Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 13, 2018 | Jun. 30, 2017 | |
Document Information [Line Items] | |||
Entity Registrant Name | TALLGRASS ENERGY PARTNERS, LP | ||
Entity Central Index Key | 1,569,134 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
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 | $ 2,336.2 | ||
Common Units | |||
Document Information [Line Items] | |||
Entity Common Stock, Shares Outstanding | 73,199,753 | ||
General Partner Units | |||
Document Information [Line Items] | |||
Entity Common Stock, Shares Outstanding | 834,391 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets: | ||
Cash and cash equivalents | $ 1,809 | $ 1,873 |
Accounts receivable, net | 119,955 | 59,536 |
Gas imbalances | 1,990 | 1,597 |
Inventories | 21,609 | 13,093 |
Derivative assets | 0 | 10,967 |
Prepayments and other current assets | 11,175 | 7,628 |
Total Current Assets | 156,538 | 94,694 |
Property, plant and equipment, net | 2,394,337 | 2,079,232 |
Goodwill | 404,838 | 343,288 |
Intangible assets, net | 97,731 | 93,522 |
Unconsolidated investments | 909,531 | 475,625 |
Deferred financing costs, net | 11,684 | 4,815 |
Deferred charges and other assets | 2,694 | 11,037 |
Total Assets | 3,977,353 | 3,102,213 |
Current Liabilities: | ||
Accounts payable | 98,882 | 24,122 |
Accounts payable to related parties | 5,461 | 5,935 |
Gas imbalances | 1,663 | 1,239 |
Derivative liabilities | 2,368 | 556 |
Accrued taxes | 19,272 | 16,996 |
Accrued liabilities | 35,659 | 16,702 |
Deferred revenue | 88,471 | 60,757 |
Other current liabilities | 7,171 | 6,446 |
Total Current Liabilities | 258,947 | 132,753 |
Long-term debt, net | 2,146,993 | 1,407,981 |
Other long-term liabilities and deferred credits | 18,965 | 7,063 |
Total Long-term Liabilities | 2,165,958 | 1,415,044 |
Commitments and Contingencies | ||
Equity: | ||
Predecessor Equity | 0 | 82,295 |
Limited partners (73,199,753 and 72,485,954 common units issued and outstanding at December 31, 2017 and 2016, respectively) | 2,109,316 | 2,070,495 |
General partner (834,391 units issued and outstanding at December 31, 2017 and 2016) | (625,537) | (632,339) |
Total Partners' Equity | 1,483,779 | 1,520,451 |
Noncontrolling interests | 68,669 | 33,965 |
Total Equity | 1,552,448 | 1,554,416 |
Total Liabilities and Equity | $ 3,977,353 | $ 3,102,213 |
BALANCE SHEETS (UNAUDITED) (Par
BALANCE SHEETS (UNAUDITED) (Parenthetical) - shares | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
General partner units issued (in units) | 834,391 | 834,391 |
General partner units outstanding (in units) | 834,391 | 834,391 |
Limit partner units issued (in units) | 73,199,753 | 72,485,954 |
Limited Partner Common Units | 73,199,753 | 72,485,954 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues: | |||||||||||
Crude oil transportation services | $ 345,733 | $ 374,949 | $ 300,436 | ||||||||
Natural gas transportation services | 122,364 | 119,962 | 119,895 | ||||||||
Sales of natural gas, NGLs, and crude oil | 108,503 | 77,123 | 82,133 | ||||||||
Processing and other revenues | 79,298 | 39,628 | 40,197 | ||||||||
Total Revenues | $ 174,766 | $ 175,869 | $ 160,863 | $ 144,400 | $ 162,211 | $ 153,268 | $ 149,015 | $ 147,168 | 655,898 | 611,662 | 542,661 |
Operating Costs and Expenses: | |||||||||||
Cost of sales | 91,213 | 71,650 | 75,285 | ||||||||
Cost of transportation services | 46,200 | 47,669 | 46,840 | ||||||||
Operations and maintenance | 62,069 | 55,070 | 50,823 | ||||||||
Depreciation and amortization | 90,800 | 86,247 | 84,258 | ||||||||
General and administrative | 63,296 | 55,102 | 51,351 | ||||||||
Taxes, other than income taxes | 28,832 | 25,400 | 21,796 | ||||||||
Contract termination | 0 | 8,061 | 0 | ||||||||
(Gain) loss on disposal of assets | 599 | (1,849) | (4,795) | ||||||||
Total Operating Costs and Expenses | 381,811 | 351,048 | 335,148 | ||||||||
Operating Income | 68,236 | 74,567 | 67,504 | 63,780 | 73,830 | 67,511 | 55,307 | 63,966 | 274,087 | 260,614 | 207,513 |
Other Income (Expense): | |||||||||||
Interest expense, net | (83,542) | (40,688) | (15,514) | ||||||||
Unrealized gain (loss) on derivative instrument | 1,885 | (1,291) | 0 | ||||||||
Equity in earnings of unconsolidated investments | 237,110 | 54,531 | 2,759 | ||||||||
Gain on remeasurement of unconsolidated investment | 9,728 | 0 | 0 | ||||||||
Other income, net | 1,221 | 1,723 | 2,413 | ||||||||
Total Other Income (Expense) | 166,402 | 14,275 | (10,342) | ||||||||
Net income | 440,489 | 274,889 | 197,171 | ||||||||
Net income attributable to noncontrolling interests | (6,499) | (4,365) | (24,268) | ||||||||
Net income attributable to partners | 89,115 | 184,090 | 89,880 | 70,905 | 70,264 | 64,345 | 88,160 | 47,755 | 433,990 | 270,524 | 172,903 |
Predecessor operations interest in net income | 0 | (6,995) | (12,357) | ||||||||
General partner interest in net income | (147,823) | (102,465) | (46,478) | ||||||||
Net income attributable to noncontrolling interests | |||||||||||
Net income available to common unitholders | $ 48,985 | $ 144,281 | $ 52,579 | $ 40,322 | $ 37,559 | $ 33,060 | $ 66,728 | $ 23,717 | $ 286,167 | $ 161,064 | $ 114,068 |
Basic net income per common unit | $ 0.67 | $ 1.97 | $ 0.72 | $ 0.56 | $ 0.52 | $ 0.45 | $ 0.93 | $ 0.35 | $ 3.93 | $ 2.26 | $ 1.95 |
Diluted net income per common unit | $ 0.67 | $ 1.96 | $ 0.72 | $ 0.55 | $ 0.51 | $ 0.45 | $ 0.92 | $ 0.35 | $ 3.90 | $ 2.23 | $ 1.91 |
Basic average number of common units outstanding | 72,876 | 71,150 | 58,597 | ||||||||
Diluted average number of common units outstanding | 73,458 | 72,107 | 59,575 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash Flows from Operating Activities: | |||
Net income | $ 440,489 | $ 274,889 | $ 197,171 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | |||
Depreciation and amortization | 98,064 | 93,605 | 88,949 |
Equity in earnings of unconsolidated investments | (237,110) | (54,531) | (2,759) |
Distributions from unconsolidated investments | 237,192 | 54,449 | 3,096 |
Gain on remeasurement of unconsolidated investment | (9,728) | 0 | 0 |
Other noncash items, net | 8,988 | 9,519 | 10,124 |
Changes in components of working capital: | |||
Accounts receivable and other | (57,937) | 2,818 | (15,936) |
Accounts payable and accrued liabilities | 85,071 | 10,502 | 10,211 |
Deferred revenue | 27,283 | 33,815 | 20,612 |
Other current assets and liabilities | (10,542) | (5,578) | (6,143) |
Other operating, net | (2,709) | 95 | (1,672) |
Net Cash Provided by Operating Activities | 579,061 | 419,583 | 303,653 |
Cash Flows from Investing Activities: | |||
Acquisition of Rockies Express membership interest | 400,000 | 436,022 | 0 |
Capital expenditures | (145,144) | (84,491) | (120,718) |
Payments to Acquire Assets | (128,526) | 0 | 0 |
Distributions from unconsolidated investment in excess of cumulative earnings | 69,434 | 24,120 | 1,552 |
Contributions to unconsolidated investments | 45,948 | 50,076 | 383 |
Acquisition of Pony Express membership interest | 0 | (49,118) | (700,000) |
Acquisition of Western | 0 | 0 | (75,000) |
Other investing, net | (15,125) | 48 | (4,883) |
Net Cash Used in Investing Activities | (898,541) | (595,539) | (899,432) |
Net Cash Provided by Financing Activities | |||
Proceeds from issuance of long-term debt | 1,103,750 | 400,000 | 0 |
Distributions to unitholders | (392,861) | (292,834) | (161,834) |
(Repayments) borrowings under revolving credit facility, net | (354,000) | 262,000 | 194,000 |
Proceeds from public offering, net of offering costs | 112,420 | 337,671 | 554,084 |
Payments for Repurchase of Common Stock | (35,335) | 0 | 0 |
Payments for deferred financing costs | (22,250) | (10,251) | (1,522) |
Proceeds from private placement, net of offering costs | 0 | 90,009 | 0 |
Other financing, net | (19,927) | 20,139 | 11,795 |
Net Cash Provided by Financing Activities | 319,416 | 176,218 | 596,523 |
Net Change in Cash and Cash Equivalents | |||
Net Change in Cash and Cash Equivalents | (64) | 262 | 744 |
Cash and Cash Equivalents, beginning of period | 1,873 | 1,611 | 867 |
Cash and Cash Equivalents, end of period | 1,809 | 1,873 | 1,611 |
Supplemental Disclosures: | |||
Cash payments for interest, net | (67,360) | (29,754) | (14,021) |
Increase in accrual for payment of property, plant and equipment | 8,975 | 0 | 0 |
Common units issued as partial consideration to acquire additional 9% membership interest in Deeprock Development | 6,617 | 0 | 0 |
Property, plant and equipment acquired via the cash management agreement with TD | 0 | 0 | 138,936 |
Contributions from noncontrolling interests settled via the cash management agreement with TD | 0 | 0 | 68,277 |
Distributions to noncontrolling interests settled via the cash management agreement with TD | 0 | 0 | (69,017) |
Terminals and NatGas | |||
Cash Flows from Investing Activities: | |||
Payments to Acquire Businesses | (140,000) | 0 | 0 |
Deeprock Development, LLC | |||
Cash Flows from Investing Activities: | |||
Payments to Acquire Businesses, Net of Cash Acquired | (57,202) | 0 | 0 |
Tallgrass Crude Gathering, LLC | |||
Cash Flows from Investing Activities: | |||
Payments to Acquire Businesses | (36,030) | 0 | 0 |
Equity Option | |||
Net Cash Provided by Financing Activities | |||
Payments for Repurchase of Common Stock | (72,381) | (204,634) | 0 |
Pony Express Pipeline | |||
Net Cash Provided by Financing Activities | |||
Payments to Noncontrolling Interests | $ 0 | $ (425,882) | $ 0 |
CONSOLIDATED STATEMENTS OF EQUI
CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Thousands, $ in Thousands | Total | Predecessor Equity | General Partner | Common unitholdersLimited Partner | Subordinated UnitsLimited Partner | Total Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | Noncontrolling Interest | Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Pony Express Pipeline | Pony Express PipelinePredecessor Equity | Pony Express PipelineGeneral Partner | Pony Express PipelineCommon unitholdersLimited Partner | Pony Express PipelineSubordinated UnitsLimited Partner | Pony Express PipelineTotal Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | Pony Express PipelineNoncontrolling Interest | Pony Express PipelineTotal Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Water SolutionsPredecessor Equity | Water SolutionsGeneral Partner | Water SolutionsCommon unitholdersLimited Partner | Water SolutionsSubordinated UnitsLimited Partner | Water SolutionsTotal Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | Water SolutionsNoncontrolling Interest | Water SolutionsTotal Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Terminals and NatGasPredecessor Equity | Terminals and NatGasGeneral Partner | Terminals and NatGasCommon unitholdersLimited Partner | Terminals and NatGasSubordinated UnitsLimited Partner | Terminals and NatGasTotal Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | Terminals and NatGasNoncontrolling Interest | Terminals and NatGasTotal Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Tallgrass Development LPCommon unitholdersLimited Partner | Rockies Express Pipeline LLCPredecessor Equity | Rockies Express Pipeline LLCGeneral Partner | Rockies Express Pipeline LLCCommon unitholdersLimited Partner | Rockies Express Pipeline LLCSubordinated UnitsLimited Partner | Rockies Express Pipeline LLCTotal Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | Rockies Express Pipeline LLCNoncontrolling Interest | Rockies Express Pipeline LLCTotal Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Deeprock Development, LLCPredecessor Equity | Deeprock Development, LLCGeneral Partner | Deeprock Development, LLCCommon unitholdersLimited Partner | Deeprock Development, LLCSubordinated UnitsLimited Partner | Deeprock Development, LLCTotal Partner Equity Excluding Portion Attributable to Noncontrolling Interest [Member] | Deeprock Development, LLCNoncontrolling Interest | Deeprock Development, LLCTotal Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] |
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | $ 19,402 | $ (35,743) | $ 800,333 | $ 274,133 | $ 1,058,125 | $ 756,428 | $ 1,814,553 | ||||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units | 835 | 32,834 | 16,200 | ||||||||||||||||||||||||||||||||||||||||||
Increase (Decrease) in Partners' Capital [Roll Forward] | |||||||||||||||||||||||||||||||||||||||||||||
Net income | $ 197,171 | 12,357 | $ 46,478 | $ 108,888 | $ 5,180 | 172,903 | 24,268 | 197,171 | |||||||||||||||||||||||||||||||||||||
Issuance of units to public, net of offering costs | 3,000 | 0 | 0 | $ 554,084 | 0 | 554,084 | 0 | 554,084 | |||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 11,266 | ||||||||||||||||||||||||||||||||||||||||||||
Distributions to unitholders | 0 | (35,248) | $ (118,729) | (7,857) | (161,834) | 0 | (161,834) | ||||||||||||||||||||||||||||||||||||||
Noncash compensation expense | 0 | 0 | 9,337 | 0 | 9,337 | 0 | 9,337 | ||||||||||||||||||||||||||||||||||||||
Common units issued under LTIP, net of units tendered by employees to satisfy tax withholding obligations | 0 | 0 | $ (6,603) | 0 | (6,603) | 0 | (6,603) | ||||||||||||||||||||||||||||||||||||||
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures | 344 | ||||||||||||||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests | 0 | 0 | $ 0 | 0 | 0 | 110,127 | 110,127 | ||||||||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | 0 | 0 | 0 | 0 | 0 | 69,474 | 69,474 | $ 0 | |||||||||||||||||||||||||||||||||||||
Acquisitions | $ 0 | $ (324,328) | $ 0 | $ 0 | $ (324,328) | $ (375,672) | $ (700,000) | ||||||||||||||||||||||||||||||||||||||
Acquisition of noncontrolling interests | (700,000) | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ (600) | $ (600) | |||||||||||||||||||||||||||||||||||||
Conversion of subordinated units | 0 | 0 | $ 271,456 | $ (271,456) | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||
Conversion of Stock, Shares Converted | 16,200 | (16,200) | |||||||||||||||||||||||||||||||||||||||||||
Contributions from Predecessor Entities, net | 39,805 | 39,805 | 39,805 | ||||||||||||||||||||||||||||||||||||||||||
