Tallgrass Energy Partners 10-Q 2 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Nov. 02, 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	Sep. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	Q3
Trading Symbol	TEP
Amendment Flag	false
Common Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		72,115,405
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	Sep. 30, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 417	$ 1,611
Accounts receivable, net	53,085	57,757
Gas imbalances	890	1,227
Inventories	13,375	13,793
Derivative assets at fair value	25,690	0
Prepayments and other current assets	3,838	2,835
Total Current Assets	97,295	77,223
Property, plant and equipment, net	2,003,532	2,025,018
Goodwill	343,288	343,288
Intangible asset, net	94,280	96,546
Unconsolidated investment	455,401	0
Deferred financing costs, net	5,676	5,105
Deferred charges and other assets	10,816	14,894
Total Assets	3,010,288	2,562,074
Current Liabilities:
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)	17,046	22,218
Accounts payable to related parties	6,207	7,852
Gas imbalances	1,117	1,605
Derivative liabilities at fair value	197	0
Accrued taxes	20,676	13,844
Accrued liabilities	10,214	10,019
Deferred revenue	52,138	26,511
Other current liabilities	6,725	6,880
Total Current Liabilities	114,320	88,929
Long-term debt, net	1,398,003	753,000
Other long-term liabilities and deferred credits	7,341	5,143
Total Long-term Liabilities	1,405,344	758,143
Commitments and Contingencies
Equity:
Common unitholders (72,738,251 and 60,644,232 units issued and outstanding at September 30, 2016 and December 31, 2015, respectively)	2,094,821	1,618,766
General partner (834,391 units issued and outstanding at September 30, 2016 and December 31, 2015)	(637,945)	(348,841)
Total Partners' Equity	1,456,876	1,269,925
Noncontrolling interests	33,748	445,077
Total Equity	1,490,624	1,715,002
Total Liabilities and Equity	$ 3,010,288	$ 2,562,074

CONDENSED CONSOLIDATED BALANC3

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - USD ($)	Sep. 30, 2016	Dec. 31, 2015
Accounts payable (including $10,554 at December 31, 2015 related to variable interest entities)	$ 17,046,000	$ 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)	72,738,251	60,644,232
Limited Partner Units Outstanding (in units)	72,738,251	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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Crude oil transportation services	$ 91,387	$ 81,928	$ 279,281	$ 206,331
Natural gas transportation services	31,444	29,431	89,406	90,620
Sales of natural gas, NGLs, and crude oil	20,758	20,252	51,514	62,132
Processing and other revenues	8,536	6,557	24,260	26,730
Total Revenues	152,125	138,168	444,461	385,813
Operating Costs and Expenses:
Cost of sales (exclusive of depreciation and amortization shown below)	18,590	18,186	48,116	54,959
Cost of transportation services (exclusive of depreciation and amortization shown below)	13,528	14,862	43,924	39,069
Operations and maintenance	14,714	14,071	41,055	36,054
Depreciation and amortization	20,831	20,802	64,099	61,762
General and administrative	13,147	11,807	40,072	37,947
Taxes, other than income taxes	6,717	5,521	19,862	16,547
Loss on disposal of assets	0	0	(1,849)	(4,483)
Total Operating Costs and Expenses	87,527	85,249	258,977	250,821
Operating Income	64,598	52,919	185,484	134,992
Other Income (Expense):
Interest expense, net	(10,907)	(3,871)	(27,639)	(11,204)
Unrealized (loss) gain on derivative instrument	(4,419)	0	5,588	0
Equity in earnings of unconsolidated investment	12,066	0	35,387	0
Other income, net	480	502	1,267	1,983
Total Other (Expense) Income	(2,780)	(3,369)	14,603	(9,221)
Net income	61,818	49,550	200,087	125,771
Net income attributable to noncontrolling interests	(1,084)	(6,871)	(3,235)	(5,874)
Net income attributable to partners	60,734	42,679	196,852	119,897
Net income attributable to noncontrolling interests
General partner interest in net income	(27,674)	(12,146)	(73,347)	(30,614)
Common and subordinated unitholders' interest in net income	$ 33,060	$ 30,533	$ 123,505	$ 89,283
Basic net income per common and subordinated unit	$ 0.45	$ 0.50	$ 1.75	$ 1.54
Diluted net income per common and subordinated unit	$ 0.45	$ 0.50	$ 1.73	$ 1.52
Basic average number of common and subordinated units outstanding	73,089	60,576	70,686	57,917
Diluted average number of common and subordinated units outstanding	74,063	61,536	71,590	58,884

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash Flows from Operating Activities:
Net income	$ 200,087	$ 125,771
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	68,693	64,624
Equity in earnings of unconsolidated investment	35,387	0
Distributions from unconsolidated investment	35,387	0
Noncash compensation expense	4,270	3,988
Noncash change in fair value of derivative financial instruments	5,391	218
Loss on disposal of assets	(1,849)	(4,483)
Changes in components of working capital:
Accounts receivable and other	(7,924)	11,538
Inventories	867	5,265
Accounts payable and accrued liabilities	4,827	6,786
Deferred revenue	25,303	13,995
Other operating, net	(779)	(5,142)
Net Cash Provided by Operating Activities	(305,916)	(197,484)
Cash Flows from Investing Activities:
Capital expenditures	45,252	65,146
Payments to Acquire Equity Method Investments	35,452	0
Payments to Acquire Additional Interest in Subsidiaries	49,118	700,000
Distributions from unconsolidated investment in excess of cumulative earnings	16,073	0
Other investing, net	(205)	4,625
Net Cash Used in Investing Activities	(549,566)	(769,771)
Net Cash Provided by Financing Activities
Payments to Noncontrolling Interests	425,882	0
Proceeds from Issuance of Senior Long-term Debt	400,000	0
Proceeds from public offering, net of offering costs	290,474	551,243
Borrowings under revolving credit facility, net	252,000	137,000
Distributions to unitholders	207,539	113,260
Partial exercise of call option	151,434	0
Proceeds from private placement, net of offering costs	90,009	0
Contributions from noncontrolling interests	8,700	19,303
Other financing, net	(13,872)	(4,161)
Net Cash Provided by (Used in) Financing Activities	242,456	590,125
Net Change in Cash and Cash Equivalents
Net Change in Cash and Cash Equivalents	(1,194)	17,838
Cash and Cash Equivalents, beginning of period	1,611	867
Cash and Cash Equivalents, end of period	417	18,705
Supplemental Disclosures:
Property, plant and equipment acquired via the cash management agreement with Tallgrass Development, LP	0	120,254
Contributions from noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP	0	43,401
Distribution to noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP	0	44,142
Rockies Express Pipeline LLC
Adjustments to reconcile net income to net cash flows provided by operating activities:
Equity in earnings of unconsolidated investment	35,400
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 SolutionsGeneral Partner	Water SolutionsCommon unitholdersLimited Partner	Water SolutionsSubordinated UnitsLimited Partner	Water SolutionsTotal Partner Equity Excluding Portion Attributable to Noncontrolling Interest	Water SolutionsNoncontrolling Interest	Water SolutionsTotal 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	$ 125,771	30,614	84,103	5,180	119,897	5,874	125,771
Issuance of units to public, net of offering costs		0	551,243	0	551,243	0	551,243
Proceeds from private placement, net of offering costs	0
Distributions to unitholders		(23,021)	(82,382)	(7,857)	(113,260)	0	(113,260)
Noncash compensation expense		0	7,325	0	7,325	0	7,325
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)
Partial exercise of call option	0
Contributions from noncontrolling interests	19,303	0	0	0	0	110,553	110,553
Payments to Noncontrolling Interests	0	0	0	0	0	44,543	44,543
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		(352,478)	1,625,516	0	1,273,038	452,040	1,725,078
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	200,087	73,347	123,505	0	196,852	3,235	200,087
Issuance of units to public, net of offering costs	290,500	0	290,474	0	290,474	0	290,474
Proceeds from private placement, net of offering costs	90,009	0	90,009	0	90,009	0	90,009
Distributions to unitholders		(61,875)	(145,664)	0	(207,539)	0	(207,539)
Noncash compensation expense		0	5,931	0	5,931	0	5,931
Acquisitions									$ (279,967)	$ 268,607	$ 0	$ (11,360)	$ (417,679)	$ (429,039)
Equity impact of partial exercise of call option		25,858	151,434	0	177,292	0	177,292
Partial exercise of call option	151,434
Contributions from TD		5,308	0	0	5,308	0	5,308
Contributions from noncontrolling interests	8,700	0	0	0	0	8,700	8,700
Payments to Noncontrolling Interests	425,882	0	0	0	0	5,017	5,017	$ 425,882
Payments to Acquire Additional Interest in Subsidiaries	49,118							$ 49,118							$ 59	$ 5,373	$ 0	$ 5,432	$ 568	$ 6,000
Partners' Capital, Including Portion Attributable to Noncontrolling Interest	$ 1,490,624	$ (637,945)	$ 2,094,821	$ 0	$ 1,456,876	$ 33,748	$ 1,490,624

