Tallgrass Energy Partners 10-Q 3 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 03, 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	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	Q2
Trading Symbol	TEP
Amendment Flag	false
Common Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		72,108,934
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	Jun. 30, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 1,943	$ 1,611
Accounts receivable, net	53,033	57,757
Gas imbalances	878	1,227
Inventories	14,754	13,793
Derivative asset at fair value	148	0
Prepayments and other current assets	3,615	2,835
Total Current Assets	74,371	77,223
Property, plant and equipment, net	2,007,067	2,025,018
Goodwill	343,288	343,288
Intangible asset, net	95,038	96,546
Derivative asset at fair value	55,967	0
Unconsolidated investment	444,074	0
Deferred financing costs, net	6,882	5,105
Deferred charges and other assets	13,232	14,894
Total Assets	3,039,919	2,562,074
Current Liabilities:
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)	17,451	22,218
Accounts payable to related parties	7,191	7,852
Gas imbalances	1,199	1,605
Derivative liabilities at fair value	351	0
Accrued taxes	15,298	13,844
Accrued liabilities	8,136	10,019
Deferred revenue	42,901	26,511
Other current liabilities	6,687	6,880
Total Current Liabilities	99,214	88,929
Long-term debt	1,278,000	753,000
Other long-term liabilities and deferred credits	6,815	5,143
Total Long-term Liabilities	1,284,815	758,143
Commitments and Contingencies
Equity:
Common unitholders (75,669,080 and 60,644,232 units issued and outstanding at June 30, 2016 and December 31, 2015, respectively)	2,242,195	1,618,766
General partner (834,391 units issued and outstanding at June 30, 2016 and December 31, 2015)	(619,837)	(348,841)
Total Partners' Equity	1,622,358	1,269,925
Noncontrolling interests	33,532	445,077
Total Equity	1,655,890	1,715,002
Total Liabilities and Equity	$ 3,039,919	$ 2,562,074

CONDENSED CONSOLIDATED BALANC3

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - USD ($)	Jun. 30, 2016	Dec. 31, 2015
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)	$ 17,451,000	$ 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)	75,669,080	60,644,232
Limited Partner Units Outstanding (in units)	75,669,080	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		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues:
Crude oil transportation services	$ 93,322	$ 74,022	$ 187,894	$ 124,403
Natural gas transportation services	28,682	29,041	57,962	61,189
Sales of natural gas, NGLs, and crude oil	16,830	20,011	30,756	41,880
Processing and other revenues	8,097	9,896	15,724	20,173
Total Revenues	146,931	132,970	292,336	247,645
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	15,958	17,180	29,526	36,773
Cost of transportation services (exclusive of depreciation and amortization shown below)	14,240	13,492	30,396	24,207
Operations and maintenance	13,864	12,408	26,341	21,983
Depreciation and amortization	21,576	20,355	43,268	40,960
General and administrative	13,909	13,451	26,925	26,140
Taxes, other than income taxes	5,639	(271)	13,145	11,026
Loss on sale of assets	1,849	0	1,849	4,483
Total Operating Costs and Expenses	87,035	76,615	171,450	165,572
Operating Income	59,896	56,355	120,886	82,073
Other Income (Expense):
Interest expense, net	(9,233)	(3,893)	(16,732)	(7,333)
Unrealized gain on derivative instrument	18,953	0	10,007	0
Equity in earnings of unconsolidated investment	23,321	0	23,321	0
Other income, net	221	769	787	1,481
Total Other Income (Expense)	33,262	(3,124)	17,383	(5,852)
Net income	93,158	53,231	138,269	76,221
Net (income) loss attributable to noncontrolling interests	(1,110)	(8,332)	(2,151)	997
Net income attributable to partners	92,048	44,899	136,118	77,218
Net (income) loss attributable to noncontrolling interests
General partner interest in net income	(25,320)	(11,030)	(45,673)	(18,468)
Common and subordinated unitholders' interest in net income	$ 66,728	$ 33,869	$ 90,445	$ 58,750
Basic net income per common and subordinated unit	$ 0.93	$ 0.56	$ 1.30	$ 1.04
Diluted net income per common and subordinated unit	$ 0.92	$ 0.55	$ 1.29	$ 1.02
Basic average number of common and subordinated units outstanding	71,975	60,362	69,471	56,566
Diluted average number of common and subordinated units outstanding	72,925	61,225	70,360	57,404

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash Flows from Operating Activities:
Net income	$ 138,269	$ 76,221
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	46,077	42,867
Equity in earnings of unconsolidated investment	(23,321)	0
Distributions from unconsolidated investment	23,321	0
Noncash compensation expense	2,635	3,254
Noncash change in fair value of derivative financial instruments	(9,804)	41
Loss on disposal of assets	(1,849)	(4,483)
Changes in components of working capital:
Accounts receivable and other	6,578	(10,215)
Inventories	(1,683)	(6,068)
Accounts payable and accrued liabilities	(2,303)	2,183
Deferred revenue	16,174	4,198
Other operating, net	(1,246)	(4,746)
Net Cash Provided by Operating Activities	(196,546)	(112,218)
Cash Flows from Investing Activities:
Capital expenditures	(28,491)	(49,544)
Payments to Acquire Equity Method Investments	(14,387)	0
Payments to Acquire Additional Interest in Subsidiaries	49,118	700,000
Distributions from unconsolidated investment in excess of cumulative earnings	6,335	0
Other investing, net	411	(4,648)
Net Cash Used in Investing Activities	(521,272)	(754,192)
Net Cash Provided by Financing Activities
Distributions to unitholders	127,924	67,080
Payments to Noncontrolling Interests	425,882	0
Contributions from noncontrolling interests	7,273	16,294
Borrowings under revolving credit facility, net	525,000	147,000
Proceeds from public offering, net of offering costs	261,770	551,673
Proceeds from private placement, net of offering costs	90,009	0
Other financing, net	(5,188)	(5,002)
Net Cash Provided by (Used in) Financing Activities	325,058	642,885
Net Change in Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents	332	911
Cash and Cash Equivalents, beginning of period	1,611	867
Cash and Cash Equivalents, end of period	1,943	1,778
Supplemental Disclosures:
Property, plant and equipment acquired via the cash management agreement with Tallgrass Development, LP	0	103,239
Contributions from noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP	0	21,525
Distribution to noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP	0	22,266
Rockies Express Pipeline LLC
Adjustments to reconcile net income to net cash flows provided by operating activities:
Equity in earnings of unconsolidated investment	(23,300)
Cash Flows from Investing Activities:
Payments to Acquire Equity Method Investments	$ (436,022)	$ 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	Water Solutions [Member]General Partner	Water Solutions [Member]Common unitholdersLimited Partner	Water Solutions [Member]Subordinated UnitsLimited Partner	Water Solutions [Member]Total Partner Equity Excluding Portion Attributable to Noncontrolling Interest	Water Solutions [Member]Noncontrolling Interest	Water Solutions [Member]Total 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	$ 76,221	18,468	53,570	5,180	77,218	(997)	76,221
Issuance of units to public, net of offering costs		0	551,673	0	551,673	0	551,673
Proceeds from private placement, net of offering costs	0
Noncash compensation expense		0	6,000	0	6,000	0	6,000
Distributions to unitholders		(11,976)	(47,247)	(7,857)	(67,080)	0	(67,080)
LTIP units tendered by employees to satisfy tax withholding obligations		0	(6,562)	0	(6,562)	0	(6,562)
Acquisitions									$ (324,328)	$ 0	$ 0	$ (324,328)	$ (375,672)	$ (700,000)
Contributions from noncontrolling interests	16,294	0	0	0	0	68,651	68,651
Distributions to noncontrolling interests	0	0	0	0	0	(22,607)	(22,607)
Payments to Acquire Additional Interest in Subsidiaries	700,000														$ 0	$ 0	$ 0	$ 0	$ 600	$ 600
Conversion of subordinated units		0	(271,456)	271,456	0	0	0
Partners' Capital, Including Portion Attributable to Noncontrolling Interest		(353,579)	1,629,223	0	1,275,644	425,203	1,700,847
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	138,269	45,673	90,445	0	136,118	2,151	138,269
Issuance of units to public, net of offering costs	261,800	0	261,770	0	261,770	0	261,770
Proceeds from private placement, net of offering costs	90,009	0	90,009	0	90,009	0	90,009
Noncash compensation expense		0	3,820	0	3,820	0	3,820
Distributions to unitholders		(36,702)	(91,222)	0	(127,924)	0	(127,924)
Acquisitions									$ (279,967)	$ 268,607	$ 0	$ (11,360)	$ (417,679)	$ (429,039)
Contributions from noncontrolling interests	7,273	0	0	0	0	7,273	7,273
Distributions to noncontrolling interests	(425,882)	0	0	0	0	(3,290)	(3,290)	$ (425,882)
Payments to Acquire Additional Interest in Subsidiaries	49,118							$ 49,118
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	$ 1,655,890	$ (619,837)	$ 2,242,195	$ 0	$ 1,622,358	$ 33,532	$ 1,655,890