Proceeds from private placement, net of offering costs | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Payments for Repurchase of Common Stock | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | 71,564 | $ (348,841) | $ 1,618,766 | $ 0 | 1,341,489 | 445,077 | 1,786,566 | ||||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units | 835 | 60,644 | 0 | ||||||||||||||||||||||||||||||||||||||||||
Net income | 274,889 | 6,995 | $ 102,465 | $ 161,064 | $ 0 | 270,524 | 4,365 | 274,889 | |||||||||||||||||||||||||||||||||||||
Issuance of units to public, net of offering costs | 337,700 | 0 | 0 | $ 337,671 | 0 | 337,671 | 0 | 337,671 | |||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 7,697 | ||||||||||||||||||||||||||||||||||||||||||||
Distributions to unitholders | 0 | (89,838) | $ (202,996) | 0 | (292,834) | 0 | (292,834) | ||||||||||||||||||||||||||||||||||||||
Noncash compensation expense | 0 | 0 | 7,879 | 0 | 7,879 | 0 | 7,879 | ||||||||||||||||||||||||||||||||||||||
Common units issued under LTIP, net of units tendered by employees to satisfy tax withholding obligations | 0 | 0 | $ (498) | 0 | (498) | 0 | 498 | ||||||||||||||||||||||||||||||||||||||
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures | 25 | ||||||||||||||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests | 0 | 0 | $ 0 | 0 | 0 | 9,304 | 9,304 | ||||||||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | 0 | 0 | 0 | 0 | 6,534 | 6,534 | 425,882 | ||||||||||||||||||||||||||||||||||||||
Acquisitions | $ 0 | $ (279,967) | $ 268,607 | $ 0 | $ (11,360) | $ (417,679) | $ (429,039) | ||||||||||||||||||||||||||||||||||||||
Acquisition of noncontrolling interests | (49,118) | $ 0 | $ (59) | $ (5,373) | $ 0 | $ (5,432) | $ (568) | $ (6,000) | |||||||||||||||||||||||||||||||||||||
Contributions from Predecessor Entities, net | 3,736 | 3,736 | 3,736 | ||||||||||||||||||||||||||||||||||||||||||
Proceeds from private placement, net of offering costs | 90,009 | 0 | 0 | $ 90,009 | 0 | 90,009 | 0 | 90,009 | |||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Private Placement of Units | 2,417 | ||||||||||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units, Acquisitions | 6,518 | ||||||||||||||||||||||||||||||||||||||||||||
Partial exercise of call option | 0 | (33,993) | $ (204,634) | 0 | (238,627) | 0 | (238,627) | ||||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units, Treasury Units Purchased | (4,815) | ||||||||||||||||||||||||||||||||||||||||||||
Contributions from TD | 0 | 17,894 | $ 0 | 0 | 17,894 | 0 | 17,894 | ||||||||||||||||||||||||||||||||||||||
Payments for Repurchase of Common Stock | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | 1,554,416 | 82,295 | $ (632,339) | $ 2,070,495 | $ 0 | 1,520,451 | 33,965 | 1,554,416 | |||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units | 835 | 72,486 | 0 | ||||||||||||||||||||||||||||||||||||||||||
Net income | 440,489 | 0 | $ 147,823 | $ 286,167 | $ 0 | 433,990 | 6,499 | 440,489 | |||||||||||||||||||||||||||||||||||||
Issuance of units to public, net of offering costs | 0 | 0 | $ 112,420 | 0 | 112,420 | 0 | 112,420 | ||||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units, Sale of Units | 2,341 | ||||||||||||||||||||||||||||||||||||||||||||
Distributions to unitholders | 0 | (136,737) | $ (256,124) | 0 | (392,861) | 0 | (392,861) | ||||||||||||||||||||||||||||||||||||||
Noncash compensation expense | 0 | 0 | 10,390 | 0 | 10,390 | 0 | 10,390 | ||||||||||||||||||||||||||||||||||||||
Common units issued under LTIP, net of units tendered by employees to satisfy tax withholding obligations | 0 | 0 | $ (12,933) | 0 | (12,933) | 0 | 12,933 | ||||||||||||||||||||||||||||||||||||||
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures | 683 | ||||||||||||||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests | 0 | 0 | $ 0 | 0 | 0 | 1,589 | 1,589 | ||||||||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests | 0 | 0 | 0 | 0 | 6,196 | 6,196 | $ 0 | ||||||||||||||||||||||||||||||||||||||
Acquisitions | $ (82,295) | $ (57,705) | $ 0 | $ 0 | $ (140,000) | $ 0 | $ (140,000) | $ 0 | $ 63,681 | $ 0 | $ 0 | $ 63,681 | $ 0 | $ 63,681 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 45,869 | $ 45,869 | ||||||||||||||||||||||||
Acquisition of noncontrolling interests | 0 | $ 0 | $ 0 | $ 6,617 | $ 0 | $ 6,617 | $ (13,057) | $ (6,440) | |||||||||||||||||||||||||||||||||||||
Proceeds from private placement, net of offering costs | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units, Acquisitions | 0 | 0 | (129) | ||||||||||||||||||||||||||||||||||||||||||
Partial exercise of call option | 0 | (12,561) | $ (72,381) | 0 | (84,942) | 0 | (84,942) | ||||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units, Treasury Units Purchased | (1,703) | (736) | |||||||||||||||||||||||||||||||||||||||||||
Contributions from TD | 0 | 2,301 | $ 0 | 0 | 2,301 | 0 | 2,301 | ||||||||||||||||||||||||||||||||||||||
Payments for Repurchase of Common Stock | 35,335 | 0 | 0 | (35,335) | 0 | (35,335) | 0 | (35,335) | |||||||||||||||||||||||||||||||||||||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | $ 1,552,448 | $ 0 | $ (625,537) | $ 2,109,316 | $ 0 | $ 1,483,779 | $ 68,669 | $ 1,552,448 | |||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Units | 835 | 73,200 | 0 |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of Business | Tallgrass Energy Partners, LP ("TEP" or the "Partnership") is a publicly traded, growth-oriented limited partnership formed to own, operate, acquire and develop midstream energy assets in North America. "We," "us," "our" and similar terms refer to TEP together with its consolidated subsidiaries. Our operations are located in and provide services to certain key United States hydrocarbon basins, including the Denver-Julesburg, Powder River, Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime, Eagle Ford, Bakken, Marcellus, and Utica shale formations. Our reportable business segments are: • Natural Gas Transportation—the ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities; • Crude Oil Transportation—the ownership and operation of a FERC-regulated crude oil pipeline system; and • Gathering, Processing & Terminalling—the ownership and operation of natural gas gathering and processing facilities; crude oil gathering, storage and terminalling facilities; the provision of water business services primarily to the oil and gas exploration and production industry; the transportation of NGLs; and the marketing of crude oil and NGLs. Natural Gas Transportation. We provide natural gas transportation and storage services for customers in the Rocky Mountain, Midwest and Appalachian regions of the United States through: (1) our 49.99% membership interest in Rockies Express Pipeline LLC ("Rockies Express"), which owns the Rockies Express Pipeline, a FERC-regulated natural gas pipeline system extending from Opal, Wyoming and Meeker, Colorado to Clarington, Ohio (the "Rockies Express Pipeline"), inclusive of the additional 24.99% membership interest acquired from Tallgrass Development, LP ("TD") effective March 31, 2017 as discussed in Note 3 - Acquisitions , and our 100% membership interest in Tallgrass NatGas Operator, LLC ("NatGas") acquired effective January 1, 2017, which operates the Rockies Express Pipeline, (2) the Tallgrass Interstate Gas Transmission system, a FERC-regulated natural gas transportation and storage system located in Colorado, Kansas, Missouri, Nebraska and Wyoming (the "TIGT System"), and (3) the Trailblazer Pipeline system, a FERC-regulated natural gas pipeline system extending from the Colorado and Wyoming border to Beatrice, Nebraska (the "Trailblazer Pipeline"). Crude Oil Transportation. We provide crude oil transportation to customers in Wyoming, Colorado, and the surrounding regions through Tallgrass Pony Express Pipeline, LLC ("Pony Express"), which owns a FERC-regulated crude oil pipeline commencing in Guernsey, Wyoming and terminating in Cushing, Oklahoma, and includes a lateral in Northeast Colorado commencing in Weld County, Colorado that interconnects with the pipeline just east of Sterling, Colorado (the "Pony Express System"). Gathering, Processing & Terminalling. We provide natural gas gathering and processing services for customers in Wyoming through: (1) a natural gas gathering system in the Powder River Basin (the "Douglas Gathering System") that was acquired on June 5, 2017, as discussed in Note 3 – Acquisitions , (2) the Casper and Douglas natural gas processing facilities, and (3) the West Frenchie Draw natural gas treating facility. We also provide crude oil gathering services for customers in Wyoming through a crude oil gathering system in the Powder River Basin (the "PRB Crude System") that was acquired on August 3, 2017, as discussed in Note 3 – Acquisitions ; and NGL transportation services in Northeast Colorado and Wyoming. We perform water business services, including freshwater transportation and produced water gathering and disposal, in Colorado, Texas, and Wyoming through BNN Water Solutions, LLC ("Water Solutions"), and crude oil storage and terminalling services through our 100% membership interest in Tallgrass Terminals, LLC ("Terminals") acquired effective January 1, 2017, which owns and operates crude oil terminals near Sterling, Colorado (the "Sterling Terminal") and in Weld County, Colorado (the "Buckingham Terminal"). Terminals also owns a 69% membership interest in Deeprock Development, LLC ("Deeprock Development"), which owns a crude oil terminal in Cushing, Oklahoma (the "Cushing Terminal"), inclusive of an additional 49% membership interest in Deeprock Development acquired in July 2017 as discussed in Note 3 – Acquisitions . The Gathering, Processing & Terminalling segment also includes newly formed Stanchion Energy, LLC ("Stanchion"), which transacts in crude oil. As discussed in Note 20 – Subsequent Events , on January 2, 2018, Terminals acquired an approximately 38% interest in Deeprock North, LLC ("Deeprock North"), which was merged into Deeprock Development immediately following the acquisition, and on January 12, 2018, Water Solutions acquired a 100% membership interest in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC (collectively, "BNN North Dakota"). The table below summarizes our equity ownership as of December 31, 2017 : Unit holder Limited Partner Common Units General Partner Units Percentage of Outstanding Limited Partner Common Units Percentage of Outstanding Common and General Partner Units Public Unitholders 47,580,535 — 65.00 % 64.27 % Tallgrass Equity, LLC 20,000,000 — 27.32 % 27.01 % Tallgrass Development, LP (1) 5,619,218 — 7.68 % 7.59 % Tallgrass MLP GP, LLC (2) — 834,391 — % 1.13 % Total 73,199,753 834,391 100.00 % 100.00 % (1) Effective February 7, 2018, Tallgrass Equity, LLC ("Tallgrass Equity") acquired the 5,619,218 common units held by TD in connection with the merger of TD into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity ("Tallgrass Development Holdings"). (2) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights. The term "Terminals Predecessor" refers to Terminals and the term "NatGas Predecessor" refers to NatGas prior to their acquisition by TEP on January 1, 2017. Terminals Predecessor and NatGas Predecessor are collectively referred to as the Predecessor Entities, as further discussed in Note 2 – Summary of Significant Accounting Policies . Financial results for all prior periods have been recast to reflect the operations of the Predecessor Entities. Predecessor Equity as presented in the consolidated financial statements represents the capital account activity of Terminals Predecessor and NatGas Predecessor prior to January 1, 2017. For additional information regarding these acquisitions, see Note 3 – Acquisitions . |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Basis of Presentation The accompanying consolidated financial statements and related notes were prepared in conformity with accounting principles generally accepted in the United States of America ("GAAP"). 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. As further discussed in Note 3 – Acquisitions , TEP closed the acquisition of Terminals and NatGas effective January 1, 2017. As the acquisitions of Terminals and NatGas are considered transactions between entities under common control, and a change in reporting entity, the financial information presented has been recast to include Terminals and NatGas for all periods presented. Net equity contributions of the Predecessor Entities included in the consolidated financial statements represent transfers of cash as a result of TD's centralized cash management system prior to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the subsidiaries of TD. These loans were then periodically recorded as equity distributions. The accompanying consolidated financial statements of TEP include historical cost-basis accounts of the assets of Terminals and NatGas for the periods prior to January 1, 2017, the date TEP acquired Terminals and NatGas from TD, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. TEP and the Predecessor Entities are all considered "entities under common control" as defined under GAAP and, as such, the transfers between the entities of the assets and liabilities have been recorded by TEP at historical cost. 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. Prior to January 1, 2016, Pony Express participated in a cash management agreement with TD, which currently holds a 2.0% common membership interest in Pony Express, under which cash balances were swept periodically and recorded as loans from Pony Express to TD. Effective January 1, 2016, Pony Express entered into a cash management agreement with TEP. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP and noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the allocation of cash distributions and may not follow the respective ownership percentages held by TEP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Pony Express effective September 1, 2014, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million through the quarter ended September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ended December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 are attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests. A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. Pony Express was considered to be a VIE under the applicable authoritative guidance prior to our acquisition of an additional 31.3% membership interest effective January 1, 2016. Effective January 1, 2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in Pony Express. Use of Estimates Certain amounts included in or affecting these 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. Net equity contributions 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 January 1, 2017 for Terminals and NatGas, 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. 