Description of Business

Description of Business	9 Months Ended
	Sep. 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 September 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 (1) 43,427,917 — 59.70 % 59.04 % Tallgrass Equity, LLC 20,000,000 — 27.50 % 27.18 % Tallgrass Development, LP (2) 9,310,334 — 12.80 % 12.65 % Tallgrass MLP GP, LLC (3) — 834,391 — % 1.13 % Total (4) 72,738,251 834,391 100.00 % 100.00 % (1) As discussed in Note 10 – Partnership Equity and Distributions , we issued and sold an additional 628,914 common units subsequent to September 30, 2016 . As of November 2, 2016 , there were 44,056,831 common units held by public unitholders outstanding. (2) As discussed in Note 8 – Risk Management , 1,251,760 of the common units held by Tallgrass Development, LP ("TD") as of September 30, 2016 were subsequently deemed cancelled as of October 31, 2016. As of November 2, 2016 , there were 8,058,574 common units held by TD outstanding. (3) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights. (4) As of November 2, 2016 , there were 72,949,796 total limited partner and general partner units outstanding.

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 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 nine months ended September 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 nine months ended September 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 nine months ended September 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. Accounting Pronouncements Not Yet Adopted Revenue Recognition In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. Throughout 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. In light of this recently issued accounting guidance, we have started the process of reviewing our existing revenue contracts. Due to the early stage of this process, we are currently not in a position to estimate the impact the guidance will have on our consolidated financial statements. We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts as of January 1, 2018 through a cumulative adjustment to equity. Consolidated revenues for periods prior to January 1, 2018 would not be revised. 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, but do not anticipate a material impact on our consolidated financial statements. 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, but do not anticipate a material impact on our consolidated financial statements. Accounting Pronouncements Recently Adopted ASU No. 2016-15, "Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments" In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 provides explicit guidance on accounting for eight specific cash flow issues with the objective of reducing diversity in practice, including debt prepayment or debt extinguishment costs, settlement of certain debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. The amendments in ASU 2016-015 are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. We adopted the standard effective January 1, 2016. The adoption of ASU 2016-15 did not have a material impact on our financial position and results of operations. 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 changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 modifies the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, and changes 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	9 Months Ended
	Sep. 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 September 30, 2016 was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 7,878 2 - 25 years Property, plant and equipment (406,987 ) 35 years Total basis difference $ (399,109 ) During the period from May 6, 2016 to September 30, 2016 , we recognized equity in earnings from Rockies Express of $35.4 million , inclusive of the amortization of the negative basis difference discussed above, and received distributions from and made contributions to Rockies Express of $51.5 million and $35.5 million , respectively. Summarized financial information for Rockies Express is as follows: September 30, 2016 (in thousands) Current assets $ 170,472 Noncurrent assets $ 6,058,941 Current liabilities $ 173,447 Noncurrent liabilities $ 2,638,071 Members' equity $ 3,417,895 Three Months Ended September 30, 2016 Period from May 6, 2016 to September 30, 2016 (in thousands) Revenue $ 159,421 $ 257,582 Operating income $ 66,436 $ 110,268 Net income to Members $ 34,184 $ 118,925 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 covering 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 8 – Risk Management , on July 21, 2016, we partially exercised the option covering 3,563,146 of the common units. On October 31, 2016, we partially exercised the option covering 1,251,760 of the common units, leaving 1,703,094 remaining common units subject to the call option as of November 2, 2016 . As a result of the partial exercise on July 21, 2016, TEP derecognized a portion of the derivative asset balance, recognizing approximately $25.9 million through equity during the nine months ended September 30, 2016 , as discussed further in Note 10 – Partnership Equity and Distributions . 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 has 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 10 – 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 nine months ended September 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. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of September 30, 2016. TEP's unaudited pro forma revenue and net income attributable to partners for the three and nine months ended September 30, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015: Three Months Ended September 30, 2015 Nine Months Ended September 30, 2015 (in thousands) Revenue $ 138,651 $ 387,245 Net income attributable to partners $ 42,847 $ 120,395 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. Acquisition of Additional Membership Interest in Water Solutions 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% .

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 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 nine months ended September 30, 2016 . During the nine months ended September 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. Transactions with affiliated companies, excluding transactions otherwise disclosed, are as follows: Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in thousands) Cost of transportation services $ 7,313 $ 7,180 $ 21,864 $ 17,771 Charges to TEP: (1) Property, plant and equipment, net $ 432 $ 958 $ 1,953 $ 3,859 Operation and maintenance $ 6,317 $ 6,077 $ 18,778 $ 17,325 General and administrative $ 9,567 $ 9,541 $ 28,784 $ 28,112 (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: September 30, 2016 December 31, 2015 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 126 $ 15 Total receivable from related parties $ 126 $ 15 Accounts payable to related parties: Tallgrass Operations, LLC $ 6,139 $ 7,792 Tallgrass Equity, LLC 68 36 Deeprock Development, LLC — 17 Rockies Express Pipeline LLC — 7 Total accounts payable to related parties $ 6,207 $ 7,852 Balances of gas imbalances with affiliated shippers are as follows: September 30, 2016 December 31, 2015 (in thousands) Affiliate gas imbalance receivables $ 82 $ 92 Affiliate gas imbalance payables $ 161 $ 227

Inventory

Inventory	9 Months Ended
	Sep. 30, 2016
Inventory Disclosure [Abstract]
Inventory	The components of inventory at September 30, 2016 and December 31, 2015 consisted of the following: September 30, 2016 December 31, 2015 (in thousands) Crude oil $ 4,223 $ 2,661 Materials and supplies 6,505 8,581 Natural gas liquids 255 395 Gas in underground storage 2,392 2,156 Total inventory $ 13,375 $ 13,793

Property, Plant and Equipment

Property, Plant and Equipment	9 Months Ended
	Sep. 30, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	A summary of net property, plant and equipment by classification is as follows: September 30, 2016 December 31, 2015 (in thousands) Crude oil pipelines $ 1,182,806 $ 1,172,684 Natural gas pipelines 553,437 550,710 Processing and treating assets 256,331 254,073 Water business assets 81,507 81,098 General and other 71,190 69,181 Construction work in progress 38,454 30,699 Accumulated depreciation and amortization (180,193 ) (133,427 ) Total property, plant and equipment, net $ 2,003,532 $ 2,025,018

Risk Management

Risk Management	9 Months Ended
	Sep. 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 September 30, 2016 December 31, 2015 (in thousands) Call option derivative (1) Current assets $ 25,690 $ — Natural gas derivative contracts (2) Current liabilities $ 190 $ — Crude oil derivative contract (3) Current liabilities $ 7 $ — (1) 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 covering the 6,518,000 common units issued to TD. (2) As of September 30, 2016 , the fair value shown for natural gas derivative 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. (3) As of September 30, 2016 , the fair value shown for crude oil derivative contracts was comprised of the sale of 30,000 barrels in October 2016. As of December 31, 2015 there were no crude oil 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 nine months ended September 30, 2016 and 2015 : Location of gain (loss) recognized Amount of gain (loss) recognized in income on derivatives Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in thousands) Derivatives not designated as hedging contracts: Call option derivative Unrealized (loss) gain on derivative instrument $ (4,419 ) $ — $ 5,588 $ — Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ 161 $ 252 $ (190 ) $ 211 Crude oil derivative contract Sales of natural gas, NGLs, and crude oil $ 318 $ — $ 466 $ — 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 covering 3,563,146 common units for a cash payment of $151.4 million . On October 31, 2016, we partially exercised the call option again covering an additional 1,251,760 common units for a cash payment of $53.2 million . These common units were deemed canceled upon the exercise of the call option and as of such exercise date were no longer issued and outstanding. As of November 2, 2016 , 1,703,094 common units remained subject to 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. 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 September 30, 2016 , the fair value of our crude oil and natural gas derivative contracts were a liability, resulting in no credit exposure from TEP's counterparties as of that date. As of September 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 commodity derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy. The call option granted by TD 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. Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management's best estimate is used. The following table summarizes the fair value measurements of our derivative contracts as of September 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 September 30, 2016: Call option derivative $ 25,690 $ — $ 25,690 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of September 30, 2016: Natural gas derivative contracts $ 190 $ — $ 190 $ — Crude oil derivative contract $ 7 $ — $ 7 $ —