Description of Business

Description of Business	6 Months Ended
	Jun. 30, 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, Midwest and Appalachian regions of the United States through: (1) our 25% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), a Delaware limited liability company which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio, (2) the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and (3) the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline") . 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, Bakken, Marcellus and Utica shale formations. Our reportable business segments are: • Crude Oil Transportation & Logistics—the ownership and operation of a FERC-regulated crude oil pipeline system; • 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 June 30, 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 42,795,600 — 56.56 % 55.94 % Tallgrass Equity, LLC 20,000,000 — 26.43 % 26.14 % Tallgrass Development, LP (1) 12,873,480 — 17.01 % 16.83 % Tallgrass MLP GP, LLC (2) — 834,391 — % 1.09 % Total 75,669,080 834,391 100.00 % 100.00 % (1) As discussed in Note 7 – Risk Management , 3,563,146 of the common units held by Tallgrass Development, LP ("TD") as of June 30, 2016 were subsequently repurchased and deemed cancelled. (2) 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	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Basis of Presentation These condensed consolidated financial statements and related notes for the three and six months ended June 30, 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 and six months ended June 30, 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 and six months ended June 30, 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 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 ended 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 liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Our consolidated VIEs do not have material assets that can only be used to settle specific obligations of the consolidated VIEs. 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 Revenue Recognition In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. Throughout the first half of 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, and ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, and ASU 2016-12 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 these updates. 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. 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. 2016-09, "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. 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. 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. 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.

Acquisitions

Acquisitions	6 Months Ended
	Jun. 30, 2016
Business Combinations [Abstract]
Acquisitions	Acquisition of a 25% 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 "REX Purchase Agreement") with a unit of Sempra U.S. Gas and Power ("Sempra") to acquire Sempra's 25% membership interest in Rockies Express for cash consideration of $440 million , subject to adjustment under the REX Purchase Agreement. On April 28, 2016, we announced that TD offered TEP the right to assume the rights and obligations of REX Holdings under the REX Purchase Agreement. On May 6, 2016, TEP REX Holdings, LLC ("TEP REX"), an indirect wholly-owned subsidiary of TEP, 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 REX Purchase Agreement and, in exchange, TEP REX assumed all of the rights and obligations of REX Holdings under the REX Purchase Agreement. Subsequently on May 6, 2016, TEP REX closed the purchase of a 25% membership interest in Rockies Express from Sempra pursuant to the REX Purchase Agreement for cash consideration of approximately $436.0 million , after making the adjustments to the purchase price required by the REX Purchase Agreement. Our investment in Rockies Express is recorded under the equity method of accounting and reported as "Unconsolidated investment" on our condensed consolidated balance sheet. As of May 6, 2016, the difference between the fair value of our investment in Rockies Express of $436.0 million and the book value of the underlying net assets of approximately $840.7 million results in a negative basis difference of approximately $404.7 million . The basis difference has been allocated to property, plant and equipment and long-term debt based on their respective fair values at the date of acquisition. The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years , which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. The basis difference at June 30, 2016 was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 7,002 2 - 25 years Property, plant and equipment (411,730 ) 35 years Total basis difference $ (404,728 ) During the period from May 6, 2016 to June 30, 2016 , we recognized equity in earnings from Rockies Express of $23.3 million , inclusive of the amortization of the negative basis difference discussed above, and received distributions from and made contributions to Rockies Express of $29.7 million and $14.4 million , respectively. Summarized financial information for Rockies Express is as follows: June 30, 2016 (in thousands) Current assets $ 170,874 Noncurrent assets $ 6,038,268 Current liabilities $ 185,793 Noncurrent liabilities $ 2,636,680 Members' equity $ 3,386,669 Period from May 6, 2016 to June 30, 2016 (in thousands) Revenue $ 98,161 Operating income $ 43,832 Net income to Members $ 84,741 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 . As discussed in Note 7 – Risk Management , on July 21, 2016, we partially exercised the option and repurchased 3,563,146 of the common units, leaving 2,954,854 remaining common units available for repurchase under the call option. 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 six months ended June 30, 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 and six months ended June 30, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015: Three Months Ended June 30, 2015 Six Months Ended June 30, 2015 (in thousands) Revenue $ 133,447 $ 248,594 Net income attributable to partners $ 45,065 $ 77,548 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	6 Months Ended
	Jun. 30, 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 and six months ended June 30, 2016 . During the six months ended June 30, 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 June 30, Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Cost of transportation services $ 7,295 $ 6,233 $ 14,551 $ 10,591 Charges to TEP: (1) Property, plant and equipment, net $ 622 $ 1,594 $ 1,521 $ 2,901 Operation and maintenance $ 6,323 $ 5,825 $ 12,461 $ 11,248 General and administrative $ 10,251 $ 9,315 $ 19,217 $ 18,571 (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: June 30, 2016 December 31, 2015 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ — $ 15 Total receivable from related parties $ — $ 15 Accounts payable to related parties: Tallgrass Operations, LLC $ 7,040 $ 7,792 Tallgrass Equity, LLC 93 36 Deeprock Development, LLC — 17 Rockies Express Pipeline LLC 58 7 Total accounts payable to related parties $ 7,191 $ 7,852 Balances of gas imbalances with affiliated shippers are as follows: June 30, 2016 December 31, 2015 (in thousands) Affiliate gas balance receivables $ 23 $ 92 Affiliate gas balance payables $ 167 $ 227

Inventory

Inventory	6 Months Ended
	Jun. 30, 2016
Inventory Disclosure [Abstract]
Inventory	The components of inventory at June 30, 2016 and December 31, 2015 consisted of the following: June 30, 2016 December 31, 2015 (in thousands) Crude oil $ 5,752 $ 2,661 Materials and supplies 6,429 8,581 Natural gas liquids 351 395 Gas in underground storage 2,222 2,156 Total inventory $ 14,754 $ 13,793

Property, Plant and Equipment

Property, Plant and Equipment	6 Months Ended
	Jun. 30, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	A summary of net property, plant and equipment by classification is as follows: June 30, 2016 December 31, 2015 (in thousands) Crude oil pipelines $ 1,180,989 $ 1,172,684 Natural gas pipelines 552,107 550,710 Processing and treating assets 255,767 254,073 Water business assets 80,736 81,098 General and other 81,876 69,181 Construction work in progress 27,182 30,699 Accumulated depreciation and amortization (171,590 ) (133,427 ) Total property, plant and equipment, net $ 2,007,067 $ 2,025,018

