Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 17, 2016 | Jun. 30, 2015 | |
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-K | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus (Q1,Q2,Q3,FY) | FY | ||
Trading Symbol | TEP | ||
Amendment Flag | false | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 1,622.7 | ||
Common Units [Member] | |||
Document Information [Line Items] | |||
Entity Common Stock, Shares Outstanding | 67,162,232 | ||
General Partner Units [Member] | |||
Document Information [Line Items] | |||
Entity Common Stock, Shares Outstanding | 834,391 |
CONSOLIDATED BALANCE SHEETS BAL
CONSOLIDATED BALANCE SHEETS BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current Assets: | ||
Cash and cash equivalents | $ 1,611 | $ 867 |
Accounts receivable, net | 57,742 | 39,768 |
Receivable from related parties | 15 | 73,393 |
Gas imbalances | 1,227 | 2,442 |
Inventories | 13,793 | 13,045 |
Prepayments and other current assets | 2,835 | 2,766 |
Total Current Assets | 77,223 | 132,281 |
Property, plant and equipment, net | 2,025,018 | 1,853,081 |
Goodwill | 343,288 | 343,288 |
Intangible asset, net | 96,546 | 104,538 |
Deferred financing costs, net | 5,105 | 5,528 |
Deferred charges and other assets | 14,894 | 18,481 |
Total Assets | 2,562,074 | 2,457,197 |
Current Liabilities: | ||
Accounts payable, including $10,554 and $45,534 related to variable interest entities | 22,218 | 62,329 |
Accounts payable to related parties | 7,852 | 3,915 |
Gas imbalances | 1,605 | 3,611 |
Accrued taxes | 13,844 | 3,989 |
Accrued liabilities | 10,019 | 9,384 |
Deferred revenue | 26,511 | 5,468 |
Other current liabilities | 6,880 | 7,872 |
Total Current Liabilities | 88,929 | 96,568 |
Long-term debt | 753,000 | 559,000 |
Other long-term liabilities and deferred credits | 5,143 | 6,478 |
Total Long-term Liabilities | $ 758,143 | $ 565,478 |
Commitments and Contingencies | ||
Equity: | ||
General partner (834,391 units issued and outstanding at December 31, 2015 and 2014, respectively) | $ (348,841) | $ (35,743) |
Total Partners’ Equity | 1,269,925 | 1,038,723 |
Noncontrolling interests | 445,077 | 756,428 |
Total Equity | 1,715,002 | 1,795,151 |
Total Liabilities and Equity | 2,562,074 | 2,457,197 |
Common unitholders | ||
Equity: | ||
Unitholders | 1,618,766 | 800,333 |
Subordinated unitholder | ||
Equity: | ||
Unitholders | $ 0 | $ 274,133 |
CONDENSED BALANCE SHEETS (UNAU
CONDENSED BALANCE SHEETS (UNAUDITED) (Parenthetical) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Accounts payable, including $10,554 and $45,534 related to variable interest entities | $ 22,218,000 | $ 62,329,000 |
Limited Partner Common Units | 60,644,232 | |
General partner units issued (in shares) | 834,391 | 834,391 |
General partner units outstanding (in shares) | 834,391 | 834,391 |
Common unitholders | ||
Unitholders units issued (in shares) | 60,644,232 | 32,834,105 |
Limited Partner Common Units | 60,644,232 | 32,834,105 |
Subordinated unitholder | ||
Unitholders units issued (in shares) | 0 | 16,200,000 |
Limited Partner Common Units | 0 | 16,200,000 |
Variable Interest Entity, Primary Beneficiary [Member] | ||
Accounts payable, including $10,554 and $45,534 related to variable interest entities | $ 10,554 | $ 45,534 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands | 5 Months Ended | 7 Months Ended | 12 Months Ended | ||
May. 16, 2013 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues: | |||||
Crude oil transportation services | $ 300,436 | $ 28,343 | $ 0 | ||
Natural gas transportation services | 119,895 | 126,733 | 120,025 | ||
Sales of natural gas, NGLs, and crude oil | 82,133 | 181,249 | 155,700 | ||
Processing and other revenues | 33,733 | 35,231 | 14,801 | ||
Total Revenues | 536,197 | 371,556 | 290,526 | ||
Operating Costs and Expenses: | |||||
Cost of sales (exclusive of depreciation and amortization shown below) | 75,285 | 167,545 | 131,095 | ||
Cost of transportation services (exclusive of depreciation and amortization shown below) | 53,597 | 24,109 | 15,059 | ||
Operations and maintenance | 49,138 | 39,577 | 35,404 | ||
Depreciation and amortization | 83,476 | 47,048 | 39,917 | ||
General and administrative | 50,195 | 33,160 | 27,651 | ||
Taxes, other than income taxes | 21,796 | 6,704 | 7,401 | ||
Loss on sale of assets | 4,795 | 0 | 0 | ||
Total Operating Costs and Expenses | 338,282 | 318,143 | 256,527 | ||
Operating Income | 197,915 | 53,413 | 33,999 | ||
Other (Expense) Income: | |||||
Interest expense, net | (15,514) | (7,292) | (11,054) | ||
Gain on remeasurement of unconsolidated investment | 0 | 9,388 | 0 | ||
Loss on extinguishment of debt | (226) | 0 | (17,526) | ||
Equity in earnings of unconsolidated investment | 0 | 717 | 0 | ||
Other income, net | 2,639 | 3,103 | 2,205 | ||
Total Other (Expense) Income | (13,101) | 5,916 | (26,375) | ||
Net income | 184,814 | 59,329 | 7,624 | ||
Net (income) loss attributable to noncontrolling interests | $ (761) | $ (1,362) | 24,268 | (11,352) | (2,123) |
Net income attributable to partners | 160,546 | 70,681 | 9,747 | ||
Predecessor operations interest in net (income) loss | 1,172 | 3,260 | 0 | (1,508) | 4,432 |
Net (income) loss attributable to noncontrolling interests | |||||
Net income attributable to partners, excluding predecessor operations interest | 160,546 | 69,173 | 14,179 | ||
General partner interest in net income | (6,982) | (206) | (46,478) | (7,399) | (7,188) |
Common and subordinated unitholders' interest in net income subsequent to May 17, 2013 | 0 | $ 6,991 | $ 114,068 | $ 61,774 | $ 6,991 |
Basic net income per common and subordinated unit | $ 0.17 | $ 1.95 | $ 1.39 | $ 0.17 | |
Diluted net income per common and subordinated unit | $ 0.17 | $ 1.91 | $ 1.36 | $ 0.17 | |
Basic average number of common and subordinated units outstanding | 40,450 | 58,597 | 44,346 | 40,450 | |
Diluted average number of common and subordinated units outstanding | 41,458 | 59,575 | 45,394 | 41,458 | |
Prior to May 17, 2013 | |||||
Net (income) loss attributable to noncontrolling interests | |||||
Net income attributable to partners, excluding predecessor operations interest | $ (6,982) | $ 0 | $ 0 | ||
Subsequent to May 17, 2013 | |||||
Net (income) loss attributable to noncontrolling interests | |||||
Net income attributable to partners, excluding predecessor operations interest | $ 7,197 | $ 160,546 | $ 69,173 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash Flows from Operating Activities: | |||
Net income | $ 184,814 | $ 59,329 | $ 7,624 |
Adjustments to reconcile net income to net cash flows from operating activities: | |||
Depreciation and amortization | 87,367 | 49,041 | 41,663 |
Gain on remeasurement of unconsolidated investment | 0 | (9,388) | 0 |
Loss on extinguishment of debt | 226 | 0 | 17,526 |
Noncash compensation expense | 5,103 | 5,136 | 1,798 |
Loss on sale of assets | 4,795 | 0 | 0 |
Changes in components of working capital: | |||
Accounts receivable and other | (15,605) | (348) | 8,506 |
Gas imbalances | (757) | 1,504 | 2,393 |
Inventories | (5,169) | (8,367) | (2,807) |
Accounts payable and accrued liabilities | 9,799 | (21,787) | 12,207 |
Deferred revenue | 20,612 | 6,619 | 0 |
Deferred lease payment | 0 | 0 | (4,563) |
Other operating, net | (1,889) | (2,295) | (1,865) |
Net Cash Provided by Operating Activities | (289,296) | (79,444) | (82,482) |
Cash Flows from Investing Activities: | |||
Capital expenditures | (65,387) | (665,650) | (346,020) |
Issuance of related party loan | 0 | (270,000) | 0 |
Acquisition of Western | 75,000 | 0 | 0 |
Acquisition of Trailblazer | 0 | (150,000) | 0 |
Acquisition of additional equity interests in Water Solutions | 0 | 7,600 | 0 |
Acquisition of Pony Express membership interest | (700,000) | (27,000) | 0 |
Other investing, net | (4,883) | 17,521 | (1,590) |
Net Cash Used in Investing Activities | 845,270 | 1,102,729 | 347,610 |
Net Cash Provided by Financing Activities | |||
Distributions to unitholders | (161,834) | (68,117) | (18,171) |
Distributions to noncontrolling interests | (25,136) | 0 | 0 |
Contribution from TD | 0 | 27,488 | 0 |
Repayment of debt assumed from TD | 0 | 0 | (400,000) |
Borrowings under revolving credit facility, net | 194,000 | 424,000 | 135,000 |
Proceeds from public offering, net of offering costs | 554,084 | 320,385 | 290,483 |
Contributions from Predecessor Entities, net | 0 | 312,125 | 379,872 |
Distributions to Member, net | 0 | 0 | (118,538) |
Other financing, net | (4,396) | 8,271 | (3,518) |
Net Cash Provided by Financing Activities | 556,718 | 1,024,152 | 265,128 |
Net Change in Cash and Cash Equivalents | |||
Net Change in Cash and Cash Equivalents | 744 | 867 | 0 |
Cash and Cash Equivalents, beginning of period | 867 | 0 | 0 |
Cash and Cash Equivalents, end of period | 1,611 | 867 | 0 |
Supplemental Disclosures: | |||
Cash payments for interest, net | (14,021) | (6,801) | (3,450) |
Property, plant and equipment acquired via the cash management agreement with TD | 138,936 | 158,357 | 0 |
Contributions from noncontrolling interests settled via the cash management agreement with TD | 68,277 | 0 | 0 |
Distributions to noncontrolling interests settled via the cash management agreement with TD | (69,017) | (5,361) | 0 |
Increase in accrual for payment of property, plant and equipment | 0 | 0 | 90,373 |
Increase in accrual for reimbursable construction in progress projects | 0 | 0 | 14,470 |
Fair value of TIGT & TMID [Member] | |||
Supplemental Disclosures: | |||
Fair value of assets acquired | 0 | 0 | 1,027,127 |
Fair value of liabilities | $ 0 | $ 0 | $ (566,849) |
CONSOLIDATED STATEMENTS OF EQUI
CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands | Total | TEP Predecessor Pre-IPO [Member] | TEP Predecessor Post-IPO [Member] | General Partner | Common unitholdersLimited Partner [Member] | Subordinated Units [Member]Limited Partner [Member] | Total Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | Noncontrolling Interest [Member] | Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | TrailblazerTEP Predecessor Pre-IPO [Member] | TrailblazerTEP Predecessor Post-IPO [Member] | TrailblazerGeneral Partner | TrailblazerCommon unitholdersLimited Partner [Member] | TrailblazerSubordinated Units [Member]Limited Partner [Member] | TrailblazerTotal Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | TrailblazerNoncontrolling Interest [Member] | TrailblazerTotal Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Water Solutions [Member]TEP Predecessor Pre-IPO [Member] | Water Solutions [Member]TEP Predecessor Post-IPO [Member] | Water Solutions [Member]General Partner | Water Solutions [Member]Common unitholdersLimited Partner [Member] | Water Solutions [Member]Subordinated Units [Member]Limited Partner [Member] | Water Solutions [Member]Total Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | Water Solutions [Member]Noncontrolling Interest [Member] | Water Solutions [Member]Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Pony Express PipelineTEP Predecessor Pre-IPO [Member] | Pony Express PipelineTEP Predecessor Post-IPO [Member] | Pony Express PipelineGeneral Partner | Pony Express PipelineCommon unitholdersLimited Partner [Member] | Pony Express PipelineSubordinated Units [Member]Limited Partner [Member] | Pony Express PipelineTotal Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | Pony Express PipelineNoncontrolling Interest [Member] | Pony Express PipelineTotal Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] |
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||||||||||||||||||||||||||||||
Partners' Capital Account, Units | 0 | 0 | 0 | ||||||||||||||||||||||||||||||
Partners' Capital | $ 571,834 | $ 121,446 | $ 0 | $ 0 | $ 0 | $ 693,280 | $ 70,397 | ||||||||||||||||||||||||||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | $ 763,677 | ||||||||||||||||||||||||||||||||
Net income | $ 7,624 | ||||||||||||||||||||||||||||||||
Partners' Capital Account, Units | 827,000 | 24,300,000 | 16,200,000 | ||||||||||||||||||||||||||||||
Partners' Capital | 0 | 247,221 | $ 14,078 | $ 455,197 | $ 274,666 | 991,162 | 317,939 | ||||||||||||||||||||||||||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | 1,309,101 | ||||||||||||||||||||||||||||||||
Initial public offering of common units | 28,625 | ||||||||||||||||||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 8,000 | 8,079,000 | |||||||||||||||||||||||||||||||
Partners' Capital Account, Units, Acquisitions | 385,000 | 70,000 | |||||||||||||||||||||||||||||||
Net income | $ 59,329 | 0 | 1,508 | $ 7,399 | $ 39,141 | 22,633 | 70,681 | (11,352) | 59,329 | ||||||||||||||||||||||||
Acquisitions | $ 0 | $ (91,090) | $ (72,933) | $ 14,023 | $ 0 | $ (150,000) | $ 0 | $ (150,000) | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 1,400 | $ 1,400 | $ 0 | $ (59,752) | $ (8,654) | $ 3,000 | $ 0 | $ (65,406) | $ 38,406 | $ (27,000) | |||||||||
Contributions | 0 | 0 | 27,488 | 0 | 0 | (27,488) | 0 | (27,488) | |||||||||||||||||||||||||
Distributions | 0 | 0 | (3,384) | (41,567) | (23,166) | (68,117) | 0 | (68,117) | |||||||||||||||||||||||||
Contributions from Noncontrolling Interest | 0 | 0 | 0 | 0 | 0 | 0 | 5,429 | 5,429 | |||||||||||||||||||||||||
Distributions to Noncontrolling Interests | 0 | 0 | 0 | 0 | 0 | 0 | (5,406) | (5,406) | |||||||||||||||||||||||||
Noncash compensation expense | 0 | 0 | 0 | 10,154 | 0 | 10,154 | 0 | 10,154 | |||||||||||||||||||||||||
Partner's Capital Account Contributions from Predecessor | 0 | (97,887) | 0 | 0 | 0 | (97,887) | 410,012 | 312,125 | |||||||||||||||||||||||||
Issuance of general partner units | 0 | 0 | 263 | 0 | 0 | 263 | 0 | 263 | |||||||||||||||||||||||||
Issuance of units to public, net of offering costs | 1,100 | 0 | 0 | $ 0 | $ 320,385 | $ 0 | 320,385 | 0 | 320,385 | ||||||||||||||||||||||||
Partners' Capital Account, Units | 835,000 | 32,834,000 | 16,200,000 | ||||||||||||||||||||||||||||||
Partners' Capital | 1,038,723 | 0 | 0 | $ (35,743) | $ 800,333 | $ 274,133 | 1,038,723 | 756,428 | |||||||||||||||||||||||||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | $ 1,795,151 | 1,795,151 | |||||||||||||||||||||||||||||||
Initial public offering of common units | 65,744 | ||||||||||||||||||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 11,266,000 | ||||||||||||||||||||||||||||||||
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures | 344,000 | ||||||||||||||||||||||||||||||||
Conversion of Stock, Shares Converted | 16,200,000 | (16,200,000) | |||||||||||||||||||||||||||||||
Net income | $ 184,814 | 0 | 0 | 46,478 | $ 108,888 | $ 5,180 | 160,546 | 24,268 | 184,814 | ||||||||||||||||||||||||
Acquisitions | $ 0 | $ 0 | $ (324,328) | $ 0 | $ 0 | $ (324,328) | $ (375,672) | $ (700,000) | |||||||||||||||||||||||||
Distributions | 0 | 0 | (35,248) | (118,729) | (7,857) | (161,834) | 0 | (161,834) | |||||||||||||||||||||||||
Adjustments Related to Tax Withholding for Share-based Compensation | 0 | 0 | 0 | (6,603) | 0 | (6,603) | 0 | (6,603) | |||||||||||||||||||||||||
Contributions from Noncontrolling Interest | 0 | 0 | 0 | 0 | 0 | 0 | 110,127 | 110,127 | |||||||||||||||||||||||||
Distributions to Noncontrolling Interests | 0 | 0 | 0 | 0 | 0 | 0 | (69,474) | (69,474) | |||||||||||||||||||||||||
Noncash compensation expense | 0 | 0 | 0 | 9,337 | 0 | 9,337 | 0 | 9,337 | |||||||||||||||||||||||||
Issuance of units to public, net of offering costs | 3,000 | 0 | 0 | 0 | 554,084 | 0 | 554,084 | 0 | 554,084 | ||||||||||||||||||||||||
Acquisition of additional equity interests in Water Solutions | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ (600) | $ (600) | |||||||||||||||||||||||||
Conversion of subordinated units | 0 | 0 | $ 0 | $ 271,456 | $ (271,456) | 0 | 0 | 0 | |||||||||||||||||||||||||
Partners' Capital Account, Units | 835,000 | 60,644,000 | 0 | ||||||||||||||||||||||||||||||
Partners' Capital | 1,269,925 | $ 0 | $ 0 | $ (348,841) | $ 1,618,766 | $ 0 | $ 1,269,925 | $ 445,077 | |||||||||||||||||||||||||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | $ 1,715,002 | $ 1,715,002 |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2015 | |
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 our membership interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma that includes a lateral in Northeast Colorado that commences in Weld County, Colorado, and interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). We provide natural gas transportation and storage services for customers in the Rocky Mountain and Midwest regions of the United States through the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). We also provide services for customers in Wyoming at the Casper and Douglas natural gas processing facilities and the West Frenchie Draw natural gas treating facility (collectively, the "Midstream Facilities"), and NGL transportation services in Northeast Colorado. We perform water business services in Colorado and Texas through BNN Water Solutions, LLC ("Water Solutions"). Our operations are strategically located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford and Bakken shale formations. Our reportable business segments are: • Crude Oil Transportation & Logistics—the ownership and operation of a crude oil pipeline system; • Natural Gas Transportation & Logistics—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; and • Processing & Logistics—the ownership and operation of natural gas processing, treating and fractionation facilities, the provision of water business services primarily to the oil and gas exploration and production industry and the transportation of NGLs. The table below summarizes our equity ownership as of December 31, 2015 : Unit Holder Limited Partner Common Units General Partner Units Percentage of Outstanding Limited Partner Common Units Percentage of Outstanding Common and General Partner Units Public Unitholders 34,288,752 — 56.54 % 55.77 % Tallgrass Equity, LLC 20,000,000 — 32.98 % 32.53 % Tallgrass Development, LP 6,355,480 — 10.48 % 10.34 % Tallgrass MLP GP, LLC (1) — 834,391 — 1.36 % Total 60,644,232 834,391 100.00 % 100.00 % (1) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights ("IDRs"). The term "TEP Predecessor" refers to Tallgrass Energy Partners Predecessor, which is comprised of businesses that were owned by Tallgrass Development, LP ("TD") from November 13, 2012 through the completion of the initial public offering on May 17, 2013 ("IPO"). The businesses included in the TEP Predecessor consist of Tallgrass Interstate Gas Transmission, LLC ("TIGT") and Tallgrass Midstream, LLC ("TMID"), in addition to the businesses described below. The term "Trailblazer Predecessor" refers to Trailblazer Pipeline Company LLC ("Trailblazer") for the period from November 13, 2012 to its acquisition by TEP on April 1, 2014, and the term "Pony Express Predecessor" refers to Pony Express for the period from November 13, 2012 to September 1, 2014, the date on which TEP acquired a 33.3% membership interest. TEP Predecessor, Trailblazer Predecessor and Pony Express Predecessor are collectively referred to as the Predecessor Entities, as further discussed in Note 2 – Summary of Significant Accounting Policies . Financial results for all prior periods have been recast to reflect the operations of the Predecessor Entities. Predecessor Equity as presented in the consolidated financial statements represents the capital account activity of Trailblazer Predecessor prior to April 1, 2014 and of Pony Express Predecessor prior to September 1, 2014. For additional information regarding these acquisitions, see Note 4 – Acquisitions . |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Basis of Presentation The accompanying financial statements and related notes were prepared in accordance with the generally accepted accounting principles ("GAAP") contained in the Financial Accounting Standards Board’s Accounting Standards Codification. 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. The accompanying consolidated financial statements of TEP include historical cost-basis accounts of the assets of TEP Predecessor, contributed to TEP by TD in connection with the IPO, for the periods prior to May 17, 2013, the closing date of TEP’s IPO, as well as Trailblazer for the periods prior to April 1, 2014, the date TEP acquired Trailblazer from TD, and Pony Express for the periods prior to September 1, 2014, the date TEP acquired a controlling 33.3% membership interest in Pony Express, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. Both TEP and TEP Predecessor are considered "entities under common control" as defined under GAAP and, as such, the transfers between the entities of the assets and liabilities have been recorded by TEP at historical cost. TEP, or the Partnership, as used herein refers to the consolidated financial results and operations for TEP Predecessor from its inception through its contribution to TEP and thereafter. As further discussed in Note 4 – Acquisitions , TEP closed the acquisition of Trailblazer on April 1, 2014 and the acquisition of a 33.3% membership interest in Pony Express effective September 1, 2014. As the acquisitions of Trailblazer and the initial 33.3% membership interest in Pony Express are considered transactions between entities under common control, and a change in reporting entity, the financial information presented for prior periods has been recast to include Trailblazer and the initial 33.3% membership interest in Pony Express for all periods presented. The acquisition of the additional 33.3% 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 March 1, 2015 have not been recast to reflect the additional 33.3% membership interest. The consolidated financial statements include the accounts of TEP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Net equity contributions of the TEP Predecessor included in the consolidated statements of cash flows represent transfers of cash as a result of TD’s centralized cash management systems prior to May 17, 2013, and prior to April 1, 2014 for Trailblazer and September 1, 2014 for Pony Express, under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions. As of December 31, 2015, Pony Express participated in a cash management agreement with TD, which held a 33.3% common membership interest in Pony Express as of December 31, 2015, under which cash balances were swept periodically and recorded as loans from Pony Express to TD. 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 will be 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 consolidated balance sheets, to the extent material, the assets of our consolidated VIE that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of our consolidated VIE for which creditors do not have recourse to our general credit. Pony Express is considered to be a VIE under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, we have determined that we are the primary beneficiary as we have the power to direct matters that most significantly impact the activities of Pony Express and have the right to receive benefits of Pony Express that could potentially be significant to Pony Express. We have consolidated Pony Express accordingly. For additional information see Note 3 – Variable Interest Entities . Use of Estimates Certain amounts included in or affecting these 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. Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. On November 12, 2012, TIGT and TMID entered into a centralized cash management agreement with TD. In accordance with the cash management agreement, the subsidiary companies made loans on each business day equal to the amount swept from their depository bank accounts. At the beginning of the following month, the total of these loans for each company, less reimbursement payments under the agreements described below in Note 5 – Related Party Transactions , was transferred to an interest bearing account and subsequently, periodically recorded as equity distributions. This practice was discontinued effective May 17, 2013, when TIGT and TMID were contributed to TEP. Subsequent to May 17, 2013, all payable and receivable balances between TEP and TD are cash settled with the exception of certain balances payable from Pony Express to TD, which have been settled against the receivable from TD via the Pony Express cash management agreement. Net equity distributions of the Predecessor Entities included in the Consolidated Statements of Cash Flows represent transfers of cash as a result of TD’s centralized cash management systems prior to May 17, 2013, and prior to April 1, 2014 for Trailblazer and September 1, 2014 for Pony Express, under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions. As of December 31, 2015, Pony Express participated in a cash management agreement with TD, which held a 33.3% common membership interest in Pony Express as of December 31, 2015, under which cash balances were swept daily and recorded as loans from Pony Express to TD. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are carried at their estimated collectible amounts. We make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and adjustments are recorded as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $0.6 million and $0.5 million at December 31, 2015 and 2014 , respectively. Inventories Inventories primarily consist of gas in underground storage, materials and supplies, natural gas liquids and crude oil. Gas in underground storage, sometimes referred to as working gas, and natural gas liquids are recorded at the lower of historical cost or market using the average cost method. As discussed further under " Revenue Recognition " below, a loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil, which we can then sell. As pipeline allowance oil is accumulated, it is recorded as inventory at the lower of historical cost or market using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence. For additional information, see " Gas in Underground Storage " below. Accounting for Regulatory Activities Regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We recorded regulatory assets of approximately $2.8 million and $1.4 million included in "Deferred charges and other assets" in the consolidated balance sheets at December 31, 2015 and 2014 , respectively. Regulatory assets at December 31, 2015 were primarily attributable to costs associated with both TIGT's 2015 Rate Case Filing and Trailblazer’s 2013 Rate Case Filing as more fully described in Note 16 – Regulatory Matters , while regulatory assets at December 31, 2014 were primarily attributable to costs associated with Trailblazer’s 2013 Rate Case Filing . We recorded regulatory liabilities of approximately $2.2 million and $2.3 million included in "Other current liabilities" in the consolidated balance sheet at December 31, 2015 and 2014 , respectively, related to Trailblazer's fuel tracker liabilities as described in Note 16 – Regulatory Matters . Property, Plant and Equipment Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs related to the construction of assets, including internal labor costs, interest and engineering costs. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred. Intangible Assets We account for intangible assets in accordance with ASC 805, which established that an intangible asset is identifiable if it meets either the separability criterion or the contractual-legal criterion. Further, in accordance with ASC 805, contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of TIGT's natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years , the period of expected future benefit. Intangible assets arose at BNN Redtail, LLC ("Redtail") as a result of a significant customer contract with favorable market terms which was acquired as part of the Water Solutions transaction discussed in Note 4 – Acquisitions . This intangible asset was amortized on a straight-line basis over a period of 1.6 years , the remaining term of the contract at the time of acquisition, and was fully amortized as of December 31, 2015. Impairment of Long-Lived Assets We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset or asset group’s use and its eventual disposition are less than its carrying amount. We assess our long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset or asset group is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Examples of long-lived asset impairment indicators include: • a significant decrease in the market value of a long-lived asset or group; • a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition; • a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process; • an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group; • a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and • a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. When an impairment indicator is present, we first assess the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset to the carrying amount of the asset. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the assets is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized. Gas in Underground Storage Gas in underground storage represents the cost of base gas, which refers to the volumes necessary to maintain pressure and deliverability requirements in our storage facilities. We record base gas as a component of property, plant and equipment. We maintain working gas in our underground storage facilities on behalf of certain third parties. We receive a fee for our storage services but do not reflect the value of third-party gas in the accompanying consolidated financial statements. We occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost or market. Depreciation and Amortization For non-regulated assets, we have elected to use the straight-line method of depreciation. For our regulated assets, we have elected to compute depreciation using a composite method employed by applying a single depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. The rates of depreciation for the various classes of depreciable assets are as follows: Range of Depreciation Rates Crude oil pipelines 2.8% Natural gas pipelines 0.7 - 3.4% Processing & treating assets 3.3% Water business assets 3.3 - 20.0% Replacement Gas Facilities (1) 10.0% General & other 6.8 - 12.0% (1) Represents the Replacement Gas Facilities as discussed in Note 5 – Related Party Transactions and Note 16 – Regulatory Matters . Gas Imbalances Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing and imbalance agreements. Gas imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements. Imbalances are valued at applicable average market index prices. Deferred Financing Costs Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method. Goodwill 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 the fair value over the carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31st. 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. See Note 8 – Goodwill and Other Intangible Assets for additional information regarding impairment testing performed during 2015. Investment in Unconsolidated Affiliates We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where we have the ability to exercise significant influence. We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary. Our investment in Grasslands Water Services I, LLC ("GWSI"), which owns a fresh water transportation pipeline, was initially recorded under the equity method of accounting as we had the ability to exercise significant influence, but not control, over this investment. There was $0.7 million equity in earnings recognized for the year ended December 31, 2014. There were no equity in earnings recognized for the year ended December 31, 2015. As discussed in Note 4 – Acquisitions , during the year ended December 31, 2014, TEP acquired a controlling interest in GWSI, which was subsequently renamed BNN Redtail, LLC ("Redtail"), and consolidated its investment in Redtail as of May 13, 2014 accordingly. Revenue Recognition We recognize revenues as services are rendered or goods are sold to a purchaser at a fixed and determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. We provide various types of natural gas storage and transportation services and crude oil transportation services to our customers in which the commodity remains the property of these customers at all times. Crude oil transportation services occur in the Crude Oil Transportation & Logistics segment. We provide various types of crude oil transportation services to our customers and, other than pipeline allowance oil, do not take title to the crude oil and do not incur the risks and rewards of ownership. In many cases the customer has committed to ship a fixed quantity of oil barrels per month. For barrels physically received by us and delivered to the customers’ agreed upon destination point, revenue is recognized in the period the service is provided. Shipper deficiencies, or barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers’ agreed upon destination point, are charged at the committed tariff rate per barrel and recorded as a deferred liability until the barrels are physically transported and delivered. In the case of non-committed shippers, revenue is recognized in the same manner utilized for the barrels physically transported and delivered. A loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil. Any pipeline allowance oil that remains after replacing losses in transit can be sold. We take title and record revenue at market prices when the volumes included in the pipeline loss allowance are delivered from the customer. When pipeline loss allowance oil is eventually sold we record revenue at the contractual sales price and cost of sales at average cost as discussed in "Inventories" above. Natural gas transportation and storage services occur in the Natural Gas Transportation & Logistics segment. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fee-based component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to "firm" and "interruptible" transportation services, we also provide natural gas park and loan services to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized as services are provided, based on the terms negotiated under these contracts. Natural gas liquids sales occur in the Processing & Logistics segment and consist of the sale of outputs from our processing plants and the marketing of natural gas liquids that are delivered by our suppliers under either fee-based arrangements or percent-of-proceeds arrangements. Under these arrangements, we treat and process the natural gas delivered by our suppliers, and then sell the resulting NGLs and condensate based on published index market prices. We remit to the producers an agreed-upon percentage of the actual proceeds that we receive from our sales of the NGLs and condensate. We keep the difference between the proceeds received and the amount remitted back to the producer. We generally report gross revenues in the consolidated statements of income, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Processing and other revenues primarily represent fees for processing, treating and fractionation of natural gas and NGLs earned under fee-based arrangements and revenue from water services earned in the Processing & Logistics segment. Natural gas sales occur in both the Natural Gas Transportation & Logistics segment and in the Processing & Logistics segment. In the Natural Gas Transportation & Logistics segment, transportation services revenue is recognized when a portion of the natural gas transported by customers is collected as a contractual fee to compensate us for fuel consumed by pipeline and storage operations. We take title and record revenue at market prices when the volumes included in the contractual fee are delivered from the customer and injected into our storage facility. When the excess volumes are eventually sold we record natural gas sales revenue at the contractual sales price and cost of sales at average cost. In addition, when operational conditions allow, we occasionally sell "base gas," which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Processing & Logistics segment, we purchase natural gas primarily for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased that exceed our business needs. Commitments and Contingencies We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. Environmental Costs We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action. Estimates of environmental liabilities are based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of other factors including our prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information. Fair Value Fair value, as defined in the Codification, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. We apply the fair value measurement guidance to financial assets and liabilities in determining the fair value of derivative assets and liabilities, and to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill. The fair value measurement accounting guidance requires that we make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments’ fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity. Fair value, where available, is based on observable market prices. Where observable market prices or inputs are not available, different valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments’ complexity. To increase consistency and enhance disclosure of fair value, the Codification creates a fair value hierarchy to prioritize th |
Variable Interest Entity (Notes
Variable Interest Entity (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Variable Interest Entity Disclosure [Text Block] | TEP does not have the obligation to absorb expected losses from Pony Express as a result of the minimum quarterly preference payments as discussed in Note 4 – Acquisitions . In addition, for the period from our acquisition of the initial 33.3% membership interest effective September 1, 2014 to our acquisition of an additional 33.3% membership interest effective March 1, 2015, TEP, as the managing member of Pony Express, had voting rights disproportionate to its ownership interest. As a result, we determined that Pony Express is a VIE of which TEP is the primary beneficiary and consolidated Pony Express accordingly. We have not provided any additional financial support to Pony Express other than our initial capital contribution of $570 million and our pro rata portion of expansion capital projects as discussed below, and have no contractual commitments or obligations to provide additional financial support. In the event that the costs of construction of the Pony Express System, including the lateral in Northeast Colorado, exceed the $270 million retained by Pony Express as discussed in Note 4 – Acquisitions , TD is obligated to fund the remaining costs. As of December 31, 2015 , the costs to complete construction have exceeded the amount retained, and as such TD will continue to fund any remaining costs associated with construction of the mainline and lateral in Northeast Colorado. Although TEP has no obligation to provide further financial support to Pony Express, expansion capital projects are funded by TEP and TD on a pro rata basis in accordance with the Pony Express LLC Agreement. Contributions from TEP to Pony Express to fund expansion capital projects totaled $4.4 million for the year ended December 31, 2015 . As discussed in Note 20 – Subsequent Events , TEP acquired an additional 31.3% membership interest in Pony Express effective January 1, 2016. The carrying amounts and classifications of the Pony Express assets and liabilities included in TEP's consolidated balance sheet at December 31, 2015 and December 31, 2014 are as follows: December 31, 2015 December 31, 2014 (in thousands) Current assets $ 46,800 $ 93,019 Noncurrent assets 1,391,906 1,300,816 Total assets $ 1,438,706 $ 1,393,835 Current liabilities $ 51,349 $ 52,547 Total liabilities $ 51,349 $ 52,547 |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Acquisitions | TEP Acquisition of Trailblazer On April 1, 2014 , TEP closed the acquisition of Trailblazer from a wholly owned subsidiary of TD for total consideration valued at approximately $164 million , consisting of $150 million in cash and the issuance of 385,140 common units (valued at approximately $14 million based on the March 31, 2014 closing price of TEP’s common units). On that same date, the general partner contributed additional capital in the amount of approximately $263,000 in exchange for the issuance of 7,860 general partner units in order to maintain its 2% general partner interest. The acquisition of Trailblazer represents a change in reporting entity and a transaction between entities under common control. The excess purchase price over the net book value of Trailblazer's assets and liabilities was accounted for as a deemed distribution as discussed further in Note 11 – Partnership Equity and Distributions . TEP Acquisitions of 66.7% of Pony Express Effective September 1, 2014 , TEP acquired a controlling 33.3% membership interest in Pony Express for total consideration of approximately $600 million . At closing, Pony Express, TD, and TEP entered into the Second Amended Pony Express LLC Agreement, which set forth the relative rights of TD and TEP as the owners of Pony Express. Of the total consideration of $600 million , TEP directly paid TD $30 million , consisting of $27 million in cash and 70,340 TEP common units with an aggregate fair value of approximately $3 million , in exchange for the transfer by TD to TEP of a 1.9585% membership interest in Pony Express (computed before giving effect to the issuance of the new membership interest by Pony Express to TEP). TEP also contributed cash of $570 million to Pony Express in exchange for a newly issued membership interest which, when combined with the membership interest transferred from TD and the parties' entry at closing into the Second Amended Pony Express LLC Agreement, constituted TEP's 33.3% membership interest in Pony Express, which represented 100% of the preferred membership units issued by Pony Express. Of the $570 million cash consideration received by Pony Express, $300 million was immediately distributed to TD at closing and $270 million was retained by Pony Express to fund the estimated remaining costs of construction for the Pony Express System and the lateral in Northeast Colorado. The $270 million cash balance was subsequently swept to TD under a cash management agreement between Pony Express and TD and was recorded as a related party loan which bears interest at TD's incremental borrowing rate. There was no remaining balance outstanding on the related party loan at December 31, 2015 . The terms of TEP's first acquisition of a 33.3% membership interest in Pony Express provided TEP a minimum quarterly preference payment of $16.65 million through the quarter ended September 30, 2015 (prorated to approximately $5.4 million for the quarter ended September 30, 2014) with distributions thereafter shared in accordance with the terms of the Second Amended Pony Express LLC Agreement. At the effective date of that transaction, TEP determined that Pony Express was a VIE of which TEP was the primary beneficiary, and consolidated Pony Express accordingly. For additional discussion and disclosure, see Note 3 – Variable Interest Entities . The acquisition of the initial 33.3% membership interest in Pony Express represented a transaction between entities under common control and a change in reporting entity. Effective March 1, 2015 , TEP acquired an additional 33.3% membership interest in Pony Express for cash consideration of $700 million . At closing, Pony Express, TD, and TEP entered into the Pony Express LLC Agreement, which sets forth the relative rights of TD and TEP as the owners of Pony Express. The terms of the transaction increased the minimum quarterly preference payment provided to TEP to $36.65 million through the quarter ending December 31, 2015 (prorated to approximately $23.5 million for the quarter ended March 31, 2015) with distributions thereafter shared in accordance with the terms of the Pony Express LLC Agreement. Upon the effective date of the second acquisition, TEP reevaluated its VIE assessment and determined that Pony Express continued to be considered a VIE of which TEP is the primary beneficiary. The acquisition of the additional 33.3% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction have not been recast to reflect the additional 33.3% membership interest. As discussed in Note 20 – Subsequent Events , effective January 1, 2016 TEP acquired an additional 31.3% membership interest in Pony Express. Formation of BNN Water Solutions, LLC On November 26, 2013, TEP, through its wholly-owned subsidiary Tallgrass Energy Investments, LLC ("TEI"), entered into a joint venture agreement with BNN Energy LLC ("BNN") to form GWSI, which subsequently built and began operating an intrastate fresh water pipeline in Colorado. TEP accounted for its 50% equity interest in GWSI as an equity method investment. On May 13, 2014, TEI entered into a contribution agreement with BNN and several other parties to form a new entity known as Water Solutions. Under the terms of the contribution agreement, TEI agreed to contribute its existing 50% interest in GWSI, along with $7.6 million cash, in exchange for an 80% membership interest in Water Solutions. As part of the transaction, GWSI was renamed Redtail, became a subsidiary of Water Solutions, and issued preferred equity interests to TEI. Among the assets contributed by BNN and the other parties to the transaction were the other 50% interest in Redtail and a 100% equity interest in Alpha Reclaim Technology, LLC ("Alpha"), a company which sources treated wastewater from municipalities in Texas. Alpha is wholly-owned by Redtail. Upon closing of the transaction, TEP obtained a controlling financial interest in Water Solutions and accordingly has accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEP remeasured its previously held 50% equity interest in Redtail to its fair value of $11.9 million , recognized a gain of $9.4 million , and consolidated Water Solutions. The 20% equity interest in Water Solutions held by noncontrolling interests was recorded at its acquisition date fair value of $1.4 million . The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow analysis. These fair value measurements are based on significant inputs that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820. At December 31, 2014, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. During the three months ended June 30, 2015, the preliminary purchase price allocation with respect to Water Solutions was finalized with no material adjustments. On May 20, 2015, TEP acquired an additional 12% equity interest in Water Solutions from NR2, LLC for cash consideration of $600,000 , which was accounted for as an acquisition of noncontrolling interest. As of December 31, 2015 , TEP's aggregate membership interest in Water Solutions was 92% . TEP Acquisition of BNN Western, LLC On December 16, 2015, Whiting Oil and Gas Corporation ("Whiting"), 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. The purchase agreement with Whiting includes a five -year fresh water service contract and a nine -year gathering and disposal contract. At December 31, 2015 , the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. The $75 million purchase price of the assets was allocated entirely to property, plant and equipment. TEP is in the process of obtaining additional information to identify and measure all assets acquired and liabilities assumed in the acquisition within the measurement period. Such provisional amounts will be adjusted if necessary to reflect any new information about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of these amounts. Actual revenue and net income attributable to TEP from Western of $0.3 million and $0.1 million , respectively, was recognized in the accompanying consolidated statements of income for the period from December 16, 2015 to December 31, 2015. Unaudited pro forma revenue and net income attributable to partners for the years ended December 31, 2015 and 2014 is presented below as if the acquisition of Western had been completed on January 1, 2014: Year Ended December 31, 2015 2014 (in thousands) Revenue 538,033 373,470 Net income attributable to partners 161,184 71,347 The pro forma financial information is not necessarily indicative of what the actual results of operations or financial position of TEP would have been if the transactions had in fact occurred on the date or for the period indicated, nor do they purport to project the results of operations or financial position of TEP for any future periods or as of any date. The pro forma financial information does not give effect to any cost savings, operating synergies, or revenue enhancements expected to result from the transactions or the costs to achieve these cost savings, operating synergies, and revenue enhancements. The pro forma revenue and net income includes adjustments to give effect to TEP's consolidated interest in the estimated results of operations of Western for the periods presented. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
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. TEP’s general and administrative costs under the TEP Omnibus Agreement were $21.5 million for the year ended December 31, 2015 , excluding costs attributable to Pony Express. Pony Express had general and administrative costs under the TEP Omnibus Agreement of $20.6 million for the year ended December 31, 2015 . TEP also pays a quarterly reimbursement to TD for costs associated with being a public company, which was $2.5 million for the year ended December 31, 2015 . These amounts will be periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEP. Due to the cash management agreement discussed in Note 2 – Summary of Significant Accounting Policies , intercompany balances at the Predecessor Entities were periodically settled and treated as equity distributions prior to the completion of the IPO on May 17, 2013, prior to April 1, 2014 for Trailblazer, and prior to September 1, 2014 for Pony Express. Balances lent to TD under the Pony Express cash management agreement effective September 1, 2014 are classified as related party receivables in the consolidated balance sheets. During the years ended December 31, 2015 and 2014 we recognized interest income from TD of $0.4 million and $1.5 million , respectively, on the receivable balance under the Pony Express cash management agreement. Totals of transactions with affiliated companies are as follows: Year Ended December 31, 2015 2014 2013 (in thousands) Cost of transportation services (1) $ 25,046 $ — $ — Charges to TEP: (2) Property, plant and equipment, net $ 4,320 $ 17,936 $ 7,604 Other deferred charges $ 7 $ 27 $ 799 Operation and maintenance $ 23,520 $ 18,783 $ 18,439 General and administrative $ 33,432 $ 23,475 $ 20,140 (1) Reflects rent expense under operating lease agreements that primarily consist of crude oil storage capacity leased by Pony Express from Deeprock Development, LLC ("Deeprock"), an unconsolidated affiliate of TD, and Tallgrass Sterling Terminal, LLC ("Sterling"), a consolidated subsidiary of TD. For more information, see Note 12 – Commitments & Contingent Liabilities . (2) 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 "Receivable from related parties" and "Accounts payable to related parties" in the consolidated balance sheets are as follows: December 31, 2015 December 31, 2014 (in thousands) Receivables from related parties: Tallgrass Operations, LLC $ — $ 73,393 Rockies Express Pipeline LLC 15 — Total receivables from related parties $ 15 $ 73,393 Accounts payable to related parties: Tallgrass Operations, LLC $ 7,792 $ 3,894 Tallgrass Equity, LLC 36 — Deeprock Development, LLC 17 — Rockies Express Pipeline LLC 7 21 Total accounts payable to related parties $ 7,852 $ 3,915 Balances of gas imbalances with affiliated shippers are as follows: December 31, 2015 December 31, 2014 (in thousands) Affiliate gas balance receivables $ 92 $ 275 Affiliate gas balance payables $ 227 $ 455 Pursuant to the terms of a Purchase and Sale Agreement dated August 1, 2012, TD, through August 31, 2014, reimbursed TIGT for all costs TIGT incurred with respect to the Pony Express Abandonment, as defined in Note 16 – Regulatory Matters , including, but not limited to, development costs, capital costs and related interest costs associated with the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System (the "Replacement Gas Facilities"). The Replacement Gas Facilities are required as part of the Pony Express Abandonment in order for TIGT to continue service to existing customers after having sold approximately 433 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013. For more information, see Note 16 – Regulatory Matters . Any costs incurred by TIGT subsequent to August 31, 2014 are reimbursed directly by Pony Express. TIGT’s expenditures for the Replacement Gas Facilities are captured in "Prepayments and other current assets" in the consolidated balance sheets as they are incurred and interest is accrued until reimbursement takes place (which is typically monthly). During the year ended December 31, 2014 we received proceeds from TD of $69.2 million and incurred expenditures of $41.7 million . We recognized a contribution of $27.5 million from TD in our Consolidated Statement of Partners' Capital which represents the difference between the carrying amount of the Replacement Gas Facilities and the proceeds received from TD. At December 31, 2015 and 2014, TEP had not incurred any expenditures for the Replacement Gas Facilities that had not been reimbursed. During the year ended December 31, 2013, reimbursements of $4.3 million related to expenditures prior to the closing of the IPO on May 17, 2013 were settled as equity distributions with TD. During the year ended December 31, 2013, reimbursements of $30.4 million related to expenditures subsequent to the closing of the IPO on May 17, 2013 were cash settled by TD. At December 31, 2013, TEP had $17.0 million in "Prepayments and other current assets" related to this project that were cash settled by TD in the first quarter of 2014. |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2015 | |