Long-term Debt

Long-term Debt	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Long-term Debt	Long-term debt consisted of the following at September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 (in thousands) Revolving credit facility $ 1,005,000 $ 753,000 5.50% senior notes due September 15, 2024 400,000 — Less: Deferred financing costs, net (1) (6,997 ) — Total long-term debt, net $ 1,398,003 $ 753,000 (1) Deferred financing costs, net as presented above relate solely to the 2024 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our condensed consolidated balance sheets. Senior Unsecured Notes On September 1, 2016, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016 (the "Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). TEP used the net proceeds of the offering to repay outstanding borrowings under its existing senior secured revolving credit facility. The 2024 Notes are general unsecured senior obligations of the Issuers. The 2024 Notes are unconditionally guaranteed jointly and severally on a senior unsecured basis by TEP's existing direct and indirect wholly owned subsidiaries (other than the Co-Issuer) and certain of TEP's future subsidiaries (the "Guarantors"). The 2024 Notes rank equal in right of payment with all existing and future senior indebtedness of the Issuers, and senior in right of payment to any future subordinated indebtedness of the Issuers. The 2024 Notes will mature on September 15, 2024 and interest on the 2024 Notes is payable in cash semi-annually in arrears on each March 15 and September 15, commencing March 15, 2017. TEP may redeem the 2024 Notes prior to their scheduled maturity at the applicable redemption price set forth in the Indenture, plus accrued and unpaid interest. The Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. As of September 30, 2016 , we are in compliance with the covenants required under the 2024 Notes. 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 September 30, 2016 and December 31, 2015 : September 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) (1,005,000 ) (753,000 ) Available capacity under the revolving credit facility $ 745,000 $ 347,000 (1) As of October 31, 2016, our outstanding borrowings under the revolving credit facility were approximately $1.003 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 September 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 September 30, 2016 , the weighted average interest rate on outstanding borrowings was 2.28% . During the nine months ended September 30, 2016 , our weighted average effective interest rate, including the interest on outstanding borrowings, commitment fees, and amortization of deferred financing costs, was 2.72% . 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 September 30, 2016 and December 31, 2015 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of September 30, 2016: Revolving credit facility $ — $ 1,005,000 $ — $ 1,005,000 $ 1,005,000 2024 Notes $ — $ 403,752 $ — $ 403,752 $ 393,003 As of December 31, 2015: Revolving credit facility $ — $ 753,000 $ — $ 753,000 $ 753,000 The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of September 30, 2016 and December 31, 2015 , the fair value of borrowings under the revolving credit facility approximates the carrying amount of the borrowings using a discounted cash flow analysis. The 2024 Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the 2024 Notes is based upon quoted market prices adjusted for illiquid markets. We are not aware of any factors that would significantly affect the estimated fair value subsequent to September 30, 2016 .

Partnership Equity and Distribu

Partnership Equity and Distributions	9 Months Ended
	Sep. 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 Partnership's exercise of the call option with respect to the 6,518,000 common units issued to TD in connection with the Partnership's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to working capital. During the three months ended September 30, 2016 , we issued and sold 622,846 common units with a weighted average sales price of $47.39 per unit under our equity distribution agreements for net cash proceeds of approximately $28.7 million (net of approximately $0.8 million in commissions and professional service expenses). During the nine months ended September 30, 2016 , we issued and sold 6,703,984 common units with a weighted average sales price of $43.98 per unit under our equity distribution agreements for net cash proceeds of approximately $290.5 million (net of approximately $4.4 million in commissions and professional service expenses). During the period from October 1, 2016 to November 2, 2016, we issued and sold an additional 628,914 common units with a weighted average sales price of $48.05 per unit under our equity distribution agreement for net cash proceeds of approximately $29.9 million (net of approximately $0.3 million in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes as described above. 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 nine months ended September 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) September 30, 2016 November 14, 2016 (1) $ 57,332 $ 26,987 $ 976 $ 85,295 $ 0.7950 June 30, 2016 August 12, 2016 54,442 24,262 911 79,615 0.7550 March 31, 2016 May 13, 2016 48,238 19,816 830 68,884 0.7050 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 October 5, 2016 for the third quarter of 2016 will be paid on November 14, 2016 to unitholders of record at the close of business on October 31, 2016 . Other Contributions and Distributions During the nine months ended September 30, 2016 , TEP was deemed to have made noncash capital distributions of $280.0 million and $25.9 million to the general partner, which represent the excess purchase price over the carrying value of the additional 31.3% membership interest in Pony Express acquired effective January 1, 2016 and the derecognition of a portion of the derivative asset associated with the partial exercise of the call option, respectively. See Note 3 – Acquisitions for additional information regarding these transactions. During the nine months ended September 30, 2016 , TEP also received contributions of $5.3 million from TD to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 13 – Legal and Environmental Matters , and received contributions and distributions from noncontrolling interests of $8.7 million and $5.0 million , which primarily consisted of activity associated with TD's 2% noncontrolling interest in Pony Express. During the nine months ended September 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 $110.6 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 $44.5 million .

Net Income per Limited Partner

Net Income per Limited Partner Unit	9 Months Ended
	Sep. 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 nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in thousands, except per unit amounts) Net income $ 61,818 $ 49,550 $ 200,087 $ 125,771 Net income attributable to noncontrolling interests (1,084 ) (6,871 ) (3,235 ) (5,874 ) Net income attributable to partners 60,734 42,679 196,852 119,897 General partner interest in net income (27,674 ) (12,146 ) (73,347 ) (30,614 ) Net income available to common and subordinated unitholders $ 33,060 $ 30,533 $ 123,505 $ 89,283 Basic net income per common and subordinated unit $ 0.45 $ 0.50 $ 1.75 $ 1.54 Diluted net income per common and subordinated unit $ 0.45 $ 0.50 $ 1.73 $ 1.52 Basic average number of common and subordinated units outstanding 73,089 60,576 70,686 57,917 Equity Participation Unit equivalent units 974 960 904 967 Diluted average number of common and subordinated units outstanding 74,063 61,536 71,590 58,884

Regulatory Matters

Regulatory Matters	9 Months Ended
	Sep. 30, 2016
Regulatory Matters [Abstract]
Regulatory Matters	There are currently no proceedings challenging the currently effective transportation 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, had a right to challenge any aspect of TIGT's rate case filing. Accordingly, numerous TIGT customers 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 the 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 FERC 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 FERC 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 FERC'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 FERC 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 FERC policy implications, and appears to be just, reasonable, and in the public interest. The FERC issued an order on November 2, 2016 approving the settlement, finding that it appears to be fair and reasonable and in the public interest. Trailblazer 2016 Annual Fuel Tracker Filing – FERC Docket Nos. RP16-814-000 and RP16-814-001 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. On May 19, 2016, Trailblazer filed its refund report associated with the April 1, 2016 annual fuel tracker filing, which the FERC accepted on July 11, 2016. On September 7, 2016, Trailblazer filed an adjustment to its April 1, 2016 fuel tracker filing. As a result of this adjustment, Trailblazer proposed to issue additional cash-out refunds to applicable shippers and also reflect this adjustment in its applicable fuel accounts. The FERC accepted this filing on October 3, 2016. On October 14, 2016, Trailblazer filed its refund report associated with its September 7, 2016 adjustment filing. Rockies Express Annual FERC Fuel Tracking Filings – FERC Docket Nos. RP16-702-000 and RP16-1301-000 On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702. The FERC issued an order accepting the filing on March 25, 2016. On September 30, 2016, Rockies Express elected to make an interim fuel tracker filing with a proposed effective date of November 1, 2016 in Docket No. RP16-1301-000. This interim filing proposes increases to most applicable fuel and power rates as a result of increased system utilization. On October 12, 2016, certain shippers filed a protest with the FERC regarding the proposed increases. Rockies Express filed a response to the protest on October 20, 2016, to which the shippers replied on October 25, 2016. On October 20, 2016, Rockies Express also filed an errata to rates applicable to a pooling and wheeling service. The FERC set a November 1, 2016 comment deadline on the errata filing. The interim filing remains pending before the FERC. Seneca Lateral Facilities Conversion – FERC Docket No. CP15-102-000 On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with the 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 Seneca Lateral commenced Natural Gas Act service on June 1, 2016. Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000 On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The 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.

Legal and Environmental Matters

Legal and Environmental Matters	9 Months Ended
	Sep. 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 September 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 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 in the Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels 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 $4.3 million and $4.8 million at September 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. During the nine months ended September 30, 2016 , TEP received contributions of $5.3 million from TD related to the indemnity.