Risk Management

Risk Management	6 Months Ended
	Jun. 30, 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 crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs. Fair Value of Derivative Contracts The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets: Balance Sheet June 30, 2016 December 31, 2015 (in thousands) Crude oil derivative contract (1) Current assets $ 148 $ — Call option derivative (2) Noncurrent assets $ 55,967 $ — Natural gas derivative contracts (3) Current liabilities $ 351 $ — (1) As of June 30, 2016 , the fair value of crude oil derivative contracts represents the sale of 85,000 barrels in July 2016. As of December 31, 2015 there were no crude oil derivative contracts outstanding. (2) 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 . (3) As of June 30, 2016 , the fair value shown for commodity contracts was comprised of derivative volumes for short natural gas fixed-price swaps totaling 0.8 Bcf. As of December 31, 2015 there were no natural gas derivative contracts outstanding. Effect of Derivative Contracts in the Statements of Income The following table summarizes the impact of derivative contracts for the three and six months ended June 30, 2016 and 2015 : Location of gain (loss) recognized Amount of gain (loss) recognized in income on derivatives Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Derivatives not designated as hedging contracts: Call option derivative Unrealized gain on derivative instrument $ 18,953 $ — $ 10,007 $ — Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ (307 ) $ (131 ) $ (351 ) $ (41 ) Crude oil derivative contract Sales of natural gas, NGLs, and crude oil $ 148 $ — $ 148 $ — Exercise of Call Option On July 21, 2016, we partially exercised the call option granted by TD in January 2016 as discussed in Note 3 – Acquisitions and repurchased 3,563,146 common units for a cash payment of $151.4 million . These common units were deemed canceled upon repurchase by TEP and as of July 21, 2016 are no longer issued and outstanding. As of July 29, 2016, 2,954,854 common units remained available for repurchase under the call option. Credit Risk We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our crude oil and natural gas derivatives consist of major financial institutions. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. The counterparty to our call option derivative is TD. Settlement of the call option derivative, when exercised, requires 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 June 30, 2016 , the fair value of our natural gas commodity derivative contracts was a liability, resulting in no credit exposure from TEP's counterparties as of that date. The maximum potential exposure to credit losses on our crude oil derivative contract at June 30, 2016 was: Asset Position (in thousands) Gross $ 148 Netting agreement impact — Cash collateral held — Net Exposure $ 148 As of June 30, 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 natural gas 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 June 30, 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 June 30, 2016 Call option derivative $ 55,967 $ — $ 55,967 $ — Crude oil derivative contract $ 148 $ — $ 148 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of June 30, 2016 Natural gas derivative contracts $ 351 $ — $ 351 $ —

Long-term Debt

Long-term Debt	6 Months Ended
	Jun. 30, 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 . In connection with the acquisition of a 25% membership interest in Rockies Express, TEP amended the revolving credit facility to increase the total capacity to $1.75 billion , which increase became effective May 6, 2016. The following table sets forth the available borrowing capacity under the revolving credit facility as of June 30, 2016 and December 31, 2015 : June 30, 2016 December 31, 2015 (in thousands) Total capacity under the revolving credit facility $ 1,750,000 $ 1,100,000 Less: Outstanding borrowings under the revolving credit facility (1) (1,278,000 ) (753,000 ) Available capacity under the revolving credit facility $ 472,000 $ 347,000 (1) As of July 29, 2016, our outstanding borrowings under the revolving credit facility were approximately $1.423 billion . 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 June 30, 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 June 30, 2016 , the weighted average interest rate on outstanding borrowings was 2.72% . During the six months ended June 30, 2016 , our weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 2.66% . 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 June 30, 2016 and December 31, 2015 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) June 30, 2016 $ — $ 1,278,000 $ — $ 1,278,000 $ 1,278,000 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 June 30, 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 June 30, 2016 .

Partnership Equity and Distribu

Partnership Equity and Distributions	6 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Partnership Equity and Distributions	Equity Distribution Agreements 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. On May 17, 2016, we entered into a new equity distribution agreement allowing for the sale of common units with an aggregate offering price of up to $657.5 million . Sales of 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, the exercise of the Partnership's right to repurchase all or a portion of the 6,518,000 common units issued by the Partnership to TD in connection with the Partnership's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to working capital. During the six months ended June 30, 2016 , we issued and sold 6,081,138 common units with a weighted average sales price of $43.63 per unit under our equity distribution agreements for net cash proceeds of approximately $261.8 million (net of approximately $3.6 million in commissions and professional service expenses). Private Placement On April 28, 2016, we issued an aggregate of 2,416,987 common units for net cash proceeds of $90.0 million in a private placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C. The units were subsequently registered pursuant to our Form S-3/A (File No. 333-210976) filed with the SEC on May 6, 2016, which became effective May 17, 2016. 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 six months ended June 30, 2016 . Distributions to Holders of Common 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 Partner General Partner Distributions Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) June 30, 2016 August 12, 2016 (1) $ 54,442 $ 24,262 $ 911 $ 79,615 $ 0.7550 March 31, 2016 May 13, 2016 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 July 6, 2016 for the second quarter of 2016 will be paid on August 12, 2016 to unitholders of record at the close of business on July 29, 2016. Other Contributions and Distributions During the six months ended June 30, 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 six months ended June 30, 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. TEP also recognized contributions from noncontrolling interests of $68.7 million , which consisted primarily of contributions from TD to Pony Express to fund construction of the lateral in Northeast Colorado, and distributions to noncontrolling interests of $22.6 million .

Net Income per Limited Partner

Net Income per Limited Partner Unit	6 Months Ended
	Jun. 30, 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 and six months ended June 30, 2016 and 2015 : Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 (in thousands, except per unit amounts) Net income $ 93,158 $ 53,231 $ 138,269 $ 76,221 Net (income) loss attributable to noncontrolling interests (1,110 ) (8,332 ) (2,151 ) 997 Net income attributable to partners 92,048 44,899 136,118 77,218 General partner interest in net income (25,320 ) (11,030 ) (45,673 ) (18,468 ) Net income available to common and subordinated unitholders $ 66,728 $ 33,869 $ 90,445 $ 58,750 Basic net income per common and subordinated unit $ 0.93 $ 0.56 $ 1.30 $ 1.04 Diluted net income per common and subordinated unit $ 0.92 $ 0.55 $ 1.29 $ 1.02 Basic average number of common and subordinated units outstanding 71,975 60,362 69,471 56,566 Equity Participation Unit equivalent units 950 863 889 838 Diluted average number of common and subordinated units outstanding 72,925 61,225 70,360 57,404

Regulatory Matters

Regulatory Matters	6 Months Ended
	Jun. 30, 2016
Regulatory Matters [Abstract]
Regulatory Matters	There are currently no proceedings challenging the currently effective rates of Pony Express, Rockies 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 certain 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. On March 22, 2016, a Settlement Judge was appointed in the case to assist the participants in exploring the possibility of settlement. On March 31, 2016, the FERC issued an order denying certain rehearing requests concerning the CRM, granting in part a motion to remove certain pro forma tariff records from the hearing, and also requested comments in order to assess the need for a technical conference. The FERC also 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 any 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. On June 23, 2016, the Commission approved the implementation of TIGT’s filed postage stamp rates, subject to refund, effective on May 1, 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. On May 5, 2016, the Acting Chief Administrative Law Judge issued an Order suspending the procedural schedule in the case as a result of the agreement in principle. On June 8, 2016, TIGT filed with the Commission its offer of settlement which resolves all issues in the case, with the exception of certain non-rate related tariff issues which remain subject to the Commission’s review and approval. On June 9, 2016, the Presiding Administrative Law Judge issued an Order shortening the period for any comments on the settlement, such that comments were due by June 13, 2016. No adverse comments were filed. The offer of settlement was certified to the Commission by the Administrative Law Judge on July 14, 2016. The Judge found that the settlement is uncontested, presents no issues of first impression, has no Commission policy implications, and appears to be just, reasonable, and in the public interest. The settlement is now 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. Rockies Express Annual FERC Fuel Tracking Filings – Docket No. RP16-702 On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702. The FERC issued an order accepting the filing on March 25, 2016. Seneca Lateral Facilities Conversion On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with FERC an application for (1) authorization to convert certain existing and operating pipeline and compression facilities located in Noble and Monroe Counties, Ohio (Seneca Lateral Facilities described in Docket Nos. CP13-539-000 and CP14-194-000) from Natural Gas Policy Act of 1978 Section 311 authority to Natural Gas Act Section 7 jurisdiction, and (2) issuance of a certificate of public convenience and necessity authorizing Rockies Express to operate and maintain the Seneca Lateral Facilities. On April 7, 2016, the FERC issued a Certificate to Rockies Express granting its requested authorizations. As directed by the FERC, Rockies Express filed revised rates for Natural Gas Act service on the Seneca Lateral and the pipeline announced that Natural Gas Act service would commence on June 1, 2016. Rockies Express Zone 3 Capacity Enhancement Project On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The proposed facilities will increase the Rockies Express Zone 3 east-to-west mainline capacity by 800,000 Dth/d from receipts at Clarington, Ohio to corresponding deliveries of 520,000 Dth/d and 280,000 Dth/d to Lebanon, Ohio and Moultrie County, Illinois, respectively. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities, which are expected to be placed into service in the fourth quarter of 2016.