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 $0.5 million and $0.6 million at December 31, 2017 and 2016 , 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 and net realizable value 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 and net realizable value 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 $2.6 million and $2.9 million included in "Prepayments and other current assets" and "Deferred charges and other assets" in the consolidated balance sheets at December 31, 2017 and 2016 , respectively. Regulatory assets at December 31, 2017 and December 31, 2016 were primarily attributable to costs associated with both TIGT's 2015 Rate Case Filing and Trailblazer's 2013 Rate Case Filing as well as fuel tracker assets at our regulated natural gas pipelines . We recorded regulatory liabilities of approximately $2.3 million and $1.7 million included in "Other current liabilities" in the consolidated balance sheets at December 31, 2017 and 2016 , respectively, related to fuel tracker liabilities at our regulated natural gas pipelines. For further information regarding our rate case filings and fuel tracker balances, see 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 and/or the negative salvage liability discussed under "Depreciation and Amortization" below, as appropriate, 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 establish identifiable intangible assets when they meet either the separability criterion or the contractual-legal criterion. 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. Other intangible assets include customer contracts amortized on a straight-line basis over a period of 2 to 8 years , based on the remaining term of the contracts at the time of acquisition. 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 asset 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 or asset group to its carrying amount. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the asset or asset group 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 and net realizable value. 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 depreciation rates for our regulated natural gas pipeline assets include two components, one based on economic service life (capital recovery) and one based on net costs of removal (negative salvage). The accumulated liability related to negative salvage is classified as "Other long-term liabilities and deferred credits" in our consolidated balance sheets. 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 - 5.0% Gathering & processing assets 2.2 - 5.0% Water business assets 2.3 - 20.0% Terminal assets 1.8 - 2.8% Replacement Gas Facilities (1) 10.0% General & other 2.5 - 25.0% (1) Represents costs incurred by TIGT, and reimbursed by Pony Express, for the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System after having sold approximately 433 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013. 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. Deferred financing costs associated with long-term debt are presented as a reduction to the corresponding debt in our consolidated balance sheets. Deferred financing costs associated with our revolving credit facility are presented as noncurrent assets in our consolidated balance sheets. 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 fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. We evaluate goodwill for impairment at the reporting unit level, which is the same as, or one level below, an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or proceeding directly to the quantitative impairment test 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, then goodwill is not considered impaired. When goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the reporting unit's fair value, then the reporting unit should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. See Note 7 – Goodwill and Other Intangible Assets for additional information regarding impairment testing performed during 2017. Investment in Unconsolidated Affiliates We use the equity method to account for investments in 20% or greater 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. See Note 8 – Investments in Unconsolidated Affiliates for additional information regarding our investment in unconsolidated affiliates. 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 transportation and storage services and crude oil transportation services to our customers in which the commodity remains the property of these customers at all times. Natural gas transportation and storage services occur in the Natural Gas Transportation 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. Crude oil transportation services occur in the Crude Oil Transportation 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 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 liquids sales occur in the Gathering, Processing & Terminalling 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 Gathering, Processing & Terminalling segment. Natural gas sales occur in both the Natural Gas Transportation segment and in the Gathering, Processing & Terminalling segment. In the Natural Gas Transportation 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. As of the date of the TIGT rate case settlement in 2016, all of our regulated gas pipelines operate under fuel tracker mechanisms, as discussed under "Accounting for Regulatory Activities" above, and as a result our regulated gas pipelines no longer recognize revenue associated with volumes retained from the customer. 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 Gathering, Processing & Terminalling 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 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 We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of crude oil and 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 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 TEP is comprised primarily of limited liability companies that are considered flow-through entities (partnerships or disregarded entities) for in |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Acquisitions | Acquisition of Outrigger Powder River Operating, LLC On August 3, 2017, we acquired 100% of the membership interests of Outrigger Powder River Operating, LLC (subsequently renamed as Tallgrass Crude Gathering, LLC, "TCG"), which owns the PRB Crude System, a crude oil gathering system in the Powder River Basin with approximately 34 miles of gathering lines as of the acquisition date and approximately 150,000 acres dedicated on a long-term fee-based contract, for approximately $36 million . The transaction qualifies as an acquisition of a business and is accounted for as a business combination under ASC 805. The following represents the fair value of assets acquired and liabilities assumed at August 3, 2017 (in thousands): Accounts receivable $ 117 Property, plant and equipment 29,306 Intangible asset 6,694 (1) Accounts payable and accrued liabilities (87 ) Net identifiable assets acquired $ 36,030 (1) The $6.7 million intangible asset acquired represents a major customer contract. This intangible asset is amortized on a straight-line basis over a period of 8 years , the remaining term of the contract at the time of acquisition. At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of December 31, 2017. Actual revenue and net loss attributable to TEP from TCG of less than $1 million was recognized in the accompanying consolidated statements of income for the period from August 3, 2017 to December 31, 2017. Acquisitions of Additional Interests in Deeprock Development, LLC On July 20, 2017, we acquired an additional 40% membership interest in Deeprock Development from Kinder Morgan Cushing, LLC for cash consideration of approximately $57.2 million , net of cash acquired. We subsequently acquired an additional 9% membership interest in Deeprock Development from Deeprock Energy Resources LLC ("DER") on July 21, 2017, as discussed further below. Upon closing of the acquisition of the 40% membership interest on July 20, 2017, we obtained a controlling financial interest in Deeprock Development and accordingly have accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEP remeasured its previously held 20% equity interest in Deeprock Development to its fair value of $22.9 million , recognized a gain of $9.7 million in "Gain on remeasurement of unconsolidated investment" in the consolidated statements of income, and consolidated Deeprock Development in our consolidated financial statements. The 40% equity interest in Deeprock Development held by noncontrolling interests was recorded at its acquisition date fair value of $45.9 million . The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow analysis and adjusted for lack of control. These fair value measurements are based on significant inputs, such as forecasted cash flows and discount rates, 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. The following represents the fair value of assets acquired and liabilities assumed at July 20, 2017 (in thousands): Accounts receivable $ 968 Other current assets 598 Property, plant and equipment 70,148 Accounts payable (712 ) Deferred revenue (6,546 ) Net identifiable assets acquired 64,456 Goodwill 61,550 Net assets acquired (excluding cash) $ 126,006 At September 30, 2017, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of December 31, 2017. The goodwill recognized of $61.6 million is primarily attributed to synergies expected from combining the operations of TEP and Deeprock Development. All the goodwill was assigned to our Gathering, Processing & Terminalling segment. Actual revenue and net income attributable to TEP from Deeprock Development of $10.5 million and $8.5 million , respectively, was recognized in the accompanying consolidated statements of income for the period from July 20, 2017 to December 31, 2017. On July 21, 2017, subsequent to the acquisition of an additional 40% membership interest discussed above, we acquired an additional 9% membership interest in Deeprock Development from DER for total consideration valued at approximately $13.1 million , consisting of approximately $6.4 million in cash and the issuance of 128,790 common units (valued at approximately $6.7 million based on the July 20, 2017 closing price of TEP's common units), which was accounted for as an acquisition of noncontrolling interest. Subsequent to the closing of the transaction, our aggregate membership interest in Deeprock Development is 69% . Acquisition of DCP Douglas, LLC On June 5, 2017, we acquired 100% of the membership interests in DCP Douglas, LLC (subsequently renamed as Tallgrass Midstream Gathering, LLC), which owns the Douglas Gathering System, a natural gas gathering system in the Powder River Basin with approximately 1,500 miles of gathering pipeline connected to the Douglas processing plant, for approximately $128.5 million , subject to working capital adjustments. The acquisition has been accounted for as an asset acquisition, with substantially all the fair value allocated to the long-lived assets acquired based on their relative fair values. Acquisitions of 49.99% in Rockies Express Pipeline LLC On May 6, 2016, TD assigned us its right to purchase a 25% membership interest in Rockies Express from a unit of Sempra U.S. Gas and Power ("Sempra") pursuant to the purchase agreement originally entered into between TD's wholly-owned subsidiary and Sempra in March 2016. Subsequently on May 6, 2016, we closed the purchase of a 25% membership interest in Rockies Express from Sempra pursuant to the purchase agreement for cash consideration of approximately $436.0 million , after making the adjustments to the purchase price required by the purchase agreement. On March 31, 2017, TEP, TD, and Rockies Express Holdings, LLC, entered into a definitive Purchase and Sale Agreement, pursuant to which we acquired an additional 24.99% membership interest in Rockies Express from TD in exchange for cash consideration of $400 million . Together with the 25% membership interest in Rockies Express that we acquired from a unit of Sempra U.S. Gas and Power on May 6, 2016, this transaction increases our aggregate membership interest in Rockies Express to 49.99% . For additional information, see Note 8 – Investments in Unconsolidated Affiliates . Acquisition of Tallgrass Terminals, LLC and Tallgrass NatGas Operator, LLC Effective January 1, 2017, we acquired 100% of the issued and outstanding membership interests in Terminals and 100% of the issued and outstanding membership interests in NatGas from TD for total cash consideration of $140 million . These acquisitions are considered transactions between entities under common control, and a change in reporting entity. Terminals owns several fully operational assets providing storage capacity and additional injection points for the Pony Express System, including the Sterling Terminal near Sterling, Colorado, the Buckingham Terminal in northeast Colorado, and a 69% interest in the Deeprock Development Terminal in Cushing, Oklahoma following the acquisition of an aggregate additional 49% membership interest in Deeprock Development in July 2017 discussed above. Terminals also owns acreage in Cushing, Oklahoma and Guernsey, Wyoming, which is under development to provide additional storage capacity and other potential opportunities. NatGas is the operator of the Rockies Express Pipeline and receives a fee from Rockies Express as compensation for its services. Acquisitions of 100% 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. The terms of TEP's 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 with distributions thereafter shared in accordance with the terms of the Second Amended Pony Express LLC Agreement. 