Reporting Segments

Reporting Segments	9 Months Ended
	Sep. 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, Denver-Julesburg and Powder River Basins, and other nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado and was placed in service in the second quarter of 2015. 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 September 30, 2016 Three Months Ended September 30, 2015 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 95,826 $ — $ 95,826 $ 83,272 $ — $ 83,272 Natural Gas Transportation & Logistics 33,812 (1,427 ) 32,385 33,636 (1,346 ) 32,290 Processing & Logistics 23,914 — 23,914 22,606 — 22,606 Corporate and Other — — — — — — Total Revenue $ 153,552 $ (1,427 ) $ 152,125 $ 139,514 $ (1,346 ) $ 138,168 Nine Months Ended September 30, 2016 Nine Months Ended September 30, 2015 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 283,868 $ — $ 283,868 $ 208,872 $ — $ 208,872 Natural Gas Transportation & Logistics 94,949 (4,192 ) 90,757 98,215 (4,036 ) 94,179 Processing & Logistics 69,836 — 69,836 82,762 — 82,762 Corporate and Other — — — — — — Total Revenue $ 448,653 $ (4,192 ) $ 444,461 $ 389,849 $ (4,036 ) $ 385,813 Three Months Ended September 30, 2016 Three Months Ended September 30, 2015 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 65,431 $ 1,346 $ 66,777 $ 47,526 $ 1,346 $ 48,872 Natural Gas Transportation & Logistics 41,253 (1,427 ) 39,826 15,983 (1,346 ) 14,637 Processing & Logistics 3,210 81 3,291 3,046 — 3,046 Corporate and Other (1,368 ) — (1,368 ) (703 ) — (703 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment 12,066 — Less: Interest expense, net of noncontrolling interest (10,907 ) (3,872 ) Depreciation and amortization expense, net of noncontrolling interest (21,102 ) (18,826 ) Distributions from unconsolidated investment (21,804 ) — Non-cash (loss) gain related to derivative instruments, net of noncontrolling interest (4,410 ) 259 Non-cash compensation expense (1,635 ) (734 ) Net income attributable to partners $ 60,734 $ 42,679 Nine Months Ended September 30, 2016 Nine Months Ended September 30, 2015 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 195,732 $ 4,037 $ 199,769 $ 119,352 $ 4,036 $ 123,388 Natural Gas Transportation & Logistics 104,168 (4,192 ) 99,976 51,820 (4,036 ) 47,784 Processing & Logistics 10,110 155 10,265 18,841 — 18,841 Corporate and Other (3,809 ) — (3,809 ) (2,374 ) — (2,374 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment 35,387 — Non-cash loss allocated to noncontrolling interest — 9,377 Less: Interest expense, net of noncontrolling interest (27,639 ) (11,205 ) Depreciation and amortization expense, net of noncontrolling interest (64,909 ) (57,661 ) Distributions from unconsolidated investment (51,460 ) — Non-cash gain related to derivative instruments, net of noncontrolling interest 5,391 218 Non-cash compensation expense (4,270 ) (3,988 ) Non-cash loss from asset sales (1,849 ) (4,483 ) Net income attributable to partners $ 196,852 $ 119,897 Nine Months Ended September 30, Capital Expenditures: 2016 2015 (in thousands) Crude Oil Transportation & Logistics $ 25,985 $ 40,579 Natural Gas Transportation & Logistics 11,146 10,858 Processing & Logistics 8,121 13,709 Corporate and Other — — Total capital expenditures $ 45,252 $ 65,146 Assets: September 30, 2016 December 31, 2015 (in thousands) Crude Oil Transportation & Logistics $ 1,417,241 $ 1,439,418 Natural Gas Transportation & Logistics 1,155,372 706,576 Processing & Logistics 405,760 409,795 Corporate and Other 31,915 6,285 Total assets $ 3,010,288 $ 2,562,074

Subsequent Events Subsequent Ev

Subsequent Events Subsequent Events	9 Months Ended
	Sep. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	[PLACEHOLDER]

Goodwill (Notes)

Goodwill (Notes)	9 Months Ended
	Sep. 30, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill Disclosure	Annual Goodwill Impairment Analysis We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. We evaluate goodwill for impairment at the reporting unit level, which is an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or the two-step test approach depending on facts and circumstances of the reporting unit. If we, after performing the qualitative assessment, determine it is “more likely than not” that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. When goodwill is evaluated for impairment using the two-step test, the carrying amount of the reporting unit is compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit's fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss. We did not elect to apply the qualitative assessment option during our 2016 annual goodwill impairment testing; instead we proceeded directly to the two-step quantitative test. In Step 1 of the two-step quantitative test, we compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the Step 1 impairment analysis indicated no potential impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, Step 2 of the impairment analysis was not necessary as part of the annual impairment analysis in 2016. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These condensed consolidated financial statements and related notes for the three and nine months ended September 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 nine months ended September 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 nine months ended September 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	Accounting Pronouncements Not Yet Adopted Revenue Recognition In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. Throughout 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. In light of this recently issued accounting guidance, we have started the process of reviewing our existing revenue contracts. Due to the early stage of this process, we are currently not in a position to estimate the impact the guidance will have on our consolidated financial statements. We expect to adopt the new standard on January 1, 2018 using the modified retrospective approach. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts as of January 1, 2018 through a cumulative adjustment to equity. Consolidated revenues for periods prior to January 1, 2018 would not be revised. 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, but do not anticipate a material impact on our consolidated financial statements. 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, but do not anticipate a material impact on our consolidated financial statements. Accounting Pronouncements Recently Adopted ASU No. 2016-15, "Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments" In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 provides explicit guidance on accounting for eight specific cash flow issues with the objective of reducing diversity in practice, including debt prepayment or debt extinguishment costs, settlement of certain debt instruments, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. The amendments in ASU 2016-015 are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. We adopted the standard effective January 1, 2016. The adoption of ASU 2016-15 did not have a material impact on our financial position and results of operations. 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 changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 modifies the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, and changes 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)	9 Months Ended
	Sep. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments, Policy	Our investment in Rockies Express is recorded under the equity method of accounting and 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.

Goodwill (Policies)

Goodwill (Policies)	9 Months Ended
	Sep. 30, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets, Goodwill, Policy	Annual Goodwill Impairment Analysis We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. We evaluate goodwill for impairment at the reporting unit level, which is an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or the two-step test approach depending on facts and circumstances of the reporting unit. If we, after performing the qualitative assessment, determine it is “more likely than not” that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. When goodwill is evaluated for impairment using the two-step test, the carrying amount of the reporting unit is compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit's fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss. We did not elect to apply the qualitative assessment option during our 2016 annual goodwill impairment testing; instead we proceeded directly to the two-step quantitative test. In Step 1 of the two-step quantitative test, we compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the Step 1 impairment analysis indicated no potential impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, Step 2 of the impairment analysis was not necessary as part of the annual impairment analysis in 2016. Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary.

Description of Business Schedul

Description of Business Schedule of Other Ownership Interests (Tables)	9 Months Ended
	Sep. 30, 2016
Schedule of Other Ownership Interests [Abstract]
Schedule of Ownership Interests	The table below summarizes our equity ownership as of September 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 (1) 43,427,917 — 59.70 % 59.04 % Tallgrass Equity, LLC 20,000,000 — 27.50 % 27.18 % Tallgrass Development, LP (2) 9,310,334 — 12.80 % 12.65 % Tallgrass MLP GP, LLC (3) — 834,391 — % 1.13 % Total (4) 72,738,251 834,391 100.00 % 100.00 % (1) As discussed in Note 10 – Partnership Equity and Distributions , we issued and sold an additional 628,914 common units subsequent to September 30, 2016 . As of November 2, 2016 , there were 44,056,831 common units held by public unitholders outstanding. (2) As discussed in Note 8 – Risk Management , 1,251,760 of the common units held by Tallgrass Development, LP ("TD") as of September 30, 2016 were subsequently deemed cancelled as of October 31, 2016. As of November 2, 2016 , there were 8,058,574 common units held by TD outstanding. (3) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights. (4) As of November 2, 2016 , there were 72,949,796 total limited partner and general partner units outstanding.

