purchase Agreement for cash consideration of approximately $436.0 million , after making the adjustments to the purchase price required by the Purchase Agreement. Revolving Credit Facility Increase In connection with our acquisition of an interest in REX, we have amended our revolving credit facility to, among other things, increase the lender commitments from $1.5 billion to $1.75 billion effective May 6, 2016. As of May 6, 2016, TEP had approximately $1.4 billion of outstanding borrowings under its revolving credit facility. Unregistered Sale of Equity Securities On April 28, 2016, we issued an aggregate of 2,416,987 common units representing limited partnership interests in the Partnership for net cash proceeds of $90.0 million in a private placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C.

Summary of Significant Accoun21

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These condensed consolidated financial statements and related notes for the three months ended March 31, 2016 and 2015 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, 2016 and 2015 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, 2016 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2016. 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, 2015 ("2015 Form 10-K") filed with the United States Securities and Exchange Commission (the "SEC") on February 17, 2016.
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. Prior to January 1, 2016, Pony Express participated in a cash management agreement with Tallgrass Development, LP ("TD"), which currently holds a 2.0% common membership interest in Pony Express, under which cash balances were swept periodically and recorded as loans from Pony Express to TD. Effective January 1, 2016, Pony Express entered into a cash management agreement with TEP. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP and noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the allocation of cash distributions and may not follow the respective ownership percentages held by TEP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Pony Express effective September 1, 2014, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million (prorated to approximately $5.4 million for the quarter ended September 30, 2014) through the quarter ended September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ending December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 are attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests. A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. We have presented separately in our condensed consolidated balance sheets, to the extent material, the assets of our consolidated VIE that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of our consolidated VIE for which creditors do not have recourse to our general credit. Pony Express was considered to be a VIE under the applicable authoritative guidance prior to our acquisition of an additional 31.3% membership interest effective January 1, 2016. Effective January 1, 2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in Pony Express.
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 Issued But Not Yet Effective	New Accounting Pronouncements Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers (Topic 606)" In May 2014, the FASB issued 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. The amendments in ASU 2014-09 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 ASU 2014-09. ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period" In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2014-12 did not have a material impact on our financial position and results of operations. ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis" In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis. ASU 2015-02 will change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 will modify the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminate the presumption that a general partner should consolidate a limited partnership, and change certain aspects of the consolidation analysis for reporting entities that are involved with VIEs, particularly for those with fee arrangements and related party relationships. The amendments in ASU 2015-02 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2015-02 did not have a material impact on our financial position and results of operations. ASU No. 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory" In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory. ASU 2015-11 establishes a "lower of cost and net realizable value" model for the measurement of most inventory balances. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The amendments in ASU 2015-11 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 are currently evaluating the impact of ASU 2015-11. ASU No. 2015-16, "Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments" In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. ASU 2015-16 simplifies the accounting for measurement-period adjustments for provisional amounts recognized in a business combination by eliminating the requirement for an acquirer to retrospectively account for measurement-period adjustments. Under the updated guidance, the acquirer must recognize adjustments in the reporting period in which the adjustment amounts are determined and the effect on earnings as a result of the change to the provisional amounts must be calculated as if the accounting had been completed at the acquisition date. The amendments in ASU 2015-16 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. The adoption of ASU 2015-16 did not have a material impact on our financial position and results of operations. 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. 2016-08, "Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)" In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). ASU 2016-08 provides further clarification of the guidance in ASU 2014-09 with respect to principal versus agent considerations and are intended to improve the operability and understandability of the implementation guidance provided in ASU 2014-09. The amendments in ASU 2016-08 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 ASU 2016-08. 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 are currently evaluating the impact of ASU 2016-09.