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. The transaction resulted in a deemed distribution to our general partner as discussed further in Note 11 – Partnership Equity and Distributions . Effective January 1, 2016, TEP acquired an additional 31.3% membership interest in Pony Express in exchange for cash consideration of $475 million and 6,518,000 TEP common units (valued at approximately $268.6 million based on the December 31, 2015 closing price of our common units) issued to TD, for total consideration of approximately $743.6 million . The transaction increased our aggregate membership interest in Pony Express to 98% . As part of the transaction, TD granted us an 18 -month call option covering the newly issued 6,518,000 common units at a price of $42.50 . On the effective date of the acquisition, the call option was valued at $46.0 million . As discussed in Note 9 – Risk Management , in July 2016 and October 2016, we partially exercised the option covering 3,563,146 and 1,251,760 of the common units, respectively. On February 1, 2017, we exercised the remainder of the call option covering an additional 1,703,094 common units, leaving no remaining common units subject to the call option as of such date. As a result of the partial exercises in 2016 and 2017, TEP derecognized a portion of the derivative asset balance, recognizing approximately $34.0 million and $12.6 million through equity for the years ended December 31, 2016 and 2017, respectively, as discussed further in Note 11 – Partnership Equity and Distributions . The acquisition of the additional 31.3% membership interest in Pony Express represents a transaction between entities under common control and an acquisition of noncontrolling interests. As a result, financial information for periods prior to the transaction has not been recast to reflect the additional 31.3% membership interest. The transaction resulted in a deemed distribution to our general partner as discussed further in Note 11 – Partnership Equity and Distributions . Cash outflows to acquire an additional noncontrolling interest in Pony Express are classified as an investing activity in the accompanying consolidated statements of cash flows to the extent the consideration paid was used to directly fund the construction of the underlying assets by the noncontrolling member. Cash outflows to acquire an additional noncontrolling interest in excess of the cost to construct the underlying assets are classified as financing activities. For the year ended December 31, 2016, $49.1 million of the $475 million paid to acquire the additional 31.3% membership interest in Pony Express was classified as an investing activity and $425.9 million was classified as a financing activity. As discussed in Note 20 – Subsequent Events , we acquired the remaining 2% of Pony Express from TD effective February 1, 2018. Acquisition of BNN Western, LLC On December 16, 2015, Whiting Oil and Gas Corporation ("Whiting"), BNN Redtail, LLC ("Redtail"), and BNN Western, LLC ("Western"), a newly formed Delaware limited liability company, entered into a definitive Transfer, Purchase and Sale Agreement, pursuant to which Redtail acquired 100% of the outstanding membership interests of Western from Whiting in exchange for total cash consideration of $75 million . Western's assets consist of a fresh water delivery and storage system and produced water gathering and produced water disposal system, which together comprise 62 miles of pipeline along with associated fresh water ponds and disposal wells. As part of the transaction with Whiting, Whiting also executed a five -year fresh water service contract and a nine -year gathering and disposal contract, each of which commenced in December 2015. At December 31, 2015, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. The $75 million purchase price of the assets was allocated entirely to property, plant and equipment. No adjustments were made to these provisional amounts and the allocation of assets acquired and liabilities assumed in the acquisition was considered final as of September 30, 2016. Pro Forma Financial Information Unaudited pro forma revenue and net income attributable to TEP for the years ended December 31, 2017 and 2016 is presented below as if the acquisitions of TCG and Deeprock Development had been completed on January 1, 2016. Unaudited pro forma revenue and net income attributable to TEP for the year ended December 31, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015. Year Ended December 31, 2017 2016 2015 (in thousands) Revenue $ 667,391 $ 632,528 $ 544,497 Net income attributable to partners $ 427,522 $ 275,506 $ 173,542 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 the estimated results of operations of TCG, Deeprock Development, and Western for the periods presented, as well as to eliminate the equity in earnings and gain on remeasurement of unconsolidated investment associated with our previously held 20% membership interest in Deeprock Development. Historical Financial Information The results of our acquisitions of Terminals and NatGas are included in the consolidated balance sheets as of December 31, 2017 and December 31, 2016 . The following table presents our previously reported December 31, 2016 consolidated balance sheet, adjusted for the acquisitions of Terminals and NatGas: December 31, 2016 TEP (As previously reported) Consolidate Terminals Consolidate NatGas TEP (As currently reported) (in thousands) ASSETS Current Assets: Cash and cash equivalents $ 1,873 $ — $ — $ 1,873 Accounts receivable, net 59,469 38 29 59,536 Gas imbalances 1,597 — — 1,597 Inventories 12,805 288 — 13,093 Derivative assets 10,967 — — 10,967 Prepayments and other current assets 6,820 808 — 7,628 Total Current Assets 93,531 1,134 29 94,694 Property, plant and equipment, net 2,012,263 66,969 — 2,079,232 Goodwill 343,288 — — 343,288 Intangible assets, net 93,522 — — 93,522 Unconsolidated investments 461,915 13,710 — 475,625 Deferred financing costs, net 4,815 — — 4,815 Deferred charges and other assets 9,637 1,400 — 11,037 Total Assets $ 3,018,971 $ 83,213 $ 29 $ 3,102,213 LIABILITIES AND EQUITY Current Liabilities: Accounts payable $ 24,076 $ 46 $ — $ 24,122 Accounts payable to related parties 5,879 56 — 5,935 Gas imbalances 1,239 — — 1,239 Derivative liabilities 556 — — 556 Accrued taxes 16,328 668 — 16,996 Accrued liabilities 16,525 177 — 16,702 Deferred revenue 60,757 — — 60,757 Other current liabilities 6,446 — — 6,446 Total Current Liabilities 131,806 947 — 132,753 Long-term debt, net 1,407,981 — — 1,407,981 Other long-term liabilities and deferred credits 7,063 — — 7,063 Total Long-term Liabilities 1,415,044 — — 1,415,044 Equity: Net Equity 1,472,121 82,266 29 1,554,416 Total Equity 1,472,121 82,266 29 1,554,416 Total Liabilities and Equity $ 3,018,971 $ 83,213 $ 29 $ 3,102,213 The results of our acquisitions of Terminals and NatGas are included in the consolidated statements of income for the years ended December 31, 2017 , 2016 , and 2015 . The following tables present the previously reported consolidated statements of income for the years ended December 31, 2016 and 2015 , adjusted for the acquisitions of Terminals and NatGas: Year Ended December 31, 2016 TEP (As previously reported) Consolidate Terminals Consolidate NatGas Elimination TEP (As currently reported) (in thousands) Revenues: Crude oil transportation services $ 374,949 $ — $ — $ — $ 374,949 Natural gas transportation services 119,962 — — — 119,962 Sales of natural gas, NGLs, and crude oil 77,394 99 — (370 ) (1) 77,123 Processing and other revenues 32,817 12,043 6,228 (11,460 ) (2) 39,628 Total Revenues 605,122 12,142 6,228 (11,830 ) 611,662 Operating Costs and Expenses: Cost of sales 71,920 100 — (370 ) (1) 71,650 Cost of transportation services 58,341 788 — (11,460 ) (2) 47,669 Operations and maintenance 53,386 1,684 — — 55,070 Depreciation and amortization 84,896 1,351 — — 86,247 General and administrative 53,633 1,469 — — 55,102 Taxes, other than income taxes 24,727 673 — — 25,400 Contract termination — 8,061 (3) — — 8,061 Loss on disposal of assets 1,849 — — — 1,849 Total Operating Costs and Expenses 348,752 14,126 — (11,830 ) 351,048 Operating Income (Expense) 256,370 (1,984 ) 6,228 — 260,614 Other Income (Expense): Interest expense, net (40,688 ) — — — (40,688 ) Unrealized loss on derivative instrument (1,291 ) — — — (1,291 ) Equity in earnings of unconsolidated investments 51,780 2,751 — — 54,531 Other income, net 1,723 — — — 1,723 Total Other Income 11,524 2,751 — — 14,275 Net income 267,894 767 6,228 — 274,889 Net income attributable to noncontrolling interests (4,365 ) — — — (4,365 ) Net income attributable to partners $ 263,529 $ 767 $ 6,228 $ — $ 270,524 Year Ended December 31, 2015 TEP (As previously reported) Consolidate Terminals Consolidate NatGas Elimination TEP (As currently reported) (in thousands) Revenues: Crude oil transportation services $ 300,436 $ — $ — $ — $ 300,436 Natural gas transportation services 119,895 — — — 119,895 Sales of natural gas, NGLs, and crude oil 82,133 — — — 82,133 Processing and other revenues 33,733 7,689 6,332 (7,557 ) (2) 40,197 Total Revenues 536,197 7,689 6,332 (7,557 ) 542,661 Operating Costs and Expenses: Cost of sales 75,285 — — — 75,285 Cost of transportation services 53,597 800 — (7,557 ) (2) 46,840 Operations and maintenance 49,138 1,685 — — 50,823 Depreciation and amortization 83,476 782 — — 84,258 General and administrative 50,195 1,156 — — 51,351 Taxes, other than income taxes 21,796 — — — 21,796 Loss on disposal of assets 4,795 — — — 4,795 Total Operating Costs and Expenses 338,282 4,423 — (7,557 ) 335,148 Operating Income 197,915 3,266 6,332 — 207,513 Other Income (Expense): Interest expense, net (15,514 ) — — — (15,514 ) Equity in earnings of unconsolidated investments — 2,759 — — 2,759 Other income, net 2,413 — — — 2,413 Total Other (Expense) Income (13,101 ) 2,759 — — (10,342 ) Net income 184,814 6,025 6,332 — 197,171 Net income attributable to noncontrolling interests (24,268 ) — — — (24,268 ) Net income attributable to partners $ 160,546 $ 6,025 $ 6,332 $ — $ 172,903 (1) Represents the elimination of revenue and cost of sales associated with the purchase of crude oil from Pony Express by Terminals. (2) Represents the elimination of revenue and cost of transportation services associated with the lease of the Sterling Terminal facilities by Pony Express. (3) Represents a one-time charge related to the termination of an operating agreement at the Sterling Terminal. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | As a result of our relationship with Tallgrass Energy Holdings and its affiliates, we have entered into a number of related party transactions. The following disclosure includes those related party transactions which are not otherwise disclosed in these notes to our consolidated financial statements. We have no employees. In connection with the closing of our initial public offering on May 17, 2013, TEP and its general partner entered into an Omnibus Agreement with Tallgrass Energy Holdings and certain of its affiliates (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse Tallgrass Energy Holdings 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 Tallgrass Energy Holdings and its affiliates, 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. 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 January 1, 2017 for Terminals and NatGas. Balances lent to TD under the Pony Express cash management agreement effective September 1, 2014 were classified as related party receivables in the consolidated balance sheets. There was no interest income from TD recognized for the years ended December 31, 2017 and 2016 . During the year ended December 31, 2015 we recognized interest income from TD of $0.4 million on the receivable balance under the Pony Express cash management agreement in effect through December 31, 2015. Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Processing and other revenues (1) $ 8,516 $ 6,228 $ 6,331 Cost of transportation services (2) $ 10,476 $ 18,585 $ 18,288 Charges to TEP: (3) Property, plant and equipment, net $ 2,679 $ 3,084 $ 4,342 Other deferred charges $ 25 $ 44 $ 7 Operations and maintenance $ 29,881 $ 25,431 $ 23,658 General and administrative $ 41,032 $ 39,574 $ 33,820 (1) Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline. (2) Reflects rent expense for the crude oil storage at the Deeprock Terminal prior to our consolidation of Deeprock Development during the third quarter of 2017, as discussed in Note 3 – Acquisitions . (3) Charges to TEP include directly charged wages and salaries, other compensation and benefits, and shared services. Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable to related parties" in the consolidated balance sheets are as follows: December 31, 2017 December 31, 2016 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 1,340 $ 590 Total receivable from related parties $ 1,340 $ 590 Accounts payable to related parties: Tallgrass Operations, LLC $ 5,381 $ 5,854 Tallgrass Equity, LLC 80 68 Deeprock Development, LLC — 13 Total accounts payable to related parties $ 5,461 $ 5,935 Gas imbalances with affiliated shippers are as follows: December 31, 2017 December 31, 2016 (in thousands) Affiliate gas imbalance receivables $ 18 $ 177 Affiliate gas imbalance payables $ 442 $ — |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2017 | |
Inventory Disclosure [Abstract] | |