Acquisitions Equity Method In26

Acquisitions Equity Method Investment (Tables)	9 Months Ended
	Sep. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Summarized financial information for Rockies Express is as follows: September 30, 2016 (in thousands) Current assets $ 170,472 Noncurrent assets $ 6,058,941 Current liabilities $ 173,447 Noncurrent liabilities $ 2,638,071 Members' equity $ 3,417,895 Three Months Ended September 30, 2016 Period from May 6, 2016 to September 30, 2016 (in thousands) Revenue $ 159,421 $ 257,582 Operating income $ 66,436 $ 110,268 Net income to Members $ 34,184 $ 118,925 The basis difference at September 30, 2016 was allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 7,878 2 - 25 years Property, plant and equipment (406,987 ) 35 years Total basis difference $ (399,109 )
Business Acquisition, Pro Forma Information	TEP's unaudited pro forma revenue and net income attributable to partners for the three and nine months ended September 30, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015: Three Months Ended September 30, 2015 Nine Months Ended September 30, 2015 (in thousands) Revenue $ 138,651 $ 387,245 Net income attributable to partners $ 42,847 $ 120,395

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2016
Related Party Transactions [Abstract]
Schedule of Transactions with Affiliated Companies	ransactions with affiliated companies, excluding transactions otherwise disclosed, are as follows: Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in thousands) Cost of transportation services $ 7,313 $ 7,180 $ 21,864 $ 17,771 Charges to TEP: (1) Property, plant and equipment, net $ 432 $ 958 $ 1,953 $ 3,859 Operation and maintenance $ 6,317 $ 6,077 $ 18,778 $ 17,325 General and administrative $ 9,567 $ 9,541 $ 28,784 $ 28,112 (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: September 30, 2016 December 31, 2015 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 126 $ 15 Total receivable from related parties $ 126 $ 15 Accounts payable to related parties: Tallgrass Operations, LLC $ 6,139 $ 7,792 Tallgrass Equity, LLC 68 36 Deeprock Development, LLC — 17 Rockies Express Pipeline LLC — 7 Total accounts payable to related parties $ 6,207 $ 7,852
Schedule of Balances of Gas Imbalance with Affiliated Shippers	Balances of gas imbalances with affiliated shippers are as follows: September 30, 2016 December 31, 2015 (in thousands) Affiliate gas imbalance receivables $ 82 $ 92 Affiliate gas imbalance payables $ 161 $ 227

Inventory (Tables)

Inventory (Tables)	9 Months Ended
	Sep. 30, 2016
Inventory Disclosure [Abstract]
Schedule of Components of Inventory	The components of inventory at September 30, 2016 and December 31, 2015 consisted of the following: September 30, 2016 December 31, 2015 (in thousands) Crude oil $ 4,223 $ 2,661 Materials and supplies 6,505 8,581 Natural gas liquids 255 395 Gas in underground storage 2,392 2,156 Total inventory $ 13,375 $ 13,793

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	9 Months Ended
	Sep. 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: September 30, 2016 December 31, 2015 (in thousands) Crude oil pipelines $ 1,182,806 $ 1,172,684 Natural gas pipelines 553,437 550,710 Processing and treating assets 256,331 254,073 Water business assets 81,507 81,098 General and other 71,190 69,181 Construction work in progress 38,454 30,699 Accumulated depreciation and amortization (180,193 ) (133,427 ) Total property, plant and equipment, net $ 2,003,532 $ 2,025,018

Risk Management (Tables)

Risk Management (Tables)	9 Months Ended
	Sep. 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 September 30, 2016 December 31, 2015 (in thousands) Call option derivative (1) Current assets $ 25,690 $ — Natural gas derivative contracts (2) Current liabilities $ 190 $ — Crude oil derivative contract (3) Current liabilities $ 7 $ — (1) 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 covering the 6,518,000 common units issued to TD. (2) As of September 30, 2016 , the fair value shown for natural gas derivative 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. (3) As of September 30, 2016 , the fair value shown for crude oil derivative contracts was comprised of the sale of 30,000 barrels in October 2016. As of December 31, 2015 there were no crude oil derivative contracts outstanding.
Derivative Contracts Included in Consolidated Statements of Income	The following table summarizes the impact of derivative contracts for the three and nine months ended September 30, 2016 and 2015 : Location of gain (loss) recognized Amount of gain (loss) recognized in income on derivatives Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in thousands) Derivatives not designated as hedging contracts: Call option derivative Unrealized (loss) gain on derivative instrument $ (4,419 ) $ — $ 5,588 $ — Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ 161 $ 252 $ (190 ) $ 211 Crude oil derivative contract Sales of natural gas, NGLs, and crude oil $ 318 $ — $ 466 $ —
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 September 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 September 30, 2016: Call option derivative $ 25,690 $ — $ 25,690 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of September 30, 2016: Natural gas derivative contracts $ 190 $ — $ 190 $ — Crude oil derivative contract $ 7 $ — $ 7 $ —

Long-term Debt (Tables)

Long-term Debt (Tables)	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Schedule of Debt	Long-term debt consisted of the following at September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 (in thousands) Revolving credit facility $ 1,005,000 $ 753,000 5.50% senior notes due September 15, 2024 400,000 — Less: Deferred financing costs, net (1) (6,997 ) — Total long-term debt, net $ 1,398,003 $ 753,000 (1) Deferred financing costs, net as presented above relate solely to the 2024 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our condensed consolidated balance sheets.
Schedule of Line of Credit Facilities	The following table sets forth the available borrowing capacity under the revolving credit facility as of September 30, 2016 and December 31, 2015 : September 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) (1,005,000 ) (753,000 ) Available capacity under the revolving credit facility $ 745,000 $ 347,000 (1) As of October 31, 2016, our outstanding borrowings under the revolving credit facility were approximately $1.003 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 September 30, 2016 and December 31, 2015 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of September 30, 2016: Revolving credit facility $ — $ 1,005,000 $ — $ 1,005,000 $ 1,005,000 2024 Notes $ — $ 403,752 $ — $ 403,752 $ 393,003 As of December 31, 2015: Revolving credit facility $ — $ 753,000 $ — $ 753,000 $ 753,000

Partnership Equity and Distri32

Partnership Equity and Distributions (Tables)	9 Months Ended
	Sep. 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) September 30, 2016 November 14, 2016 (1) $ 57,332 $ 26,987 $ 976 $ 85,295 $ 0.7950 June 30, 2016 August 12, 2016 54,442 24,262 911 79,615 0.7550 March 31, 2016 May 13, 2016 48,238 19,816 830 68,884 0.7050 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 October 5, 2016 for the third quarter of 2016 will be paid on November 14, 2016 to unitholders of record at the close of business on October 31, 2016 .

Net Income per Limited Partne33

Net Income per Limited Partner Unit (Tables)	9 Months Ended
	Sep. 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 nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 (in thousands, except per unit amounts) Net income $ 61,818 $ 49,550 $ 200,087 $ 125,771 Net income attributable to noncontrolling interests (1,084 ) (6,871 ) (3,235 ) (5,874 ) Net income attributable to partners 60,734 42,679 196,852 119,897 General partner interest in net income (27,674 ) (12,146 ) (73,347 ) (30,614 ) Net income available to common and subordinated unitholders $ 33,060 $ 30,533 $ 123,505 $ 89,283 Basic net income per common and subordinated unit $ 0.45 $ 0.50 $ 1.75 $ 1.54 Diluted net income per common and subordinated unit $ 0.45 $ 0.50 $ 1.73 $ 1.52 Basic average number of common and subordinated units outstanding 73,089 60,576 70,686 57,917 Equity Participation Unit equivalent units 974 960 904 967 Diluted average number of common and subordinated units outstanding 74,063 61,536 71,590 58,884

Reporting Segments (Tables)