Description of Business Schedul

Description of Business Schedule of Other Ownership Interests (Tables)	3 Months Ended
	Mar. 31, 2016
Schedule of Other Ownership Interests [Abstract]
Schedule of Other Ownership Interests	The table below summarizes our equity ownership as of March 31, 2016 : 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 34,626,063 — 51.30 % 50.67 % Tallgrass Equity, LLC 20,000,000 — 29.63 % 29.27 % Tallgrass Development, LP 12,873,480 — 19.07 % 18.84 % Tallgrass MLP GP, LLC (1) — 834,391 — 1.22 % Total 67,499,543 834,391 100.00 % 100.00 % (1) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights.

Acquisitions Business Acquisiti

Acquisitions Business Acquisition Pro Forma Information (Tables)	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
Business Acquisition, Pro Forma Information	TEP's unaudited pro forma revenue and net income attributable to partners for the three months ended March 31, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015: Three Months Ended March 31, 2015 (in thousands) Revenue $ 115,147 Net income attributable to partners $ 32,483

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2016
Related Party Transactions [Abstract]
Schedule of Transactions with Affiliated Companies	Totals of transactions with affiliated companies are as follows: Three Months Ended March 31, 2016 2015 (in thousands) Cost of transportation services $ 7,256 $ 4,358 Charges to TEP: (1) Property, plant and equipment, net $ 899 $ 1,307 Operation and maintenance $ 6,138 $ 5,423 General and administrative $ 8,966 $ 9,256 (1) Charges to TEP, inclusive of Pony Express, 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, 2016 December 31, 2015 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 31 $ 15 Total receivable from related parties $ 31 $ 15 Accounts payable to related parties: Tallgrass Operations, LLC $ 4,385 $ 7,792 Tallgrass Equity, LLC 41 36 Deeprock Development, LLC — 17 Rockies Express Pipeline LLC 9 7 Total accounts payable to related parties $ 4,435 $ 7,852
Schedule of Balances of Gas Imbalance with Affiliated Shippers	Balances of gas imbalances with affiliated shippers are as follows: March 31, 2016 December 31, 2015 (in thousands) Affiliate gas balance receivables $ 7 $ 92 Affiliate gas balance payables $ 102 $ 227

Inventory (Tables)

Inventory (Tables)	3 Months Ended
	Mar. 31, 2016
Inventory Disclosure [Abstract]
Schedule of Components of Inventory	The components of inventory at March 31, 2016 and December 31, 2015 consisted of the following: March 31, 2016 December 31, 2015 (in thousands) Crude oil $ 4,194 $ 2,661 Materials and supplies 6,741 8,581 Natural gas liquids 303 395 Gas in underground storage 2,501 2,156 Total inventory $ 13,739 $ 13,793

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	3 Months Ended
	Mar. 31, 2016
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, 2016 December 31, 2015 (in thousands) Crude oil pipelines $ 1,177,790 $ 1,172,684 Natural gas pipelines 551,983 550,710 Processing and treating assets 255,663 254,073 Water business assets 82,608 81,098 General and other 80,660 69,181 Construction work in progress 21,255 30,699 Accumulated depreciation and amortization (152,821 ) (133,427 ) Total property, plant and equipment, net $ 2,017,138 $ 2,025,018

Risk Management (Tables)

Risk Management (Tables)	3 Months Ended
	Mar. 31, 2016
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, 2016 December 31, 2015 (in thousands) Call option derivative Noncurrent assets $ 37,014 $ — Energy commodity derivative contracts Current liabilities $ 44 $ —
Derivative Contracts Included in Consolidated Statements of Income	The following table summarizes the impact of derivative contracts for the three months ended March 31, 2016 and 2015 : Location of gain (loss) recognized Amount of gain (loss) recognized in income on derivatives Three Months Ended March 31, 2016 2015 (in thousands) Derivatives not designated as hedging contracts: Call option derivative Unrealized loss on derivative instrument $ (8,946 ) $ — Energy commodity derivative contracts Sales of natural gas, NGLs, and crude oil $ (44 ) $ 90
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, 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, 2016 Call option derivative $ 37,014 $ — $ 37,014 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of March 31, 2016 Energy commodity derivative contracts $ 44 $ — $ 44 $ —