Inventory | The components of inventory at December 31, 2017 and 2016 consisted of the following: December 31, 2017 December 31, 2016 (in thousands) Crude oil $ 12,792 $ 5,462 Materials and supplies 5,891 6,383 Natural gas liquids 942 265 Gas in underground storage 1,984 983 Total inventory $ 21,609 $ 13,093 |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | A summary of net property, plant and equipment by classification is as follows: December 31, 2017 December 31, 2016 (in thousands) Crude oil pipelines $ 1,220,379 $ 1,202,125 Gathering, processing and terminalling assets (1) 675,092 397,701 Natural gas pipelines 581,400 572,150 General and other 98,680 82,510 Construction work in progress 97,978 20,606 Accumulated depreciation and amortization (279,192 ) (195,860 ) Total property, plant and equipment, net (2) $ 2,394,337 $ 2,079,232 (1) Includes approximately $138.2 million of assets associated with the Douglas Gathering System acquired in June 2017, approximately $68.4 million of assets associated with the acquisition of the aggregate additional 49% membership interest in Deeprock Development in July 2017, and approximately $29.3 million of assets associated with the PRB Crude System acquired in August 2017. (2) Property, plant and equipment, net includes approximately $431.6 million of assets at our regulated natural gas pipelines at December 31, 2017 . Depreciation expense was approximately $86.9 million , $83.2 million , and $76.3 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Capitalized interest was approximately $1.1 million , $0.6 million , and $0.9 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Under lease agreements effective October 3, 2015 and January 1, 2017, TMID, as lessor, leases capacity on NGL pipelines that were constructed for third parties. Rental income was approximately $3.8 million , $3.2 million , and $0.8 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, 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 for the years ended December 31, 2017 , 2016 , and 2015 and was recorded as "Other income, net" in the accompanying consolidated statements of income. As of December 31, 2017 , future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands): Year Total 2018 $ 4,575 2019 4,590 2020 3,978 2021 3,773 2022 3,773 Thereafter 11,127 Total $ 31,816 |
Goodwill and Intangible Assets
Goodwill and Intangible Assets | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Goodwill and Intangible Assets Disclosure | Reconciliation of Goodwill The following table presents a reconciliation of the carrying amount of goodwill by reportable segment for the periods indicated: Year Ended December 31, 2017 Year Ended December 31, 2016 Natural Gas Transportation Gathering, Processing & Terminalling Total Natural Gas Transportation Gathering, Processing & Terminalling Total (in thousands) Balance at beginning of period $ 255,558 $ 87,730 $ 343,288 $ 255,558 $ 87,730 $ 343,288 Goodwill acquired — 61,550 (1) 61,550 — — — Balance at end of period $ 255,558 $ 149,280 $ 404,838 $ 255,558 $ 87,730 $ 343,288 (1) The $61.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Deeprock Development on July 20, 2017 as discussed further in Note 3 – Acquisitions . Annual Goodwill Impairment Analysis We did not elect to apply the qualitative assessment option during our 2017 annual goodwill impairment testing; instead we proceeded directly to the quantitative impairment test. We compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the quantitative impairment test indicated no impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, we did not record a goodwill impairment during the year ended December 31, 2017 . Unpredictable events or deteriorating market or operating conditions could result in a future change to the discounted cash flow models and cause impairments in the future. We continue to monitor potential impairment indicators to determine if a triggering event occurs and will perform additional goodwill impairment analyses as necessary. Other Intangible Assets A summary of amortized intangible assets is as follows: December 31, 2017 December 31, 2016 (in thousands) Pony Express oil conversion use rights $ 105,973 $ 105,973 Customer contracts 8,064 — Accumulated amortization (16,306 ) (12,451 ) Intangible assets, net $ 97,731 $ 93,522 Amortization of intangible assets was approximately $3.8 million , $3.0 million , and $8.0 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Estimated future amortization for the intangible assets is as follows (in thousands): Year Total 2018 $ 4,581 2019 4,048 2020 3,868 2021 3,868 2022 3,868 Thereafter 77,498 Total $ 97,731 |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 12 Months Ended |
Dec. 31, 2017 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Method Investments | Rockies Express Our investment in Rockies Express is recorded under the equity method of accounting and is reported as "Unconsolidated investments" on our consolidated balance sheets. As of May 6, 2016, the difference between the fair value of our 25% membership interest in Rockies Express of $436.0 million and the book value of the underlying net assets resulted in a negative basis difference of approximately $404.7 million . As discussed in Note 3 – Acquisitions , we acquired an additional 24.99% membership interest in Rockies Express from TD on March 31, 2017. As of March 31, 2017, the negative basis difference carried over from TD from the transfer of the 24.99% Rockies Express membership interest was approximately $386.8 million . The transfer of the 24.99% Rockies Express membership interest between TD and the Partnership is considered a transaction between entities under common control, but does not represent a change in reporting entity. As a result of the common control nature of the transaction, the 24.99% membership interest in Rockies Express was transferred to the Partnership at TD's historical carrying amount, including the remaining unamortized basis difference driven by the difference between the fair value of the investment and the book value of the underlying assets and liabilities on November 13, 2012, the date of acquisition by TD. The basis difference was allocated to property, plant and equipment and long-term debt based on their respective fair values at the date of acquisition. The amount of the basis difference allocated to property, plant and equipment is accreted over 35 years , which equates to the 2.86% composite depreciation rate utilized by Rockies Express to depreciate the underlying property, plant and equipment. The amount allocated to long-term debt is amortized over the remaining life of the various debt facilities. At December 31, 2017 , the basis difference for the membership interests acquired in May 2016 and March 2017 were allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 29,458 2 - 25 years Property, plant and equipment (788,631 ) 35 years Total basis difference $ (759,173 ) During the year ended December 31, 2017 , we recognized equity in earnings associated with our 49.99% membership interest in Rockies Express of $235.6 million , inclusive of the amortization of the negative basis difference, and received distributions from and made contributions to Rockies Express of $304.7 million and $39.3 million , respectively. Deeprock Development As discussed in Note 3 – Acquisitions , on July 20, 2017, we acquired an additional 40% membership interest in Deeprock Development. As a result of the acquisition, TEP consolidated Deeprock Development and effective July 20, 2017 no longer accounts for its investment in Deeprock Development under the equity method of accounting. Summarized Financial Information of Unconsolidated Affiliates Combined summarized financial information for all our unconsolidated affiliates is shown in the tables below. Summarized financial information for Deeprock Development is presented from January 1, 2015 to July 20, 2017, the date TEP acquired a controlling interest in Deeprock Development. Summarized financial information for Rockies Express is presented from the date of the initial acquisition of May 6, 2016 to December 31, 2017. Summarized financial information for BNN Colorado is presented from the date of the acquisition, June 23, 2017 to December 31, 2017. December 31, 2017 December 31, 2016 (in thousands) Current assets $ 122,362 $ 199,958 Noncurrent assets $ 5,974,926 $ 6,148,203 Current liabilities $ 714,037 $ 197,305 Noncurrent liabilities $ 2,049,189 $ 2,656,836 Members' equity $ 3,334,062 $ 3,494,020 Year Ended December 31, 2017 2016 2015 (in thousands) Revenue $ 860,115 $ 440,838 $ 18,646 Operating income $ 480,337 $ 203,801 $ 13,794 Net income to Members $ 465,592 $ 184,314 $ 13,794 |
Risk Management
Risk Management | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management | We enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of crude oil and natural gas include, among others (i) pre-existing or anticipated physical crude oil and natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs. Fair Value of Derivative Contracts The following table summarizes the fair values of our derivative contracts included in the consolidated balance sheets: Balance Sheet December 31, 2017 December 31, 2016 (in thousands) Call option derivative (1) Current assets $ — $ 10,676 Natural gas derivative contracts (2) Current assets $ — $ 291 Crude oil derivative contracts (3) Current liabilities $ 2,368 $ 440 Natural gas derivative contracts (2) Current liabilities $ — $ 116 (1) As discussed below, in conjunction with our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option covering the 6,518,000 common units issued to TD. As of February 1, 2017, no common units remained subject to the call option. (2) As of December 31, 2017 , there were no natural gas derivative contracts outstanding. As of December 31, 2016 , the fair value shown for natural gas derivative contracts was comprised of derivative volumes for short and long natural gas fixed-price swaps totaling 0.3 Bcf and 0.4 Bcf, respectively. (3) As of December 31, 2017 , the fair value shown for crude oil derivative contracts represents the forward sale of 356,000 barrels which will settle throughout the first quarter of 2018. As of December 31, 2016 , the fair value shown for crude oil derivative contracts represents the sale of 125,000 barrels of crude oil which settled throughout 2017. Effect of Derivative Contracts in the Statements of Income The following table summarizes the impact of derivative contracts not designated as hedging contracts for the years ended December 31, 2017 , 2016 and 2015 : Location of Amount of gain (loss) recognized in income on derivatives Year Ended December 31, 2017 2016 2015 (in thousands) Derivatives not designated as hedging contracts: Crude oil derivative contracts Sales of natural gas, NGLs, and crude oil $ 39 $ (40 ) $ — Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ 75 $ 74 $ 427 Call option derivative Unrealized gain (loss) on derivative instrument $ 1,885 $ (1,291 ) $ — Call Option Derivative As part of our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option at an exercise price of $42.50 per common unit covering the 6,518,000 common units issued to TD as a portion of the consideration. In July 2016 and October 2016, we partially exercised the call option covering 3,563,146 and 1,251,760 common units, respectively, for cash payments of $151.4 million and $53.2 million , respectively. On February 1, 2017 , we exercised the remainder of the call option covering an additional 1,703,094 common units for a cash payment of $72.4 million . These common units were deemed canceled upon the exercise of the call option and as of the applicable exercise date were no longer issued and outstanding. Credit Risk We have counterparty credit risk as a result of our use of derivative contracts. Counterparties to our commodity derivatives consist of market participants and major financial institutions. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. The counterparty to our call option derivative was TD. Our derivative contracts are entered into with counterparties through central trading organizations such as futures, options or stock exchanges or counterparties outside of central trading organizations. While we typically enter into derivative transactions with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. As of December 31, 2017 , the fair value of our crude oil derivative contracts were in a liability position, resulting in no credit exposure from TEP's counterparties as of that date. As of December 31, 2017 , we had $3.0 million of cash in margin accounts and outstanding letters of credit in support of our commodity derivative contracts. As of December 31, 2016 , we did not have any outstanding letters of credit or cash in margin accounts in support of our hedging of commodity price risks associated with our commodity derivative contracts. Fair Value Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). OTC commodity derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy. The call option granted by TD was valued using a Black-Scholes option pricing model. Key inputs to the valuation model included the term of the option, risk free rate, the exercise price and current market price, expected volatility and expected distribution yield of the underlying units. The call option valuation was classified within Level 2 of the fair value hierarchy as the value was based on significant observable inputs. Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our consolidated financial statements. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management's best estimate is used. The following table summarizes the fair value measurements of our derivative contracts as of December 31, 2017 and 2016 , based on the fair value hierarchy: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2016: Call option derivative $ 10,676 $ — $ 10,676 $ — Natural gas derivative contracts $ 291 $ — $ 291 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2017: Crude oil derivative contracts $ 2,368 $ — $ 2,368 $ — As of December 31, 2016: Crude oil derivative contracts $ 440 $ — $ 440 $ — Natural gas derivative contracts $ 116 $ — $ 116 $ — |
Long-term Debt