Reporting Segments (Tables)	9 Months Ended
	Sep. 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 September 30, 2016 Three Months Ended September 30, 2015 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 95,826 $ — $ 95,826 $ 83,272 $ — $ 83,272 Natural Gas Transportation & Logistics 33,812 (1,427 ) 32,385 33,636 (1,346 ) 32,290 Processing & Logistics 23,914 — 23,914 22,606 — 22,606 Corporate and Other — — — — — — Total Revenue $ 153,552 $ (1,427 ) $ 152,125 $ 139,514 $ (1,346 ) $ 138,168 Nine Months Ended September 30, 2016 Nine Months Ended September 30, 2015 Revenue: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 283,868 $ — $ 283,868 $ 208,872 $ — $ 208,872 Natural Gas Transportation & Logistics 94,949 (4,192 ) 90,757 98,215 (4,036 ) 94,179 Processing & Logistics 69,836 — 69,836 82,762 — 82,762 Corporate and Other — — — — — — Total Revenue $ 448,653 $ (4,192 ) $ 444,461 $ 389,849 $ (4,036 ) $ 385,813
Summary of TEP's Segment Information of Earnings	Three Months Ended September 30, 2016 Three Months Ended September 30, 2015 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 65,431 $ 1,346 $ 66,777 $ 47,526 $ 1,346 $ 48,872 Natural Gas Transportation & Logistics 41,253 (1,427 ) 39,826 15,983 (1,346 ) 14,637 Processing & Logistics 3,210 81 3,291 3,046 — 3,046 Corporate and Other (1,368 ) — (1,368 ) (703 ) — (703 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment 12,066 — Less: Interest expense, net of noncontrolling interest (10,907 ) (3,872 ) Depreciation and amortization expense, net of noncontrolling interest (21,102 ) (18,826 ) Distributions from unconsolidated investment (21,804 ) — Non-cash (loss) gain related to derivative instruments, net of noncontrolling interest (4,410 ) 259 Non-cash compensation expense (1,635 ) (734 ) Net income attributable to partners $ 60,734 $ 42,679 Nine Months Ended September 30, 2016 Nine Months Ended September 30, 2015 Adjusted EBITDA: Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 195,732 $ 4,037 $ 199,769 $ 119,352 $ 4,036 $ 123,388 Natural Gas Transportation & Logistics 104,168 (4,192 ) 99,976 51,820 (4,036 ) 47,784 Processing & Logistics 10,110 155 10,265 18,841 — 18,841 Corporate and Other (3,809 ) — (3,809 ) (2,374 ) — (2,374 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment 35,387 — Non-cash loss allocated to noncontrolling interest — 9,377 Less: Interest expense, net of noncontrolling interest (27,639 ) (11,205 ) Depreciation and amortization expense, net of noncontrolling interest (64,909 ) (57,661 ) Distributions from unconsolidated investment (51,460 ) — Non-cash gain related to derivative instruments, net of noncontrolling interest 5,391 218 Non-cash compensation expense (4,270 ) (3,988 ) Non-cash loss from asset sales (1,849 ) (4,483 ) Net income attributable to partners $ 196,852 $ 119,897
Summary of TEP's Segment Capital Expenditures	Nine Months Ended September 30, Capital Expenditures: 2016 2015 (in thousands) Crude Oil Transportation & Logistics $ 25,985 $ 40,579 Natural Gas Transportation & Logistics 11,146 10,858 Processing & Logistics 8,121 13,709 Corporate and Other — — Total capital expenditures $ 45,252 $ 65,146
Summary of TEP's Segment Information of Assets	Assets: September 30, 2016 December 31, 2015 (in thousands) Crude Oil Transportation & Logistics $ 1,417,241 $ 1,439,418 Natural Gas Transportation & Logistics 1,155,372 706,576 Processing & Logistics 405,760 409,795 Corporate and Other 31,915 6,285 Total assets $ 3,010,288 $ 2,562,074

Description of Business - Addit

Description of Business - Additional Information (Detail) - shares	Oct. 31, 2016	Jul. 21, 2016	Nov. 02, 2016	Sep. 30, 2016	Sep. 30, 2016	Dec. 31, 2015
Organization [Line Items]
Limited Partner Common Units				72,738,251	72,738,251	60,644,232
General Partner Units				834,391	834,391	834,391
Percentage of Outstanding Limited Partner Common Units				100.00%	100.00%
Percentage of Outstanding Common and General Partner Units				100.00%	100.00%
Partners' Capital Account, Units, Sold in Public Offering				622,846	6,703,984
Partners' Capital Account, Units, Treasury Units Purchased		3,563,146
Ownership Interests Held By Public
Organization [Line Items]
Limited Partner Common Units				43,427,917	43,427,917
General Partner Units				0	0
Percentage of Outstanding Limited Partner Common Units				59.70%	59.70%
Percentage of Outstanding Common and General Partner Units				59.04%	59.04%
Ownership Interests Held By Tallgrass Equity, LLC
Organization [Line Items]
Limited Partner Common Units				20,000,000	20,000,000
General Partner Units				0	0
Percentage of Outstanding Limited Partner Common Units				27.50%	27.50%
Percentage of Outstanding Common and General Partner Units				27.18%	27.18%
Ownership Interests Held By Tallgrass Development , LP
Organization [Line Items]
Limited Partner Common Units				9,310,334	9,310,334
General Partner Units				0	0
Percentage of Outstanding Limited Partner Common Units				12.80%	12.80%
Percentage of Outstanding Common and General Partner Units				12.65%	12.65%
Ownership Interests Held By Tallgrass MLP GP, LLC
Organization [Line Items]
Limited Partner Common Units				0	0
General Partner Units				834,391	834,391
Percentage of Outstanding Limited Partner Common Units				0.00%	0.00%
Percentage of Outstanding Common and General Partner Units				1.13%	1.13%
Rockies Express Pipeline LLC
Organization [Line Items]
Equity Method Investment, Ownership Percentage				25.00%	25.00%
Subsequent Event [Member]
Organization [Line Items]
Partners' Capital Account, Units, Sold in Public Offering			628,914
Partners' Capital Account, Units, Treasury Units Purchased	1,251,760
Capital Units, Outstanding			72,949,796
Subsequent Event [Member] | Ownership Interests Held By Public
Organization [Line Items]
Limited Partner Common Units			44,056,831
Subsequent Event [Member] | Ownership Interests Held By Tallgrass Development , LP
Organization [Line Items]
Limited Partner Common Units			8,058,574

Summary of Significant Accoun36

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	Sep. 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 In37

Acquisitions Equity Method Investments (Details) - Rockies Express Pipeline LLC - USD ($) $ in Thousands	May 06, 2016	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2016
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ (399,109)	$ (399,109)	$ (399,109)
Basis Difference, Amortization Period	35 years
Equity Method Investment, Summarized Financial Information, Current Assets		170,472	170,472	170,472
Equity Method Investment, Summarized Financial Information, Noncurrent Assets		6,058,941	6,058,941	6,058,941
Equity Method Investment, Summarized Financial Information, Current Liabilities		173,447	173,447	173,447
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities		2,638,071	2,638,071	2,638,071
Equity Method Investment Summarized Financial Information, Equity		3,417,895	3,417,895	3,417,895
Equity Method Investment, Summarized Financial Information, Revenue		159,421	257,582
Equity Method Investment Summarized Financial Information Operating Income		66,436	110,268
Equity Method Investment, Summarized Financial Information, Net Income (Loss)		34,184	118,925
Long-term Debt
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		7,878	7,878	7,878
Property, Plant and Equipment
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ (406,987)	$ (406,987)	$ (406,987)
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	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Business Combinations [Abstract]
Business Acquisition, Pro Forma Revenue	$ 138,651	$ 387,245
Business Acquisition, Pro Forma Net Income (Loss)	$ 42,847	$ 120,395

Acquisitions (Details)

Acquisitions (Details) $ / shares in Units, $ in Thousands

Nov. 02, 2016shares

Oct. 31, 2016shares

Jul. 21, 2016shares

Jul. 01, 2016USD ($)

May 06, 2016USD ($)

Mar. 29, 2016USD ($)

Jan. 01, 2016USD ($)$ / sharesshares

Sep. 30, 2016USD ($)

Sep. 30, 2015USD ($)

Sep. 30, 2016USD ($)

Sep. 30, 2015USD ($)

Dec. 31, 2015USD ($)

Dec. 16, 2015mi

Mar. 01, 2015

Business Acquisition [Line Items]

Unconsolidated investment

$ 455,401

$ 455,401

$ 0

Equity in earnings of unconsolidated investment

12,066

$ 0

35,387

$ 0

Payments to Acquire Equity Method Investments

35,452

0

Payments to Noncontrolling Interests

425,882

0

Derivative asset at fair value

$ 46,000

Partners' Capital Account, Units, Treasury Units Purchased | shares

3,563,146

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%

Payments to Noncontrolling Interests

$ 475,000

425,882

Common Unit, Issuance Value

268,600

Business Combination, Consideration Transferred, Including Equity Interest in Acquiree Held Prior to Combination

$ 743,600

Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares

6,518,000

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

Water Solutions

Business Acquisition [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%

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]

Business Acquisition, Percentage of Voting Interests Acquired

25.00%

Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners

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

$ (399,109)

(399,109)

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

35,400

Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries

51,500

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

1,703,094

Partners' Capital Account, Units, Treasury Units Purchased | shares

1,251,760

General Partner [Member]

Business Acquisition [Line Items]

Payments to Noncontrolling Interests

0

0

Equity impact of partial exercise of call option

(25,858)

General Partner [Member] | Pony Express Pipeline

Business Acquisition [Line Items]

Partners' Capital Account, Acquisitions

(279,967)

(324,328)

General Partner [Member] | Water Solutions

Business Acquisition [Line Items]