Inventory Disclosure [Abstract] | |
Inventory | The components of inventory at December 31, 2015 and December 31, 2014 consisted of the following: December 31, 2015 December 31, 2014 (in thousands) Crude oil $ 2,661 $ 581 Materials and supplies 8,581 3,049 Natural gas liquids 395 519 Gas in underground storage 2,156 8,896 Total inventory $ 13,793 $ 13,045 In July 2014, Pony Express entered into an agreement with Shell Trading (US) Company ("Shell") for the purchase of 800,000 barrels of crude oil that was available for initial line fill on the Pony Express System, which was subsequently sold back to Shell in November 2014. To support the resale obligation of Pony Express, in July 2014 TD paid Shell a deposit of $20 million and issued a letter of credit for $20 million and a parent guarantee of $40 million to Shell on behalf of Pony Express. TEP returned the barrels to Shell in November 2014. At that time, the letter of credit was cancelled and Shell returned the $20 million deposit to Pony Express, which Pony Express subsequently returned to TD. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | A summary of net property, plant and equipment by classification is as follows: December 31, 2015 December 31, 2014 (in thousands) Crude oil pipelines $ 1,172,684 $ 939,536 Natural gas pipelines 550,710 548,482 Processing and treating assets 254,073 237,218 Water business assets 81,098 4,453 General and other 69,181 42,719 Construction work in progress 30,699 139,873 Accumulated depreciation and amortization (133,427 ) (59,200 ) Total property, plant and equipment, net $ 2,025,018 $ 1,853,081 Depreciation expense was approximately $75.5 million , $40.9 million , and $36.6 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Capitalized interest was approximately $0.9 million , $1.2 million , and $0.9 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Under a lease agreement effective October 3, 2015, TMID, as lessor, leases capacity on an NGL pipeline that was constructed for a third party. Rental income was approximately $0.8 million for the year ended December 31, 2015 , and was recorded as "Processing and other revenues" in the accompanying consolidated statements of income. Under a lease agreement initially effective November 13, 2012, TIGT, as lessor, leases a portion of its office space to a third party. Rental income was approximately $0.8 million , $1.0 million , and $1.0 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively, and was recorded as "Other income, net" in the accompanying consolidated statements of income. As of December 31, 2015 , future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands): Year Total 2016 $ 3,952 2017 3,967 2018 3,982 2019 3,997 2020 3,385 Thereafter 15,114 Total $ 34,397 |
Goodwill and Intangible Assets
Goodwill and Intangible Assets (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill and Intangible Assets Disclosure [Text Block] | Reconciliation of Goodwill The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the reporting period: Year Ended December 31, 2015 Year Ended December 31, 2014 Natural Gas Transportation & Logistics Processing & Logistics Total Natural Gas Transportation & Logistics Processing & Logistics Total (in thousands) (in thousands) Balance at beginning of period $ 255,558 $ 87,730 $ 343,288 $ 255,558 $ 79,157 $ 334,715 Goodwill acquired — — — — 8,573 (1) 8,573 Balance at end of period $ 255,558 $ 87,730 $ 343,288 $ 255,558 $ 87,730 $ 343,288 (1) The $8.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Water Solutions on May 13, 2014. Annual Goodwill Impairment Analysis We did not elect to apply the qualitative assessment option during our 2015 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. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. 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. Fair value exceeded the book value by at least 10% for each of the reporting units. 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 2015 . Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and potential future impairments. We continue to monitor potential impairment indicators, including declines in our market price, to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary. As a result of a decreased commodity prices in late 2015 and into early 2016, which caused a significant drop in the volumes anticipated from several producers from which TMID receives natural gas for processing, we identified a potential impairment trigger with respect to the $79.2 million of goodwill at the TMID reporting unit, which is a component of our Processing & Logistics segment. We tested TMID's goodwill for impairment as of December 31, 2015 and determined that the fair value of the reporting unit exceeds the carrying value by approximately 21% . As a result, no impairment charge was recorded, however our analysis includes assumptions of a gradual recovery of commodity prices and a corresponding increase in volumes over time. If our outlook for long-term commodity prices is not realized, or our producers further decrease volumes, we could have an impairment in the future. Other Intangible Assets A summary of amortized intangible assets is as follows: December 31, 2015 December 31, 2014 (in thousands) Pony Express oil conversion use rights $ 105,973 $ 105,973 Redtail customer contract (1) — 8,200 Accumulated amortization (9,427 ) (9,635 ) Intangible assets, net $ 96,546 $ 104,538 (1) The Redtail customer contract was fully amortized as of December 31, 2015. Amortization of intangible assets was approximately $8.0 million , $6.2 million , and $3.0 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Estimated future amortization for these intangible assets is as follows (in thousands): Year Total 2016 $ 3,028 2017 3,028 2018 3,028 2019 3,028 2020 3,028 Thereafter 81,406 Total $ 96,546 |
Risk Management
Risk Management | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management | We occasionally enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of natural gas, include, among others (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. 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. As of December 31, 2015 and December 31, 2014 , we had no derivative contracts outstanding. Effect of Derivative Contracts on the Income Statement The following tables summarize the impact of derivative contracts for the years ended December 31, 2015 , 2014 and 2013 : Location of Amount of gain (loss) recognized in income on derivatives Year Ended December 31, 2015 2014 2013 (in thousands) Derivatives not designated as hedging contracts: Energy commodity derivative contracts Natural gas sales $ 427 $ (410 ) $ (548 ) Fair Value Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. We value exchange-traded derivative contracts using quoted market prices for identical securities. OTC derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy. Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. As of December 31, 2015 and December 31, 2014 , we had no derivative contracts outstanding. |
Long-term Debt
Long-term Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-term Debt | Revolving Credit Facility On May 17, 2013, in connection with the IPO, TEP entered into a senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders ("the Credit Agreement"), which will mature on May 17, 2018. On June 25, 2014, TEP and certain of its subsidiaries entered into Amendment No. 1 to the Credit Agreement. On November 24, 2015, TEP and certain of its subsidiaries entered into Amendment No. 2 to the Credit Agreement, which modified certain provisions of the Credit Agreement to increase the amount of the revolving facility from $850 million to $1.1 billion and provide for a committed accordion in an amount up to an additional $400 million , subject to the satisfaction of certain other conditions. The revolving credit facility includes a $75 million sublimit for letters of credit and a $60 million sublimit for swing line loans. As discussed in Note 20 – Subsequent Events , 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 to $1.5 billion . As of January 31, 2016, TEP had approximately $1.2 billion of outstanding borrowings under its revolving credit facility. The following table sets forth the available borrowing capacity under our revolving credit facility as of December 31, 2015 and December 31, 2014 : December 31, 2015 December 31, 2014 (in thousands) Total capacity under the revolving credit facility $ 1,100,000 $ 850,000 Less: Outstanding borrowings under the revolving credit facility (753,000 ) (559,000 ) Available capacity under the revolving credit facility $ 347,000 $ 291,000 The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict our ability (as well as the ability of our restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of our business, engage in certain mergers or make certain investments and acquisitions, enter into non-arms-length transactions with affiliates and designate certain subsidiaries as "Unrestricted Subsidiaries." In addition, we are required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of December 31, 2015 , 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 December 31, 2015 , the weighted average interest rate on outstanding borrowings was 2.08% . 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 consolidated balance sheets as of December 31, 2015 and 2014 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) December 31, 2015 $ — $ 753,000 $ — $ 753,000 $ 753,000 December 31, 2014 $ — $ 559,000 $ — $ 559,000 $ 559,000 The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of December 31, 2015 and December 31, 2014 , the fair value approximates the carrying amount for the borrowings under the revolving credit facility using a discounted cash flow analysis. We are not aware of any factors that would significantly affect the estimated fair value subsequent to December 31, 2015 . |
Partnership Equity and Distribu
Partnership Equity and Distributions | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Partnership Equity and Distributions | Public Offerings On February 27, 2015, we sold 10,000,000 common units representing limited partner interests in an underwritten public offering at a price of $50.82 per unit, or $49.29 per unit net of the underwriter's discount, for net proceeds of approximately $492.4 million after deducting the underwriter's discount and offering expenses. We used the net proceeds from the offering to fund a portion of the consideration for the acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions . Pursuant to the underwriters' option to purchase additional units, we sold an additional 1,200,000 common units representing limited partner interests to the underwriters at a price of $50.82 per unit, or $49.29 per unit net of the underwriter’s discount, for net proceeds of approximately $59.3 million after deducting the underwriter’s discount and offering expenses. We used the net proceeds from this additional purchase of common units to reduce borrowings under our revolving credit facility, a portion of which were used to fund the March 2015 acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions . On July 25, 2014, we sold 8,050,000 common units representing limited partner interests in an underwritten public offering at a price of $41.07 per unit, or $39.74 per unit net of the underwriter's discount, for net proceeds of approximately $319.3 million after deducting the underwriter's discount and offering expenses. We used the net proceeds from the offering to fund a portion of the consideration for the acquisition of the initial 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions . Equity Distribution Agreement On October 31, 2014, we entered into an equity distribution agreement pursuant to which we may sell from time to time through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate offering price of up to $200 million . On May 13, 2015 the amount was subsequently amended to $100.2 million in order to account for follow-on equity offerings under our S-3 shelf registration statement. Sales of the common units, if any, will be made by means of ordinary brokers’ transactions, to or through a market maker or directly on or through an electronic communication network, a "dark pool" or any similar market venue, or as otherwise agreed by the Partnership and one or more of the managers. We intend to use the net proceeds from any sale of the units for general partnership purposes, which may include, among other things, capital expenditures, acquisitions and the repayment of debt. During the year ended December 31, 2015 , we issued and sold 65,744 common units with a weighted average sales price of $45.58 per unit under our equity distribution agreement for net proceeds of approximately $3.0 million (net of approximately $30,000 in commissions and professional service expenses). We used the net proceeds for general partnership purposes. At December 31, 2015 , approximately $95.9 million in aggregate offering price remained available to be issued and sold under the equity distribution agreement. During the year ended December 31, 2014 , we issued and sold 28,625 common units with a weighted average sales price of $44.20 per unit under our equity distribution agreement for net proceeds of approximately $1.1 million (net of approximately $215,000 in commissions and professional service expenses). We used the net proceeds for general partnership purposes. Distributions to Holders of Common Units, Subordinated Units, General Partner Units and Incentive Distribution Rights Our partnership agreement requires us to distribute our available cash, as defined generally below, to unitholders of record on the applicable record date within 45 days after the end of each quarter. Our partnership agreement provides that available cash, each quarter, is first distributed to the common unitholders and the general partner on a pro rata basis until each common unitholder has received $0.2875 per unit, which amount is defined in our partnership agreement as the minimum quarterly distribution ("MQD"). The following table shows the distributions for the periods indicated: Distributions Distribution per Limited Partner Common and Subordinated Unit Limited Partner General Partner Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) 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 December 31, 2014 February 13, 2015 23,782 4,039 473 28,294 0.4850 September 30, 2014 November 14, 2014 20,092 1,208 363 21,663 0.4100 June 30, 2014 August 14, 2014 18,596 758 330 19,684 0.3800 March 31, 2014 May 14, 2014 13,288 126 274 13,688 0.3250 December 31, 2013 February 12, 2014 12,757 63 262 13,082 0.3150 September 30, 2013 November 13, 2013 12,049 — 245 12,294 0.2975 June 30, 2013 August 13, 2013 5,759 — 118 5,877 0.1422 (1) March 31, 2013 N/A N/A N/A N/A N/A N/A (1) The distribution declared on July 18, 2013 for the second quarter of 2013 represented a prorated amount of the MQD of $0.2875 per common unit, based upon the number of days between the closing of the IPO on May 17, 2013 and June 30, 2013. Subordinated Units Under the terms of TEP's partnership agreement and upon the payment of the quarterly cash distribution to unitholders on February 13, 2015, the subordination period ended. As a result, the 16,200,000 subordinated units then held by TD converted into common units on a one for one basis on February 17, 2015. General Partner Units As of December 31, 2015 , the general partner owns an approximate 1.36% general partner interest in TEP, represented by 834,391 general partner units. Under TEP's partnership agreement, the general partner may at any time, but is under no obligation to, contribute additional capital to TEP in order to maintain or attain a 2% general partner interest. Incentive Distribution Rights The general partner also owns all of the IDRs. IDRs represent the right to receive an increasing percentage ( 13% , 23% and 48% ) of quarterly distributions of available cash from operating surplus after the MQD and each target distribution level has been achieved. The general partner may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement. The following discussion related to incentive distributions assumes that our general partner holds a 2% general partner interest and continues to own all of the IDRs. If for any quarter: • We have distributed available cash from operating surplus to all of the common unitholders (and during the subordination period, to the subordinated unitholders) in an amount equal to the MQD for each outstanding unit for such quarter; and • We have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in the payment of the MQD to common unitholders; then, we will distribute additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner: • first , 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $0.3048 per unit for that quarter (the "first target distribution"); • second , 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.3536 per unit for that quarter (the "second target distribution"); • third , 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.4313 per unit for that quarter (the "third target distribution"); and • thereafter , 50% to all unitholders, pro rata, and 50% to our general partner. Definition of Available Cash Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter: • less, the amount of cash reserves established by our general partner to: ▪ provide for the proper conduct of our business (including reserves for future capital expenditures, for anticipated future credit needs subsequent to that quarter, for legal matters and for refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings); ▪ comply with applicable law or regulation, or any of our debt instruments or other agreements; or ▪ provide funds for distributions to unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the MQD on all common units and any cumulative arrearages on such common units for the current quarter); • plus , if our general partner so determines, all or any portion of the cash on hand on the date of distribution of available cash for the quarter, including cash on hand resulting from working capital borrowings made subsequent to the end of such quarter. Other Contributions and Distributions During the year ended December 31, 2015 , TEP was deemed to have made a noncash capital distribution of $324.3 million to the general partner, which represents the excess purchase price over the carrying value of the additional 33.3% membership interest in Pony Express acquired effective March 1, 2015. See Note 4 – Acquisitions for additional information regarding the transaction. We also recognized contributions from noncontrolling interests of $110.1 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 $69.5 million , which consisted primarily of distributions from Pony Express to TD. During the year ended December 31, 2014 , we received net contributions of $312.1 million , $27.5 million , and $5.4 million from the Predecessor Entities, TD, and noncontrolling interests, respectively. Net contributions of $312.1 million from the Predecessor Entities is composed of net contributions of $612.1 million relating to the cash management agreements with TD, as well as a cash distribution of $300 million of the proceeds from the issuance of the preferred membership interest to TEP from Pony Express to TD pursuant to the Pony Express Contribution and Sale Agreement. As discussed in Note 2 – Summary of Significant Accounting Policies , prior to May 17, 2013 for TIGT and TMID, prior to April 1, 2014 for Trailblazer, and prior to September 1, 2014 for Pony Express, the net amount of transfers for loans made each day through the centralized cash management system with TD, less reimbursement payments under the agency agreement described in Note 5 – Related Party Transactions , was recognized as net equity contributions or distributions during that time period. There were no equity contributions or distributions made to TD subsequent to Trailblazer's acquisition by TEP on April 1, 2014 or the acquisition of Pony Express effective September 1, 2014. The $27.5 million contribution from TD represents the difference between the carrying amount of the Replacement Gas Facilities and the proceeds received from TD, as discussed in Note 5 – Related Party Transactions . The $5.4 million contribution from noncontrolling interests represents the cash contributed to Pony Express from TD to fund the quarterly preference payment to TEP as discussed in Note 4 – Acquisitions . During the year ended December 31, 2014, Pony Express made a distribution of $5.4 million to TD, which was settled via the Pony Express cash management agreement. During the year ended December 31, 2014 , TEP was deemed to have made a noncash, net capital distribution of $72.9 million to the general partner, which represents the excess purchase price over the carrying value of the Trailblazer net assets acquired on April 1, 2014. Also during the year ended December 31, 2014, TEP was deemed to have made a capital distribution of $8.7 million to the general partner, which represents the excess purchase price, consisting of $27 million in cash and limited partner common units valued at $3.0 million issued directly to TD, over the net book value of the 1.9585% membership interest in Pony Express transferred from TD to TEP in accordance with the Pony Express Contribution and Sale Agreement. See Note 4 – Acquisitions for additional information regarding the Trailblazer and Pony Express acquisitions. During the year ended December 31, 2013, net distributions from TEP Predecessor to TD were approximately $118.5 million , and included the $85.5 million cash distribution to TD related to the contribution of TIGT and TMID to TEP as well as the $31.2 million net proceeds from the exercise of the underwriter’s option to purchase additional common units as part of the IPO. During the year ended December 31, 2013, the Predecessor Entities recognized net contributions from TD of $379.9 million . |
Commitments and Contingencies (
Commitments and Contingencies (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies Disclosure [Text Block] | Leases Rent expense under operating leases and right of way agreements totaled approximately $25.8 million , $4.7 million , and $327,000 for the years ended December 31, 2015 , 2014 , and 2013 , respectively. At December 31, 2015 , future minimum rental commitments under major, non-cancelable operating leases were as follows (in thousands): Year Total 2016 $ 27,805 2017 28,355 2018 28,714 2019 29,246 2020 29,879 Thereafter 478,550 Total $ 622,549 Operating lease agreements primarily consist of storage capacity leased by Pony Express from Deeprock, an unconsolidated affiliate of TD and Sterling, an indirect wholly-owned subsidiary of TD. Pony Express entered into a lease agreement with Deeprock on November 7, 2012 for the use by Pony Express of storage capacity at the Deeprock tank storage facility near Cushing, Oklahoma. The lease has a five year term which commenced on October 7, 2014. Pony Express made upfront payments totaling $10.9 million , of which $4.6 million was paid in 2013 and $6.3 million was paid in 2014. The upfront payments are recorded as "Deferred charges and other assets" on the accompanying consolidated balance sheets and will be amortized over the lease term. Pony Express has the right to extend the term of the lease for additional periods of five or two years, not to exceed a total of 20 years from when the lease commences. Future minimum rental commitments in the table above assume renewal of the Deeprock lease for the full 20 year term as the storage capacity at Deeprock is integral to the operations of the Pony Express System and renewal of the lease is reasonably assured as a result. On August 26, 2014, Pony Express entered into a lease agreement with Sterling for the use by Pony Express of storage capacity at the Sterling tank storage facility in northeast Colorado. The lease has a five year term which commenced on May 1, 2015. Pony Express has the right to extend the term of the lease for additional periods of five years, not to exceed a total of 20 years from the commencement of the lease agreement. Future minimum rental commitments in the table above assume renewal of the Sterling lease for the full 20 year term as the storage capacity at Sterling is integral to the operations of the lateral in Northeast Colorado and renewal of the lease is reasonably assured as a result. Capital Expenditures We had committed approximately $5.8 million for the future purchase of property, plant and equipment at December 31, 2015 . |