Legal and Environmental Matters

Legal and Environmental Matters	6 Months Ended
	Jun. 30, 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 June 30, 2016 or December 31, 2015 . Rockies Express Mineral Management Service Lawsuit On June 30, 2009, Rockies Express filed claims against Mineral Management Service, a former unit of the U.S. Department of Interior (collectively "Interior") for breach of its contractual obligation to sign transportation service agreements and to pay approximately $192 million for pipeline capacity that it had agreed to take on Rockies Express. The Civilian Board of Contract Appeals ("CBCA") conducted a trial and ruled that Interior was liable for breach of contract, but limited the damages Interior was required to pay. On September 13, 2013, the United States Court of Appeals for the Federal Circuit issued a decision affirming that Interior was liable for its breach of contract, but reversing the CBCA's decision to limit damages. The case was remanded to the CBCA for the purpose of calculating damages at a hearing. On May 20, 2016, Rockies Express and Interior agreed to resolve the claims in this matter in exchange for a $65 million cash payment to Rockies Express. Interior paid the amount due Rockies Express on June 23, 2016. Ultra Resources In early 2016, Ultra Resources, Inc. ("Ultra"), defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, in which Rockies Express seeks approximately $303 million in damages and other relief. Specifically, Rockies Express has asserted that Ultra owes approximately $303 million for past transportation service charges and for reservation charge fees that Rockies Express would have received over the term of the service agreement had Ultra not defaulted, in addition to other amounts owed under law or equity. On April 29, 2016, Ultra and certain of its debtor affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District of Texas. On May 10, 2016, Ultra filed a notice of bankruptcy in the Harris County state court proceeding, which asserted that pursuant to section 362(a) of the Bankruptcy Code, the filing of Ultra’s Chapter 11 petition operated as a stay of the Harris County state court proceeding. Accordingly, Rockies Express intends to pursue its approximately $303 million claim in Ultra’s Chapter 11 proceeding. Michels Corporation On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels seeks unspecified damages from Rockies Express and asserts claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels has also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due. The case is currently scheduled to go to trial in April 2017. Rockies Express also previously filed Petition for Declaratory Judgment, Injunctive Relief and Damages against Michels in Johnson County, Kansas. That claim was dismissed without prejudice in September 2015. Rockies Express believes Michels' claims are without merit and plans to continue to vigorously contest all of the claims in this matter. 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 $4.4 million and $4.8 million at June 30, 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 replace approximately 8 miles of pipe, install additional ground beds, and continue remediating areas with external control anomalies 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	6 Months Ended
	Jun. 30, 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. The Natural Gas Transportation & Logistics segment includes our 25% membership interest in Rockies Express effective May 6, 2016, as discussed in Note 3 – Acquisitions . 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 June 30, 2016 Three Months Ended June 30, 2015 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 93,470 $ — $ 93,470 $ 75,219 $ — $ 75,219 Natural Gas Transportation & Logistics 30,150 (1,410 ) 28,740 30,969 (1,344 ) 29,625 Processing & Logistics 24,721 — 24,721 28,126 — 28,126 Corporate and Other — — — — — — Total Revenue $ 148,341 $ (1,410 ) $ 146,931 $ 134,314 $ (1,344 ) $ 132,970 Six Months Ended June 30, 2016 Six Months Ended June 30, 2015 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 188,042 $ — $ 188,042 $ 125,600 $ — $ 125,600 Natural Gas Transportation & Logistics 61,137 (2,765 ) 58,372 64,579 (2,690 ) 61,889 Processing & Logistics 45,922 — 45,922 60,156 — 60,156 Corporate and Other — — — — — — Total Revenue $ 295,101 $ (2,765 ) $ 292,336 $ 250,335 $ (2,690 ) $ 247,645 Three Months Ended June 30, 2016 Three Months Ended June 30, 2015 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 65,760 $ 1,346 $ 67,106 $ 46,320 $ 1,344 $ 47,664 Natural Gas Transportation & Logistics 45,763 (1,410 ) 44,353 16,591 (1,344 ) 15,247 Processing & Logistics 3,549 64 3,613 7,077 — 7,077 Corporate and Other (1,089 ) — (1,089 ) (1,036 ) — (1,036 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment 23,321 — Less: Interest expense, net of noncontrolling interest (9,233 ) (3,893 ) Depreciation and amortization expense, net of noncontrolling interest (21,840 ) (18,302 ) Distributions from unconsolidated investment (29,656 ) — Non-cash gain (loss) related to derivative instruments, net of noncontrolling interest 18,791 (131 ) Non-cash compensation expense (1,469 ) (1,727 ) Non-cash loss from disposal of assets (1,849 ) — Net income attributable to partners $ 92,048 $ 44,899 Six Months Ended June 30, 2016 Six Months Ended June 30, 2015 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 130,301 $ 2,691 $ 132,992 $ 71,826 $ 2,690 $ 74,516 Natural Gas Transportation & Logistics 62,915 (2,765 ) 60,150 35,837 (2,690 ) 33,147 Processing & Logistics 6,900 74 6,974 15,795 — 15,795 Corporate and Other (2,441 ) — (2,441 ) (1,671 ) — (1,671 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment 23,321 — Non-cash loss allocated to noncontrolling interest — 9,377 Less: Interest expense, net of noncontrolling interest (16,732 ) (7,333 ) Depreciation and amortization expense, net of noncontrolling interest (43,807 ) (38,835 ) Distributions from unconsolidated investment (29,656 ) — Non-cash gain (loss) related to derivative instruments, net of noncontrolling interest 9,801 (41 ) Non-cash compensation expense (2,635 ) (3,254 ) Non-cash loss from disposal of assets (1,849 ) (4,483 ) Net income attributable to partners $ 136,118 $ 77,218 Six Months Ended June 30, Capital Expenditures: 2016 2015 (in thousands) Crude Oil Transportation & Logistics $ 19,160 $ 32,501 Natural Gas Transportation & Logistics 4,115 7,061 Processing & Logistics 5,216 9,982 Corporate and Other — — Total capital expenditures $ 28,491 $ 49,544 Assets: June 30, 2016 December 31, 2015 (in thousands) Crude Oil Transportation & Logistics $ 1,425,917 $ 1,439,418 Natural Gas Transportation & Logistics 1,142,222 706,576 Processing & Logistics 408,055 409,795 Corporate and Other 63,725 6,285 Total assets $ 3,039,919 $ 2,562,074

Subsequent Events Subsequent Ev

Subsequent Events Subsequent Events	6 Months Ended
	Jun. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	On July 1, 2016, we acquired the remaining 8% noncontrolling equity interest in Water Solutions and additional interests in certain of Water Solutions' subsidiaries from Regency Investments I, LLC and BSEG Water Group LLC for total cash consideration of $6.0 million , which will be accounted for as an acquisition of noncontrolling interest. Subsequent to the closing of the transaction, our aggregate membership interest in Water Solutions is 100% .

Summary of Significant Accoun21

Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These condensed consolidated financial statements and related notes for the three and six months ended June 30, 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 and six months ended June 30, 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 and six months ended June 30, 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 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 ended 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 liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Our consolidated VIEs do not have material assets that can only be used to settle specific obligations of the consolidated VIEs. 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 Revenue Recognition In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. Throughout the first half of 2016, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, and ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients. The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, and ASU 2016-12 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 these updates. 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. 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. 2016-09, "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. 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. 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. 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.

Acquisitions Equity Method Inve

Acquisitions Equity Method Investments (Policies)	6 Months Ended
	Jun. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments, Policy [Policy Text Block]	Our investment in Rockies Express is recorded under the equity method of accounting and reported as "Unconsolidated investment" on our condensed consolidated balance sheet. As of May 6, 2016, the difference between the fair value of our investment in Rockies Express of $436.0 million and the book value of the underlying net assets of approximately $840.7 million results in a negative basis difference of approximately $404.7 million . The basis difference has been allocated to property, plant and equipment and long-term debt based on their respective fair values at the date of acquisition. The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years , which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities.