Payments to Acquire Additional Interest in Subsidiaries

$ 59

$ 0

Related Party Transactions - Sc

Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Related Party Transaction [Line Items]
Related Party Transactions, Cost of Sales and Transportation Services	$ 7,313	$ 7,180	$ 21,864	$ 17,771
Operation and maintenance [Member]
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	6,317	6,077	18,778	17,325
General and Administrative Expense [Member]
Related Party Transaction [Line Items]
Expenses related to transactions with affiliated companies	9,567	9,541	28,784	28,112
Property, Plant and Equipment
Related Party Transaction [Line Items]
Related Party Transaction Costs Capitalized From Transactions With Related Party	$ 432	$ 958	$ 1,953	$ 3,859

Related Party Transactions - 41

Related Party Transactions - Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Receivable from related parties	$ 126	$ 15
Accounts Payable, Related Parties, Current	6,207	7,852
Rockies Express Pipeline LLC
Related Party Transaction [Line Items]
Receivable from related parties	126	15
Accounts Payable, Related Parties, Current	0	7
Tallgrass Operations, LLC
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	6,139	7,792
Tallgrass Equity, LLC
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	68	36
Deeprock Development, LLC
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	$ 0	$ 17

Related Party Transactions - 42

Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Affiliate gas balance receivables	$ 82	$ 92
Affiliate gas balance payables	$ 161	$ 227

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
Related Party Transactions [Abstract]
Interest Income, Related Party	$ 0.4

Inventory Inventory (Details)

Inventory Inventory (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Crude oil	$ 4,223	$ 2,661
Materials and supplies	6,505	8,581
Natural gas liquids	255	395
Gas in underground storage	2,392	2,156
Inventory, Net	$ 13,375	$ 13,793

Property Plant and Equipment -

Property Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Accumulated depreciation and amortization	$ (180,193)	$ (133,427)
Property, plant and equipment	2,003,532	2,025,018
Crude oil pipelines
Property, Plant and Equipment [Line Items]
Property , plant and equipment	1,182,806	1,172,684
Natural gas pipelines
Property, Plant and Equipment [Line Items]
Property , plant and equipment	553,437	550,710
Processing and treating assets
Property, Plant and Equipment [Line Items]
Property , plant and equipment	256,331	254,073
Water business assets
Property, Plant and Equipment [Line Items]
Property , plant and equipment	81,507	81,098
General and other
Property, Plant and Equipment [Line Items]
Property , plant and equipment	71,190	69,181
Construction work in progress
Property, Plant and Equipment [Line Items]
Property , plant and equipment	$ 38,454	$ 30,699

Risk Management - Schedule of F

Risk Management - Schedule of Fair Value of Derivative Contracts (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 25,690
Equity Option | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	25,690	$ 0
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	190
Energy commodity derivative contracts | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	190	0
Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	7
Energy Related Derivative | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	$ 7	$ 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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Equity Option
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ (4,419)	$ 0	$ 5,588	$ 0
Energy commodity derivative contracts
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	161	252	(190)	211
Energy Related Derivative
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain (loss) recognized in income on derivatives	$ 318	$ 0	$ 466	$ 0

Risk Management - Schedule of E

Risk Management - Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification (Detail) $ in Thousands	Sep. 30, 2016USD ($)
Equity Option
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	$ 25,690
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	25,690
Equity Option | Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative asset at fair value	0
Energy commodity derivative contracts
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	190
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	190
Energy commodity derivative contracts | Significant unobservable inputs (Level 3)
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	0
Energy Related Derivative
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	7
Energy Related Derivative | Quoted prices in active markets for identical assets (Level 1)
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	0
Energy Related Derivative | Significant other observable inputs (Level 2)
Derivatives, Fair Value [Line Items]
Derivative liabilities at fair value	7
Energy Related Derivative | 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) $ in Thousands	Nov. 02, 2016shares	Oct. 31, 2016USD ($)shares	Jul. 21, 2016USD ($)shares	Jan. 01, 2016shares	Sep. 30, 2016USD ($)Bcfbbl	Sep. 30, 2015USD ($)	Mar. 01, 2015
Derivative [Line Items]
Partners' Capital Account, Units, Treasury Units Purchased			3,563,146
Partial exercise of call option | $			$ 151,400		$ 151,434	$ 0
Commodity | Energy Related Derivative
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | bbl					30,000
Commodity | 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
Subsequent Event [Member]
Derivative [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	1,703,094
Partners' Capital Account, Units, Treasury Units Purchased		1,251,760
Partial exercise of call option | $		$ 53,200

Long-term Debt Schedule of Debt

Long-term Debt Schedule of Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Tallgrass Energy Partners
Debt Instrument [Line Items]
Debt Issuance Costs, Net	$ 6,997	$ 0
Long-term debt	1,398,003	753,000
Tallgrass Energy Partners | Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Gross	400,000	0
Revolving credit facility
Debt Instrument [Line Items]
Long-term debt	1,005,000	753,000
Revolving credit facility | Tallgrass Energy Partners
Debt Instrument [Line Items]
Long-term Debt, Gross	1,005,000	753,000
Long-term debt	$ 1,005,000	$ 753,000

Long-term Debt Capacity under R

Long-term Debt Capacity under Revolving Credit Facility (Details) - USD ($)	Sep. 30, 2016	May 06, 2016	Jan. 04, 2016	Dec. 31, 2015	Nov. 24, 2015
Revolving credit facility
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility (1)	$ (1,005,000,000)			$ (753,000,000)
Tallgrass Energy Partners
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility (1)	(1,398,003,000)			(753,000,000)
Tallgrass Energy Partners | Revolving credit facility
Line of Credit Facility [Line Items]
Less: Outstanding borrowings under the revolving credit facility (1)	(1,005,000,000)			(753,000,000)
Available capacity under the revolving credit facility	745,000,000			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	Sep. 30, 2016	Dec. 31, 2015
Senior Notes
Debt Instrument [Line Items]
Fair Value	$ 403,752
Long-term debt	393,003
Senior Notes | Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Fair Value	0
Senior Notes | Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Fair Value	403,752
Senior Notes | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Fair Value	0
Revolving credit facility
Debt Instrument [Line Items]
Fair Value	1,005,000	$ 753,000
Long-term debt	1,005,000	753,000
Revolving credit facility | Quoted prices in active markets for identical assets (Level 1)
Debt Instrument [Line Items]
Fair Value	0	0
Revolving credit facility | Significant other observable inputs (Level 2)
Debt Instrument [Line Items]
Fair Value	1,005,000	753,000
Revolving credit facility | Significant unobservable inputs (Level 3)
Debt Instrument [Line Items]
Fair Value	$ 0	$ 0

Long-term Debt - Additional Inf

Long-term Debt - Additional Information (Detail)	Sep. 01, 2016USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Oct. 31, 2016USD ($)	May 06, 2016USD ($)	Jan. 04, 2016USD ($)	Jan. 01, 2016	Dec. 31, 2015USD ($)	Nov. 24, 2015USD ($)	Mar. 01, 2015
Debt Instrument [Line Items]
Proceeds from Issuance of Senior Long-term Debt		$ 400,000,000	$ 0
Weighted average interest rate on outstanding borrowings		2.28%
Debt Instrument, Interest Rate, Effective Percentage		2.72%
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
Debt Instrument [Line Items]
Long-term debt		$ 1,398,003,000						$ 753,000,000
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
Sempra U.S. Gas and Power [Member] | Rockies Express Pipeline LLC
Debt Instrument [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired					25.00%
Senior Notes | Tallgrass Energy Partners
Debt Instrument [Line Items]
Proceeds from Issuance of Senior Long-term Debt	$ 400,000,000
Debt Instrument, Interest Rate, Stated Percentage		5.50%
Revolving credit facility
Debt Instrument [Line Items]
Long-term debt		$ 1,005,000,000						753,000,000
Revolving credit facility | Tallgrass Energy Partners
Debt Instrument [Line Items]
Long-term debt		$ 1,005,000,000						$ 753,000,000
Revolving credit facility | Subsequent Event [Member] | Tallgrass Energy Partners
Debt Instrument [Line Items]
Long-term debt				$ 1,003,000,000

Partnership Equity and Distri54

Partnership Equity and Distributions - Summary of Distributions (Detail) - Tallgrass Energy Partners - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Sep. 30, 2016	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	$ 57,332	$ 54,442	$ 48,238	$ 42,984	$ 36,347	$ 35,135	$ 31,322
Distributions General Partner Incentive	26,987	24,262	19,816	15,332	11,567	10,418	6,934
General Partner Distributions	976	911	830	724	660	627	530
Distributions Total	$ 85,295	$ 79,615	$ 68,884	$ 59,040	$ 48,574	$ 46,180	$ 38,786
Distributions per Limited Partner unit	$ 0.7950	$ 0.7550	$ 0.7050	$ 0.6400	$ 0.6000	$ 0.5800	$ 0.5200