Net Income per Limited Partner
Net Income per Limited Partner Unit | 12 Months Ended |
Dec. 31, 2015 | |
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. As discussed in Note 11 – Partnership Equity and Distributions , the subordinated units were converted to common units effective February 17, 2015. 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. As the IPO was completed on May 17, 2013, no income from the period from January 1, 2013 to May 16, 2013 is allocated to the limited partner units that were issued on May 17, 2013 and all income for such period was allocated to the general partner or predecessor operations. All net income or loss from Trailblazer prior to its acquisition on April 1, 2014 and Pony Express prior to its acquisition effective September 1, 2014 is allocated to predecessor operations in the table below. Historical earnings of transferred businesses for periods prior to the date of those common control drop-down transactions are solely those of the general partner and, therefore we have appropriately excluded any allocation to the limited partner units when determining net income available to common and subordinated unitholders. We present the financial results of any transferred business prior to the drop down transaction date in the line item "Predecessor operations interest in net (income) loss" in the table below. The following table illustrates the Partnership’s calculation of net income per common and subordinated unit for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 Year Ended December 31, 2014 Year Ended December 31, 2013 Period from January 1, 2013 to May 16, 2013 Period from May 17, 2013 to December 31, 2013 (in thousands, except per unit amounts) Net income $ 184,814 $ 59,329 $ 7,624 $ 5,049 $ 2,575 Net (income) loss attributable to noncontrolling interests (24,268 ) 11,352 2,123 761 1,362 Net income attributable to partners 160,546 70,681 9,747 5,810 3,937 Predecessor operations interest in net (income) loss — (1,508 ) 4,432 1,172 3,260 General partner interest in net income (46,478 ) (7,399 ) (7,188 ) (6,982 ) (206 ) Net income available to common and subordinated unitholders $ 114,068 $ 61,774 $ 6,991 $ — $ 6,991 Basic net income per common and subordinated unit $ 1.95 $ 1.39 $ 0.17 $ 0.17 Diluted net income per common and subordinated unit $ 1.91 $ 1.36 $ 0.17 $ 0.17 Basic average number of common and subordinated units outstanding 58,597 44,346 40,450 40,450 Equity Participation Unit equivalent units 978 1,048 1,008 1,008 Diluted average number of common and subordinated units outstanding 59,575 45,394 41,458 41,458 |
Major Customers and Concentrati
Major Customers and Concentration of Credit Risk (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Risks and Uncertainties [Abstract] | |
Major Customers and Concentration of Credit Risk | During the year ended December 31, 2015 , two non-affiliated customers, Continental Resources and Shell, accounted for $84.5 million ( 16% ) and $78.6 million ( 15% ) of our total operating revenues, respectively. The revenues from Continental Resources were earned in our Crude Oil Transportation & Logistics, while the revenues from Shell were earned in both our Crude Oil Transportation & Logistics and Processing & Logistics segments. During the years ended December 31, 2014 and 2013 one non-affiliated customer, Phillips 66, accounted for $113.6 million ( 31% ) and $102.0 million ( 35% ) of our total operating revenues, respectively. All of the Phillips 66 revenues for 2014 and 2013 were earned in our Processing & Logistics segment. For the year ended December 31, 2015 , the percentage of segment revenues from the top ten non-affiliated customers for each segment was as follows: Percentage of Segment Revenue Crude Oil Transportation & Logistics 96% Natural Gas Transportation & Logistics 51% Processing & Logistics 93% We attempt to mitigate credit risk by seeking collateral or financial guarantees and letters of credit from customers with specific credit concerns. In support of credit extended to certain customers, we had received prepayments of $4.7 million and $3.1 million at December 31, 2015 and 2014 , respectively, included in the caption "Other current liabilities" in the accompanying consolidated balance sheets. |
Equity-Based Compensation
Equity-Based Compensation | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Equity-Based Compensation | Long-term Incentive Plan Effective May 13, 2013, the general partner adopted a Long-term Incentive Plan ("LTIP") pursuant to which awards in the form of unrestricted units, restricted units, equity participation units, options, unit appreciation rights or distribution equivalent rights may be granted to employees, consultants, and directors of the general partner and its affiliates who perform services for or on behalf of TEP or its affiliates, including TD. Vesting and forfeiture requirements are at the discretion of the board of directors of the general partner. The LTIP limits the number of units that may be delivered pursuant to vested awards to 10,000,000 common units. Common units canceled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan is administered by the board of directors of TEP’s general partner or a committee thereof, which is referred to as the plan administrator. The plan administrator may terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the LTIP or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The LTIP will expire on the earliest of (i) the date common units are no longer available under the plan for grants, (ii) termination of the plan by the plan administrator or (iii) May 13, 2023 . Equity Participation Units On June 26, 2013, TEP’s general partner approved the grant of up to 1.5 million equity participation units ("EPUs") for issuance to employees and 177,500 EPUs to certain Section 16 officers under the LTIP. Vesting of the EPUs granted to employees is contingent upon the mainline portion of the Pony Express System being placed into service and will generally occur in two parts, with one-third vesting on the later of the in-service date or May 13, 2015, and the remaining two-thirds vesting on the later of the in-service date or May 13, 2017. The mainline portion of the Pony Express System was placed in service in October 2014. Accordingly, one-third of these grants vested on May 13, 2015. New EPUs granted after the first quarter of 2014 will vest on terms and conditions as approved by the general partner or the plan administrator. The EPU grants under the LTIP are measured at their grant date fair value. The EPUs granted are non-participating with respect to distributions, therefore the grant date fair value is discounted from the grant date fair value of TEP’s common units for the present value of the expected future distributions during the vesting period. Total equity-based compensation cost related to the EPU grants was approximately $9.3 million , $10.2 million , and $4.2 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. Of the total compensation cost, $5.1 million , $5.1 million , and $1.8 millions for the years ended December 31, 2015 , 2014 , and 2013 , respectively, were recognized as compensation expense at TEP and the remainder was allocated to TD. As of December 31, 2015 , $14.7 million of total compensation cost related to non-vested EPUs is expected to be recognized over a weighted average period of 2.2 years , a portion of which will be charged to TD. The following table summarizes the changes in the EPUs outstanding for the year ended December 31, 2015 : Year Ended December 31, 2015 Equity Participation Units Weighted Average Beginning of period 1,525,750 $ 18.75 Granted 338,591 40.01 Vested (1) (480,555 ) (19.39 ) Forfeited (58,825 ) (16.98 ) End of period 1,324,961 $ 24.11 (1) During the year ended December 31, 2015 , approximately 344,383 common units (net of tax withholding of approximately 136,172 common units) were issued in connection with the settlement of vested awards. |
Regulatory Matters
Regulatory Matters | 12 Months Ended |
Dec. 31, 2015 | |
Regulatory Matters [Abstract] | |
Regulatory Matters | There are currently no proceedings challenging the currently effective rates of Pony Express or Trailblazer. On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to Section 4 of the Natural Gas Act, discussed in more detail below. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable regulations, to challenge the rates that we charge at our regulated entities. Further, the statute 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 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 Pony Express Abandonment – FERC Docket CP12-495 On August 6, 2012, TIGT filed an application to: (1) abandon for FERC purposes approximately 433 miles of mainline natural gas pipeline facilities, along with associated rights of way and other related equipment (collectively, the "Pony Express Assets"), and the natural gas service therefrom, by transferring those assets to Pony Express, which subsequently converted the Pony Express Assets into crude oil pipeline facilities; and (2) construct and operate certain replacement-type facilities necessary to continue service to existing natural gas firm transportation customers following the conversion, which we refer to as the Replacement Gas Facilities. This project is referred to as the "Pony Express Abandonment." The FERC abandonment does not constitute an abandonment for accounting purposes. Pursuant to the terms of the Purchase and Sale Agreement filed with the FERC and cited by the FERC in approving the Pony Express Abandonment, Pony Express is required to reimburse TIGT for the net book value of the Pony Express Assets plus other TIGT incurred costs required to construct the Replacement Gas Facilities and to arrange substitute gas transportation services to certain TIGT shippers. The Pony Express Abandonment and completion of the Pony Express Project by Pony Express re-deployed existing pipeline assets to meet the growing market need to transport crude oil while at the same time continuing to operate TIGT’s natural gas transportation facilities to meet all current and expected needs of its natural gas customers. By a FERC order issued September 12, 2013, TIGT was granted authorization to abandon the Pony Express Assets and construct the Replacement Gas Facilities. On October 7, 2013 TIGT commenced the mobilization of personnel and equipment for the construction of the Replacement Gas Facilities necessary to complete the Pony Express Abandonment to continue service to existing TIGT customers. In December 2013, TIGT removed the Pony Express Assets from gas service and sold those assets to Pony Express. On May 1, 2014, TIGT commenced commercial service through all of the Replacement Gas Facilities, with the exception of Units 3 and 4 at the Tescott Compressor Station. Service through Units 3 and 4 at the Tescott Compressor Station commenced on May 30, 2014. Cost and Revenue Study – FERC Docket RP11-1494 On October 3, 2015, TIGT submitted a cost and revenue study in compliance with Article IV of the Stipulation and Agreement of Settlement filed on May 5, 2011 in FERC Docket No. RP11-1494 ("2011 Settlement") and approved by the FERC on September 22, 2011. The cost and revenue study demonstrates that TIGT is under-recovering its cost of service. Consistent with the 2011 Settlement, the study was based on the unadjusted actual costs, revenues and volumes for a 12-month base period ended June 30, 2015, in compliance with Section 154.303(a)(1) of the FERC’s regulations. The cost and revenue study did not propose any change to TIGT’s currently effective rates. The cost and revenue study was accepted by FERC on February 1, 2016 in compliance with the 2011 Settlement. 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 Natural Gas Act ("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 expenses and costs it incurs to comply with anticipated new PHMSA and EPA regulations. TIGT also proposed to replace its fixed fuel and lost and unaccounted for ("FL&U") charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period’s under/over collection and the forecasted FL&U expense for the upcoming period. TIGT also proposed to implement a power cost tracker to recover the actual power costs incurred by TIGT to power its compressors. Finally, TIGT proposed certain revisions to its FERC Gas Tariff addressing a number of other rate and non-rate matters. Under the NGA and the FERC’s regulations, TIGT’s shippers and other interested parties, including the FERC’s Trial Staff, have a right to challenge any aspect of TIGT’s rate case filing. Accordingly, numerous TIGT customers have protested aspects of TIGT’s NGA Section 4 rate filing. On November 30, 2015, the FERC issued an order accepting and suspending the proposed rates and a majority of the proposed tariff records to be effective upon motion May 1, 2016, subject to refund, certain modifications to TIGT’s proposed CRM charge, and the outcome of an evidentiary hearing before a FERC Administrative Law Judge (the "Suspension Order"). In the Suspension Order, the FERC also accepted two tariff records related to force majeure events and reservation charge crediting to be effective December 1, 2015, subject to certain modifications. On December 21, 2015, TIGT made a compliance filing with the FERC to modify TIGT’s proposed CRM charge and update the tariff records related to force majeure events and reservation charge crediting as directed by the FERC in the Suspension Order. No comments or protests were filed in response to the compliance filing and FERC accepted the compliance filing on February 1, 2016. One request for rehearing of the Suspension Order is currently pending before the FERC with respect to the Suspension Order’s acceptance, subject to a five-month suspension period, refund, the outcome of the hearing and the modifications made in TIGT's December 21, 2015 compliance filing, of TIGT’s proposed CRM charge. The FERC Administrative Law Judge assigned to the proceeding has issued an order establishing the procedural schedule and TIGT, the FERC’s Trial Staff, and other participants that successfully intervened are actively participating in the litigated proceeding to address those rate and tariff matters set for hearing by the FERC in its Suspension Order. On January 27, 2016, the FERC issued a tolling order to afford the FERC additional time for consideration of matters raised on rehearing regarding the Suspension Order. Additional FERC action is pending. Trailblazer 2013 Rate Case Filing - Docket No. RP13-1031 On January 22, 2014, Trailblazer, the FERC’s Trial Staff, and the active parties in the pipeline’s general rate case finalized a settlement in principle resolving the pending rate issues, including: (i) establishing transportation rates, as well as fuel and lost and unaccounted for charges; (ii) providing a limited profit sharing arrangement for certain revenues earned from interruptible and short-term firm transport; and (iii) setting the minimum and maximum time that can elapse before Trailblazer’s next rate case at the FERC. Trailblazer filed a motion with the FERC’s Chief Administrative Law Judge to accept the settlement rates on an interim basis ("Interim Rates") while the participants finalized a definitive settlement. The Chief Administrative Law Judge accepted the Interim Rates effective February 1, 2014. On February 24, 2014, Trailblazer filed an uncontested offer of settlement ("Stipulation and Agreement") among active party shippers. The Stipulation and Agreement established the Interim Rates as final settlement rates effective February 1, 2014, subject to the issuance of refunds to certain shippers for January 2014 transportation services and revised fuel and lost and unaccounted for rates, effective July 1, 2014. On March 11, 2014, the Presiding Administrative Law Judge certified the Stipulation and Agreement. On May 29, 2014, the FERC approved the Stipulation and Agreement. On June 30, 2014, Trailblazer filed tariff sheets to implement the Stipulation and Agreement effective July 1, 2014. Estimated refunds were reserved from revenues recorded in January 2014. On July 1, 2014, Trailblazer submitted refunds to its customers for amounts collected in excess of amounts that would have been collected under the Settlement Rates, with interest, and on July 18, 2014, filed a report of refunds with the FERC. The FERC issued orders accepting the tariff sheets with the requested effective date of July 1, 2014 and accepting the refund report filing on July 25, 2014 and August 7, 2014, respectively. Per the terms of the Stipulation and Agreement, Trailblazer is required to file a new rate case by January 1, 2019, and no settling party was permitted to file a change to the settlement rates before January 1, 2016. 2015 Annual Fuel Tracker Filing - Docket No. RP15-841-000 On April 1, 2015, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2015 in Docket No. RP15-841-000. This filing incorporates the revised fuel tracker and power cost tracker mechanisms agreed to in the Stipulation and Agreement, which resolves all outstanding issues related to Trailblazer fuel recoveries. The FERC approved this filing on April 23, 2015. Pony Express On September 19, 2014 Pony Express filed with the FERC to adopt a tariff for initial local non-contract rates as well as initial Rules and Regulations in accordance with the Interstate Commerce Act to be effective starting on October 1, 2014. Local Contract Tariff rates were filed with the FERC on October 29, 2014 to be effective starting November 1, 2014. Joint Contract Tariff rates for oil received into the Pony Express pipeline system from the Belle Fourche Pipeline were filed on October 16, 2014 to be effective starting November 1, 2014. Joint Contract Tariff rates for oil received into the Pony Express System from Hiland Pipeline Company were filed on February 27, 2015 and effective April 1, 2015. On May 18, 2015, Pony Express filed with the FERC to implement tariff contract rates for Pony Express’ newly constructed lateral in Northeast Colorado effective June 1, 2015. On May 29, 2015, tariff filings were made with the FERC in Docket No. IS15-492-000 to increase the Pony Express local contract rates for service from the Guernsey origin, and for local non-contract rates from all origins, by amounts reflecting the FERC annual index adjustment of approximately 4.6% effective July 1, 2015. A tariff filing was also made in Docket No. IS15-493-000 on that date to increase joint tariff contract rates for service on Pony Express by approximately 4.6% effective July 1, 2015. On October 29, 2015, Pony Express made a tariff filing with the FERC in Docket No. IS16-42-000 to increase the contract rates under its Local Pipeline Tariff for transportation from receipt points on its lateral in Northeast Colorado to various delivery points in Oklahoma, by an amount reflecting the most recent FERC annual index adjustment of approximately 4.6% effective December 1, 2015. |
Legal and Environmental Matters
Legal and Environmental Matters | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Legal and Environmental Matters | Legal In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on our business, financial position, results of operations or cash flows. We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, have recorded no reserve for legal claims as of December 31, 2015 . We had reserves for legal claims of approximately $0.6 million as of December 31, 2014 . Prairie Horizon On July 3, 2014, Prairie Horizon Agri-Energy LLC ("Prairie Horizon") filed an action in the District Court of Phillips County, Kansas against TIGT seeking damages from an alleged intrusion of foreign material and oil from TIGT into Prairie Horizon's ethanol plant. The matter was removed to the U.S. District Court for the District of Kansas. Prairie Horizon asserted that this intrusion caused substantial damage to Prairie Horizon's ethanol production facilities and resulted in corresponding business income losses. Prairie Horizon also claimed that the intrusion was a violation of TIGT's FERC gas tariff. On September 25, 2015, TIGT and Prairie Horizon reached a settlement agreeing to dismiss all claims with prejudice and releasing TIGT from any further liability. 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 $4.8 million and $5.3 million at December 31, 2015 and 2014 , respectively. TMID Casper Plant, U.S. EPA Notice of Violation In August 2011, the U.S. 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 U.S. 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 U.S. EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the U.S. EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including attempted resolution of more recently identified LDAR issues and 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. TIGT System Failure On June 13, 2013, a failure occurred on a segment of the TIGT pipeline system in Goshen County, Wyoming, resulting in the release of natural gas and the issuance of a Corrective Action Order ("CAO") by PHMSA. The line was promptly brought back into service and the failure did not cause any known injuries, fatalities, fires or evacuations. Pursuant to a letter dated August 14, 2015, PHMSA informed TIGT that it had complied with the terms of the CAO and declared the case closed. As of December 31, 2015, remediation activities were complete. The total cost of remediation was not material. Trailblazer Pipeline Integrity Management Program Trailblazer recently 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 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. Pony Express System Failures On August 31, 2014, a leak occurred at the Sterling Pump Station on the Pony Express System in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on our property and the costs to remediate were not material. In April 2015, PHSMA granted our request to consider the Sterling Pump Station incident closed with no further action. On March 12, 2015, an event occurred at the Yoder Pump Station in Goshen County, Wyoming, related to repair and replacement activities resulting in a spill of approximately 300 bbls of crude oil. As of December 31, 2015, remediation activities were complete. The total cost of remediation was not material and the matters have been closed by the applicable agencies. |
Reporting Segments
Reporting Segments | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Reporting Segments | Our operations are located in the United States. We are organized into three reporting segments: (1) Crude Oil Transportation & Logistics, (2) Natural Gas Transportation & Logistics, and (3) Processing & Logistics. Crude Oil Transportation & Logistics The Crude Oil Transportation & Logistics segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale and other nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado and was placed in service in the second quarter of 2015. As discussed in Note 2 – Summary of Significant Accounting Policies , results for prior periods have been recast to reflect the operations of Pony Express. 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. As discussed in Note 2 – Summary of Significant Accounting Policies , results for prior periods have been recast to reflect the operations of Trailblazer. 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. 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 reimbursed to TD, 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: Year Ended December 31, 2015 2014 2013 Revenue: Total Inter- External Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 304,227 $ — $ 304,227 $ 28,343 $ — $ 28,343 $ — $ — $ — Natural Gas Transportation & Logistics 131,657 (5,384 ) 126,273 140,080 (5,257 ) 134,823 127,877 (1,920 ) 125,957 Processing & Logistics 105,697 — 105,697 208,390 — 208,390 164,569 — 164,569 Corporate and other — — — — — — — — — Total revenue $ 541,581 $ (5,384 ) $ 536,197 $ 376,813 $ (5,257 ) $ 371,556 $ 292,446 $ (1,920 ) $ 290,526 Year Ended December 31, 2015 2014 2013 Adjusted EBITDA: Total Inter- External Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 165,204 $ 5,384 $ 170,588 $ 15,711 $ — $ 15,711 $ (43 ) $ — $ (43 ) Natural Gas Transportation & Logistics 67,368 (5,384 ) 61,984 67,593 (4,015 ) 63,578 56,821 (1,920 ) 54,901 Processing & Logistics 22,746 — 22,746 33,089 — 33,089 23,192 1,920 25,112 Corporate and other (2,979 ) — (2,979 ) (2,500 ) — (2,500 ) (1,580 ) — (1,580 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment — 717 — Non-cash loss allocated to noncontrolling interest 9,377 10,151 — Gain on remeasurement of unconsolidated investment — 9,388 — Less: Interest expense, net of noncontrolling interest (15,517 ) (7,648 ) (11,035 ) Depreciation and amortization expense, net of noncontrolling interest (75,529 ) (45,389 ) (37,898 ) Non-cash (gain) loss related to derivative instruments — 184 (386 ) Non-cash compensation expense (5,103 ) (5,136 ) (1,798 ) Non-cash loss from asset sales (4,795 ) — — Distributions from unconsolidated investment — (1,464 ) — Loss on extinguishment of debt (226 ) — (17,526 ) Net income attributable to partners $ 160,546 $ 70,681 $ 9,747 Year Ended December 31, Capital Expenditures: 2015 2014 2013 (in thousands) Crude Oil Transportation & Logistics $ 38,802 $ 631,883 $ 286,824 Natural Gas Transportation & Logistics 10,478 20,580 28,184 Processing & Logistics 16,107 13,187 31,012 Total capital expenditures $ 65,387 $ 665,650 $ 346,020 Assets: December 31, 2015 December 31, 2014 (in thousands) Crude Oil Transportation & Logistics $ 1,439,418 $ 1,394,793 Natural Gas Transportation & Logistics 706,576 716,106 Processing & Logistics 409,795 340,620 Corporate and other 6,285 5,678 Total assets $ 2,562,074 $ 2,457,197 |
Selected Quarterly Financial Da
Selected Quarterly Financial Data (Unaudited) (Notes) | 12 Months Ended |
Dec. 31, 2015 | |
Selected Quarterly Financial Data (Unaudited) [Abstract] | |