Long-term Debt (Tables)

Long-term Debt (Tables)	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Schedule of Line of Credit Facilities	The following table sets forth the available borrowing capacity under our revolving credit facility as of March 31, 2016 and December 31, 2015 : March 31, 2016 December 31, 2015 (in thousands) Total capacity under the revolving credit facility $ 1,500,000 $ 1,100,000 Less: Outstanding borrowings under the revolving credit facility (1,200,000 ) (753,000 ) Available capacity under the revolving credit facility $ 300,000 $ 347,000
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, 2016 and December 31, 2015 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) March 31, 2016 $ — $ 1,200,000 $ — $ 1,200,000 $ 1,200,000 December 31, 2015 $ — $ 753,000 $ — $ 753,000 $ 753,000

Partnership Equity and Distri29

Partnership Equity and Distributions (Tables)	3 Months Ended
	Mar. 31, 2016
Equity [Abstract]
Summary of Distributions	The following table shows the distributions for the periods indicated: Distributions Limited Partners General Partner Distributions Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) March 31, 2016 May 13, 2016 (1) $ 48,238 $ 19,816 $ 830 $ 68,884 $ 0.7050 December 31, 2015 February 12, 2016 42,984 15,332 724 59,040 0.6400 September 30, 2015 November 13, 2015 36,347 11,567 660 48,574 0.6000 June 30, 2015 August 14, 2015 35,135 10,418 627 46,180 0.5800 March 31, 2015 May 14, 2015 31,322 6,934 530 38,786 0.5200 (1) The distribution announced on April 12, 2016 for the first quarter of 2016 will be paid on May 13, 2016 to unitholders of record at the close of business on April 21, 2016.

Net Income per Limited Partne30

Net Income per Limited Partner Unit (Tables)	3 Months Ended
	Mar. 31, 2016
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 and subordinated unit for the three months ended March 31, 2016 and 2015 : Three Months Ended March 31, 2016 2015 (in thousands, except per unit amounts) Net income $ 45,111 $ 22,990 Net (income) loss attributable to noncontrolling interests (1,041 ) 9,329 Net income attributable to partners 44,070 32,319 General partner interest in net income (20,353 ) (7,438 ) Net income available to common and subordinated unitholders $ 23,717 $ 24,881 Basic net income per common and subordinated unit $ 0.35 $ 0.47 Diluted net income per common and subordinated unit $ 0.35 $ 0.46 Basic average number of common and subordinated units outstanding 66,967 52,727 Equity Participation Unit equivalent units 840 1,267 Diluted average number of common and subordinated units outstanding 67,807 53,994

Reporting Segments (Tables)

Reporting Segments (Tables)	3 Months Ended
	Mar. 31, 2016
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, 2016 Three Months Ended March 31, 2015 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 94,572 $ — $ 94,572 $ 50,381 $ — $ 50,381 Natural Gas Transportation & Logistics 30,987 (1,355 ) 29,632 33,610 (1,346 ) 32,264 Processing & Logistics 21,201 — 21,201 32,030 — 32,030 Corporate and Other — — — — — — Total Revenue $ 146,760 $ (1,355 ) $ 145,405 $ 116,021 $ (1,346 ) $ 114,675
Summary of TEP's Segment Information of Earnings	Three Months Ended March 31, 2016 Three Months Ended March 31, 2015 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 64,541 $ 1,345 $ 65,886 $ 25,506 $ 1,346 $ 26,852 Natural Gas Transportation & Logistics 17,152 (1,355 ) 15,797 19,246 (1,346 ) 17,900 Processing & Logistics 3,351 10 3,361 8,718 — 8,718 Corporate and Other (1,352 ) — (1,352 ) (635 ) — (635 ) Reconciliation to Net Income: Add: Non-cash loss allocated to noncontrolling interest — 9,377 Less: Interest expense, net of noncontrolling interest (7,499 ) (3,440 ) Depreciation and amortization expense, net of noncontrolling interest (21,967 ) (20,533 ) Non-cash (loss) gain related to derivative instruments (8,990 ) 90 Non-cash compensation expense (1,166 ) (1,527 ) Non-cash loss from asset sales — (4,483 ) Net income attributable to partners $ 44,070 $ 32,319
Summary of TEP's Segment Capital Expenditures	Three Months Ended March 31, Capital Expenditures: 2016 2015 (in thousands) Crude Oil Transportation & Logistics $ 12,311 $ 6,480 Natural Gas Transportation & Logistics 2,133 3,865 Processing & Logistics 3,101 2,955 Corporate and Other — — Total capital expenditures $ 17,545 $ 13,300
Summary of TEP's Segment Information of Assets	Assets: March 31, 2016 December 31, 2015 (in thousands) Crude Oil Transportation & Logistics $ 1,433,153 $ 1,439,418 Natural Gas Transportation & Logistics 698,745 706,576 Processing & Logistics 411,509 409,795 Corporate and Other 43,365 6,285 Total assets $ 2,586,772 $ 2,562,074