Long-term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long-term Debt | Long-term debt consisted of the following at December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 (in thousands) Revolving credit facility $ 661,000 $ 1,015,000 5.50% senior notes due September 15, 2024 750,000 400,000 5.50% senior notes due January 15, 2028 750,000 — Less: Deferred financing costs, net (1) (17,737 ) (7,019 ) Plus: Unamortized premium on 2028 Notes 3,730 — Total long-term debt, net $ 2,146,993 $ 1,407,981 (1) Deferred financing costs, net as presented above relate solely to the 2024 and 2028 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our consolidated balance sheets. Senior Unsecured Notes due 2028 On September 15, 2017, TEP and Tallgrass Energy Finance Corp. (the "Co-Issuer" and together with TEP, the "Issuers"), the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 15, 2017 (the "2028 Indenture") pursuant to which the Issuers issued $500 million in aggregate principal amount of 5.50% senior notes due 2028 (the "2028 Notes"). On December 11, 2017, the Issuers issued an additional $250 million in aggregate principal amount of the 2028 Notes, which are also governed by the 2028 Indenture. The notes issued on September 15, 2017 and December 11, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date, offering price and first interest payment date. The 2028 Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) create liens to secure indebtedness; (ii) enter into sale-leaseback transactions; and (iii) consolidate with or merge with or into, or sell substantially all TEP’s properties to, another person. As of December 31, 2017 , we are in compliance with the covenants required under the 2028 Notes. Senior Unsecured Notes due 2024 On September 1, 2016, the Issuers, the Guarantors named therein and U.S. Bank, National Association, as trustee, entered into an Indenture dated September 1, 2016 (the "2024 Indenture"), pursuant to which the Issuers issued $400 million in aggregate principal amount of 5.50% senior notes due 2024 (the "2024 Notes"). On May 16, 2017, the Issuers issued an additional $350 million in aggregate principal amount of the 2024 Notes, which are also governed by the 2024 Indenture. The notes issued on September 1, 2016 and May 16, 2017 are treated as a single class of debt securities and have identical terms, other than the issue date, offering price and first interest payment date. The 2024 Indenture contains covenants that, among other things, limit TEP's ability and the ability of its restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests in the event of default or noncompliance with the covenants required, repurchase equity securities or redeem subordinated securities; (iv) make investments; (v) restrict distributions, loans or other asset transfers from TEP's restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of TEP's properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. As of December 31, 2017 , we are in compliance with the covenants required under the 2024 Notes. Revolving Credit Facility On June 2, 2017, TEP entered into a $1.75 billion Second Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as administrative agent and collateral agent, and a syndicate of lenders (the "Amended Credit Agreement"). The Amended Credit Agreement amends and restates TEP's existing revolving credit facility. The Amended Credit Agreement, among other things, extends the maturity date of TEP's existing revolving credit facility from May 13, 2018 to June 2, 2022, and provides for an uncommitted accordion in an amount up to an additional $250 million , subject to the satisfaction of certain other conditions. In addition, the revolving credit facility includes a $60 million sublimit for swing line loans and a $75 million sublimit for letters of credit The following table sets forth the available borrowing capacity under the revolving credit facility as of December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 (in thousands) Total capacity under the revolving credit facility $ 1,750,000 $ 1,750,000 Less: Outstanding borrowings under the revolving credit facility (661,000 ) (1,015,000 ) Less: Letters of credit issued under the revolving credit facility (94 ) — Available capacity under the revolving credit facility $ 1,088,906 $ 735,000 The revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict our ability (as well as the ability of our restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions, including distributions from available cash, if a default or event of default under the credit agreement then exists or would result therefrom, 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 5.00 to 1.00 (which will be increased to 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions), a consolidated senior secured leverage ratio of not more than 3.75 to 1.00 and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of December 31, 2017 , we are in compliance with the covenants required under the revolving credit facility. The unused portion of the revolving credit facility is subject to a commitment fee, which ranges from 0.250% to 0.500% , based on our total leverage ratio. As of December 31, 2017 , the weighted average interest rate on outstanding borrowings under the revolving credit facility was 3.24% . During the year ended December 31, 2017 , our weighted average effective interest rate, including the interest on outstanding borrowings under the revolving credit facility, commitment fees, and amortization of deferred financing costs, was 3.31% . 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, 2017 and 2016 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of December 31, 2017: Revolving credit facility $ — $ 661,000 $ — $ 661,000 $ 661,000 2024 Notes $ — $ 771,645 $ — $ 771,645 $ 739,824 2028 Notes $ — $ 758,168 $ — $ 758,168 $ 746,169 As of December 31, 2016: Revolving credit facility $ — $ 1,015,000 $ — $ 1,015,000 $ 1,015,000 2024 Notes $ — $ 398,000 $ — $ 398,000 $ 392,981 The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of December 31, 2017 and 2016 , the fair value of borrowings under the revolving credit facility approximates the carrying amount of the borrowings using a discounted cash flow analysis. The 2024 and 2028 Notes are carried at amortized cost, net of deferred financing costs. The estimated fair value of the 2024 and 2028 Notes is based upon quoted market prices adjusted for illiquid markets. We are not aware of any factors that would significantly affect the estimated fair value subsequent to December 31, 2017 . |
Partnership Equity and Distribu
Partnership Equity and Distributions | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Partnership Equity and Distributions | Equity Distribution Agreements We have active equity distribution agreements pursuant to which we may sell from time to time through a group of managers, as our sales agents, common units representing limited partner interests having an aggregate offering price of up to $100.2 million and $657.5 million . Net cash proceeds from any sale of the common units may be used for general partnership purposes, which includes, among other things, the Partnership's exercise of the call option with respect to the 6,518,000 common units issued to TD in connection with the Partnership's acquisition of an additional 31.3% of Pony Express in January 2016, repayment or refinancing of debt, funding for acquisitions, capital expenditures and additions to working capital. During the year ended December 31, 2017 , we issued and sold 2,341,061 common units with a weighted average sales price of $48.82 per unit under our equity distribution agreements for net cash proceeds of approximately $112.4 million (net of approximately $1.9 million in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes as described above. During the year ended December 31, 2016 , we issued and sold 7,696,708 common units with a weighted average sales price of $44.46 per unit under our equity distribution agreement for net cash proceeds of approximately $337.7 million (net of approximately $4.5 million in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes as described above. 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 agreements for net cash proceeds of approximately $3.0 million (net of approximately $30,000 in commissions and professional service expenses). We used the net cash proceeds for general partnership purposes as described above. Repurchase of Common Units Owned by TD Following an offer received from TD with respect to common units owned by TD not subject to the call option, we repurchased 736,262 common units from TD at an aggregate price of approximately $35.3 million , or $47.99 per common unit, on February 1, 2017 , which was approved by the conflicts committee of the board of directors of our general partner. These common units were deemed canceled upon our purchase and as of such transaction date were no longer issued and outstanding. Private Placement On April 28, 2016, we issued an aggregate of 2,416,987 common units for net cash proceeds of $90 million in a private placement transaction to certain funds managed by Tortoise Capital Advisors, L.L.C. The units were subsequently registered pursuant to our Form S-3/A (File No. 333-210976) filed with the SEC on May 6, 2016, which became effective May 17, 2016. Tallgrass Development Purchase Program On February 17, 2016, TEP and Tallgrass Energy GP, LP ("TEGP") announced that the Board of Directors of Tallgrass Energy Holdings, LLC, the sole member of TEGP's general partner and the general partner of TD at the time of the announcement had authorized an equity purchase program under which TD could purchase up to an aggregate of $100 million of the outstanding Class A shares of TEGP or the outstanding common units of TEP on the open market or in negotiated purchases. No purchases were made under this program during the years ended December 31, 2017 and 2016 , nor during the period commencing January 1, 2018 and prior to the merger of TD into Tallgrass Development Holdings on February 7, 2018. As a result of such merger, no future purchases are expected to be made under the program. 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 3 - 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 3 - Acquisitions . Distributions to Holders of Common Units, General Partner Units and Incentive Distribution Rights Our partnership agreement requires us to distribute our available cash, as defined in the partnership agreement, to unitholders of record on the applicable record date within 45 days after the end of each quarter. 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 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, 2017 February 14, 2018 (1) $ 70,638 $ 39,125 $ 1,251 $ 111,014 $ 0.9650 September 30, 2017 November 14, 2017 69,174 37,744 1,219 108,137 0.9450 June 30, 2017 August 14, 2017 67,671 36,342 1,186 105,199 0.9250 March 31, 2017 May 15, 2017 60,486 29,840 1,040 91,366 0.8350 December 31, 2016 February 14, 2017 58,793 28,358 1,008 88,159 0.8150 September 30, 2016 November 14, 2016 57,332 26,987 976 85,295 0.7950 June 30, 2016 August 12, 2016 54,442 24,262 911 79,615 0.7550 March 31, 2016 May 13, 2016 48,238 19,816 830 68,884 0.7050 December 31, 2015 February 12, 2016 42,984 15,332 724 59,040 0.6400 September 30, 2015 November 13, 2015 36,347 11,567 660 48,574 0.6000 June 30, 2015 August 14, 2015 35,135 10,418 627 46,180 0.5800 March 31, 2015 May 14, 2015 31,322 6,934 530 38,786 0.5200 (1) The distribution announced on January 8, 2018 for the fourth quarter of 2017 will be paid on February 14, 2018 to unitholders of record at the close of business on January 31, 2018. 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, 2017 , the general partner owns an approximate 1.13% 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 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 the IDRs. If for any quarter: • We have distributed available cash from operating surplus to all 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, 2017 , TEP recognized the following other contributions and distributions: • TEP was deemed to have made a noncash capital distribution of $57.7 million to the general partner, which represents the excess purchase price over the carrying value of the Terminals and NatGas net assets acquired January 1, 2017; • TEP was deemed to have made a noncash capital distribution of $12.6 million to the general partner, which represents the derecognition of a portion of the derivative asset associated with the partial exercise of the call option; • TEP was deemed to have received a noncash capital contribution of $63.7 million from the general partner, which represents the excess carrying value of the additional 24.99% membership interest in Rockies Express acquired March 31, 2017 over the fair value of the consideration paid; • TEP received contributions from TD of $2.3 million primarily to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed in Note 17 – Legal and Environmental Matters ; and • TEP recognized contributions from and distributions to noncontrolling interests of $1.6 million , and $6.2 million , respectively, which primarily consisted of activity associated with TD's 2% noncontrolling interest in Pony Express. During the year ended December 31, 2016 , TEP recognized the following other contributions and distributions: • TEP was deemed to have made noncash capital distributions of $280.0 million and $34.0 million to the general partner, which represent the excess purchase price over the carrying value of the additional 31.3% membership interest in Pony Express acquired effective January 1, 2016 and the derecognition of a portion of the derivative asset associated with the partial exercise of the call option, respectively; • TEP received contributions of $17.9 million from TD to indemnify TEP for costs associated with Trailblazer's Pipeline Integrity Management Program, as discussed above; and • TEP recognized contributions from and distributions to noncontrolling interests of $9.3 million and $6.5 million , respectively, which primarily consisted of activity associated with TD's 2% noncontrolling interest in Pony Express. During the year ended December 31, 2015 , TEP recognized the following other contributions and distributions: • 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; and • TEP 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. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies Disclosure | Leases Rent expense under operating leases and right of way agreements totaled approximately $9.5 million , $16.5 million , and $16.1 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. At December 31, 2017 , future minimum rental commitments under major, non-cancelable operating leases were as follows (in thousands): Year Total 2018 $ 1,226 2019 1,351 2020 1,414 2021 1,093 2022 828 Thereafter 4,394 Total $ 10,306 Operating leases consist of leases for office space and equipment. Prior to the acquisition of a controlling interest in Deeprock Development in July 2017, as discussed in as discussed in Note 3 - Acquisitions , rent expense included payments made by Pony Express to Deeprock Development for the use by Pony Express of storage capacity at the Deeprock tank storage facility near Cushing, Oklahoma. Capital Expenditures We had committed approximately $17.3 million for the future purchase of property, plant and equipment at December 31, 2017 . Other Purchase Obligations Other purchase obligations primarily represent costs associated with Western's freshwater delivery and produced water gathering and disposal systems acquired in December 2015. Actual costs associated with these contracts totaled approximately $2.5 million , $1.4 million , and $4,000 for the years ended December 31, 2017 , 2016 , and 2015 , respectively. At December 31, 2017 , future minimum commitments under long-term, non-cancelable contracts for other purchase obligations were as follows (in thousands): Year Total 2018 $ 2,084 2019 2,091 2020 2,070 2021 20 2022 20 Thereafter 48 Total $ 6,333 |