Quarterly Financial Information [Text Block] | The following tables summarize our unaudited quarterly financial data for 2015 and 2014 : Quarter Ended 2015 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 114,675 $ 132,970 $ 138,168 $ 150,384 Operating income $ 25,718 $ 56,355 $ 52,919 $ 62,923 Net income $ 22,990 $ 53,231 $ 49,550 $ 59,043 Net income attributable to partners $ 32,319 $ 44,899 $ 42,679 $ 40,649 Net income allocable to limited partners $ 24,881 $ 33,869 $ 30,533 $ 24,785 Basic net income per limited partner unit $ 0.47 $ 0.56 $ 0.50 $ 0.41 Diluted net income per limited partner unit $ 0.46 $ 0.55 $ 0.50 $ 0.40 Quarter Ended 2014 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 94,779 $ 77,320 $ 89,953 $ 109,504 Operating income $ 16,529 $ 6,475 $ 11,580 $ 18,829 Net income $ 16,617 $ 14,728 $ 11,253 $ 16,731 Net income attributable to partners $ 17,124 $ 15,286 $ 11,444 $ 26,827 Net income allocable to limited partners $ 12,518 $ 15,771 $ 11,143 $ 22,342 Basic net income per limited partner unit $ 0.31 $ 0.39 $ 0.24 $ 0.46 Diluted net income per limited partner unit $ 0.30 $ 0.38 $ 0.23 $ 0.45 |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | Acquisition of an Additional 31.3% of 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 TEP’s common units) issued to TD for total consideration of approximately $743.6 million . The transaction increases TEP’s aggregate membership interest in Pony Express to 98.0% . As part of the transaction, TD granted TEP an 18 month call option to repurchase the newly issued 6,518,000 common units at a price of $42.50 . Revolving Credit Facility In connection with the acquisition of an additional 31.3% membership interest in Pony Express as discussed above, TEP exercised its option to increase the commitment under its existing Credit Agreement from $1.1 billion to $1.5 billion effective January 4, 2016. As of January 31, 2016, TEP had approximately $1.2 billion of outstanding borrowings under its revolving credit facility. 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. |
Summary of Significant Accoun27
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying financial statements and related notes were prepared in accordance with the generally accepted accounting principles ("GAAP") contained in the Financial Accounting Standards Board’s Accounting Standards Codification. 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. The accompanying consolidated financial statements of TEP include historical cost-basis accounts of the assets of TEP Predecessor, contributed to TEP by TD in connection with the IPO, for the periods prior to May 17, 2013, the closing date of TEP’s IPO, as well as Trailblazer for the periods prior to April 1, 2014, the date TEP acquired Trailblazer from TD, and Pony Express for the periods prior to September 1, 2014, the date TEP acquired a controlling 33.3% membership interest in Pony Express, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. Both TEP and TEP Predecessor are considered "entities under common control" as defined under GAAP and, as such, the transfers between the entities of the assets and liabilities have been recorded by TEP at historical cost. TEP, or the Partnership, as used herein refers to the consolidated financial results and operations for TEP Predecessor from its inception through its contribution to TEP and thereafter. |
Consolidation | As further discussed in Note 4 – Acquisitions , TEP closed the acquisition of Trailblazer on April 1, 2014 and the acquisition of a 33.3% membership interest in Pony Express effective September 1, 2014. As the acquisitions of Trailblazer and the initial 33.3% membership interest in Pony Express are considered transactions between entities under common control, and a change in reporting entity, the financial information presented for prior periods has been recast to include Trailblazer and the initial 33.3% membership interest in Pony Express for all periods presented. The acquisition of the additional 33.3% 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 March 1, 2015 have not been recast to reflect the additional 33.3% membership interest. The consolidated financial statements include the accounts of TEP and its subsidiaries and controlled affiliates. Significant intra-entity items have been eliminated in the presentation. Net equity contributions of the TEP Predecessor included in the consolidated statements of cash flows represent transfers of cash as a result of TD’s centralized cash management systems prior to May 17, 2013, and prior to April 1, 2014 for Trailblazer and September 1, 2014 for Pony Express, under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions. As of December 31, 2015, Pony Express participated in a cash management agreement with TD, which held a 33.3% common membership interest in Pony Express as of December 31, 2015, under which cash balances were swept periodically and recorded as loans from Pony Express to TD. 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 will be 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 consolidated balance sheets, to the extent material, the assets of our consolidated VIE that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of our consolidated VIE for which creditors do not have recourse to our general credit. Pony Express is considered to be a VIE under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, we have determined that we are the primary beneficiary as we have the power to direct matters that most significantly impact the activities of Pony Express and have the right to receive benefits of Pony Express that could potentially be significant to Pony Express. We have consolidated Pony Express accordingly. For additional information see Note 3 – Variable Interest Entities . |
Use of Estimates | Use of Estimates Certain amounts included in or affecting these 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. |
Cash and Cash Equivalents | Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. On November 12, 2012, TIGT and TMID entered into a centralized cash management agreement with TD. In accordance with the cash management agreement, the subsidiary companies made loans on each business day equal to the amount swept from their depository bank accounts. At the beginning of the following month, the total of these loans for each company, less reimbursement payments under the agreements described below in Note 5 – Related Party Transactions , was transferred to an interest bearing account and subsequently, periodically recorded as equity distributions. This practice was discontinued effective May 17, 2013, when TIGT and TMID were contributed to TEP. Subsequent to May 17, 2013, all payable and receivable balances between TEP and TD are cash settled with the exception of certain balances payable from Pony Express to TD, which have been settled against the receivable from TD via the Pony Express cash management agreement. Net equity distributions of the Predecessor Entities included in the Consolidated Statements of Cash Flows represent transfers of cash as a result of TD’s centralized cash management systems prior to May 17, 2013, and prior to April 1, 2014 for Trailblazer and September 1, 2014 for Pony Express, under which cash balances were swept daily and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions. As of December 31, 2015, Pony Express participated in a cash management agreement with TD, which held a 33.3% common membership interest in Pony Express as of December 31, 2015, under which cash balances were swept daily and recorded as loans from Pony Express to TD. |
Accounts Receivable and Allowance for Doubtful Accounts | Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable are carried at their estimated collectible amounts. We make periodic reviews and evaluations of the appropriateness of the allowance for doubtful accounts based on a historical analysis of uncollected amounts, and adjustments are recorded as necessary for changed circumstances and customer-specific information. When specific receivables are determined to be uncollectible, the reserve and receivable are relieved. Our allowance for doubtful accounts totaled $0.6 million and $0.5 million at December 31, 2015 and 2014 , respectively. |
Inventories | Inventories Inventories primarily consist of gas in underground storage, materials and supplies, natural gas liquids and crude oil. Gas in underground storage, sometimes referred to as working gas, and natural gas liquids are recorded at the lower of historical cost or market using the average cost method. As discussed further under " Revenue Recognition " below, a loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil, which we can then sell. As pipeline allowance oil is accumulated, it is recorded as inventory at the lower of historical cost or market using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence. For additional information, see " Gas in Underground Storage " below. |
Accounting for Regulatory Activities | Accounting for Regulatory Activities Regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We recorded regulatory assets of approximately $2.8 million and $1.4 million included in "Deferred charges and other assets" in the consolidated balance sheets at December 31, 2015 and 2014 , respectively. Regulatory assets at December 31, 2015 were primarily attributable to costs associated with both TIGT's 2015 Rate Case Filing and Trailblazer’s 2013 Rate Case Filing as more fully described in Note 16 – Regulatory Matters , while regulatory assets at December 31, 2014 were primarily attributable to costs associated with Trailblazer’s 2013 Rate Case Filing . We recorded regulatory liabilities of approximately $2.2 million and $2.3 million included in "Other current liabilities" in the consolidated balance sheet at December 31, 2015 and 2014 , respectively, related to Trailblazer's fuel tracker liabilities as described in Note 16 – Regulatory Matters . |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is stated at historical cost, which for constructed plants includes indirect costs such as payroll taxes, other employee benefits, allowance for funds used during construction for regulated assets and other costs directly related to the projects. Expenditures that increase capacities, improve efficiencies or extend useful lives are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs related to the construction of assets, including internal labor costs, interest and engineering costs. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred. |
Intangible Assets | Intangible Assets We account for intangible assets in accordance with ASC 805, which established that an intangible asset is identifiable if it meets either the separability criterion or the contractual-legal criterion. Further, in accordance with ASC 805, contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of TIGT's natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years , the period of expected future benefit. Intangible assets arose at BNN Redtail, LLC ("Redtail") as a result of a significant customer contract with favorable market terms which was acquired as part of the Water Solutions transaction discussed in Note 4 – Acquisitions . This intangible asset was amortized on a straight-line basis over a period of 1.6 years , the remaining term of the contract at the time of acquisition, and was fully amortized as of December 31, 2015. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset or asset group’s use and its eventual disposition are less than its carrying amount. We assess our long-lived assets for impairment in accordance with the relevant Codification guidance. A long-lived asset or asset group is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Examples of long-lived asset impairment indicators include: • a significant decrease in the market value of a long-lived asset or group; • a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition; • a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process; • an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group; • a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and • a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. When an impairment indicator is present, we first assess the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset to the carrying amount of the asset. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the assets is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized. |
Gas in Underground Storage | Gas in Underground Storage Gas in underground storage represents the cost of base gas, which refers to the volumes necessary to maintain pressure and deliverability requirements in our storage facilities. We record base gas as a component of property, plant and equipment. We maintain working gas in our underground storage facilities on behalf of certain third parties. We receive a fee for our storage services but do not reflect the value of third-party gas in the accompanying consolidated financial statements. We occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost or market. |
Depreciation and Amortization | Depreciation and Amortization For non-regulated assets, we have elected to use the straight-line method of depreciation. For our regulated assets, we have elected to compute depreciation using a composite method employed by applying a single depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. The rates of depreciation for the various classes of depreciable assets are as follows: Range of Depreciation Rates Crude oil pipelines 2.8% Natural gas pipelines 0.7 - 3.4% Processing & treating assets 3.3% Water business assets 3.3 - 20.0% Replacement Gas Facilities (1) 10.0% General & other 6.8 - 12.0% (1) Represents the Replacement Gas Facilities as discussed in Note 5 – Related Party Transactions and Note 16 – Regulatory Matters . |
Gas Imbalances | Gas Imbalances Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts from and gas deliveries to interconnecting pipelines under various operational balancing and imbalance agreements. Gas imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements. Imbalances are valued at applicable average market index prices. |
Deferred Financing Costs | Deferred Financing Costs Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method. |
Goodwill | Goodwill 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 the fair value over the carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31st. 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. See Note 8 – Goodwill and Other Intangible Assets for additional information regarding impairment testing performed during 2015. |
Investment in Unconsolidated Affiliates | Investment in Unconsolidated Affiliates We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where we have the ability to exercise significant influence. We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary. Our investment in Grasslands Water Services I, LLC ("GWSI"), which owns a fresh water transportation pipeline, was initially recorded under the equity method of accounting as we had the ability to exercise significant influence, but not control, over this investment. There was $0.7 million equity in earnings recognized for the year ended December 31, 2014. There were no equity in earnings recognized for the year ended December 31, 2015. As discussed in Note 4 – Acquisitions , during the year ended December 31, 2014, TEP acquired a controlling interest in GWSI, which was subsequently renamed BNN Redtail, LLC ("Redtail"), and consolidated its investment in Redtail as of May 13, 2014 accordingly. |
Revenue Recognition | Revenue Recognition We recognize revenues as services are rendered or goods are sold to a purchaser at a fixed and determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. We provide various types of natural gas storage and transportation services and crude oil transportation services to our customers in which the commodity remains the property of these customers at all times. Crude oil transportation services occur in the Crude Oil Transportation & Logistics segment. We provide various types of crude oil transportation services to our customers and, other than pipeline allowance oil, do not take title to the crude oil and do not incur the risks and rewards of ownership. In many cases the customer has committed to ship a fixed quantity of oil barrels per month. For barrels physically received by us and delivered to the customers’ agreed upon destination point, revenue is recognized in the period the service is provided. Shipper deficiencies, or barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers’ agreed upon destination point, are charged at the committed tariff rate per barrel and recorded as a deferred liability until the barrels are physically transported and delivered. In the case of non-committed shippers, revenue is recognized in the same manner utilized for the barrels physically transported and delivered. A loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil. Any pipeline allowance oil that remains after replacing losses in transit can be sold. We take title and record revenue at market prices when the volumes included in the pipeline loss allowance are delivered from the customer. When pipeline loss allowance oil is eventually sold we record revenue at the contractual sales price and cost of sales at average cost as discussed in "Inventories" above. Natural gas transportation and storage services occur in the Natural Gas Transportation & Logistics segment. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fee-based component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to "firm" and "interruptible" transportation services, we also provide natural gas park and loan services to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized as services are provided, based on the terms negotiated under these contracts. Natural gas liquids sales occur in the Processing & Logistics segment and consist of the sale of outputs from our processing plants and the marketing of natural gas liquids that are delivered by our suppliers under either fee-based arrangements or percent-of-proceeds arrangements. Under these arrangements, we treat and process the natural gas delivered by our suppliers, and then sell the resulting NGLs and condensate based on published index market prices. We remit to the producers an agreed-upon percentage of the actual proceeds that we receive from our sales of the NGLs and condensate. We keep the difference between the proceeds received and the amount remitted back to the producer. We generally report gross revenues in the consolidated statements of income, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Processing and other revenues primarily represent fees for processing, treating and fractionation of natural gas and NGLs earned under fee-based arrangements and revenue from water services earned in the Processing & Logistics segment. Natural gas sales occur in both the Natural Gas Transportation & Logistics segment and in the Processing & Logistics segment. In the Natural Gas Transportation & Logistics segment, transportation services revenue is recognized when a portion of the natural gas transported by customers is collected as a contractual fee to compensate us for fuel consumed by pipeline and storage operations. We take title and record revenue at market prices when the volumes included in the contractual fee are delivered from the customer and injected into our storage facility. When the excess volumes are eventually sold we record natural gas sales revenue at the contractual sales price and cost of sales at average cost. In addition, when operational conditions allow, we occasionally sell "base gas," which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Processing & Logistics segment, we purchase natural gas primarily for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased that exceed our business needs. |
Commitments and Contingencies | Commitments and Contingencies We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. |
Environmental Costs | Environmental Costs We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense amounts that relate to an existing condition caused by past operations that do not contribute to current or future revenue generation. We do not discount environmental liabilities to a net present value, and record environmental liabilities when environmental assessments and/or remedial efforts are probable and costs can be reasonably estimated. Recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action. Estimates of environmental liabilities are based on currently available facts and presently enacted laws and regulations taking into consideration the likely effects of other factors including our prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual cost or new information. |
Fair Value | Fair Value Fair value, as defined in the Codification, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit price. We apply the fair value measurement guidance to financial assets and liabilities in determining the fair value of derivative assets and liabilities, and to nonfinancial assets and liabilities upon the acquisition of a business or in conjunction with the measurement of an impairment loss on an asset group or goodwill under the accounting guidance for the impairment of long-lived assets or goodwill. The fair value measurement accounting guidance requires that we make assumptions that market participants would use in pricing an asset or liability based on the best information available. These factors include nonperformance risk (the risk that the obligation will not be fulfilled) and credit risk of the reporting entity (for liabilities) and of the counterparty (for assets). The fair value measurement guidance prohibits the inclusion of transaction costs and any adjustments for blockage factors in determining the instruments’ fair value. The principal or most advantageous market should be considered from the perspective of the reporting entity. Fair value, where available, is based on observable market prices. Where observable market prices or inputs are not available, different valuation models and techniques are applied. These models and techniques attempt to maximize the use of observable inputs and minimize the use of unobservable inputs. The process involves varying levels of management judgment, the degree of which is dependent on the price transparency of the instruments or market and the instruments’ complexity. To increase consistency and enhance disclosure of fair value, the Codification creates a fair value hierarchy to prioritize the inputs used to measure fair value into three categories. An asset or liability’s level within the fair value hierarchy is based on the lowest level of input significant to the fair value measurement, where Level 1 is the highest and Level 3 is the lowest. The three levels are defined as follows: • Level 1 Inputs-quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date; • Level 2 Inputs-inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and • Level 3 Inputs-unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data). Any transfers between levels within the fair value hierarchy are recognized at the end of the reporting period. For information regarding financial instruments measured at fair value on a recurring basis, see Note 9 – Risk Management . For information regarding the fair value of financial instruments not measured at fair value in the consolidated balance sheets, see Note 10 – Long-term Debt . |
Risk Management Activities | Risk Management Activities We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas. We record derivative contracts at their estimated fair values as of each reporting date. For more information on our risk management activities, see Note 9 – Risk Management . |
Equity-Based Compensation | Equity-Based Compensation Equity-based compensation grants are measured at their grant date fair value and related compensation cost is recognized over the vesting period of the grant. Compensation cost for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award. As discussed in Note 15 – Equity-Based Compensation , a portion of the expense recognized relating to equity-based compensation grants is charged to TD. |
Income Taxes | Income Taxes Prior to September 1, 2014, TEP was comprised solely of limited liability companies that were flow-through entities (that is, partnerships or disregarded entities) for income tax purposes. As discussed above, effective September 1, 2014 TEP acquired a 33.3% membership interest in Pony Express, which in turn owned 99.8% of Tallgrass Pony Express Pipeline (Colorado), Inc. ("PXP Colorado"), a C corporation. At that time, PXP Colorado was in the process of constructing the lateral in Northeast Colorado and had not yet commenced operations or generated any income. PXP Colorado was subsequently merged into Pony Express prior to the commencement of commercial operations on the lateral in Northeast Colorado. On September 14, 2015, TEP, through its membership interest in Pony Express, formed a new C corporation, Tallgrass Colorado Pipeline, Inc. ("Tallgrass Colorado"), which is 99.8% owned by Pony Express. The remaining 0.2% interest in Tallgrass Colorado is held by direct and indirect wholly owned subsidiaries of TEP. Tallgrass Colorado was formed for the purpose of the potential construction of a lateral pipeline that would interconnect with the Pony Express System's existing lateral in Northeast Colorado and has not yet commenced operations or generated any income. Accordingly, no provision for federal or state income taxes has been recorded in the financial statements of TEP. |