Description of Business Schedul

Description of Business Schedule of Other Ownership Interests (Tables)	6 Months Ended
	Jun. 30, 2016
Schedule of Other Ownership Interests [Abstract]
Schedule of Ownership Interests	The table below summarizes our equity ownership as of June 30, 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 42,795,600 — 56.56 % 55.94 % Tallgrass Equity, LLC 20,000,000 — 26.43 % 26.14 % Tallgrass Development, LP (1) 12,873,480 — 17.01 % 16.83 % Tallgrass MLP GP, LLC (2) — 834,391 — % 1.09 % Total 75,669,080 834,391 100.00 % 100.00 % (1) As discussed in Note 7 – Risk Management , 3,563,146 of the common units held by Tallgrass Development, LP ("TD") as of June 30, 2016 were subsequently repurchased and deemed cancelled. (2) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights.

Acquisitions Equity Method In24

Acquisitions Equity Method Investment (Tables)	6 Months Ended
	Jun. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Summarized financial information for Rockies Express is as follows: June 30, 2016 (in thousands) Current assets $ 170,874 Noncurrent assets $ 6,038,268 Current liabilities $ 185,793 Noncurrent liabilities $ 2,636,680 Members' equity $ 3,386,669 Period from May 6, 2016 to June 30, 2016 (in thousands) Revenue $ 98,161 Operating income $ 43,832 Net income to Members $ 84,741 The basis difference at June 30, 2016 was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 7,002 2 - 25 years Property, plant and equipment (411,730 ) 35 years Total basis difference $ (404,728 )
Business Acquisition, Pro Forma Information	TEP's unaudited pro forma revenue and net income attributable to partners for the three and six months ended June 30, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015: Three Months Ended June 30, 2015 Six Months Ended June 30, 2015 (in thousands) Revenue $ 133,447 $ 248,594 Net income attributable to partners $ 45,065 $ 77,548

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2016
Related Party Transactions [Abstract]
Schedule of Transactions with Affiliated Companies	Totals of transactions with affiliated companies are as follows: Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Cost of transportation services $ 7,295 $ 6,233 $ 14,551 $ 10,591 Charges to TEP: (1) Property, plant and equipment, net $ 622 $ 1,594 $ 1,521 $ 2,901 Operation and maintenance $ 6,323 $ 5,825 $ 12,461 $ 11,248 General and administrative $ 10,251 $ 9,315 $ 19,217 $ 18,571 (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: June 30, 2016 December 31, 2015 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ — $ 15 Total receivable from related parties $ — $ 15 Accounts payable to related parties: Tallgrass Operations, LLC $ 7,040 $ 7,792 Tallgrass Equity, LLC 93 36 Deeprock Development, LLC — 17 Rockies Express Pipeline LLC 58 7 Total accounts payable to related parties $ 7,191 $ 7,852
Schedule of Balances of Gas Imbalance with Affiliated Shippers	Balances of gas imbalances with affiliated shippers are as follows: June 30, 2016 December 31, 2015 (in thousands) Affiliate gas balance receivables $ 23 $ 92 Affiliate gas balance payables $ 167 $ 227

Inventory (Tables)

Inventory (Tables)	6 Months Ended
	Jun. 30, 2016
Inventory Disclosure [Abstract]
Schedule of Components of Inventory	The components of inventory at June 30, 2016 and December 31, 2015 consisted of the following: June 30, 2016 December 31, 2015 (in thousands) Crude oil $ 5,752 $ 2,661 Materials and supplies 6,429 8,581 Natural gas liquids 351 395 Gas in underground storage 2,222 2,156 Total inventory $ 14,754 $ 13,793

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	6 Months Ended
	Jun. 30, 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: June 30, 2016 December 31, 2015 (in thousands) Crude oil pipelines $ 1,180,989 $ 1,172,684 Natural gas pipelines 552,107 550,710 Processing and treating assets 255,767 254,073 Water business assets 80,736 81,098 General and other 81,876 69,181 Construction work in progress 27,182 30,699 Accumulated depreciation and amortization (171,590 ) (133,427 ) Total property, plant and equipment, net $ 2,007,067 $ 2,025,018

Risk Management (Tables)

Risk Management (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 2016 December 31, 2015 (in thousands) Crude oil derivative contract (1) Current assets $ 148 $ — Call option derivative (2) Noncurrent assets $ 55,967 $ — Natural gas derivative contracts (3) Current liabilities $ 351 $ — (1) As of June 30, 2016 , the fair value of crude oil derivative contracts represents the sale of 85,000 barrels in July 2016. As of December 31, 2015 there were no crude oil derivative contracts outstanding. (2) 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 . (3) As of June 30, 2016 , the fair value shown for commodity contracts was comprised of derivative volumes for short natural gas fixed-price swaps totaling 0.8 Bcf. As of December 31, 2015 there were no natural gas derivative contracts outstanding.
Derivative Contracts Included in Consolidated Statements of Income	The following table summarizes the impact of derivative contracts for the three and six months ended June 30, 2016 and 2015 : Location of gain (loss) recognized Amount of gain (loss) recognized in income on derivatives Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 (in thousands) Derivatives not designated as hedging contracts: Call option derivative Unrealized gain on derivative instrument $ 18,953 $ — $ 10,007 $ — Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ (307 ) $ (131 ) $ (351 ) $ (41 ) Crude oil derivative contract Sales of natural gas, NGLs, and crude oil $ 148 $ — $ 148 $ —
Derivative Instruments Maximum Potential Exposure to Credit Loss	The maximum potential exposure to credit losses on our crude oil derivative contract at June 30, 2016 was: Asset Position (in thousands) Gross $ 148 Netting agreement impact — Cash collateral held — Net Exposure $ 148
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 June 30, 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 June 30, 2016 Call option derivative $ 55,967 $ — $ 55,967 $ — Crude oil derivative contract $ 148 $ — $ 148 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of June 30, 2016 Natural gas derivative contracts $ 351 $ — $ 351 $ —

Long-term Debt (Tables)

Long-term Debt (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Schedule of Line of Credit Facilities	The following table sets forth the available borrowing capacity under the revolving credit facility as of June 30, 2016 and December 31, 2015 : June 30, 2016 December 31, 2015 (in thousands) Total capacity under the revolving credit facility $ 1,750,000 $ 1,100,000 Less: Outstanding borrowings under the revolving credit facility (1) (1,278,000 ) (753,000 ) Available capacity under the revolving credit facility $ 472,000 $ 347,000 (1) As of July 29, 2016, our outstanding borrowings under the revolving credit facility were approximately $1.423 billion .
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 June 30, 2016 and December 31, 2015 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) June 30, 2016 $ — $ 1,278,000 $ — $ 1,278,000 $ 1,278,000 December 31, 2015 $ — $ 753,000 $ — $ 753,000 $ 753,000

Partnership Equity and Distri30

Partnership Equity and Distributions (Tables)	6 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Summary of Distributions	The following table shows the distributions for the periods indicated: Distributions Limited Partner General Partner Distributions Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) June 30, 2016 August 12, 2016 (1) $ 54,442 $ 24,262 $ 911 $ 79,615 $ 0.7550 March 31, 2016 May 13, 2016 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 July 6, 2016 for the second quarter of 2016 will be paid on August 12, 2016 to unitholders of record at the close of business on July 29, 2016.