Description of Business - Addit

Description of Business - Additional Information (Detail) - shares	Mar. 31, 2016	Dec. 31, 2015
Organization [Line Items]
Limited Partner Common Units	67,499,543	60,644,232
General Partner Units	834,391	834,391
Percentage of Outstanding Limited Partner Common Units	100.00%
Percentage of Outstanding Common and General Partner Units	100.00%
Ownership Interests Held By Public
Organization [Line Items]
Limited Partner Common Units	34,626,063
General Partner Units	0
Percentage of Outstanding Limited Partner Common Units	51.30%
Percentage of Outstanding Common and General Partner Units	50.67%
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	29.63%
Percentage of Outstanding Common and General Partner Units	29.27%
Ownership Interests Held By Tallgrass Development , LP
Organization [Line Items]
Limited Partner Common Units	12,873,480
General Partner Units	0
Percentage of Outstanding Limited Partner Common Units	19.07%
Percentage of Outstanding Common and General Partner Units	18.84%
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	1.22%

Summary of Significant Accoun33

Summary of Significant Accounting Policies Accounting Policies (Details) - USD ($) $ in Thousands	Sep. 01, 2014	Sep. 30, 2014	Mar. 31, 2015	Dec. 31, 2015	Sep. 30, 2015	Mar. 31, 2016	Jan. 01, 2016	Mar. 01, 2015
Pony Express Pipeline
Business Acquisition [Line Items]
Equity interest held by noncontrolling interests						2.00%
Variable Interest Entity, Ownership Percentage	33.30%
Pony Express Pipeline
Business Acquisition [Line Items]
Minimum Quarterly Distribution Required by Partnership Agreement				$ 36,650	$ 0
Prorated Minimum Quarterly Distribution Required by Partnership Agreement		$ 5,400	$ 23,500
Business Acquisition, Percentage of Voting Interests Acquired							31.30%	33.30%

Acquisitions (Details)

Acquisitions (Details) $ / shares in Units, $ in Thousands	Jan. 01, 2016USD ($)$ / sharesshares	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)	Dec. 16, 2015mi	Mar. 01, 2015
Business Acquisition [Line Items]
Derivative asset at fair value	$ 46,000	$ 37,014		$ 0
Payments to Acquire Additional Interest in Subsidiaries		49,118	$ 700,000
Distributions to noncontrolling interests		(1,793)	(1,416)
Business Acquisition, Pro Forma Revenue			115,147
Business Acquisition, Pro Forma Net Income (Loss)			32,483
Pony Express Pipeline
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	31.30%					33.30%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	6,518,000
Common Unit, Issuance Value	$ 269,000
Business Combination, Consideration Transferred, Including Equity Interest in Acquiree Held Prior to Combination	$ 744,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	98.00%
Payments to Acquire Additional Interest in Subsidiaries		49,118
Distributions to noncontrolling interests	$ (475,000)	$ (425,882)	$ 0
BNN Western, LLC [Member]
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					100.00%
Partners' Capital Account, Acquisitions				$ (75,000)
Miles of water pipeline | mi					62
Fresh Water Service Contract [Member] | BNN Western, LLC [Member]
Business Acquisition [Line Items]
Lessor Leasing Arrangements, Operating Leases, Term of Contract				5 years
Gathering and Disposal Contract [Member] | BNN Western, LLC [Member]
Business Acquisition [Line Items]
Lessor Leasing Arrangements, Operating Leases, Term of Contract				9 years
Equity Option | Pony Express Pipeline
Business Acquisition [Line Items]
Derivative, Term of Contract	18 months
Option Indexed to Issuer's Equity, Strike Price | $ / shares	$ 42.50