Accounting Pronouncements Issued But Not Yet Effective | Accounting Pronouncements Issued But Not Yet Effective Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers (Topic 606)" In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. The amendments in ASU 2014-09 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact of ASU 2014-09. ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period" In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The adoption of ASU 2014-12 is not expected to have a material impact on our financial position and results of operations. ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis" In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis. ASU 2015-02 will change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 will modify the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminate the presumption that a general partner should consolidate a limited partnership, and change certain aspects of the consolidation analysis for reporting entities that are involved with VIEs, particularly for those with fee arrangements and related party relationships. The amendments in ASU 2015-02 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early application is permitted, including adoption in an interim period. The adoption of ASU 2015-02 is not expected to have a material impact on our financial position and results of operations. ASU No. 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory" In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory. ASU 2015-11 establishes a "lower of cost and net realizable value" model for the measurement of most inventory balances. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The amendments in ASU 2015-11 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We are currently evaluating the impact of ASU 2015-11. ASU No. 2015-16, "Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments" In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. ASU 2015-16 simplifies the accounting for measurement-period adjustments for provisional amounts recognized in a business combination by eliminating the requirement for an acquirer to retrospectively account for measurement-period adjustments. Under the updated guidance, the acquirer must recognize adjustments in the reporting period in which the adjustment amounts are determined and the effect on earnings as a result of the change to the provisional amounts must be calculated as if the accounting had been completed at the acquisition date. The amendments in ASU 2015-16 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted, and must be applied prospectively. We are currently evaluating the impact of ASU 2015-16. |
Description of Business Schedul
Description of Business Schedule of Other Ownership Interests (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Schedule of Other Ownership Interests [Abstract] | |
Schedule of Other Ownership Interests [Table Text Block] | The table below summarizes our equity ownership as of December 31, 2015 : Unit Holder Limited Partner Common Units General Partner Units Percentage of Outstanding Limited Partner Common Units Percentage of Outstanding Common and General Partner Units Public Unitholders 34,288,752 — 56.54 % 55.77 % Tallgrass Equity, LLC 20,000,000 — 32.98 % 32.53 % Tallgrass Development, LP 6,355,480 — 10.48 % 10.34 % Tallgrass MLP GP, LLC (1) — 834,391 — 1.36 % Total 60,644,232 834,391 100.00 % 100.00 % (1) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights ("IDRs"). |
Summary of Significant Accoun29
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Summary of Significant Accounting Policies Text Block [Abstract] | |
Estimated Useful Lives | The rates of depreciation for the various classes of depreciable assets are as follows: Range of Depreciation Rates Crude oil pipelines 2.8% Natural gas pipelines 0.7 - 3.4% Processing & treating assets 3.3% Water business assets 3.3 - 20.0% Replacement Gas Facilities (1) 10.0% General & other 6.8 - 12.0% (1) Represents the Replacement Gas Facilities as discussed in Note 5 – Related Party Transactions and Note 16 – Regulatory Matters . |
Variable Interest Entity (Table
Variable Interest Entity (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Variable Interest Entities [Table Text Block] | The carrying amounts and classifications of the Pony Express assets and liabilities included in TEP's consolidated balance sheet at December 31, 2015 and December 31, 2014 are as follows: December 31, 2015 December 31, 2014 (in thousands) Current assets $ 46,800 $ 93,019 Noncurrent assets 1,391,906 1,300,816 Total assets $ 1,438,706 $ 1,393,835 Current liabilities $ 51,349 $ 52,547 Total liabilities $ 51,349 $ 52,547 |
Acquisitions Business Acquisiti
Acquisitions Business Acquisition Pro Forma Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Business Acquisition, Pro Forma Information [Table Text Block] | Unaudited pro forma revenue and net income attributable to partners for the years ended December 31, 2015 and 2014 is presented below as if the acquisition of Western had been completed on January 1, 2014: Year Ended December 31, 2015 2014 (in thousands) Revenue 538,033 373,470 Net income attributable to partners 161,184 71,347 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Schedule of Transactions with Affiliated Companies | Totals of transactions with affiliated companies are as follows: Year Ended December 31, 2015 2014 2013 (in thousands) Cost of transportation services (1) $ 25,046 $ — $ — Charges to TEP: (2) Property, plant and equipment, net $ 4,320 $ 17,936 $ 7,604 Other deferred charges $ 7 $ 27 $ 799 Operation and maintenance $ 23,520 $ 18,783 $ 18,439 General and administrative $ 33,432 $ 23,475 $ 20,140 (1) Reflects rent expense under operating lease agreements that primarily consist of crude oil storage capacity leased by Pony Express from Deeprock Development, LLC ("Deeprock"), an unconsolidated affiliate of TD, and Tallgrass Sterling Terminal, LLC ("Sterling"), a consolidated subsidiary of TD. For more information, see Note 12 – Commitments & Contingent Liabilities . (2) 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 "Receivable from related parties" and "Accounts payable to related parties" in the consolidated balance sheets are as follows: December 31, 2015 December 31, 2014 (in thousands) Receivables from related parties: Tallgrass Operations, LLC $ — $ 73,393 Rockies Express Pipeline LLC 15 — Total receivables from related parties $ 15 $ 73,393 Accounts payable to related parties: Tallgrass Operations, LLC $ 7,792 $ 3,894 Tallgrass Equity, LLC 36 — Deeprock Development, LLC 17 — Rockies Express Pipeline LLC 7 21 Total accounts payable to related parties $ 7,852 $ 3,915 |
Schedule of Balances of Gas Imbalance with Affiliated Shippers | Balances of gas imbalances with affiliated shippers are as follows: December 31, 2015 December 31, 2014 (in thousands) Affiliate gas balance receivables $ 92 $ 275 Affiliate gas balance payables $ 227 $ 455 |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Inventory Disclosure [Abstract] | |
Schedule of Components of Inventory | The components of inventory at December 31, 2015 and December 31, 2014 consisted of the following: December 31, 2015 December 31, 2014 (in thousands) Crude oil $ 2,661 $ 581 Materials and supplies 8,581 3,049 Natural gas liquids 395 519 Gas in underground storage 2,156 8,896 Total inventory $ 13,793 $ 13,045 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Components of Property Plant and Equipment | A summary of net property, plant and equipment by classification is as follows: December 31, 2015 December 31, 2014 (in thousands) Crude oil pipelines $ 1,172,684 $ 939,536 Natural gas pipelines 550,710 548,482 Processing and treating assets 254,073 237,218 Water business assets 81,098 4,453 General and other 69,181 42,719 Construction work in progress 30,699 139,873 Accumulated depreciation and amortization (133,427 ) (59,200 ) Total property, plant and equipment, net $ 2,025,018 $ 1,853,081 |
Schedule of Future Minimum Rental Payments for Operating Leases | As of December 31, 2015 , future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands): Year Total 2016 $ 3,952 2017 3,967 2018 3,982 2019 3,997 2020 3,385 Thereafter 15,114 Total $ 34,397 At December 31, 2015 , future minimum rental commitments under major, non-cancelable operating leases were as follows (in thousands): Year Total 2016 $ 27,805 2017 28,355 2018 28,714 2019 29,246 2020 29,879 Thereafter 478,550 Total $ 622,549 |
Goodwill and Intangible Asset35
Goodwill and Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of goodwill by segment and changes during the period | The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the reporting period: Year Ended December 31, 2015 Year Ended December 31, 2014 Natural Gas Transportation & Logistics Processing & Logistics Total Natural Gas Transportation & Logistics Processing & Logistics Total (in thousands) (in thousands) Balance at beginning of period $ 255,558 $ 87,730 $ 343,288 $ 255,558 $ 79,157 $ 334,715 Goodwill acquired — — — — 8,573 (1) 8,573 Balance at end of period $ 255,558 $ 87,730 $ 343,288 $ 255,558 $ 87,730 $ 343,288 (1) The $8.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Water Solutions on May 13, 2014. |
Schedule of Finite-Lived Intangible Assets | A summary of amortized intangible assets is as follows: December 31, 2015 December 31, 2014 (in thousands) Pony Express oil conversion use rights $ 105,973 $ 105,973 Redtail customer contract (1) — 8,200 Accumulated amortization (9,427 ) (9,635 ) Intangible assets, net $ 96,546 $ 104,538 (1) The Redtail customer contract was fully amortized as of December 31, 2015. |
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense | Estimated future amortization for these intangible assets is as follows (in thousands): Year Total 2016 $ 3,028 2017 3,028 2018 3,028 2019 3,028 2020 3,028 Thereafter 81,406 Total $ 96,546 |
Risk Management (Tables)
Risk Management (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Contracts Included in Consolidated Statements of Income | The following tables summarize the impact of derivative contracts for the years ended December 31, 2015 , 2014 and 2013 : Location of Amount of gain (loss) recognized in income on derivatives Year Ended December 31, 2015 2014 2013 (in thousands) Derivatives not designated as hedging contracts: Energy commodity derivative contracts Natural gas sales $ 427 $ (410 ) $ (548 ) |
Long-term Debt (Tables)
Long-term Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Schedule of Line of Credit Facilities | The following table sets forth the available borrowing capacity under our revolving credit facility as of December 31, 2015 and December 31, 2014 : December 31, 2015 December 31, 2014 (in thousands) Total capacity under the revolving credit facility $ 1,100,000 $ 850,000 Less: Outstanding borrowings under the revolving credit facility (753,000 ) (559,000 ) Available capacity under the revolving credit facility $ 347,000 $ 291,000 |
Carrying Amount and Fair value of TEP's Long-term Debt | The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the consolidated balance sheets as of December 31, 2015 and 2014 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) December 31, 2015 $ — $ 753,000 $ — $ 753,000 $ 753,000 December 31, 2014 $ — $ 559,000 $ — $ 559,000 $ 559,000 |
Partnership Equity and Distri38
Partnership Equity and Distributions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Summary of Distributions | The following table shows the distributions for the periods indicated: Distributions Distribution per Limited Partner Common and Subordinated Unit Limited Partner General Partner Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) 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 December 31, 2014 February 13, 2015 23,782 4,039 473 28,294 0.4850 September 30, 2014 November 14, 2014 20,092 1,208 363 21,663 0.4100 June 30, 2014 August 14, 2014 18,596 758 330 19,684 0.3800 March 31, 2014 May 14, 2014 13,288 126 274 13,688 0.3250 December 31, 2013 February 12, 2014 12,757 63 262 13,082 0.3150 September 30, 2013 November 13, 2013 12,049 — 245 12,294 0.2975 June 30, 2013 August 13, 2013 5,759 — 118 5,877 0.1422 (1) March 31, 2013 N/A N/A N/A N/A N/A N/A (1) The distribution declared on July 18, 2013 for the second quarter of 2013 represented a prorated amount of the MQD of $0.2875 per common unit, based upon the number of days between the closing of the IPO on May 17, 2013 and June 30, 2013. |
Commitments and Contingencies39
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Future Minimum Rental Payments for Operating Leases | As of December 31, 2015 , future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands): Year Total 2016 $ 3,952 2017 3,967 2018 3,982 2019 3,997 2020 3,385 Thereafter 15,114 Total $ 34,397 At December 31, 2015 , future minimum rental commitments under major, non-cancelable operating leases were as follows (in thousands): Year Total 2016 $ 27,805 2017 28,355 2018 28,714 2019 29,246 2020 29,879 Thereafter 478,550 Total $ 622,549 |
Net Income per Limited Partne40
Net Income per Limited Partner Unit (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 Year Ended December 31, 2014 Year Ended December 31, 2013 Period from January 1, 2013 to May 16, 2013 Period from May 17, 2013 to December 31, 2013 (in thousands, except per unit amounts) Net income $ 184,814 $ 59,329 $ 7,624 $ 5,049 $ 2,575 Net (income) loss attributable to noncontrolling interests (24,268 ) 11,352 2,123 761 1,362 Net income attributable to partners 160,546 70,681 9,747 5,810 3,937 Predecessor operations interest in net (income) loss — (1,508 ) 4,432 1,172 3,260 General partner interest in net income (46,478 ) (7,399 ) (7,188 ) (6,982 ) (206 ) Net income available to common and subordinated unitholders $ 114,068 $ 61,774 $ 6,991 $ — $ 6,991 Basic net income per common and subordinated unit $ 1.95 $ 1.39 $ 0.17 $ 0.17 Diluted net income per common and subordinated unit $ 1.91 $ 1.36 $ 0.17 $ 0.17 Basic average number of common and subordinated units outstanding 58,597 44,346 40,450 40,450 Equity Participation Unit equivalent units 978 1,048 1,008 1,008 Diluted average number of common and subordinated units outstanding 59,575 45,394 41,458 41,458 |
Major Customers and Concentra41
Major Customers and Concentration of Credit Risk Major Customers and Concentration of Credit Risk (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Risks and Uncertainties [Abstract] | |
Schedules of Concentration of Risk | For the year ended December 31, 2015 , the percentage of segment revenues from the top ten non-affiliated customers for each segment was as follows: Percentage of Segment Revenue Crude Oil Transportation & Logistics 96% Natural Gas Transportation & Logistics 51% Processing & Logistics 93% |
Equity-Based Compensation (Tabl
Equity-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Summarizes Changes in EPUs Outstanding | The following table summarizes the changes in the EPUs outstanding for the year ended December 31, 2015 : Year Ended December 31, 2015 Equity Participation Units Weighted Average Beginning of period 1,525,750 $ 18.75 Granted 338,591 40.01 Vested (1) (480,555 ) (19.39 ) Forfeited (58,825 ) (16.98 ) End of period 1,324,961 $ 24.11 (1) During the year ended December 31, 2015 , approximately 344,383 common units (net of tax withholding of approximately 136,172 common units) were issued in connection with the settlement of vested awards. |
Reporting Segments (Tables)
Reporting Segments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Summary of TEP's Segment Information of Revenue | The following tables set forth our segment information for the periods indicated: Year Ended December 31, 2015 2014 2013 Revenue: Total Inter- External Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 304,227 $ — $ 304,227 $ 28,343 $ — $ 28,343 $ — $ — $ — Natural Gas Transportation & Logistics 131,657 (5,384 ) 126,273 140,080 (5,257 ) 134,823 127,877 (1,920 ) 125,957 Processing & Logistics 105,697 — 105,697 208,390 — 208,390 164,569 — 164,569 Corporate and other — — — — — — — — — Total revenue $ 541,581 $ (5,384 ) $ 536,197 $ 376,813 $ (5,257 ) $ 371,556 $ 292,446 $ (1,920 ) $ 290,526 |
Summary of TEP's Segment Information of Earnings | Year Ended December 31, 2015 2014 2013 Adjusted EBITDA: Total Inter- External Total Inter- External Total Inter- External (in thousands) Crude Oil Transportation & Logistics $ 165,204 $ 5,384 $ 170,588 $ 15,711 $ — $ 15,711 $ (43 ) $ — $ (43 ) Natural Gas Transportation & Logistics 67,368 (5,384 ) 61,984 67,593 (4,015 ) 63,578 56,821 (1,920 ) 54,901 Processing & Logistics 22,746 — 22,746 33,089 — 33,089 23,192 1,920 25,112 Corporate and other (2,979 ) — (2,979 ) (2,500 ) — (2,500 ) (1,580 ) — (1,580 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investment — 717 — Non-cash loss allocated to noncontrolling interest 9,377 10,151 — Gain on remeasurement of unconsolidated investment — 9,388 — Less: Interest expense, net of noncontrolling interest (15,517 ) (7,648 ) (11,035 ) Depreciation and amortization expense, net of noncontrolling interest (75,529 ) (45,389 ) (37,898 ) Non-cash (gain) loss related to derivative instruments — 184 (386 ) Non-cash compensation expense (5,103 ) (5,136 ) (1,798 ) Non-cash loss from asset sales (4,795 ) — — Distributions from unconsolidated investment — (1,464 ) — Loss on extinguishment of debt (226 ) — (17,526 ) Net income attributable to partners $ 160,546 $ 70,681 $ 9,747 Year Ended December 31, Capital Expenditures: 2015 2014 2013 (in thousands) Crude Oil Transportation & Logistics $ 38,802 $ 631,883 $ 286,824 Natural Gas Transportation & Logistics 10,478 20,580 28,184 Processing & Logistics 16,107 13,187 31,012 Total capital expenditures $ 65,387 $ 665,650 $ 346,020 |
Summary of TEP's Segment Information for Payments to Acquire Plant, Property and Equipment | Year Ended December 31, Capital Expenditures: 2015 2014 2013 (in thousands) Crude Oil Transportation & Logistics $ 38,802 $ 631,883 $ 286,824 Natural Gas Transportation & Logistics 10,478 20,580 28,184 Processing & Logistics 16,107 13,187 31,012 Total capital expenditures $ 65,387 $ 665,650 $ 346,020 |
Summary of TEP's Segment Information of Assets | Assets: December 31, 2015 December 31, 2014 (in thousands) Crude Oil Transportation & Logistics $ 1,439,418 $ 1,394,793 Natural Gas Transportation & Logistics 706,576 716,106 Processing & Logistics 409,795 340,620 Corporate and other 6,285 5,678 Total assets $ 2,562,074 $ 2,457,197 |
Selected Quarterly Financial 44
Selected Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Selected Quarterly Financial Data (Unaudited) [Abstract] | ||
Schedule of Quarterly Financial Information [Table Text Block] | The following tables summarize our unaudited quarterly financial data for 2015 and 2014 : Quarter Ended 2015 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 114,675 $ 132,970 $ 138,168 $ 150,384 Operating income $ 25,718 $ 56,355 $ 52,919 $ 62,923 Net income $ 22,990 $ 53,231 $ 49,550 $ 59,043 Net income attributable to partners $ 32,319 $ 44,899 $ 42,679 $ 40,649 Net income allocable to limited partners $ 24,881 $ 33,869 $ 30,533 $ 24,785 Basic net income per limited partner unit $ 0.47 $ 0.56 $ 0.50 $ 0.41 Diluted net income per limited partner unit $ 0.46 $ 0.55 $ 0.50 $ 0.40 | Quarter Ended 2014 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 94,779 $ 77,320 $ 89,953 $ 109,504 Operating income $ 16,529 $ 6,475 $ 11,580 $ 18,829 Net income $ 16,617 $ 14,728 $ 11,253 $ 16,731 Net income attributable to partners $ 17,124 $ 15,286 $ 11,444 $ 26,827 Net income allocable to limited partners $ 12,518 $ 15,771 $ 11,143 $ 22,342 Basic net income per limited partner unit $ 0.31 $ 0.39 $ 0.24 $ 0.46 Diluted net income per limited partner unit $ 0.30 $ 0.38 $ 0.23 $ 0.45 |
Description of Business - Addit
Description of Business - Additional Information (Detail) - shares | Sep. 01, 2014 | Jul. 25, 2014 | Dec. 31, 2015 | Dec. 31, 2014 |
Organization [Line Items] | ||||
Limited Partner Common Units | 60,644,232 | |||
General Partner Units | 834,391 | 834,391 | ||
Percentage of Outstanding Limited Partner Common Units | 100.00% | |||
Percentage of Outstanding Common and General Partner Units | 100.00% | |||
Ownership Interests Held By Public [Member] | ||||
Organization [Line Items] | ||||
Limited Partner Common Units | 34,288,752 | |||
General Partner Units | 0 | |||
Percentage of Outstanding Limited Partner Common Units | 56.54% | |||
Percentage of Outstanding Common and General Partner Units | 55.80% | |||
Ownership Interests Held By Tallgrass Equity, LLC [Member] | ||||
Organization [Line Items] | ||||
Limited Partner Common Units | 20,000,000 | |||
General Partner Units | 0 | |||
Percentage of Outstanding Limited Partner Common Units | 32.98% | |||
Percentage of Outstanding Common and General Partner Units | 32.50% | |||
Ownership Interests Held By Tallgrass Development | ||||
Organization [Line Items] | ||||
Limited Partner Common Units | 6,355,480 | |||
General Partner Units | 0 | |||
Percentage of Outstanding Limited Partner Common Units | 10.48% | |||
Percentage of Outstanding Common and General Partner Units | 10.30% | |||
Ownership Interests Held By Tallgrass MLP GP, LLC [Member] | ||||
Organization [Line Items] | ||||
Limited Partner Common Units | 0 | |||
General Partner Units | 834,391 | |||
Percentage of Outstanding Limited Partner Common Units | 0.00% | |||
Percentage of Outstanding Common and General Partner Units | 1.40% | |||
Pony Express Pipeline | ||||
Organization [Line Items] | ||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% |
Summary of Significant Accoun46
Summary of Significant Accounting Policies Accounting Policies (Details) - USD ($) $ in Thousands | Mar. 01, 2015 | Sep. 01, 2014 | Jul. 25, 2014 | Sep. 30, 2014 | Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2015 |
Business Acquisition [Line Items] | |||||||||
Allowance for Doubtful Accounts Receivable | $ 600 | $ 500 | |||||||
Regulatory Assets | 2,800 | 1,400 | |||||||
Regulatory Liabilities | $ 2,200 | 2,300 | |||||||
Equity interest ownership percentage | 20.00% | ||||||||
Equity in earnings of unconsolidated investment | $ 0 | $ 717 | $ 0 | ||||||
Crude oil pipelines | |||||||||
Business Acquisition [Line Items] | |||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.80% | ||||||||
Processing & treating | |||||||||
Business Acquisition [Line Items] | |||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 3.30% | ||||||||
Replacement Gas Facilities | |||||||||
Business Acquisition [Line Items] | |||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 10.00% | ||||||||
Minimum [Member] | Natural gas pipelines | |||||||||
Business Acquisition [Line Items] | |||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 0.70% | ||||||||
Minimum [Member] | Water business assets | |||||||||
Business Acquisition [Line Items] | |||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 3.30% | ||||||||
Minimum [Member] | General and other | |||||||||
Business Acquisition [Line Items] | |||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 6.80% | ||||||||
Maximum [Member] | Natural gas pipelines | |||||||||
Business Acquisition [Line Items] | |||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 3.40% | ||||||||
Maximum [Member] | Water business assets | |||||||||
Business Acquisition [Line Items] | |||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 20.00% | ||||||||
Maximum [Member] | General and other | |||||||||
Business Acquisition [Line Items] | |||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 12.00% | ||||||||
Use Rights | |||||||||
Business Acquisition [Line Items] | |||||||||
Finite-Lived Intangible Asset, Useful Life | 35 years | ||||||||
Customer Contracts [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Finite-Lived Intangible Asset, Useful Life | 1 year 7 months 6 days | ||||||||
Pony Express Pipeline | |||||||||
Business Acquisition [Line Items] | |||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | 66.70% | ||||||
Preferred Membership, Percentage Acquired | 33.30% | 100.00% | |||||||
Minimum Quarterly Distribution Required by Partnership Agreement | $ 36,650 | $ 16,650 | |||||||
Prorated Minimum Quarterly Distribution Required by Partnership Agreement | $ 5,400 | $ 23,500 | |||||||
Pony Express Pipeline | |||||||||
Business Acquisition [Line Items] | |||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | |||||||
Equity interest held by noncontrolling interests | 33.30% | 33.30% | |||||||
Pony Express Pipeline | Tallgrass Colorado Pipeline, Inc. [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Equity interest acquired | 99.80% | ||||||||
Pony Express Pipeline | Tallgrass Pony Express Pipeline (Colorado), Inc. | |||||||||
Business Acquisition [Line Items] | |||||||||
Equity interest acquired | 99.80% | ||||||||
Tallgrass Energy Partners | Tallgrass Colorado Pipeline, Inc. [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Equity interest acquired | 0.20% |
Variable Interest Entity (Detai
Variable Interest Entity (Details) - USD ($) $ in Millions | Jan. 01, 2016 | Mar. 01, 2015 | Sep. 01, 2014 | Jul. 25, 2014 | Dec. 31, 2015 |
Pony Express Pipeline | |||||
Business Acquisition [Line Items] | |||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | |||
Business Combination, Cash Contributed to Variable Interest Entity | $ 570 | ||||
Funds Maintained By Variable Interest Entity To Fund Construction | $ 270 | ||||
Variable Interest Entity, Qualitative or Quantitative Information, Activities of VIE | $ 4.4 | ||||
Pony Express Pipeline | |||||
Business Acquisition [Line Items] | |||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | 66.70% | ||
Preferred Membership, Percentage Acquired | 33.30% | 100.00% | |||
Business Combination, Cash Contributed to Variable Interest Entity | $ 570 | ||||
Funds Maintained By Variable Interest Entity To Fund Construction | $ 270 | ||||
Subsequent Event [Member] | Pony Express Pipeline | |||||
Business Acquisition [Line Items] | |||||
Preferred Membership, Percentage Acquired | 31.30% |
Variable Interest Entity Pony A
Variable Interest Entity Pony Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Variable Interest Entity [Line Items] | ||
Assets, Current | $ 77,223 | $ 132,281 |
Total Assets | 2,562,074 | 2,457,197 |
Liabilities, Current | 88,929 | 96,568 |
Pony Express Pipeline | ||
Variable Interest Entity [Line Items] | ||
Assets, Current | 46,800 | 93,019 |
Assets, Noncurrent | 1,391,906 | 1,300,816 |
Total Assets | 1,438,706 | 1,393,835 |
Liabilities, Current | 51,349 | 52,547 |
Liabilities | $ 51,349 | $ 52,547 |
Acquisitions (Details)