Net Income per Limited Partne31

Net Income per Limited Partner Unit (Tables)	6 Months Ended
	Jun. 30, 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 and six months ended June 30, 2016 and 2015 : Three Months Ended June 30, Six Months Ended June 30, 2016 2015 2016 2015 (in thousands, except per unit amounts) Net income $ 93,158 $ 53,231 $ 138,269 $ 76,221 Net (income) loss attributable to noncontrolling interests (1,110 ) (8,332 ) (2,151 ) 997 Net income attributable to partners 92,048 44,899 136,118 77,218 General partner interest in net income (25,320 ) (11,030 ) (45,673 ) (18,468 ) Net income available to common and subordinated unitholders $ 66,728 $ 33,869 $ 90,445 $ 58,750 Basic net income per common and subordinated unit $ 0.93 $ 0.56 $ 1.30 $ 1.04 Diluted net income per common and subordinated unit $ 0.92 $ 0.55 $ 1.29 $ 1.02 Basic average number of common and subordinated units outstanding 71,975 60,362 69,471 56,566 Equity Participation Unit equivalent units 950 863 889 838 Diluted average number of common and subordinated units outstanding 72,925 61,225 70,360 57,404

Reporting Segments (Tables)

Reporting Segments (Tables)	6 Months Ended
	Jun. 30, 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 June 30, 2016 Three Months Ended June 30, 2015 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 93,470 $ — $ 93,470 $ 75,219 $ — $ 75,219 Natural Gas Transportation & Logistics 30,150 (1,410 ) 28,740 30,969 (1,344 ) 29,625 Processing & Logistics 24,721 — 24,721 28,126 — 28,126 Corporate and Other — — — — — — Total Revenue $ 148,341 $ (1,410 ) $ 146,931 $ 134,314 $ (1,344 ) $ 132,970 Six Months Ended June 30, 2016 Six Months Ended June 30, 2015 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 188,042 $ — $ 188,042 $ 125,600 $ — $ 125,600 Natural Gas Transportation & Logistics 61,137 (2,765 ) 58,372 64,579 (2,690 ) 61,889 Processing & Logistics 45,922 — 45,922 60,156 — 60,156 Corporate and Other — — — — — — Total Revenue $ 295,101 $ (2,765 ) $ 292,336 $ 250,335 $ (2,690 ) $ 247,645
Summary of TEP's Segment Information of Earnings	Three Months Ended June 30, 2016 Three Months Ended June 30, 2015 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 65,760 $ 1,346 $ 67,106 $ 46,320 $ 1,344 $ 47,664 Natural Gas Transportation & Logistics 45,763 (1,410 ) 44,353 16,591 (1,344 ) 15,247 Processing & Logistics 3,549 64 3,613 7,077 — 7,077 Corporate and Other (1,089 ) — (1,089 ) (1,036 ) — (1,036 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment 23,321 — Less: Interest expense, net of noncontrolling interest (9,233 ) (3,893 ) Depreciation and amortization expense, net of noncontrolling interest (21,840 ) (18,302 ) Distributions from unconsolidated investment (29,656 ) — Non-cash gain (loss) related to derivative instruments, net of noncontrolling interest 18,791 (131 ) Non-cash compensation expense (1,469 ) (1,727 ) Non-cash loss from disposal of assets (1,849 ) — Net income attributable to partners $ 92,048 $ 44,899 Six Months Ended June 30, 2016 Six Months Ended June 30, 2015 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 130,301 $ 2,691 $ 132,992 $ 71,826 $ 2,690 $ 74,516 Natural Gas Transportation & Logistics 62,915 (2,765 ) 60,150 35,837 (2,690 ) 33,147 Processing & Logistics 6,900 74 6,974 15,795 — 15,795 Corporate and Other (2,441 ) — (2,441 ) (1,671 ) — (1,671 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment 23,321 — Non-cash loss allocated to noncontrolling interest — 9,377 Less: Interest expense, net of noncontrolling interest (16,732 ) (7,333 ) Depreciation and amortization expense, net of noncontrolling interest (43,807 ) (38,835 ) Distributions from unconsolidated investment (29,656 ) — Non-cash gain (loss) related to derivative instruments, net of noncontrolling interest 9,801 (41 ) Non-cash compensation expense (2,635 ) (3,254 ) Non-cash loss from disposal of assets (1,849 ) (4,483 ) Net income attributable to partners $ 136,118 $ 77,218
Summary of TEP's Segment Capital Expenditures	Six Months Ended June 30, Capital Expenditures: 2016 2015 (in thousands) Crude Oil Transportation & Logistics $ 19,160 $ 32,501 Natural Gas Transportation & Logistics 4,115 7,061 Processing & Logistics 5,216 9,982 Corporate and Other — — Total capital expenditures $ 28,491 $ 49,544
Summary of TEP's Segment Information of Assets	Assets: June 30, 2016 December 31, 2015 (in thousands) Crude Oil Transportation & Logistics $ 1,425,917 $ 1,439,418 Natural Gas Transportation & Logistics 1,142,222 706,576 Processing & Logistics 408,055 409,795 Corporate and Other 63,725 6,285 Total assets $ 3,039,919 $ 2,562,074

Description of Business - Addit

Description of Business - Additional Information (Detail) - shares	Jul. 21, 2016	Jun. 30, 2016	Dec. 31, 2015
Organization [Line Items]
Limited Partner Common Units		75,669,080	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		42,795,600
General Partner Units		0
Percentage of Outstanding Limited Partner Common Units		56.56%
Percentage of Outstanding Common and General Partner Units		55.94%
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		26.43%
Percentage of Outstanding Common and General Partner Units		26.14%
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		17.01%
Percentage of Outstanding Common and General Partner Units		16.83%
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		1.09%
Rockies Express Pipeline LLC
Organization [Line Items]
Equity Method Investment, Ownership Percentage		25.00%
Subsequent Event [Member]
Organization [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased	3,563,146

Summary of Significant Accoun34

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	Jun. 30, 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 Equity Method In35

Acquisitions Equity Method Investments (Details) - Rockies Express Pipeline LLC - USD ($) $ in Thousands	May 06, 2016	Jun. 30, 2016
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ (404,728)
Basis Difference, Amortization Period	35 years
Equity Method Investment, Summarized Financial Information, Current Assets		170,874
Equity Method Investment, Summarized Financial Information, Noncurrent Assets		6,038,268
Equity Method Investment, Summarized Financial Information, Current Liabilities		185,793
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities		2,636,680
Equity Method Investment Summarized Financial Information, Equity		3,386,669
Equity Method Investment, Summarized Financial Information, Revenue		98,161
Equity Method Investment Summarized Financial Information Operating Income		43,832
Equity Method Investment, Summarized Financial Information, Net Income (Loss)		84,741
Long-term Debt
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		7,002
Property, Plant and Equipment
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ (411,730)
Basis Difference, Amortization Period		35 years
Minimum | Long-term Debt
Schedule of Equity Method Investments [Line Items]
Basis Difference, Amortization Period		2 years
Maximum | Long-term Debt
Schedule of Equity Method Investments [Line Items]
Basis Difference, Amortization Period		25 years

Acquisitions Business Acquisiti

Acquisitions Business Acquisition, Pro Forma Information (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015
Business Combinations [Abstract]
Business Acquisition, Pro Forma Revenue	$ 133,447	$ 248,594
Business Acquisition, Pro Forma Net Income (Loss)	$ 45,065	$ 77,548

Acquisitions (Details)

Acquisitions (Details) $ / shares in Units, $ in Thousands	Jul. 21, 2016shares	May 06, 2016USD ($)	Mar. 29, 2016USD ($)	Jan. 01, 2016USD ($)$ / sharesshares	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)	Dec. 16, 2015mi	Mar. 01, 2015
Business Acquisition [Line Items]
Unconsolidated investment					$ 444,074		$ 444,074		$ 0
Equity in earnings of unconsolidated investment					23,321	$ 0	23,321	$ 0
Payments to Acquire Equity Method Investments							14,387	0
Distributions to noncontrolling interests							(425,882)	0
Derivative asset at fair value				$ 46,000	55,967		55,967		0
Payments to Acquire Additional Interest in Subsidiaries							49,118	700,000
Pony Express Pipeline
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				31.30%							33.30%
Distributions to noncontrolling interests				$ (475,000)			(425,882)
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares				6,518,000
Common Unit, Issuance Value				$ 268,600
Business Combination, Consideration Transferred, Including Equity Interest in Acquiree Held Prior to Combination				$ 743,600
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest				98.00%
Payments to Acquire Additional Interest in Subsidiaries							49,118
BNN Western, LLC
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 | BNN Western, LLC
Business Acquisition [Line Items]
Lessor Leasing Arrangements, Operating Leases, Term of Contract									5 years
Gathering and Disposal Contract | BNN Western, LLC
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
Sempra U.S. Gas and Power | Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners			25.00%
Business Acquisition, Percentage of Voting Interests Acquired		25.00%
Rockies Express Holdings, LLC | Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross			$ 440,000
Tallgrass Energy Partners | Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 436,000
Rockies Express Pipeline LLC
Business Acquisition [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity					$ 404,728		404,728
Basis Difference, Amortization Period		35 years
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service		2.86%
Equity in earnings of unconsolidated investment							23,300
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries							29,700
Payments to Acquire Equity Method Investments							$ 436,022	$ 0
Rockies Express Pipeline LLC | Tallgrass Energy Partners
Business Acquisition [Line Items]
Unconsolidated investment		$ 436,000
Equity Method Investment, Underlying Equity in Net Assets		840,700
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ 404,700
Subsequent Event [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares	2,954,854
Partners' Capital Account, Units, Treasury Units Purchased | shares	3,563,146