Related Party Transactions - Sc

Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Related Party Transaction [Line Items]
Related Party Transactions, Cost of Sales and Transportation Services	$ 7,256	$ 4,358
Operation and maintenance [Member]
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	6,138	5,423
General and Administrative Expense [Member]
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	8,966	9,256
Property, Plant and Equipment [Member]
Related Party Transaction [Line Items]
Related Party Transaction Costs Capitalized From Transactions With Related Party	$ 899	$ 1,307

Related Party Transactions - 36

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, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	$ 31	$ 15
Accounts Payable, Related Parties, Current	4,435	7,852
Rockies Express Pipeline LLC
Related Party Transaction [Line Items]
Accounts Receivable, Related Parties, Current	31	15
Accounts Payable, Related Parties, Current	9	7
Tallgrass Operations, LLC
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	4,385	7,792
Tallgrass Equity, LLC
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	41	36
Deeprock Development, LLC
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	$ 0	$ 17

Related Party Transactions - 37

Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Affiliate gas balance receivables	$ 7	$ 92
Affiliate gas balance payables	$ 102	$ 227

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)
Related Party Transactions [Abstract]
Interest Income, Related Party	$ 0.4

Inventory Inventory (Details)

Inventory Inventory (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Crude oil	$ 4,194	$ 2,661
Materials and supplies	6,741	8,581
Natural gas liquids	303	395
Gas in underground storage	2,501	2,156
Inventory, Net	$ 13,739	$ 13,793

Property Plant and Equipment -

Property Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Accumulated depreciation and amortization	$ (152,821)	$ (133,427)
Property, plant and equipment	2,017,138	2,025,018
Crude oil pipelines
Property, Plant and Equipment [Line Items]
Property , plant and equipment	1,177,790	1,172,684
Natural gas pipelines
Property, Plant and Equipment [Line Items]
Property , plant and equipment	551,983	550,710
Processing and treating assets
Property, Plant and Equipment [Line Items]
Property , plant and equipment	255,663	254,073
Water business assets
Property, Plant and Equipment [Line Items]
Property , plant and equipment	82,608	81,098
General and other
Property, Plant and Equipment [Line Items]
Property , plant and equipment	80,660	69,181
Construction work in progress
Property, Plant and Equipment [Line Items]
Property , plant and equipment	$ 21,255	$ 30,699

Risk Management - Schedule of F

Risk Management - Schedule of Fair Value of Derivative Contracts (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 37,014
Equity Option | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	37,014	$ 0
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	44
Energy commodity derivative contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	$ 44	$ 0

Risk Management - Derivative Co

Risk Management - Derivative Contracts Included in Consolidated Statement of Income (Detail) - Derivatives not designated as hedging contracts [Member] - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Equity Option
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ (8,946)	$ 0
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ (44)	$ 90

Risk Management - Schedule of E

Risk Management - Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification (Detail) $ in Thousands	Mar. 31, 2016USD ($)
Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 37,014
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	37,014
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 liabilities at fair value	44
Energy commodity derivative contracts | Quoted prices in active markets for identical assets (Level 1)
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	0
Energy commodity derivative contracts | Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	44
Energy commodity derivative contracts | Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	$ 0