Acquisitions (Details) | Jan. 01, 2016USD ($)shares | May. 20, 2015USD ($) | Mar. 01, 2015USD ($) | Sep. 01, 2014USD ($)shares | May. 13, 2014USD ($) | Apr. 01, 2014USD ($)shares | Dec. 31, 2015USD ($)shares | Sep. 30, 2014USD ($) | Dec. 31, 2015USD ($)shares | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($)shares | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($)shares | Dec. 31, 2013USD ($) | Sep. 30, 2015USD ($) | Dec. 16, 2015mi |
Business Acquisition [Line Items] | |||||||||||||||||||||
General Partner Units | shares | 834,391 | 834,391 | 834,391 | 834,391 | 834,391 | ||||||||||||||||
Cash Contributed to TD | $ 27,000,000 | ||||||||||||||||||||
Acquisition of Pony Express membership interest | $ 700,000,000 | 27,000,000 | $ 0 | ||||||||||||||||||
Equity interest ownership percentage | 20.00% | 20.00% | 20.00% | ||||||||||||||||||
Acquisition of additional equity interests in Water Solutions | $ 0 | 7,600,000 | 0 | ||||||||||||||||||
Gain on remeasurement of unconsolidated investment | 0 | 9,388,000 | 0 | ||||||||||||||||||
Miles of water pipeline | mi | 62 | ||||||||||||||||||||
Total revenues | $ 150,384,000 | $ 138,168,000 | $ 132,970,000 | $ 114,675,000 | $ 109,504,000 | $ 89,953,000 | $ 77,320,000 | $ 94,779,000 | 536,197,000 | 371,556,000 | 290,526,000 | ||||||||||
Net income attributable to partners | $ 40,649,000 | $ 42,679,000 | $ 44,899,000 | 32,319,000 | $ 26,827,000 | $ 11,444,000 | $ 15,286,000 | $ 17,124,000 | 160,546,000 | 70,681,000 | $ 9,747,000 | ||||||||||
Business Acquisition, Pro Forma Revenue | 538,033,000 | 373,470,000 | |||||||||||||||||||
Business Acquisition, Pro Forma Net Income (Loss) | $ 161,184,000 | 71,347,000 | |||||||||||||||||||
Fresh Water Service Contract [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Lessor Leasing Arrangements, Operating Leases, Term of Contract | 5 years | ||||||||||||||||||||
Gathering and Disposal Contract [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Lessor Leasing Arrangements, Operating Leases, Term of Contract | 9 years | ||||||||||||||||||||
BNN Western, LLC [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Total revenues | $ 300,000 | ||||||||||||||||||||
Net income attributable to partners | $ 100,000 | ||||||||||||||||||||
General Partner | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Issuance of general partner units | $ 263,000 | 263,000 | |||||||||||||||||||
Trailblazer | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Date of acquisition | Apr. 1, 2014 | ||||||||||||||||||||
Total consideration | $ 164,000,000 | ||||||||||||||||||||
Acquisitions | $ 150,000,000 | ||||||||||||||||||||
Common and subordinated units issued, units | shares | 385,140 | ||||||||||||||||||||
Common Unit, Issuance Value | $ 14,000,000 | ||||||||||||||||||||
General Partner Units | shares | 7,860 | ||||||||||||||||||||
General Partners capital account partnership interest percentage | 2.00% | ||||||||||||||||||||
Trailblazer | General Partner | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Acquisitions | 72,933,000 | ||||||||||||||||||||
Pony Express Pipeline | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Date of acquisition | Mar. 1, 2015 | Sep. 1, 2014 | |||||||||||||||||||
Total consideration | $ 600,000,000 | ||||||||||||||||||||
Acquisitions | $ (3,000,000) | ||||||||||||||||||||
Common and subordinated units issued, units | shares | 70,340 | ||||||||||||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | 66.70% | ||||||||||||||||||
Total Consideration Transferred Directly to TD | $ 30,000,000 | ||||||||||||||||||||
Cash Contributed to TD | $ 27,000,000 | ||||||||||||||||||||
Percentage of Membership Interest before Effect of New Membership | 1.9585% | ||||||||||||||||||||
Business Combination, Cash Contributed to Variable Interest Entity | $ 570,000,000 | ||||||||||||||||||||
Preferred Membership, Percentage Acquired | 33.30% | 100.00% | |||||||||||||||||||
Cash contributed to TD as part of Pony acquisition | $ 300,000,000 | ||||||||||||||||||||
Funds Maintained By Variable Interest Entity To Fund Construction | $ 270,000,000 | ||||||||||||||||||||
Minimum Quarterly Distribution Required by Partnership Agreement | $ 36,650,000 | $ 16,650,000 | |||||||||||||||||||
Prorated Minimum Quarterly Distribution Required by Partnership Agreement | $ 5,400,000 | $ 23,500,000 | |||||||||||||||||||
Acquisition of Pony Express membership interest | $ 700,000,000 | ||||||||||||||||||||
Pony Express Pipeline | Subsequent Event [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Total consideration | $ 744,000,000 | ||||||||||||||||||||
Common and subordinated units issued, units | shares | 6,518,000 | ||||||||||||||||||||
Common Unit, Issuance Value | $ 269,000,000 | ||||||||||||||||||||
Preferred Membership, Percentage Acquired | 31.30% | ||||||||||||||||||||
Acquisition of Pony Express membership interest | $ 475,000,000 | ||||||||||||||||||||
Pony Express Pipeline | General Partner | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Acquisitions | $ 324,328,000 | $ 8,654,000 | |||||||||||||||||||
Grasslands Water Services I, LLC [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Equity interest ownership percentage | 50.00% | 50.00% | |||||||||||||||||||
Equity interest transferred as part of acquisition | 50.00% | ||||||||||||||||||||
Acquisition fair value | $ 11,900,000 | ||||||||||||||||||||
Gain on remeasurement of unconsolidated investment | 9,400,000 | ||||||||||||||||||||
Water Solutions [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Acquisition of additional equity interests in Water Solutions | $ 7,600,000 | ||||||||||||||||||||
Equity interest acquired | 80.00% | 92.00% | 92.00% | 92.00% | |||||||||||||||||
Equity interest held by noncontrolling interests | 20.00% | ||||||||||||||||||||
Acquisition, noncontrolling interest, fair value | $ 1,400,000 | ||||||||||||||||||||
Additional Equity Interest Acquired | 12.00% | ||||||||||||||||||||
Payments to Acquire Additional Interest in Subsidiaries | $ 600,000 | ||||||||||||||||||||
Water Solutions [Member] | General Partner | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Acquisitions | $ 0 | ||||||||||||||||||||
Payments to Acquire Additional Interest in Subsidiaries | $ 0 | ||||||||||||||||||||
BNN Energy LLC [Member] | Grasslands Water Services I, LLC [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Equity interest transferred as part of acquisition | 50.00% | ||||||||||||||||||||
BNN Energy LLC [Member] | Alpha Reclaim Technology, LLC [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Equity interest transferred as part of acquisition | 100.00% | ||||||||||||||||||||
BNN Western, LLC [Member] | |||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||
Acquisitions | $ 75,000,000 | ||||||||||||||||||||
Equity interest acquired | 100.00% |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction [Line Items] | |||
Related Party Transactions, Cost of Sales and Transportation Services | $ 25,046 | $ 0 | $ 0 |
Other Deferred Charges [Member] | |||
Related Party Transaction [Line Items] | |||
Expenses related to transactions with affiliated companies | 7 | 27 | 799 |
Operation and maintenance [Member] | |||
Related Party Transaction [Line Items] | |||
Expenses related to transactions with affiliated companies | 23,520 | 18,783 | 18,439 |
General and administrative [Member] | |||
Related Party Transaction [Line Items] | |||
Expenses related to transactions with affiliated companies | 33,432 | 23,475 | 20,140 |
Property, Plant and Equipment [Member] | |||
Related Party Transaction [Line Items] | |||
Related Party Transaction Costs Capitalized From Transactions With Related Party | $ 4,320 | $ 17,936 | $ 7,604 |
Related Party Transactions - 51
Related Party Transactions - Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | $ 15 | $ 73,393 |
Accounts Payable, Related Parties, Current | 7,852 | 3,915 |
Tallgrass Operations, LLC [Member] | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 0 | 73,393 |
Accounts Payable, Related Parties, Current | 7,792 | 3,894 |
Rockies Express Pipeline LLC [Member] | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 15 | 0 |
Accounts Payable, Related Parties, Current | 7 | 21 |
Tallgrass Equity, LLC [Member] | ||
Related Party Transaction [Line Items] | ||
Accounts Payable, Related Parties, Current | 36 | 0 |
Deeprock Development, LLC [Member] | ||
Related Party Transaction [Line Items] | ||
Accounts Payable, Related Parties, Current | $ 17 | $ 0 |
Related Party Transactions - 52
Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers [Member] - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Related Party Transaction [Line Items] | ||
Affiliate gas balance receivables | $ 92 | $ 275 |
Affiliate gas balance payables | $ 227 | $ 455 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) $ in Thousands | 5 Months Ended | 12 Months Ended | ||
May. 16, 2013USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($)mi | |
Related Party Transaction [Line Items] | ||||
Interest Income, Related Party | $ 400 | $ 1,500 | ||
Gas transmission lines sold | mi | 433 | |||
Reimbursement of Capital Expenditures from Related Party | 69,200 | $ 30,400 | ||
Increase in accrual for reimbursable construction in progress projects | 0 | 0 | 14,470 | |
Prepayments and other current assets | 2,835 | 2,766 | ||
General Partner | ||||
Related Party Transaction [Line Items] | ||||
Contributions | $ 14,235 | 27,488 | ||
Public Company Expense [Member] | ||||
Related Party Transaction [Line Items] | ||||
Public company cost reimbursement | 2,500 | |||
Pony Express Pipeline | ||||
Related Party Transaction [Line Items] | ||||
General and administrative expense reimbursement | 20,600 | |||
TEP | ||||
Related Party Transaction [Line Items] | ||||
General and administrative expense reimbursement | $ 21,500 | |||
Tallgrass Development LP | Pony Express Pipeline | ||||
Related Party Transaction [Line Items] | ||||
Increase in accrual for reimbursable construction in progress projects | $ 41,700 | |||
Equity reimbursement for a portion of capital expenditures made by related party | 4,300 | |||
Prepayments and other current assets | $ 17,000 |
Inventory - Schedule of Compone
Inventory - Schedule of Components of Inventory (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Inventory Disclosure [Abstract] | ||
Crude oil | $ 2,661 | $ 581 |
Materials and supplies | 8,581 | 3,049 |
Natural gas liquids | 395 | 519 |
Gas in underground storage | 2,156 | 8,896 |
Total inventory | $ 13,793 | $ 13,045 |
Inventory Inventory (Details)
Inventory Inventory (Details) $ in Millions | 3 Months Ended | |
Dec. 31, 2014USD ($)bbl | Nov. 30, 2014USD ($) | |
Inventory details [Line Items] | ||
Number of barrels of oil Purchased | bbl | 800,000 | |
Pony Express Pipeline | ||
Inventory details [Line Items] | ||
Security Deposit | $ 20 | |
Letters of Credit Outstanding, Amount | $ 20 | |
Guarantee of Payment by Related Party | $ 40 |
Property Plant and Equipment -
Property Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Property, Plant and Equipment [Line Items] | ||
Accumulated depreciation and amortization | $ (133,427) | $ (59,200) |
Property, plant and equipment, net | 2,025,018 | 1,853,081 |
Crude oil pipelines | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | 1,172,684 | 939,536 |
Natural gas pipelines | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | 550,710 | 548,482 |
Processing and treating assets | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | 254,073 | 237,218 |
Water business assets | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | 81,098 | 4,453 |
General and other | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | 69,181 | 42,719 |
Construction work in progress | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | $ 30,699 | $ 139,873 |
Property, Plant and Equipment F
Property, Plant and Equipment Future Minimum Rental Income (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Property, Plant and Equipment [Abstract] | |
2,016 | $ 3,952 |
2,017 | 3,967 |
2,018 | 3,982 |
2,019 | 3,997 |
2,020 | 3,385 |
Thereafter | 15,114 |
Total | $ 34,397 |
Property, Plant and Equipment A
Property, Plant and Equipment Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property, Plant and Equipment [Abstract] | |||
Depreciation | $ 75.5 | $ 40.9 | $ 36.6 |
Capitalized interest | 0.9 | 1.2 | 0.9 |
Operating Leases, Income Statement, Lease Revenue | 0.8 | ||
Rental Income, Nonoperating | $ 0.8 | $ 1 | $ 1 |
Goodwill and Intangible Asset59
Goodwill and Intangible Assets Goodwill (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Goodwill [Line Items] | |||
Goodwill | $ 343,288 | $ 343,288 | $ 334,715 |
Goodwill, Acquired During Period | 0 | 8,573 | |
Natural Gas Transportation & Logistics | |||
Goodwill [Line Items] | |||
Goodwill | 255,558 | 255,558 | 255,558 |
Goodwill, Acquired During Period | 0 | 0 | |
Processing & Logistics | |||
Goodwill [Line Items] | |||
Goodwill | 87,730 | 87,730 | $ 79,157 |
Goodwill, Acquired During Period | $ 0 | $ 8,573 |
Goodwill and Intangible Asset60
Goodwill and Intangible Assets Intangible Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Acquired Finite-Lived Intangible Assets [Line Items] | ||
Finite-Lived Intangible Assets, Accumulated Amortization | $ (9,427) | $ (9,635) |
Intangible asset, net | 96,546 | 104,538 |
Use Rights | ||
Acquired Finite-Lived Intangible Assets [Line Items] | ||
Finite-lived Intangible Assets Acquired | 105,973 | 105,973 |
Customer Contracts [Member] | ||
Acquired Finite-Lived Intangible Assets [Line Items] | ||
Finite-lived Intangible Assets Acquired | $ 0 | $ 8,200 |
Goodwill and Intangible Asset61
Goodwill and Intangible Assets Future Amortization (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |
2,016 | $ 3,028 |
2,017 | 3,028 |
2,018 | 3,028 |
2,019 | 3,028 |
2,020 | 3,028 |
Thereafter | 81,406 |
Total | $ 96,546 |
Goodwill and Intangible Asset62
Goodwill and Intangible Assets Goodwill and Intangible Assets Additional Detail (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Aug. 31, 2015 | |
Finite-Lived Intangible Assets [Line Items] | ||||
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | 10.00% | |||
Goodwill | $ 343,288 | $ 343,288 | $ 334,715 | |
Amortization of Intangible Assets | $ 8,000 | $ 6,200 | $ 3,000 | |
Tallgrass Midstream, LLC [Member] | ||||
Finite-Lived Intangible Assets [Line Items] | ||||
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | 21.00% | |||
Goodwill | $ 79,200 |
Risk Management - Derivative Co
Risk Management - Derivative Contracts Included in Consolidated Statement of Income (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Not Designated as Hedging Instrument [Member] | Energy commodity derivative contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Amount of gain (loss) recognized in income on derivatives | $ 427 | $ (410) | $ (548) |
Long-term Debt Capacity under R
Long-term Debt Capacity under Revolving Credit Facility (Details) - USD ($) | Dec. 31, 2015 | Nov. 24, 2015 | Dec. 31, 2014 | Jun. 25, 2014 |
Line of Credit Facility [Line Items] | ||||
Less: Outstanding borrowings under the revolving credit facility | $ (753,000,000) | $ (559,000,000) | ||
Barclays Bank [Member] | Senior Revolving Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Total capacity under the revolving credit facility | $ 1,100,000,000 | $ 850,000,000 | ||
Tallgrass Energy Partners | Senior Revolving Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Less: Outstanding borrowings under the revolving credit facility | (753,000,000) | (559,000,000) | ||
Available capacity under the revolving credit facility | 347,000,000 | 291,000,000 | ||
Tallgrass Energy Partners | Barclays Bank [Member] | Senior Revolving Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Total capacity under the revolving credit facility | $ 1,100,000,000 | $ 850,000,000 |
Long-term Debt - Carrying Amoun
Long-term Debt - Carrying Amount and Fair Value of TEP's Long-term Debt (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||
Fair Value | $ 753,000 | $ 559,000 |
Less: Outstanding borrowings under the revolving credit facility | (753,000) | (559,000) |
Quoted prices in active markets for identical assets (Level 1) | ||
Debt Instrument [Line Items] | ||
Fair Value | 0 | 0 |
Significant other observable inputs (Level 2) | ||
Debt Instrument [Line Items] | ||
Fair Value | 753,000 | 559,000 |
Significant unobservable inputs (Level 3) | ||
Debt Instrument [Line Items] | ||
Fair Value | $ 0 | $ 0 |
Long-term Debt - Additional Inf
Long-term Debt - Additional Information (Detail) | Nov. 24, 2015USD ($) | Oct. 31, 2014 | Dec. 31, 2015USD ($) | Jan. 04, 2016USD ($) | Jan. 01, 2016USD ($) | Dec. 31, 2014USD ($) | Jun. 25, 2014USD ($) |
Debt Instrument [Line Items] | |||||||
Long-term debt | $ (753,000,000) | $ (559,000,000) | |||||
Weighted average interest rate on outstanding borrowings | 2.08% | ||||||
Maximum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Consolidated leverage ratio | 4.75 | ||||||
Contingent Consolidated Leverage Ratio | 5.25 | ||||||
Credit facility commitment fee | 0.50% | ||||||
Minimum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Consolidated interest coverage ratio | 2.50 | ||||||
Credit facility commitment fee | 0.30% | ||||||
Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Total capacity under the revolving credit facility | $ 1,100,000,000 | $ 850,000,000 | |||||
Increase in accordion borrowing | 400,000,000 | ||||||
Sublimit for Letters of Credit | 75,000,000 | ||||||
Increase in Swingline Borrowings | $ 60,000,000 | ||||||
Subsequent Event [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Total capacity under the revolving credit facility | $ 1,500,000,000 | $ 1,500,000,000 |
Partnership Equity and Distri67
Partnership Equity and Distributions - Summary of Distributions (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Dec. 31, 2015 | |
Minimum Quarterly Distribution [Member] | ||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||
Distributions per Limited Partner unit | $ 0.2875 | $ 0.2875 | ||||||||||
Tallgrass Energy Partners | ||||||||||||
Distribution Made to Limited Partner [Line Items] | ||||||||||||
Distribution Made to Limited Partner, Distribution Date | Feb. 12, 2016 | Nov. 13, 2015 | Aug. 14, 2015 | May 14, 2015 | Feb. 13, 2015 | Nov. 14, 2014 | Aug. 14, 2014 | May 14, 2014 | Feb. 12, 2014 | Nov. 13, 2013 | Aug. 13, 2013 | |
Distributions Limited Partners Common | $ 42,984 | $ 36,347 | $ 35,135 | $ 31,322 | $ 23,782 | $ 20,092 | $ 18,596 | $ 13,288 | $ 12,757 | $ 12,049 | $ 5,759 | |
Distributions General Partner Incentive | 15,332 | 11,567 | 10,418 | 6,934 | 4,039 | 1,208 | 758 | 126 | 63 | 0 | 0 | |
General Partner Distributions | 724 | 660 | 627 | 530 | 473 | 363 | 330 | 274 | 262 | 245 | 118 | |
Partners' Capital Account, Distributions | $ 59,040 | $ 48,574 | $ 46,180 | $ 38,786 | $ 28,294 | $ 21,663 | $ 19,684 | $ 13,688 | $ 13,082 | $ 12,294 | $ 5,877 | |
Distributions per Limited Partner unit | $ 0.6400 | $ 0.6000 | $ 0.5800 | $ 0.5200 | $ 0.4850 | $ 0.4100 | $ 0.3800 | $ 0.3250 | $ 0.3150 | $ 0.2975 | $ 0.1422 |
Partnership Equity and Distri68
Partnership Equity and Distributions - Additional Information (Detail) | Mar. 30, 2015USD ($)shares | Mar. 01, 2015 | Feb. 27, 2015USD ($)$ / sharesshares | Sep. 01, 2014USD ($) | Jul. 25, 2014USD ($)$ / sharesshares | Apr. 01, 2014USD ($)shares | Jun. 30, 2013$ / shares | May. 16, 2013USD ($)shares | Jun. 30, 2013USD ($) | Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014USD ($)$ / sharesshares | Dec. 31, 2013USD ($) | May. 13, 2015USD ($) | Feb. 17, 2015shares | Oct. 31, 2014USD ($) |
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Initial public offering of common units | shares | 1,200,000 | 10,000,000 | 8,050,000 | 65,744 | 28,625 | ||||||||||
Shares Issued, Price Per Share | $ / shares | $ 50.82 | $ 41.07 | $ 45.58 | $ 44.20 | |||||||||||
Shares Issued, Price Per Share, Net of Underwriters Discount | $ / shares | $ 49.29 | $ 39.74 | |||||||||||||
Proceeds from public offering, net of offering costs | $ 59,300,000 | $ 492,400,000 | $ 319,300,000 | $ 554,084,000 | $ 320,385,000 | $ 290,483,000 | |||||||||
Authorized amount | $ 100,000,000 | $ 200,000,000 | |||||||||||||
Limited Partners' Offering Costs | 30,000,000 | 215,000 | |||||||||||||
Issuance of units to public, net of offering costs | 3,000,000 | $ 1,100,000 | |||||||||||||
Partners' Capital Account, Remaining Authorized Amount | $ 95,900,000 | ||||||||||||||
General partner interest in TEP | 0.00% | ||||||||||||||
General Partner Units | shares | 834,391 | 834,391 | |||||||||||||
Contributions from Predecessor Entities, net | $ 0 | $ 312,125,000 | 379,872,000 | ||||||||||||
Contribution from TD | 0 | 27,488,000 | 0 | ||||||||||||
Proceeds from Noncontrolling Interests | 5,400,000 | ||||||||||||||
Contributions Relating to Cash Management Agreement | 612,100,000 | ||||||||||||||
Distributions to noncontrolling interests settled via the cash management agreement with Tallgrass Development, LP | $ 69,017,000 | 5,361,000 | 0 | ||||||||||||
Cash Contributed to TD | 27,000,000 | ||||||||||||||
Cash paid for contribution of pipelines | 85,500,000 | ||||||||||||||
Net Proceeds from Underwriters Option to Purchase Additional Shares | $ 31,200,000 | ||||||||||||||
Pony Express Pipeline | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | |||||||||||||
Cash contributed to TD as part of Pony acquisition | $ 300,000,000 | ||||||||||||||
Percentage of Membership Interest before Effect of New Membership | 1.9585% | ||||||||||||||
Ownership Interests Held By Tallgrass Development | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Limited Partners Subordinated Units Converted | shares | 16,200,000 | ||||||||||||||
Common Units, Conversion Ratio | 1 | ||||||||||||||
General Partner Units | shares | 0 | ||||||||||||||
Tallgrass Development LP | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Proceeds from Noncontrolling Interests | 379,900,000 | ||||||||||||||
Ownership Interests Held By Tallgrass MLP GP, LLC [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
General Partner Units | shares | 834,391 | ||||||||||||||
Minimum Quarterly Distribution [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Distributions per Limited Partner unit | $ / shares | $ 0.2875 | $ 0.2875 | |||||||||||||
Second Target Distribution [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Increasing incentive distribution right | 13.00% | ||||||||||||||
Incentive distribution per unit | $ / shares | $ 0.3536 | ||||||||||||||
Percentage of unit holders | 85.00% | ||||||||||||||
Percentage of general partner | 15.00% | ||||||||||||||
Third Target Distribution [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Increasing incentive distribution right | 23.00% | ||||||||||||||
Incentive distribution per unit | $ / shares | $ 0.4313 | ||||||||||||||
Percentage of unit holders | 75.00% | ||||||||||||||
Percentage of general partner | 25.00% | ||||||||||||||
First Target Distribution [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
General partner interest in TEP | 2.00% | ||||||||||||||
Incentive distribution per unit | $ / shares | $ 0.3048 | ||||||||||||||
Percentage of unit holders | 98.00% | ||||||||||||||
Percentage of general partner | 2.00% | ||||||||||||||
Thereafter [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Increasing incentive distribution right | 48.00% | ||||||||||||||
General Partner | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Issuance of units to public, net of offering costs | $ 0 | $ 0 | 0 | ||||||||||||
Contributions from Noncontrolling Interest | 0 | 0 | |||||||||||||
Distributions to noncontrolling interests | $ 0 | 0 | |||||||||||||
Trailblazer | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
General Partner Units | shares | 7,860 | ||||||||||||||
Acquisitions | $ (150,000,000) | ||||||||||||||
Trailblazer | General Partner | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Acquisitions | (72,933,000) | ||||||||||||||
Trailblazer | TEP Predecessor [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Acquisitions | $ 118,500,000 | ||||||||||||||
Pony Express Pipeline | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | 66.70% | ||||||||||||
Acquisitions | $ 3,000,000 | ||||||||||||||
Cash Contributed to TD | $ 27,000,000 | ||||||||||||||
Percentage of Membership Interest before Effect of New Membership | 1.9585% | ||||||||||||||
Pony Express Pipeline | General Partner | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Acquisitions | $ (324,328,000) | (8,654,000) | |||||||||||||
Thereafter [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Percentage of unit holders | 50.00% | ||||||||||||||
Percentage of general partner | 50.00% | ||||||||||||||
Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Issuance of units to public, net of offering costs | $ 290,483,000 | $ 554,084,000 | 320,385,000 | ||||||||||||
Contributions from Noncontrolling Interest | 110,127,000 | 5,429,000 | |||||||||||||
Distributions to noncontrolling interests | 69,474,000 | 5,406,000 | |||||||||||||
Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Trailblazer | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Acquisitions | (150,000,000) | ||||||||||||||
Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Pony Express Pipeline | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Acquisitions | (700,000,000) | (27,000,000) | |||||||||||||
Common unitholders | Limited Partner [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Initial public offering of common units | shares | 14,600,000 | ||||||||||||||
Issuance of units to public, net of offering costs | $ 290,483,000 | 554,084,000 | 320,385,000 | ||||||||||||
Contributions from Noncontrolling Interest | 0 | 0 | |||||||||||||
Distributions to noncontrolling interests | 0 | 0 | |||||||||||||
Common unitholders | Trailblazer | Limited Partner [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Acquisitions | 14,023,000 | ||||||||||||||
Common unitholders | Pony Express Pipeline | Limited Partner [Member] | |||||||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||||||
Acquisitions | $ 0 | $ 3,000,000 |
Commitments and Contingencies69
Commitments and Contingencies (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Oct. 07, 2014 | |