Net Income per Limited Partner
Net Income per Limited Partner Unit | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Net Income per Limited Partner Unit | The Partnership's net income is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. We compute earnings per unit using the two-class method for Master Limited Partnerships as prescribed in the FASB guidance. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period. We calculate net income available to limited partners based on the distributions pertaining to the current period's net income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement and as further prescribed in the FASB guidance under the two-class method. The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights (which are currently held by our general partner), even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit reflects the potential dilution of common equivalent units that could occur if equity participation units are converted into common units. All net income or loss from Terminals and NatGas prior to our acquisition on January 1, 2017 is allocated to predecessor operations in the consolidated statements of income and in the table below. Historical earnings of transferred businesses for periods prior to the date of those common control transactions are solely those of the general partner, and therefore we have appropriately excluded any allocation to the limited partner units when determining net income available to common unitholders. We present the financial results of any transferred business prior to the transaction date in the line item "Predecessor operations interest in net income" in the consolidated statements of income and in the table below. The following table illustrates the calculation of net income per common unit for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands, except per unit amounts) Net income $ 440,489 $ 274,889 $ 197,171 Net income attributable to noncontrolling interests (6,499 ) (4,365 ) (24,268 ) Net income attributable to partners 433,990 270,524 172,903 Predecessor operations interest in net income — (6,995 ) (12,357 ) General partner interest in net income (147,823 ) (102,465 ) (46,478 ) Net income available to common unitholders $ 286,167 $ 161,064 $ 114,068 Basic net income per common unit $ 3.93 $ 2.26 $ 1.95 Diluted net income per common unit $ 3.90 $ 2.23 $ 1.91 Basic average number of common units outstanding 72,876 71,150 58,597 Equity Participation Unit equivalent units 582 957 978 Diluted average number of common units outstanding 73,458 72,107 59,575 |
Major Customers and Concentrati
Major Customers and Concentration of Credit Risk | 12 Months Ended |
Dec. 31, 2017 | |
Risks and Uncertainties [Abstract] | |
Major Customers and Concentration of Credit Risk | During the year ended December 31, 2017 one non-affiliated customer, Continental Resources, Inc. ("Continental Resources"), accounted for $100.2 million ( 15% ) of our total operating revenue. During the year ended December 31, 2016 two non-affiliated customers, Continental Resources and Shell Trading (US) Company ("Shell"), accounted for $97.8 million ( 16% ) and $76.2 million ( 12% ) of our total operating revenues, respectively. 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 ( 14% ) of our total operating revenues, respectively. Revenues from Continental Resources for the years ended December 31, 2017, 2016, and 2015 were earned in our Crude Oil Transportation segment. Revenues from Shell for the years ended December 31, 2016 and 2015 were earned in our Natural Gas Transportation, Crude Oil Transportation, and Gathering, Processing & Terminalling segments. For the year ended December 31, 2017 , the percentage of segment revenues from the top ten non-affiliated customers for each segment was as follows: Percentage of Segment Revenue Natural Gas Transportation 56% Crude Oil Transportation 91% Gathering, Processing & Terminalling 75% We attempt to mitigate credit risk by seeking credit support, such as letters of credit, prepayments or other financial guarantees from customers with specific credit concerns. In support of credit extended to certain customers, we had received prepayments of $4.9 million at December 31, 2017 and 2016 , included in the caption "Other current liabilities" in the accompanying consolidated balance sheets. |
Equity-Based Compensation
Equity-Based Compensation | 12 Months Ended |
Dec. 31, 2017 | |
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. Vesting and forfeiture requirements are at the discretion of the board of directors of the general partner (the "Board") and can be delegated to a committee of the Board. 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 or a committee thereof, which is referred to as the plan administrator. The Board may generally terminate or amend the LTIP at any time with respect to any units for which a grant has not yet been made. The Board 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 Board or (iii) May 13, 2023. Equity Participation Units The Board has previously approved the grant of up to 1.9 million equity participation units ("EPUs") for issuance to employees and 302,500 EPUs to certain Section 16 officers under the LTIP. 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 $10.4 million , $7.9 million , and $9.3 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. Of the total compensation cost, $8.7 million , $5.8 million , and $5.1 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively, was recognized as compensation expense at TEP and the remainder was allocated to TD. As of December 31, 2017 , $24.6 million of total compensation cost related to non-vested EPUs is expected to be recognized over a weighted average period of 2.7 years , a portion of which was charged to TD. Following the merger of TD into a subsidiary of Tallgrass Equity, such costs will be allocated to Tallgrass Energy Holdings and its affiliates going forward. The following table summarizes the changes in the EPUs outstanding for the years ended December 31, 2017 , 2016 and 2015 : Equity Participation Units Weighted Average Outstanding at January 1, 2015 1,525,750 $ 18.75 Granted 338,591 40.01 Vested (1) (480,555 ) (19.39 ) Forfeited (58,825 ) (16.98 ) Outstanding at December 31, 2015 1,324,961 24.11 Granted 94,750 35.12 Vested (1) (35,998 ) (23.74 ) Forfeited (43,829 ) (20.08 ) Outstanding at December 31, 2016 1,339,884 24.92 Granted 621,400 38.58 Vested (1) (941,858 ) (19.70 ) Forfeited (30,033 ) (39.08 ) Outstanding at December 31, 2017 989,393 $ 38.58 (1) During the years ended December 31, 2017 , 2016 , and 2015 , approximately 683,304 , 24,933 , and 344,383 common units (net of tax withholding of approximately 258,554 , 11,065 , and 136,172 common units) were issued in connection with the settlement of vested awards, respectively. |
Regulatory Matters
Regulatory Matters | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
Regulatory Matters | There are no regulatory proceedings challenging the rates of Pony Express, Rockies Express, Tallgrass Interstate Gas Transmission, LLC ("TIGT") or Trailblazer Pipeline Company LLC ("Trailblazer"). We have made certain regulatory filings with the FERC, including the following: Pony Express On May 25, 2016, Pony Express made a tariff filing with the FERC in Docket No. IS16-326-000 to update its non-contract rates under its Local Pipeline Tariff for local non-contract rates from all origins, by an amount reflecting the most recent FERC annual index adjustment of approximately 0.9799 effective July 1, 2016, which resulted in a reduction of the Pony Express non-contract rates of 2.01% . On May 22, 2017 and May 31, 2017, Pony Express made tariff filings with the FERC in Docket Nos. IS17-263-000, IS17-464-00, and IS17-465-000 to increase the contract and non-contract rates by an amount reflecting the most recent FERC annual index adjustment of approximately 0.2% , which became effective July 1, 2017. On November 30, 2017, Pony Express filed with the FERC in Docket No. IS18-60-000 certain changes to its tariffs to reflect the addition of two new destination points proposed to be effective January 1, 2018. On December 29, 2017, Pony Express filed with the FERC in Docket No. IS18-113-000 certain changes to its tariffs to reflect a new origin point in Rooks County, Kansas. The changes were proposed to become effective on February 1, 2018. Rockies Express Petition for Declaratory Order – FERC Docket No. RP13-969-000 In June 2013, in Docket No. RP13-969-000, Rockies Express filed with the FERC a Petition for Declaratory Order which sought a ruling that the "most favored nations" or "MFN" provisions contained in Rockies Express' negotiated rate agreements ("NRAs") with its Foundation and Anchor Shippers would not prevent Rockies Express from providing firm transportation service at rates lower than Foundation and Anchor Shippers' rates that (1) have an east-to-west primary path; (2) are for a term of one year or longer; and (3) are limited to service in one rate zone and therefore do not utilize all of the same facilities or rate zones as the service provided pursuant to the Foundation and Anchor Shipper NRAs. In November 2013, the FERC issued a declaratory order finding that the potential transactions would not trigger the MFN rights of Rockies Express’ Foundation and Anchor Shippers. Various parties filed requests for rehearing of the FERC’s declaratory order. In September 2014 and December 2015, the FERC accepted amended contracts with the shippers holding MFN rights on Rockies Express, which reflect the terms of settlements between these shippers and Rockies Express. The settlements provide additional clarity with respect to the applicability of the settling shippers' MFN rights, sharing by Rockies Express of certain transportation revenues, and the withdrawal of the settling shippers from the Petition for Declaratory Order proceeding. On September 27, 2017, FERC issued an order denying the requests for rehearing of the declaratory order issued in November 2013, and no party sought judicial appeal of the FERC order denying rehearing within the statutory deadline. 2015 Annual FERC Fuel Tracking Filings - FERC Docket No. RP15-584-000 On February 27, 2015, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2015 in Docket No. RP15-584-000. This filing incorporated the revised fuel and lost and unaccounted-for and power cost tracker mechanisms filed in Docket No. RP14-1003. The FERC issued an order accepting the filing on March 26, 2015 and on April 9, 2015, accepted an errata to the February 27, 2015 filing reflecting a corrected rate for the Cheyenne Booster rate (PCT Reimbursement Charge). Seneca Lateral Facilities Conversion – FERC Docket No. CP15-102-000 On March 2, 2015 in Docket No. CP15-102-000, Rockies Express filed with the FERC an application for (1) authorization to convert certain existing and operating pipeline and compression facilities located in Noble and Monroe Counties, Ohio (Seneca Lateral Facilities described in Docket Nos. CP13-539-000 and CP14-194-000) from Natural Gas Policy Act of 1978 Section 311 authority to NGA Section 7 jurisdiction, and (2) issuance of a certificate of public convenience and necessity authorizing Rockies Express to operate and maintain the Seneca Lateral Facilities. On April 7, 2016, the FERC issued a Certificate to Rockies Express granting its requested authorizations and on June 1, 2016 Rockies Express commenced NGA service on the Seneca Lateral. Rockies Express Zone 3 Capacity Enhancement Project – FERC Docket No. CP15-137-000 On March 31, 2015 in Docket No. CP15-137-000, Rockies Express filed with the FERC an application for authorization to construct and operate (1) three new mainline compressor stations located in Pickaway and Fayette Counties, Ohio and Decatur County, Indiana; (2) additional compressors at an existing compressor station in Muskingum County, Ohio; and (3) certain ancillary facilities. The facilities increased the Rockies Express Zone 3 east-to-west mainline capacity by 0.8 Bcf/d. Pursuant to the FERC's obligations under the National Environmental Policy Act, FERC staff issued an Environmental Assessment for the project on August 31, 2015. On February 25, 2016, the FERC issued a Certificate of Public Convenience and Necessity authorizing Rockies Express to proceed with the project. On March 14, 2016, Rockies Express commenced construction of the project facilities. The project was placed in-service for the full 0.8 Bcf/d on January 6, 2017. 2016 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP16-702 and RP17-240 On March 1, 2016, Rockies Express made its annual fuel tracker filing with a proposed effective date of April 1, 2016 in Docket No. RP16-702. The FERC issued an order accepting the filing on March 25, 2016. On December 1, 2016, Rockies Express made an interim fuel tracker filing with a proposed effective date of January 1, 2017 in Docket No. RP17-240. The FERC issued an order accepting the filing on December 29, 2016. Electric Power Charge Clarification - FERC Docket No. RP17-285 On December 21, 2016, in Docket No. RP17-285, Rockies Express proposed certain revisions to the General Terms and Conditions of its tariff to clarify that the electric power costs associated with the operation of gas coolers installed in association with the Zone 3 Capacity Enhancement Project at both electric and gas powered stations, will be included in the Power Cost Tracker. Several shippers submitted comments on the proposal. The FERC issued an order on January 19, 2017 accepting the proposed revisions permitting the recovery of electric power costs from the operation of both gas and electric powered compressor stations, subject to certain clarifications. 