Partnership Equity and Distri55

Partnership Equity and Distributions - Additional Information (Detail) - USD ($)	Nov. 02, 2016	Apr. 28, 2016	Jan. 01, 2016	Nov. 02, 2016	Sep. 30, 2016	Sep. 30, 2016	Sep. 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					622,846	6,703,984
Shares Issued, Weighted Average Price Per Share					$ 47.39	$ 43.98
Issuance of units to public, net of offering costs					$ 28,700,000	$ 290,500,000
LimitedPartnerOfferingCosts					$ 800,000	4,400,000
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						8,700,000	19,303,000
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
Equity impact of partial exercise of call option						25,858,000
Contributions from TD						5,308,000
Contributions from noncontrolling interests						0	0
Payments to Noncontrolling Interests						0	0
General Partner | Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Partners' Capital Account, Acquisitions						(279,967,000)	(324,328,000)
Subsequent Event [Member]
Limited Partners' Capital Account [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	1,703,094
Partners' Capital Account, Units, Sold in Public Offering				628,914
Shares Issued, Weighted Average Price Per Share				$ 48.05
Issuance of units to public, net of offering costs				$ 29,900,000
LimitedPartnerOfferingCosts				$ 300,000
Total Partner Equity Including Portion Attributable to Noncontrolling Interest
Limited Partners' Capital Account [Line Items]
Issuance of units to public, net of offering costs						290,474,000	551,243,000
Proceeds from private placement, net of offering costs						90,009,000
Equity impact of partial exercise of call option						177,292,000
Contributions from TD						5,308,000
Contributions from noncontrolling interests						8,700,000	110,553,000
Payments to Noncontrolling Interests						5,017,000	44,543,000
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)
Pony Express Pipeline
Limited Partners' Capital Account [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners					2.00%	2.00%

Net Income per Limited Partne56

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		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net income	$ 61,818	$ 49,550	$ 200,087	$ 125,771
Net income attributable to noncontrolling interests	(1,084)	(6,871)	(3,235)	(5,874)
Net income attributable to partners	60,734	42,679	196,852	119,897
General partner interest in net income	(27,674)	(12,146)	(73,347)	(30,614)
Net income available to common and subordinated unitholders	$ 33,060	$ 30,533	$ 123,505	$ 89,283
Basic net income per common and subordinated unit	$ 0.45	$ 0.50	$ 1.75	$ 1.54
Diluted net income per common and subordinated unit	$ 0.45	$ 0.50	$ 1.73	$ 1.52
Basic average number of common and subordinated units outstanding	73,089	60,576	70,686	57,917
Equity Participation Unit equivalent units	974	960	904	967
Diluted average number of common and subordinated units outstanding	74,063	61,536	71,590	58,884

Regulatory Matters Regulatory M

Regulatory Matters Regulatory Matters (Details) MMBTU / d in Thousands	9 Months Ended
	Sep. 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 Matte58

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

Legal and Environmental Matte59

Legal and Environmental Matters - Additional Information (Detail) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016USD ($)ft-lbmi	Dec. 31, 2016USD ($)mi	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Estimated environmental liability	$ 4,300		$ 4,800
Trailblazer
Loss Contingencies [Line Items]
Maximum allowable operating pressure | ft-lb	144,000
Excavation digs			32
Aggregate cost of excavation digs			$ 1,300
Tallgrass Development LP
Loss Contingencies [Line Items]
Contractual indemnity provided to TEP by TD	$ 20,000
Annual deductible	$ 1,500
Minimum | Trailblazer
Loss Contingencies [Line Items]
Miles of natural gas pipeline needing repair or replacement | mi	25
Pipeline replacement costs	$ 2,200
Maximum | Trailblazer
Loss Contingencies [Line Items]
Miles of natural gas pipeline needing repair or replacement | mi	35
Pipeline replacement costs	$ 2,700
Subsequent Event | Trailblazer
Loss Contingencies [Line Items]
Miles of natural gas pipeline needing repair or replacement | mi		8
Estimated pipe replacement cost		$ 21,500
Michels Corporation Complaint
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	24,200
General Partner [Member]
Loss Contingencies [Line Items]
Contributions from TD	$ 5,308

Reporting Segments - Summary of

Reporting Segments - Summary of TEP's Segment Information of Revenue (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Segment Reporting Information [Line Items]
Revenues	$ 152,125	$ 138,168	$ 444,461	$ 385,813
TEP
Segment Reporting Information [Line Items]
Revenues	152,125	138,168	444,461	385,813
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	95,826	83,272	283,868	208,872
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	32,385	32,290	90,757	94,179
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Revenues	23,914	22,606	69,836	82,762
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
TEP | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	153,552	139,514	448,653	389,849
TEP | Operating Segments [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	95,826	83,272	283,868	208,872
TEP | Operating Segments [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Revenues	33,812	33,636	94,949	98,215
TEP | Operating Segments [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Revenues	23,914	22,606	69,836	82,762
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	(1,427)	(1,346)	(4,192)	(4,036)
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	(1,427)	(1,346)	(4,192)	(4,036)
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 61

Reporting Segments - Summary of TEP's Segment Information of Earnings (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Reconciliation to Net Income:
Equity in earnings of unconsolidated investment	$ 12,066	$ 0	$ 35,387	$ 0
Interest expense, net of noncontrolling interest	10,907	3,871	27,639	11,204
Depreciation and amortization expense, net of noncontrolling interest	20,831	20,802	64,099	61,762
Distributions from unconsolidated investment			35,387	0
Non-cash gain related to derivative instruments, net of noncontrolling interest	4,419	0	(5,588)	0
Noncash compensation expense			4,270	3,988
Net income attributable to partners	60,734	42,679	196,852	119,897
TEP
Reconciliation to Net Income:
Net income attributable to partners	60,734	42,679	196,852	119,897
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	66,777	48,872	199,769	123,388
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	39,826	14,637	99,976	47,784
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	3,291	3,046	10,265	18,841
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,368)	(703)	(3,809)	(2,374)
TEP | Operating Segments [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	65,431	47,526	195,732	119,352
TEP | Operating Segments [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	41,253	15,983	104,168	51,820
TEP | Operating Segments [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	3,210	3,046	10,110	18,841
TEP | Operating Segments [Member] | Corporate and Other
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,368)	(703)	(3,809)	(2,374)
TEP | Intersegment Eliminations [Member] | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	1,346	1,346	4,037	4,036
TEP | Intersegment Eliminations [Member] | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	(1,427)	(1,346)	(4,192)	(4,036)
TEP | Intersegment Eliminations [Member] | Processing & Logistics
Segment Reporting Information [Line Items]
Adjusted EBITDA	81	0	155	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	12,066	0	35,387	0
Non-cash loss allocated to noncontrolling interest			0	(9,377)
Interest expense, net of noncontrolling interest	(10,907)	(3,872)	(27,639)	(11,205)
Depreciation and amortization expense, net of noncontrolling interest	(21,102)	(18,826)	(64,909)	(57,661)
Distributions from unconsolidated investment	(21,804)	0	(51,460)	0
Non-cash gain related to derivative instruments, net of noncontrolling interest	(4,410)	259	5,391	218
Noncash compensation expense	$ (1,635)	$ (734)	(4,270)	(3,988)
Non-cash loss from asset sales			$ (1,849)	$ (4,483)

Reporting Segments Reporting Se

Reporting Segments Reporting Segments - Summary of TEP's Segment Capital Expenditures (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Segment Reporting Information [Line Items]
Capital expenditures	$ 45,252	$ 65,146
TEP
Segment Reporting Information [Line Items]
Capital expenditures	45,252	65,146
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	25,985	40,579
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	11,146	10,858
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Capital expenditures	8,121	13,709
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Capital expenditures	$ 0	$ 0

Reporting Segments - Summary 63

Reporting Segments - Summary of TEP's Segment Information of Assets (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Assets	$ 3,010,288	$ 2,562,074
TEP | Crude Oil Transportation & Logistics
Segment Reporting Information [Line Items]
Assets	1,417,241	1,439,418
TEP | Natural Gas Transportation & Logistics
Segment Reporting Information [Line Items]
Assets	1,155,372	706,576
TEP | Processing & Logistics
Segment Reporting Information [Line Items]
Assets	405,760	409,795
TEP | Corporate and Other
Segment Reporting Information [Line Items]
Assets	$ 31,915	$ 6,285

Reporting Segments - Additional

Reporting Segments - Additional Information (Detail) - Segment	9 Months Ended
	Sep. 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%