Operating Leased Assets [Line Items] | ||||
Rent Expense | $ 25,800 | $ 4,700 | $ 327 | |
Commitments for Future Capital Expenditures | 5,800 | |||
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract] | ||||
2,016 | 27,805 | |||
2,017 | 28,355 | |||
2,018 | 28,714 | |||
2,019 | 29,246 | |||
2,020 | 29,879 | |||
Thereafter | 478,550 | |||
Total | $ 622,549 | |||
Deeprock Lease [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Lessee Leasing Arrangements, Operating Leases, Term of Contract | 5 years | |||
Prepaid Rent | $ 10,900 | |||
Payments for Rent | $ 6,300 | $ 4,600 | ||
Maximum Lease Term | 20 years | |||
Deeprock Lease [Member] | Maximum [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Lessee Leasing Arrangements, Operating Leases, Renewal Term | 5 years | |||
Deeprock Lease [Member] | Minimum [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Lessee Leasing Arrangements, Operating Leases, Renewal Term | 2 years | |||
Tallgrass Sterling [Member] | ||||
Operating Leased Assets [Line Items] | ||||
Lessee Leasing Arrangements, Operating Leases, Term of Contract | 5 years | |||
Maximum Lease Term | 20 years | |||
Lessee Leasing Arrangements, Operating Leases, Renewal Term | 5 years |
Net Income per Limited Partne70
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 | 5 Months Ended | 7 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | May. 16, 2013 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Earnings Per Share [Abstract] | |||||||||||||
Net income | $ 59,043 | $ 49,550 | $ 53,231 | $ 22,990 | $ 16,731 | $ 11,253 | $ 14,728 | $ 16,617 | $ 5,049 | $ 2,575 | $ 184,814 | $ 59,329 | $ 7,624 |
Net (income) loss attributable to noncontrolling interests | 761 | 1,362 | (24,268) | 11,352 | 2,123 | ||||||||
Net income attributable to partners | 5,810 | 3,937 | 160,546 | 70,681 | 9,747 | ||||||||
Predecessor operations interest in net (income) loss | 1,172 | 3,260 | 0 | (1,508) | 4,432 | ||||||||
General partner interest in net income | (6,982) | (206) | (46,478) | (7,399) | (7,188) | ||||||||
Net income available to common and subordinated unitholders | $ 24,785 | $ 30,533 | $ 33,869 | $ 24,881 | $ 22,342 | $ 11,143 | $ 15,771 | $ 12,518 | $ 0 | $ 6,991 | $ 114,068 | $ 61,774 | $ 6,991 |
Basic net income per common and subordinated unit | $ 0.41 | $ 0.50 | $ 0.56 | $ 0.47 | $ 0.46 | $ 0.24 | $ 0.39 | $ 0.31 | $ 0.17 | $ 1.95 | $ 1.39 | $ 0.17 | |
Diluted net income per common and subordinated unit | $ 0.40 | $ 0.50 | $ 0.55 | $ 0.46 | $ 0.45 | $ 0.23 | $ 0.38 | $ 0.30 | $ 0.17 | $ 1.91 | $ 1.36 | $ 0.17 | |
Basic average number of common and subordinated units outstanding | 40,450 | 58,597 | 44,346 | 40,450 | |||||||||
Equity Participation Unit equivalent units | 1,008 | 978 | 1,048 | 1,008 | |||||||||
Diluted average number of common and subordinated units outstanding | 41,458 | 59,575 | 45,394 | 41,458 |
Major Customers and Concentra71
Major Customers and Concentration of Credit Risk (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Concentration Risk [Line Items] | |||||||||||
Total revenues | $ 150,384 | $ 138,168 | $ 132,970 | $ 114,675 | $ 109,504 | $ 89,953 | $ 77,320 | $ 94,779 | $ 536,197 | $ 371,556 | $ 290,526 |
Customer advances and deposits | $ 4,700 | $ 3,100 | 4,700 | 3,100 | |||||||
Continental Resources [Member] | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Total revenues | $ 84,500 | ||||||||||
Concentration Risk, Percentage | 16.00% | ||||||||||
Shell Trading (US) Company [Member] | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Total revenues | $ 78,600 | ||||||||||
Concentration Risk, Percentage | 15.00% | ||||||||||
Phillips 66 | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Total revenues | $ 113,600 | $ 102,000 | |||||||||
Concentration Risk, Percentage | 31.00% | 35.00% | |||||||||
Crude Oil Transportation & Logistics | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Concentration Risk, Percentage | 96.00% | ||||||||||
Natural Gas Transportation & Logistics | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Concentration Risk, Percentage | 51.00% | ||||||||||
Processing & Logistics | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Concentration Risk, Percentage | 93.00% |
Equity Based Compensation - Sum
Equity Based Compensation - Summarizes Changes in EPUs Outstanding (Detail) - Equity Participation Unit [Member] | 12 Months Ended |
Dec. 31, 2015$ / sharesshares | |
Shares | |
Beginning of period, Shares | shares | 1,525,750 |
Granted, Shares | shares | 338,591 |
Vested, Shares | shares | (480,555) |
Forfeited, Shares | shares | (58,825) |
End of period, Shares | shares | 1,324,961 |
Weighted Average Grant Date Fair Value | |
Beginning of period, Weighted Average Grant Date Fair Value | $ / shares | $ 18.75 |
Granted, Weighted Average Grant Date Fair Value | $ / shares | 40.01 |
Vested, Weighted Average Grant Date Fair Value | $ / shares | (19.39) |
Forfeited, Weighted Average Grant Date Fair Value | $ / shares | (16.98) |
End of period, Weighted Average Grant Date Fair Value | $ / shares | $ 24.11 |
Equity Based Compensation - Add
Equity Based Compensation - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 26, 2013 | |
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | ||||
LTIP expiration period | May 13, 2023 | |||
Share-based compensation expense related to the EPU grants recognized | $ 9.3 | $ 10.2 | $ 4.2 | |
Compensation cost related to nonvested EPUs expected to be recognized | $ 14.7 | |||
Weighted average period in which compensation cost related to nonvested EPUs expected to be recognized | 2 years 2 months | |||
TEP | ||||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | ||||
Share-based compensation expense related to the EPU grants recognized | $ 5.1 | $ 5.1 | $ 1.8 | |
Equity Participation Unit [Member] | ||||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | ||||
Stock Issued During Period, Shares, Share-based Compensation, Gross | 300,000 | |||
Shares Paid for Tax Withholding for Share Based Compensation | 100,000 | |||
Equity Participation Unit [Member] | Section 16 Officers [Member] | ||||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | ||||
Equity participation units granted | 177,500 | |||
Maximum [Member] | ||||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | ||||
Equity participation units granted | 10,000,000 | |||
Maximum [Member] | Equity Participation Unit [Member] | ||||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | ||||
Equity participation units granted | 1,500,000 |
Regulatory Matters Regulatory D
Regulatory Matters Regulatory Details (Details) - mi | Oct. 29, 2015 | Jul. 01, 2015 | Aug. 06, 2012 |
Tallgrass Interstate Gas Transmission, LLC (TIGT) [Member] | |||
Entity Information [Line Items] | |||
Gas transmission lines owned | 433 | ||
Pony Express Pipeline | |||
Entity Information [Line Items] | |||
FERC Annual Index Adjustment | 4.60% | ||
Local Non-Contract Rates [Member] | Pony Express Pipeline | |||
Entity Information [Line Items] | |||
FERC Annual Index Adjustment | 4.60% | ||
Joint Tariff Contract Rates [Member] | Pony Express Pipeline | |||
Entity Information [Line Items] | |||
FERC Annual Index Adjustment | 4.60% |
Legal and Environmental Matte75
Legal and Environmental Matters - Additional Information (Detail) | Mar. 12, 2015bbl | Aug. 31, 2014bbl | Dec. 31, 2016USD ($)mi | Dec. 31, 2015USD ($)ft-lbmi | Dec. 31, 2014USD ($) |
Loss Contingencies [Line Items] | |||||
Aggregate reserves for all claims | $ 600,000 | ||||
Environmental accruals | $ 4,800,000 | $ 5,300,000 | |||
Crude Oil Spilled or Leaked | bbl | 300 | 200 | |||
Trailblazer | |||||
Loss Contingencies [Line Items] | |||||
Maximum Allowable Operating Pressure | ft-lb | 144,000 | ||||
Excavation Digs | 32 | ||||
Aggregate Cost of Excavation Digs | $ 1,300,000 | ||||
Tallgrass Development LP | |||||
Loss Contingencies [Line Items] | |||||
Contractual Indemnity Provided By Partner | 20,000,000 | ||||
Contractual Indemnity Provided By Partner Annual Deductible | $ 1,500,000 | ||||
Minimum [Member] | Trailblazer | |||||
Loss Contingencies [Line Items] | |||||
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi | 25 | ||||
Projected Pipeline replacement costs per mile | $ 2,200,000 | ||||
Maximum [Member] | Trailblazer | |||||
Loss Contingencies [Line Items] | |||||
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi | 35 | ||||
Projected Pipeline replacement costs per mile | $ 2,700,000 | ||||
Subsequent Event [Member] | Trailblazer | |||||
Loss Contingencies [Line Items] | |||||
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi | 8 | ||||
Estimated pipeline replacement costs | $ 22,000,000 |
Reporting Segments - Summary of
Reporting Segments - Summary of TEP's Segment Information of Revenue (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | $ 150,384 | $ 138,168 | $ 132,970 | $ 114,675 | $ 109,504 | $ 89,953 | $ 77,320 | $ 94,779 | $ 536,197 | $ 371,556 | $ 290,526 |
TEP | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 536,197 | 371,556 | 290,526 | ||||||||
TEP | Natural Gas Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 126,273 | 134,823 | 125,957 | ||||||||
TEP | Crude Oil Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 304,227 | 28,343 | 0 | ||||||||
TEP | Processing & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 105,697 | 208,390 | 164,569 | ||||||||
TEP | Corporate and other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 0 | 0 | 0 | ||||||||
TEP | Operating Segments | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 541,581 | 376,813 | 292,446 | ||||||||
TEP | Operating Segments | Natural Gas Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 131,657 | 140,080 | 127,877 | ||||||||
TEP | Operating Segments | Crude Oil Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 304,227 | 28,343 | 0 | ||||||||
TEP | Operating Segments | Processing & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 105,697 | 208,390 | 164,569 | ||||||||
TEP | Operating Segments | Corporate and other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 0 | 0 | 0 | ||||||||
TEP | Inter-Segment | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | (5,384) | (5,257) | (1,920) | ||||||||
TEP | Inter-Segment | Natural Gas Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | (5,384) | (5,257) | (1,920) | ||||||||
TEP | Inter-Segment | Crude Oil Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 0 | 0 | 0 | ||||||||
TEP | Inter-Segment | Processing & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 0 | 0 | 0 | ||||||||
TEP | Inter-Segment | Corporate and other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | $ 0 | $ 0 | $ 0 |
Reporting Segments - Summary 77
Reporting Segments - Summary of TEP's Segment Information of Earnings (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Reconciliation to Net Income: | |||||||||||
Equity in earnings of unconsolidated investment | $ 0 | $ (717) | $ 0 | ||||||||
Gain on remeasurement of unconsolidated investment | 0 | (9,388) | 0 | ||||||||
Interest expense, net of noncontrolling interest | 15,514 | 7,292 | 11,054 | ||||||||
Depreciation and amortization expense, net of noncontrolling interest | 83,476 | 47,048 | 39,917 | ||||||||
Non-cash compensation expense | 5,103 | 5,136 | 1,798 | ||||||||
Loss on extinguishment of debt | 226 | 0 | 17,526 | ||||||||
Net income attributable to partners | $ 40,649 | $ 42,679 | $ 44,899 | $ 32,319 | $ 26,827 | $ 11,444 | $ 15,286 | $ 17,124 | 160,546 | 70,681 | 9,747 |
TEP | |||||||||||
Reconciliation to Net Income: | |||||||||||
Net income attributable to partners | 160,546 | 70,681 | 9,747 | ||||||||
TEP | Natural Gas Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 61,984 | 63,578 | 54,901 | ||||||||
TEP | Crude Oil Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 170,588 | 15,711 | (43) | ||||||||
TEP | Processing & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 22,746 | 33,089 | 25,112 | ||||||||
TEP | Corporate and other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | (2,979) | (2,500) | (1,580) | ||||||||
TEP | Operating Segments | Natural Gas Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 67,368 | 67,593 | 56,821 | ||||||||
TEP | Operating Segments | Crude Oil Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 165,204 | 15,711 | (43) | ||||||||
TEP | Operating Segments | Processing & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 22,746 | 33,089 | 23,192 | ||||||||
TEP | Operating Segments | Corporate and other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | (2,979) | (2,500) | (1,580) | ||||||||
TEP | Inter-Segment | Natural Gas Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | (5,384) | (4,015) | (1,920) | ||||||||
TEP | Inter-Segment | Crude Oil Transportation & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 5,384 | 0 | 0 | ||||||||
TEP | Inter-Segment | Processing & Logistics | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 0 | 0 | 1,920 | ||||||||
TEP | Inter-Segment | Corporate and other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 0 | 0 | 0 | ||||||||
TEP | Segment Reconciling Items | |||||||||||
Reconciliation to Net Income: | |||||||||||
Equity in earnings of unconsolidated investment | 0 | 717 | 0 | ||||||||
Non-cash loss allocated to noncontrolling interest | 9,377 | 10,151 | 0 | ||||||||
Gain on remeasurement of unconsolidated investment | 0 | (9,388) | 0 | ||||||||
Interest expense, net of noncontrolling interest | (15,517) | (7,648) | (11,035) | ||||||||
Depreciation and amortization expense, net of noncontrolling interest | (75,529) | (45,389) | (37,898) | ||||||||
Non-cash (gain) loss related to derivative instruments | 0 | 184 | (386) | ||||||||
Non-cash compensation expense | (5,103) | (5,136) | (1,798) | ||||||||
Gain (Loss) on Sale of Assets and Asset Impairment Charges | (4,795) | 0 | 0 | ||||||||
Distributions from unconsolidated investment | 0 | (1,464) | 0 | ||||||||
Loss on extinguishment of debt | $ (226) | $ 0 | $ (17,526) |
Reporting Segments Reporting Se
Reporting Segments Reporting Segments - Summary of TEP's Segment Information for Payments to Acquire Plant, Property and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | |||
Payments to Acquire Property, Plant, and Equipment | $ 65,387 | $ 665,650 | $ 346,020 |
TEP | |||
Segment Reporting Information [Line Items] | |||
Payments to Acquire Property, Plant, and Equipment | 65,387 | 665,650 | 346,020 |
TEP | Crude Oil Transportation & Logistics | |||
Segment Reporting Information [Line Items] | |||
Payments to Acquire Property, Plant, and Equipment | 38,802 | 631,883 | 286,824 |
TEP | Natural Gas Transportation & Logistics | |||
Segment Reporting Information [Line Items] | |||
Payments to Acquire Property, Plant, and Equipment | 10,478 | 20,580 | 28,184 |
TEP | Processing & Logistics | |||
Segment Reporting Information [Line Items] | |||
Payments to Acquire Property, Plant, and Equipment | $ 16,107 | $ 13,187 | $ 31,012 |
Reporting Segments - Summary 79
Reporting Segments - Summary of TEP's Segment Information of Assets (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Segment Reporting Information [Line Items] | ||
Assets | $ 2,562,074 | $ 2,457,197 |
TEP | Crude Oil Transportation & Logistics | ||
Segment Reporting Information [Line Items] | ||
Assets | 1,439,418 | 1,394,793 |
TEP | Natural Gas Transportation & Logistics | ||
Segment Reporting Information [Line Items] | ||
Assets | 706,576 | 716,106 |
TEP | Processing & Logistics | ||
Segment Reporting Information [Line Items] | ||
Assets | 409,795 | 340,620 |
TEP | Corporate and other | ||
Segment Reporting Information [Line Items] | ||
Assets | $ 6,285 | $ 5,678 |
Reporting Segments - Additional
Reporting Segments - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2015Segment | |
Segment Reporting [Abstract] | |
Number of reportable segments | 3 |
Selected Quarterly Financial 81
Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 5 Months Ended | 7 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | May. 16, 2013 | Dec. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Selected Quarterly Financial Data (Unaudited) [Abstract] | |||||||||||||
Total revenues | $ 150,384 | $ 138,168 | $ 132,970 | $ 114,675 | $ 109,504 | $ 89,953 | $ 77,320 | $ 94,779 | $ 536,197 | $ 371,556 | $ 290,526 | ||
Operating income | 62,923 | 52,919 | 56,355 | 25,718 | 18,829 | 11,580 | 6,475 | 16,529 | 197,915 | 53,413 | 33,999 | ||
Net income | 59,043 | 49,550 | 53,231 | 22,990 | 16,731 | 11,253 | 14,728 | 16,617 | $ 5,049 | $ 2,575 | 184,814 | 59,329 | 7,624 |
Net income attributable to partners | 40,649 | 42,679 | 44,899 | 32,319 | 26,827 | 11,444 | 15,286 | 17,124 | 160,546 | 70,681 | 9,747 | ||
Common and subordinated unitholders' interest in net income subsequent to May 17, 2013 | $ 24,785 | $ 30,533 | $ 33,869 | $ 24,881 | $ 22,342 | $ 11,143 | $ 15,771 | $ 12,518 | $ 0 | $ 6,991 | $ 114,068 | $ 61,774 | $ 6,991 |
Basic net income per common and subordinated unit | $ 0.41 | $ 0.50 | $ 0.56 | $ 0.47 | $ 0.46 | $ 0.24 | $ 0.39 | $ 0.31 | $ 0.17 | $ 1.95 | $ 1.39 | $ 0.17 | |
Diluted net income per common and subordinated unit | $ 0.40 | $ 0.50 | $ 0.55 | $ 0.46 | $ 0.45 | $ 0.23 | $ 0.38 | $ 0.30 | $ 0.17 | $ 1.91 | $ 1.36 | $ 0.17 |
Subsequent Events - Additional
Subsequent Events - Additional Information (Detail) - USD ($) | Jan. 01, 2016 | Mar. 01, 2015 | Sep. 01, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Feb. 17, 2016 | Jan. 31, 2016 | Jan. 04, 2016 | Nov. 24, 2015 | Jun. 25, 2014 |
Subsequent Event [Line Items] | |||||||||||
Acquisition of Pony Express membership interest | $ 700,000,000 | $ 27,000,000 | $ 0 | ||||||||
Long-term Debt | 753,000,000 | 559,000,000 | |||||||||
Subsequent Event [Member] | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Common Stock, Call or Exercise Features | P18M | ||||||||||
Stock Repurchase Program, Authorized Amount | $ 100,000,000 | ||||||||||
Pony Express Pipeline | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Preferred Membership, Percentage Acquired | 33.30% | 100.00% | |||||||||
Acquisition of Pony Express membership interest | $ 700,000,000 | ||||||||||
Common and subordinated units issued, units | 70,340 | ||||||||||
Total consideration | $ 600,000,000 | ||||||||||
Pony Express Pipeline | Subsequent Event [Member] | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Preferred Membership, Percentage Acquired | 31.30% | ||||||||||
Acquisition of Pony Express membership interest | $ 475,000,000 | ||||||||||
Common and subordinated units issued, units | 6,518,000 | ||||||||||
Common Unit, Issuance Value | $ 269,000,000 | ||||||||||
Total consideration | $ 744,000,000 | ||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 98.00% | ||||||||||
Derivative, Price Risk Option Strike Price | $ 42.50 | ||||||||||
Senior Revolving Credit Facility [Member] | Tallgrass Energy Partners | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Long-term Debt | 753,000,000 | 559,000,000 | |||||||||
Senior Revolving Credit Facility [Member] | Tallgrass Energy Partners | Subsequent Event [Member] | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Long-term Debt | $ 1,200,000,000 | ||||||||||
Barclays Bank [Member] | Senior Revolving Credit Facility [Member] | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Total capacity under the revolving credit facility | $ 1,100,000,000 | $ 850,000,000 | |||||||||
Barclays Bank [Member] | Senior Revolving Credit Facility [Member] | Subsequent Event [Member] | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Total capacity under the revolving credit facility | $ 1,500,000,000 | $ 1,500,000,000 | |||||||||
Barclays Bank [Member] | Senior Revolving Credit Facility [Member] | Tallgrass Energy Partners | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Total capacity under the revolving credit facility | $ 1,100,000,000 | $ 850,000,000 |
Uncategorized Items - tep-20151
Label | Element | Value |
General Partner [Member] | ||
Partners' Capital Account, Units, Contributed | us-gaap_PartnersCapitalAccountUnitsContributed | 827,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | $ 0 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 206,000 |
Partner's Capital Account Contributions from Predecessor | tep_PartnersCapitalAccountContributionsfromPredecessor | 0 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 0 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 363,000 |
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options | us-gaap_AdjustmentsToAdditionalPaidInCapitalSharebasedCompensationAndExerciseOfStockOptions | 0 |
TEP Predecessor Post-IPO [Member] | ||
Partners' Capital Account, Public Sale of Units Net of Offering Costs | us-gaap_PartnersCapitalAccountPublicSaleOfUnitsNetOfOfferingCosts | 0 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | (1,172,000) |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | (3,260,000) |
Partner's Capital Account Contributions from Predecessor | tep_PartnersCapitalAccountContributionsfromPredecessor | 130,207,000 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 0 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 0 |
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options | us-gaap_AdjustmentsToAdditionalPaidInCapitalSharebasedCompensationAndExerciseOfStockOptions | 0 |
Partners' Capital Account, Contributions | us-gaap_PartnersCapitalAccountContributions | 0 |
TEP Predecessor Pre-IPO [Member] | ||
Partners' Capital Account, Public Sale of Units Net of Offering Costs | us-gaap_PartnersCapitalAccountPublicSaleOfUnitsNetOfOfferingCosts | 0 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 6,982,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 0 |
Partner's Capital Account Contributions from Predecessor | tep_PartnersCapitalAccountContributionsfromPredecessor | 0 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 118,538,000 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 0 |
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options | us-gaap_AdjustmentsToAdditionalPaidInCapitalSharebasedCompensationAndExerciseOfStockOptions | 0 |
Partners' Capital Account, Contributions | us-gaap_PartnersCapitalAccountContributions | (460,278,000) |
Noncontrolling Interest [Member] | ||
Partners' Capital Account, Public Sale of Units Net of Offering Costs | us-gaap_PartnersCapitalAccountPublicSaleOfUnitsNetOfOfferingCosts | 0 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | (761,000) |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | (1,362,000) |
Partner's Capital Account Contributions from Predecessor | tep_PartnersCapitalAccountContributionsfromPredecessor | 249,665,000 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 0 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 0 |
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options | us-gaap_AdjustmentsToAdditionalPaidInCapitalSharebasedCompensationAndExerciseOfStockOptions | 0 |
Partners' Capital Account, Contributions | us-gaap_PartnersCapitalAccountContributions | $ 0 |
Common Unitholders [Member] | Limited Partner [Member] | ||
Partners' Capital Account, Units, Contributed | us-gaap_PartnersCapitalAccountUnitsContributed | 9,700,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | $ 0 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 4,194,000 |
Partner's Capital Account Contributions from Predecessor | tep_PartnersCapitalAccountContributionsfromPredecessor | 0 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 0 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 10,685,000 |
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options | us-gaap_AdjustmentsToAdditionalPaidInCapitalSharebasedCompensationAndExerciseOfStockOptions | 4,154,000 |
Partners' Capital Account, Contributions | us-gaap_PartnersCapitalAccountContributions | 167,051,000 |
Subordinated Units [Member] | Limited Partner [Member] | ||
Partners' Capital Account, Public Sale of Units Net of Offering Costs | us-gaap_PartnersCapitalAccountPublicSaleOfUnitsNetOfOfferingCosts | $ 0 |
Partners' Capital Account, Units, Contributed | us-gaap_PartnersCapitalAccountUnitsContributed | 16,200,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | $ 0 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 2,797,000 |
Partner's Capital Account Contributions from Predecessor | tep_PartnersCapitalAccountContributionsfromPredecessor | 0 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 0 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 7,123,000 |
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options | us-gaap_AdjustmentsToAdditionalPaidInCapitalSharebasedCompensationAndExerciseOfStockOptions | 0 |
Partners' Capital Account, Contributions | us-gaap_PartnersCapitalAccountContributions | 278,992,000 |
Total Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | ||
Partners' Capital Account, Public Sale of Units Net of Offering Costs | us-gaap_PartnersCapitalAccountPublicSaleOfUnitsNetOfOfferingCosts | 290,483,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 5,810,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 3,937,000 |
Partner's Capital Account Contributions from Predecessor | tep_PartnersCapitalAccountContributionsfromPredecessor | 130,207,000 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 118,538,000 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 18,171,000 |
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options | us-gaap_AdjustmentsToAdditionalPaidInCapitalSharebasedCompensationAndExerciseOfStockOptions | 4,154,000 |
Partners' Capital Account, Contributions | us-gaap_PartnersCapitalAccountContributions | 0 |
Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 5,049,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 2,575,000 |
Partner's Capital Account Contributions from Predecessor | tep_PartnersCapitalAccountContributionsfromPredecessor | 379,872,000 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 118,538,000 |
Partners' Capital Account, Distributions | us-gaap_PartnersCapitalAccountDistributions | 18,171,000 |
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options | us-gaap_AdjustmentsToAdditionalPaidInCapitalSharebasedCompensationAndExerciseOfStockOptions | 4,154,000 |
Partners' Capital Account, Contributions | us-gaap_PartnersCapitalAccountContributions | $ 0 |