Related Party Transactions - Sc

Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Related Party Transaction [Line Items]
Related Party Transactions, Cost of Sales and Transportation Services	$ 7,295	$ 6,233	$ 14,551	$ 10,591
Operation and maintenance [Member]
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	6,323	5,825	12,461	11,248
General and Administrative Expense [Member]
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	10,251	9,315	19,217	18,571
Property, Plant and Equipment
Related Party Transaction [Line Items]
Related Party Transaction Costs Capitalized From Transactions With Related Party	$ 622	$ 1,594	$ 1,521	$ 2,901

Related Party Transactions - 39

Related Party Transactions - Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Receivable from related parties	$ 0	$ 15
Accounts Payable, Related Parties, Current	7,191	7,852
Rockies Express Pipeline LLC
Related Party Transaction [Line Items]
Receivable from related parties	0	15
Accounts Payable, Related Parties, Current	58	7
Tallgrass Operations, LLC
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	7,040	7,792
Tallgrass Equity, LLC
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	93	36
Deeprock Development, LLC
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	$ 0	$ 17

Related Party Transactions - 40

Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Affiliate gas balance receivables	$ 23	$ 92
Affiliate gas balance payables	$ 167	$ 227

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2015USD ($)
Related Party Transactions [Abstract]
Interest Income, Related Party	$ 0.4

Inventory Inventory (Details)

Inventory Inventory (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Crude oil	$ 5,752	$ 2,661
Materials and supplies	6,429	8,581
Natural gas liquids	351	395
Gas in underground storage	2,222	2,156
Inventory, Net	$ 14,754	$ 13,793

Property Plant and Equipment -

Property Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Accumulated depreciation and amortization	$ (171,590)	$ (133,427)
Property, plant and equipment	2,007,067	2,025,018
Crude oil pipelines
Property, Plant and Equipment [Line Items]
Property , plant and equipment	1,180,989	1,172,684
Natural gas pipelines
Property, Plant and Equipment [Line Items]
Property , plant and equipment	552,107	550,710
Processing and treating assets
Property, Plant and Equipment [Line Items]
Property , plant and equipment	255,767	254,073
Water business assets
Property, Plant and Equipment [Line Items]
Property , plant and equipment	80,736	81,098
General and other
Property, Plant and Equipment [Line Items]
Property , plant and equipment	81,876	69,181
Construction work in progress
Property, Plant and Equipment [Line Items]
Property , plant and equipment	$ 27,182	$ 30,699

Risk Management - Schedule of F

Risk Management - Schedule of Fair Value of Derivative Contracts (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 148
Energy Related Derivative | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	148	$ 0
Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	55,967
Equity Option | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	55,967	0
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	351
Energy commodity derivative contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	$ 351	$ 0

Risk Management - Derivative Co

Risk Management - Derivative Contracts Included in Consolidated Statement of Income (Detail) - Derivatives not designated as hedging contracts - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Equity Option
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 18,953	$ 0	$ 10,007	$ 0
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	(307)	(131)	(351)	(41)
Energy Related Derivative
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 148	$ 0	$ 148	$ 0

Risk Management Derivative Inst

Risk Management Derivative Instruments Maximum Potential Exposure to Credit Loss (Details) - Energy Related Derivative $ in Thousands	Jun. 30, 2016USD ($)
Concentration Risk [Line Items]
Gross	$ 148
Netting agreement impact	0
Cash collateral held	0
Net Exposure	$ 148

Risk Management - Schedule of E

Risk Management - Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification (Detail) $ in Thousands	Jun. 30, 2016USD ($)
Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 55,967
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	55,967
Equity Option | Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	0
Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	148
Energy Related Derivative | Quoted prices in active markets for identical assets (Level 1)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	0
Energy Related Derivative | Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	148
Energy Related Derivative | 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	351
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	351
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) $ / shares in Units, $ in Millions	Jul. 21, 2016USD ($)shares	Jan. 01, 2016$ / sharesshares	Jun. 30, 2016Bcfbbl	Mar. 01, 2015
Commodity [Member] | Energy Related Derivative
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl			85,000
Commodity [Member] | Energy commodity derivative contracts
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | Bcf			0.8
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		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
Subsequent Event [Member]
Derivative [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	2,954,854
Partners' Capital Account, Units, Treasury Units Purchased	3,563,146
Payments for Repurchase of Common Stock | $	$ 151.4

Long-term Debt Capacity under R

Long-term Debt Capacity under Revolving Credit Facility (Details) - USD ($)	Jun. 30, 2016	May 06, 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)	$ (1,278,000,000)			$ (753,000,000)
Tallgrass Energy Partners | Line of Credit
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility (1)	(1,278,000,000)			(753,000,000)
Available capacity under the revolving credit facility	472,000,000			347,000,000
Tallgrass Energy Partners | Barclays Bank
Line of Credit Facility [Line Items]
Total capacity under the revolving credit facility	$ 1,750,000,000	$ 1,750,000,000	$ 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	Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Fair Value	$ 1,278,000	$ 753,000
Long-term debt	1,278,000	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	1,278,000	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)	6 Months Ended
	Jun. 30, 2016USD ($)	Jul. 29, 2016USD ($)	May 06, 2016USD ($)	Jan. 04, 2016USD ($)	Jan. 01, 2016	Dec. 31, 2015USD ($)	Nov. 24, 2015USD ($)	Mar. 01, 2015
Debt Instrument [Line Items]
Long-term debt	$ 1,278,000,000					$ 753,000,000
Weighted average interest rate on outstanding borrowings	2.72%
Debt Instrument, Interest Rate, Effective Percentage	2.66%
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	$ 1,750,000,000		$ 1,750,000,000	$ 1,500,000,000		1,100,000,000	$ 1,100,000,000
Line of Credit [Member] | Tallgrass Energy Partners
Debt Instrument [Line Items]
Long-term debt	$ 1,278,000,000					$ 753,000,000
Subsequent Event [Member] | Line of Credit [Member] | Tallgrass Energy Partners
Debt Instrument [Line Items]
Long-term debt		$ 1,423,000,000

Partnership Equity and Distri52

Partnership Equity and Distributions - Summary of Distributions (Detail) - Tallgrass Energy Partners - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Jun. 30, 2016	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	$ 54,442	$ 48,238	$ 42,984	$ 36,347	$ 35,135	$ 31,322
Distributions General Partner Incentive	24,262	19,816	15,332	11,567	10,418	6,934
General Partner Distributions	911	830	724	660	627	530
Distributions Total	$ 79,615	$ 68,884	$ 59,040	$ 48,574	$ 46,180	$ 38,786
Distributions per Limited Partner unit	$ 0.7550	$ 0.7050	$ 0.6400	$ 0.6000	$ 0.5800	$ 0.5200

Partnership Equity and Distri53

Partnership Equity and Distributions - Additional Information (Detail) - USD ($)	Apr. 28, 2016	Jan. 01, 2016	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015	May 17, 2016	Feb. 17, 2016	May 13, 2015	Mar. 01, 2015	Oct. 31, 2014
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Authorized Amount						$ 657,500,000		$ 100,200,000		$ 200,000,000
Partners' Capital Account, Units, Sold in Public Offering				6,081,138
Shares Issued, Price Per Share				$ 43.63
Issuance of units to public, net of offering costs				$ 261,800,000
Limited Partners' Offering Costs				3,600,000
Partners' Capital Account, Units, Sold in Private Placement	2,416,987
Proceeds from private placement, net of offering costs	$ 90,000,000			90,009,000	$ 0
General Partner Equity Purchase Plan, Authorized Amount							$ 100,000,000
Contributions from noncontrolling interests				7,273,000	16,294,000
Payments to Noncontrolling Interests				425,882,000	0
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		6,518,000
Business Acquisition, Percentage of Voting Interests Acquired		31.30%							33.30%
Payments to Noncontrolling Interests		$ 475,000,000		425,882,000
General Partner
Limited Partners' Capital Account [Line Items]
Issuance of units to public, net of offering costs				0	0
Proceeds from private placement, net of offering costs				0
Contributions from noncontrolling interests				0	0
Payments to Noncontrolling Interests				0	0
General Partner | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions			$ (324,300,000)	(279,967,000)	(324,328,000)
Total Partner Equity Including Portion Attributable to Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Issuance of units to public, net of offering costs				261,770,000	551,673,000
Proceeds from private placement, net of offering costs				90,009,000
Contributions from noncontrolling interests				7,273,000	68,651,000
Payments to Noncontrolling Interests				3,290,000	22,607,000
Total Partner Equity Including Portion Attributable to Noncontrolling Interest | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions				$ (429,039,000)	$ (700,000,000)