Risk Management Risk Management

Risk Management Risk Management - Additional Information (Details)	Jan. 01, 2016$ / sharesshares	Mar. 31, 2016Bcf	Mar. 01, 2015
Commodity [Member] | Current Portion of Derivative Notional Amount [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf		0.4
Pony Express Pipeline
Derivative [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	31.30%		33.30%
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	6,518,000
Pony Express Pipeline | Equity Option
Derivative [Line Items]
Derivative, Term of Contract	18 months
Option Indexed to Issuer's Equity, Strike Price | $ / shares	$ 42.50

Long-term Debt Capacity under R

Long-term Debt Capacity under Revolving Credit Facility (Details) - USD ($)	Mar. 31, 2016	Jan. 04, 2016	Dec. 31, 2015	Nov. 24, 2015
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility	$ (1,200,000,000)		$ (753,000,000)
Tallgrass Energy Partners | Line of Credit
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility	(1,200,000,000)		(753,000,000)
Available capacity under the revolving credit facility	300,000,000		347,000,000
Tallgrass Energy Partners | Barclays Bank
Line of Credit Facility [Line Items]
Total capacity under the revolving credit facility	$ 1,500,000,000	$ 1,500,000,000	$ 1,100,000,000	$ 1,100,000,000

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, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Fair Value	$ 1,200,000	$ 753,000
Long-term debt	1,200,000	753,000
Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Fair Value	0	0
Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Fair Value	1,200,000	753,000
Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Fair Value	$ 0	$ 0

Long-term Debt - Additional Inf

Long-term Debt - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2016USD ($)	May. 06, 2016USD ($)	Jan. 04, 2016USD ($)	Jan. 01, 2016	Dec. 31, 2015USD ($)	Nov. 24, 2015USD ($)	Mar. 01, 2015
Debt Instrument [Line Items]
Weighted average interest rate on outstanding borrowings	2.20%
Debt Instrument, Interest Rate, Effective Percentage	2.48%
Maximum
Debt Instrument [Line Items]
Consolidated leverage ratio	4.75
Contingent Consolidated Leverage Ratio	5.25
Credit facility commitment fee	0.50%
Minimum
Debt Instrument [Line Items]
Consolidated interest coverage ratio	2.50
Credit facility commitment fee	0.30%
Pony Express Pipeline
Debt Instrument [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				31.30%			33.30%
Tallgrass Energy Partners | Barclays Bank
Debt Instrument [Line Items]
Total capacity under the revolving credit facility	$ 1,500,000,000		$ 1,500,000,000		$ 1,100,000,000	$ 1,100,000,000
Subsequent Event | Tallgrass Energy Partners | Barclays Bank
Debt Instrument [Line Items]
Total capacity under the revolving credit facility		$ 1,750,000,000

Partnership Equity and Distri48

Partnership Equity and Distributions - Summary of Distributions (Detail) - Tallgrass Energy Partners - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015
Distribution Made to Limited Partner [Line Items]
Distributions Limited Partners Common	$ 48,238	$ 42,984	$ 36,347	$ 35,135	$ 31,322
Distributions General Partner Incentive	19,816	15,332	11,567	10,418	6,934
General Partner Distributions	830	724	660	627	530
Distributions Total	$ 68,884	$ 59,040	$ 48,574	$ 46,180	$ 38,786
Distributions per Limited Partner unit	$ 0.7050	$ 0.6400	$ 0.6000	$ 0.5800	$ 0.5200

Partnership Equity and Distri49

Partnership Equity and Distributions - Additional Information (Detail) - USD ($)	3 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Mar. 31, 2015	Feb. 17, 2016	Jan. 01, 2016	May. 13, 2015	Mar. 01, 2015	Oct. 31, 2014
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Authorized Amount						$ 100,000,000		$ 200,000,000
Partners' Capital Account, Units, Sold in Public Offering		337,311
Shares Issued, Price Per Share		$ 38.17
Issuance of units to public, net of offering costs		$ 12,600,000
Limited Partners' Offering Costs		240,000
Partners' Capital Account, Remaining Authorized Amount		83,100,000
General Partner Equity Purchase Plan, Authorized Amount				$ 100,000,000
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					31.30%		33.30%
General Partner
Limited Partners' Capital Account [Line Items]
Issuance of units to public, net of offering costs		0	$ 0
General Partner | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions		$ (279,967,000)	$ (324,328,000)
Subsequent Event
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Units, Sold in Public Offering	2,180,681
Shares Issued, Price Per Share	$ 37.93
Issuance of units to public, net of offering costs	$ 81,900,000
Limited Partners' Offering Costs	$ 830,000

Net Income per Limited Partne50

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, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
Net income	$ 45,111	$ 22,990
Net (income) loss attributable to noncontrolling interests	1,041	(9,329)
Net income attributable to partners	44,070	32,319
General partner interest in net income	(20,353)	(7,438)
Net income available to common and subordinated unitholders	$ 23,717	$ 24,881
Basic net income per common and subordinated unit	$ 0.35	$ 0.47
Diluted net income per common and subordinated unit	$ 0.35	$ 0.46
Basic average number of common and subordinated units outstanding	66,967	52,727
Equity Participation Unit equivalent units	840	1,267
Diluted average number of common and subordinated units outstanding	67,807	53,994

Legal and Environmental Matte51

Legal and Environmental Matters - Additional Information (Detail) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)ft-lbmi	Dec. 31, 2016USD ($)mi	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Estimated environmental liability	$ 4.6		$ 4.8
Trailblazer
Loss Contingencies [Line Items]
Maximum allowable operating pressure | ft-lb	144,000
Excavation digs			32
Aggregate cost of excavation digs			$ 1.3
Tallgrass Development LP
Loss Contingencies [Line Items]
Contractual indemnity provided to TEP by TD	$ 20
Annual deductible	$ 1.5
Minimum | Trailblazer
Loss Contingencies [Line Items]
Miles of natural gas pipeline needing repair or replacement | mi	25
Pipeline replacement costs	$ 2.2
Maximum | Trailblazer
Loss Contingencies [Line Items]
Miles of natural gas pipeline needing repair or replacement | mi	35
Pipeline replacement costs	$ 2.7
Subsequent Event | Trailblazer
Loss Contingencies [Line Items]
Miles of natural gas pipeline needing repair or replacement | mi		8
Estimated pipe replacement cost		$ 21.5

Reporting Segments - Summary of

Reporting Segments - Summary of TEP's Segment Information of Revenue (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Segment Reporting Information [Line Items]
Revenues	$ 145,405	$ 114,675
TEP
Segment Reporting Information [Line Items]
Revenues	145,405	114,675
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	94,572	50,381
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	29,632	32,264
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Revenues	21,201	32,030
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Revenues	0	0
TEP | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	146,760	116,021
TEP | Operating Segments [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	94,572	50,381
TEP | Operating Segments [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	30,987	33,610
TEP | Operating Segments [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Revenues	21,201	32,030
TEP | Operating Segments [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Revenues	0	0
TEP | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(1,355)	(1,346)
TEP | Intersegment Eliminations [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	0	0
TEP | Intersegment Eliminations [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	(1,355)	(1,346)
TEP | Intersegment Eliminations [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Revenues	0	0
TEP | Intersegment Eliminations [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Revenues	$ 0	$ 0