Net Income per Limited Partne54

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		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share [Abstract]
Net income	$ 93,158	$ 53,231	$ 138,269	$ 76,221
Net (income) loss attributable to noncontrolling interests	(1,110)	(8,332)	(2,151)	997
Net income attributable to partners	92,048	44,899	136,118	77,218
General partner interest in net income	(25,320)	(11,030)	(45,673)	(18,468)
Net income available to common and subordinated unitholders	$ 66,728	$ 33,869	$ 90,445	$ 58,750
Basic net income per common and subordinated unit	$ 0.93	$ 0.56	$ 1.30	$ 1.04
Diluted net income per common and subordinated unit	$ 0.92	$ 0.55	$ 1.29	$ 1.02
Basic average number of common and subordinated units outstanding	71,975	60,362	69,471	56,566
Equity Participation Unit equivalent units	950	863	889	838
Diluted average number of common and subordinated units outstanding	72,925	61,225	70,360	57,404

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters (Details) MMBTU / d in Thousands	6 Months Ended
	Jun. 30, 2016MMBTU / d
Public Utilities, General Disclosures [Line Items]
Capacity Enhancement	800
Clarington, Ohio to Lebanon, Ohio [Member]
Public Utilities, General Disclosures [Line Items]
Capacity Enhancement	520
Clarington, Ohio to Moultrie County, Illinois [Member]
Public Utilities, General Disclosures [Line Items]
Capacity Enhancement	280

Legal and Environmental Matte56

Legal and Environmental Matters Gain Contingencies (Details) $ in Millions	May 20, 2016USD ($)	Jun. 30, 2016Bcf / d	Apr. 14, 2016USD ($)	Jun. 30, 2009USD ($)
Mineral Management Settlement
Gain Contingencies [Line Items]
Gain Contingency, Unrecorded Amount				$ 192
Litigation Settlement, Amount	$ 65
Ultra Resources Complaint
Gain Contingencies [Line Items]
Gain Contingency, Unrecorded Amount			$ 303
Firm transportation service agreement | Bcf / d		0.2

Legal and Environmental Matte57

Legal and Environmental Matters - Additional Information (Detail) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2016USD ($)ft-lbmi	Dec. 31, 2016USD ($)mi	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Estimated environmental liability	$ 4.4		$ 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
Michels Corporation Complaint
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 24.2

Reporting Segments - Summary of

Reporting Segments - Summary of TEP's Segment Information of Revenue (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Revenues	$ 146,931	$ 132,970	$ 292,336	$ 247,645
TEP
Segment Reporting Information [Line Items]
Revenues	146,931	132,970	292,336	247,645
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	93,470	75,219	188,042	125,600
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	28,740	29,625	58,372	61,889
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Revenues	24,721	28,126	45,922	60,156
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
TEP | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	148,341	134,314	295,101	250,335
TEP | Operating Segments [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	93,470	75,219	188,042	125,600
TEP | Operating Segments [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	30,150	30,969	61,137	64,579
TEP | Operating Segments [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Revenues	24,721	28,126	45,922	60,156
TEP | Operating Segments [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
TEP | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	(1,410)	(1,344)	(2,765)	(2,690)
TEP | Intersegment Eliminations [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
TEP | Intersegment Eliminations [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	(1,410)	(1,344)	(2,765)	(2,690)
TEP | Intersegment Eliminations [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
TEP | Intersegment Eliminations [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Revenues	$ 0	$ 0	$ 0	$ 0

Reporting Segments - Summary 59

Reporting Segments - Summary of TEP's Segment Information of Earnings (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Reconciliation to Net Income:
Equity in earnings of unconsolidated investment	$ 23,321	$ 0	$ 23,321	$ 0
Interest expense, net of noncontrolling interest	9,233	3,893	16,732	7,333
Depreciation and amortization expense, net of noncontrolling interest	21,576	20,355	43,268	40,960
Distributions from unconsolidated investment			23,321	0
Non-cash gain (loss) related to derivative instruments, net of noncontrolling interest	(18,953)	0	(10,007)	0
Noncash compensation expense			2,635	3,254
Net income attributable to partners	92,048	44,899	136,118	77,218
TEP
Reconciliation to Net Income:
Net income attributable to partners	92,048	44,899	136,118	77,218
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	67,106	47,664	132,992	74,516
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	44,353	15,247	60,150	33,147
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	3,613	7,077	6,974	15,795
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,089)	(1,036)	(2,441)	(1,671)
TEP | Operating Segments [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	65,760	46,320	130,301	71,826
TEP | Operating Segments [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	45,763	16,591	62,915	35,837
TEP | Operating Segments [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	3,549	7,077	6,900	15,795
TEP | Operating Segments [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,089)	(1,036)	(2,441)	(1,671)
TEP | Intersegment Eliminations [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	1,346	1,344	2,691	2,690
TEP | Intersegment Eliminations [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,410)	(1,344)	(2,765)	(2,690)
TEP | Intersegment Eliminations [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	64	0	74	0
TEP | Intersegment Eliminations [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	0	0	0	0
TEP | Segment Reconciling Items [Member]
Reconciliation to Net Income:
Equity in earnings of unconsolidated investment	23,321	0	23,321	0
Non-cash loss allocated to noncontrolling interest			0	(9,377)
Interest expense, net of noncontrolling interest	(9,233)	(3,893)	(16,732)	(7,333)
Depreciation and amortization expense, net of noncontrolling interest	(21,840)	(18,302)	(43,807)	(38,835)
Distributions from unconsolidated investment	(29,656)	0	(29,656)	0
Non-cash gain (loss) related to derivative instruments, net of noncontrolling interest	18,791	(131)	9,801	(41)
Noncash compensation expense	(1,469)	(1,727)	(2,635)	(3,254)
Non-cash loss from disposal of assets	$ (1,849)	$ 0	$ (1,849)	$ (4,483)

Reporting Segments Reporting Se

Reporting Segments Reporting Segments - Summary of TEP's Segment Capital Expenditures (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting Information [Line Items]
Capital expenditures	$ 28,491	$ 49,544
TEP
Segment Reporting Information [Line Items]
Capital expenditures	28,491	49,544
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	19,160	32,501
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	4,115	7,061
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	5,216	9,982
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 0	$ 0

Reporting Segments - Summary 61

Reporting Segments - Summary of TEP's Segment Information of Assets (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Assets	$ 3,039,919	$ 2,562,074
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Assets	1,425,917	1,439,418
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Assets	1,142,222	706,576
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Assets	408,055	409,795
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Assets	$ 63,725	$ 6,285

Reporting Segments - Additional

Reporting Segments - Additional Information (Detail) - Segment	6 Months Ended
	Jun. 30, 2016	May 06, 2016
Segment Reporting Information [Line Items]
Number of Reportable Segments	3
Rockies Express Pipeline LLC | Sempra U.S. Gas and Power [Member]
Segment Reporting Information [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		25.00%

Subsequent Events Subsequent 63

Subsequent Events Subsequent Events (Details) - USD ($) $ in Thousands	Jul. 01, 2016	Jun. 30, 2016	Jun. 30, 2015
Subsequent Event [Line Items]
Payments to Noncontrolling Interests		$ 425,882	$ 0
Water Solutions [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	8.00%
Payments to Noncontrolling Interests	$ 6,000
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	100.00%