Reporting Segments - Summary 53

Reporting Segments - Summary of TEP's Segment Information of Earnings (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Reconciliation to Net Income:
Interest expense, net of noncontrolling interest	$ 7,499	$ 3,440
Depreciation and amortization expense, net of noncontrolling interest	21,692	20,605
Non-cash (loss) gain related to derivative instruments	8,946	0
Noncash compensation expense	1,166	1,527
Net income attributable to partners	44,070	32,319
TEP
Reconciliation to Net Income:
Net income attributable to partners	44,070	32,319
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	65,886	26,852
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	15,797	17,900
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	3,361	8,718
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,352)	(635)
TEP | Operating Segments [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	64,541	25,506
TEP | Operating Segments [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	17,152	19,246
TEP | Operating Segments [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	3,351	8,718
TEP | Operating Segments [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,352)	(635)
TEP | Intersegment Eliminations [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	1,345	1,346
TEP | Intersegment Eliminations [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,355)	(1,346)
TEP | Intersegment Eliminations [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	10	0
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:
Non-cash loss allocated to noncontrolling interest	0	(9,377)
Interest expense, net of noncontrolling interest	(7,499)	(3,440)
Depreciation and amortization expense, net of noncontrolling interest	(21,967)	(20,533)
Non-cash (loss) gain related to derivative instruments	(8,990)	90
Noncash compensation expense	(1,166)	(1,527)
Non-cash loss from asset sales	$ 0	$ 4,483

Reporting Segments Reporting Se

Reporting Segments Reporting Segments - Summary of TEP's Segment Capital Expenditures (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Segment Reporting Information [Line Items]
Capital expenditures	$ 17,545	$ 13,300
TEP
Segment Reporting Information [Line Items]
Capital expenditures	17,545	13,300
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	12,311	6,480
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	2,133	3,865
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	3,101	2,955
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 0	$ 0

Reporting Segments - Summary 55

Reporting Segments - Summary of TEP's Segment Information of Assets (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Assets	$ 2,586,772	$ 2,562,074
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Assets	1,433,153	1,439,418
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Assets	698,745	706,576
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Assets	411,509	409,795
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Assets	$ 43,365	$ 6,285

Reporting Segments - Additional

Reporting Segments - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2016Segment
Segment Reporting [Abstract]
Number of Reportable Segments	3

Subsequent Events Subsequent 57

Subsequent Events Subsequent Events (Details) - USD ($)	May. 06, 2016	Apr. 28, 2016	Mar. 29, 2016	Mar. 31, 2016	Jan. 04, 2016	Dec. 31, 2015	Nov. 24, 2015
Subsequent Event [Line Items]
Long-term debt				$ 1,200,000,000		$ 753,000,000
Rockies Express Pipeline LLC
Subsequent Event [Line Items]
Equity interest held by noncontrolling interests			25.00%
Tallgrass Energy Partners | Barclays Bank
Subsequent Event [Line Items]
Total capacity under the revolving credit facility				1,500,000,000	$ 1,500,000,000	1,100,000,000	$ 1,100,000,000
Rockies Express Pipeline LLC | Rockies Express Holdings, LLC [Member]
Subsequent Event [Line Items]
Payments to Acquire Businesses, Gross			$ 440,000,000
Subsequent Event
Subsequent Event [Line Items]
Partners' Capital Account, Units, Sold in Private Placement		2,416,987
Subsequent Event | Limited Partner
Subsequent Event [Line Items]
Proceeds from Issuance of Private Placement		$ 90,000,000
Subsequent Event | Tallgrass Energy Partners | Barclays Bank
Subsequent Event [Line Items]
Total capacity under the revolving credit facility	$ 1,750,000,000
Subsequent Event | Rockies Express Pipeline LLC | Tallgrass Energy Partners
Subsequent Event [Line Items]
Payments to Acquire Businesses, Gross	$ 436,000,000
Sempra U.S. Gas and Power | Rockies Express Pipeline LLC
Subsequent Event [Line Items]
Equity interest held by noncontrolling interests			25.00%
Sempra U.S. Gas and Power | Subsequent Event | Rockies Express Pipeline LLC
Subsequent Event [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	25.00%
Line of Credit | Tallgrass Energy Partners
Subsequent Event [Line Items]
Long-term debt				$ 1,200,000,000		$ 753,000,000
Line of Credit | Subsequent Event | Tallgrass Energy Partners
Subsequent Event [Line Items]
Long-term debt	$ 1,447,000,000