2017 Annual and Interim FERC Fuel Tracking Filings - FERC Docket Nos. RP17-401 and RP17-1064 On February 13, 2017, in Docket No. RP17-401, Rockies Express made its annual fuel and power cost tracker filing with a proposed effective date of April 1, 2017. The FERC issued an order accepting the filing, including certain requested waivers, on March 21, 2017. On September 20, 2017, Rockies Express made its interim fuel tracker filing in Docket No. RP17-1064 with a proposed effective date of November 1, 2017. The FERC issued an order accepting the filing on October 18, 2017. Increased Frequency of FL&U and PCT Adjustments - FERC Docket No. RP18-228 On December 1, 2017, in Docket No. RP18-228, Rockies Express made a filing with the FERC to increase the frequency in which it may adjust fixed fuel and lost and unaccounted for retainages and power cost tracker charges during the year so that its recovery of fixed fuel and lost and unaccounted for charges and power costs more closely track usage. Rockies Express proposed an effective date of April 1, 2018. The comment period ended on December 13, 2017, and no parties opposed Rockies Express’ filing. The matter is pending before the FERC. TIGT General Rate Case Filing - FERC Docket No. RP16-137-000, et seq. On October 30, 2015, in Docket No. RP16-137-000, et seq. , TIGT filed a general rate case with the FERC pursuant to Section 4 of the National Gas Act ("NGA"). The general rate case was ultimately resolved via settlement, which the FERC approved on November 2, 2016, and a compliance filing that modernized TIGT’s FERC Gas Tariff, consistent with prior FERC orders, which the FERC accepted on March 16, 2017. Per the terms of the settlement, TIGT is required to file a new general rate case on May 1, 2019 (provided that such rate case is not pre-empted by a pre-filing settlement). 2017 Annual Fuel Tracker Filing - FERC Docket No. RP17-428-000 On February 27, 2017, in Docket No. RP17-428-000, TIGT made its annual fuel tracker filing with a proposed effective date of April 1, 2017. The filing incorporated the FL&U tracker and power cost tracker mechanisms agreed to in the TIGT Rate Case Settlement. The FERC accepted the filing on March 21, 2017. Electric Power Charge Clarification - FERC Docket No. RP17-1051-000 On September 15, 2017, in Docket No. RP17-1051-000, TIGT proposed certain revisions to its tariff to clarify, amongst other things, that the electric power costs associated with the operation of gas coolers at both electric and gas powered stations are properly included in the Power Cost Tracker. The FERC issued an order on October 3, 2017 accepting the proposed revisions. Trailblazer General Rate Case Filing - FERC Docket No. RP13-1031-000, et. seq. On July 1, 2013, in Docket No. RP13-1031-000, et. seq. , Trailblazer filed a general rate case with the FERC pursuant to Section 4 of the NGA. The general rate case was ultimately resolved via settlement, which the FERC approved on May 29, 2014. Per the terms of the settlement, Trailblazer is required to file a new general rate case with rates to be effective no later than January 1, 2019 (presuming a maximum suspension period for any rate increase). 2016 Annual Fuel Tracker Filing – FERC Docket Nos. RP16-814-000 and RP16-814-001 On April 1, 2016, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2016 in Docket No. RP16-814-000. The FERC accepted this filing on April 18, 2016. On May 19, 2016, Trailblazer filed its refund report associated with the April 1, 2016 annual fuel tracker filing, which the FERC accepted on July 11, 2016. On September 7, 2016, Trailblazer filed an adjustment to its April 1, 2016 filing in Docket No. RP16-814-001, which the FERC accepted on October 3, 2016. Trailblazer filed a corresponding refund report on October 14, 2016, which the FERC accepted on November 16, 2016. 2017 Annual and Interim Fuel Tracker Filings - FERC Docket Nos. RP17-549-000 and RP17-1052-000 On March 22, 2017, in Docket No. RP17-549-000, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2017. The FERC accepted the filing on April 19, 2017. On September 15, 2017, Trailblazer made its interim fuel tracker filing in Docket No. RP17-1052-000 with a proposed effective date of November 1, 2017. The FERC accepted the filing on October 13, 2017. |
Legal and Environmental Matters
Legal and Environmental Matters | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Legal and Environmental Matters | Legal In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on our business, financial position, results of operations, or cash flows. We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, have recorded no reserve for legal claims as of December 31, 2017 and 2016 . Rockies Express Mineral Management Service Lawsuit On June 30, 2009, Rockies Express filed claims against Mineral Management Service, a former unit of the U.S. Department of Interior (collectively "Interior") for breach of its contractual obligation to sign transportation service agreements for pipeline capacity that it had agreed to take on Rockies Express. The Civilian Board of Contract Appeals ("CBCA") conducted a trial and ruled that Interior was liable for breach of contract, but limited the damages Interior was required to pay. On September 13, 2013, the United States Court of Appeals for the Federal Circuit issued a decision affirming that Interior was liable for its breach of contract, but reversing the CBCA's decision to limit damages. The case was remanded to the CBCA for the purpose of calculating damages at a hearing. On May 20, 2016, Rockies Express and Interior agreed to resolve the claims in this matter in exchange for a $65 million cash payment to Rockies Express. Interior paid the amount due Rockies Express on June 23, 2016. Ultra Resources In early 2016, Ultra Resources, Inc. ("Ultra") defaulted on its firm transportation service agreement for approximately 0.2 Bcf/d through November 11, 2019. In late March 2016, Rockies Express terminated Ultra's service agreement. On April 14, 2016, Rockies Express filed a lawsuit against Ultra for breach of contract and damages in Harris County, Texas, seeking approximately $303 million in damages and other relief. On April 29, 2016, Ultra and certain of its debtor affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code in United States Bankruptcy Court for the Southern District of Texas, which operated as a stay of the Harris County state court proceeding. On January 12, 2017, Rockies Express and Ultra entered into an agreement to settle Rockies Express' approximately $303 million claim against Ultra. In accordance with the settlement agreement, Ultra made a cash payment to Rockies Express of $150 million on July 12, 2017, and entered into a new, seven-year firm transportation agreement with Rockies Express commencing December 1, 2019, for west-to-east service of 0.2 Bcf/d at a rate of approximately $0.37 per dth/d, or approximately $26.8 million annually. TEP received its proportionate distribution from the cash settlement payment in July 2017. Michels Corporation On June 17, 2014, Michels Corporation ("Michels") filed a complaint and request for relief against Rockies Express in the Court of Common Pleas, Monroe County, Ohio, as a result of work performed by Michels to construct the Seneca Lateral Pipeline in Ohio. Michels sought unspecified damages from Rockies Express and asserted claims of breach of contract, negligent misrepresentation, unjust enrichment and quantum meruit. Michels also filed notices of Mechanic's Liens in Monroe and Noble Counties, asserting $24.2 million as the amount due. On February 2, 2017, Rockies Express and Michels agreed to resolve Michels' claims for a $10 million cash payment by Rockies Express. The cash payment was inclusive of approximately $5.9 million that Rockies Express had been withholding from Michels. Subsequently, Rockies Express and Michels entered into a definitive agreement with respect to the settlement and Rockies Express made the $10 million cash payment to Michels on February 16, 2017. Environmental, Health and Safety We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of $7.7 million and $4.0 million at December 31, 2017 and 2016 , respectively. TMID Casper Plant, EPA Notice of Violation In August 2011, the EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, Tallgrass Midstream, LLC ("TMID") received a letter from the EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including the expected inclusion of TIGT as a party to any possible settlement as a result of TIGT owning a compressor that is located adjacent to the Casper Gas Plant site. Casper Mystery Bridge Superfund Site The Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed and we have requested that the portion of the site attributable to us be delisted from the National Priorities List. On July 3, 2017, our partial delisting request was published by the EPA in the Federal Register. On August 3, 2017, there were no adverse public comments, therefore on August 29, 2017, the Casper Gas Plant portion of the Casper Mystery Bridge Superfund Site was 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. TMG Archibald Booster Station Tallgrass Midstream Gathering, LLC ("TMG") is currently a party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Archibald Booster Station located in Campbell County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling, and quarterly recovery activities at monitoring wells. The facility is currently in compliance with the WDEQ under the remedy agreement. Irwin Booster Station TMG is also party to a remedy agreement entered into with the WDEQ in July 2013 with respect to the Irwin Booster Station located in Converse County, Wyoming. In connection with the remedy agreement, TMG has agreed to complete certain remedial actions at the site related to a former earthen pit including semi-annual groundwater sampling. The facility is currently in compliance with the WDEQ under the remedy agreement. Trailblazer Pipeline Integrity Management Program Starting in 2014 Trailblazer’s operating capacity was decreased as a result of smart tool surveys that identified approximately 25 - 35 miles of pipe as potentially requiring repair or replacement. During 2016 and 2017, Trailblazer incurred approximately $21.8 million of remediation costs to address this issue, including replacing approximately 8 miles of pipe. To date the pressure and capacity reduction has not prevented Trailblazer from fulfilling its firm service obligations at existing subscription levels or had a material adverse financial impact on us. However, Trailblazer intends to continue performing remediation to increase and maximize its operating capacity over the long-term and expects to spend in excess of $20 million during 2018 for this pipe replacement and remediation work. Trailblazer is exploring all possible cost recovery options to recover expenditures, including recovery through a general rate increase, negotiated rate agreements with its customers, or other FERC-approved recovery mechanisms. In connection with our acquisition of Trailblazer in April 2014, TD agreed to indemnify TEP for certain out of pocket costs related to repairing or remediating the Trailblazer Pipeline. The contractual indemnity was capped at $20 million and subject to a $1.5 million deductible. TEP has received the entirety of the $20 million from TD pursuant to the contractual indemnity as of December 31, 2017. Pony Express Pipeline Integrity In connection with certain crack tool runs on the Pony Express System completed in 2015 and 2016, Pony Express completed approximately $10 million of remediation for anomalies identified on the Pony Express System associated with the initial conversion and commissioning of portions of the pipeline converted from natural gas to crude oil service, and has completed additional remediation on the Pony Express System of approximately $8.2 million during the year ended December 31, 2017 . Terminals System Failures In January 2017, approximately 10,000 bbls of crude oil were released at the Sterling Terminal as the result of a defective roof drain system on a storage tank. The release was restricted to the containment area designed for such purpose and approximately 9,000 bbls were recovered. Remediation was complete as of June 30, 2017. The total cost to remediate the release was approximately $600,000 . |
Reporting Segments
Reporting Segments | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Reporting Segments | Our operations are located in the United States. During the third quarter of 2017, management revised the operational reporting used by the chief operating decision maker in light of recent acquisitions and commercial management reorganization. As a result of this internal change, our reportable segments were updated to ensure that segment classification remains aligned with operational reporting. We are organized into three reportable segments: (1) Natural Gas Transportation, (2) Crude Oil Transportation, and (3) Gathering, Processing & Terminalling. Natural Gas Transportation The Natural Gas Transportation segment is engaged in the ownership and operation of FERC-regulated interstate natural gas pipelines and an integrated natural gas storage facility that provides services to on-system customers (such as third-party LDCs), industrial users and other shippers. The Natural Gas Transportation segment includes our 100% membership interest in NatGas acquired effective January 1, 2017 and our 49.99% membership interest in Rockies Express, including the additional 24.99% membership interest acquired effective March 31, 2017 . Crude Oil Transportation The Crude Oil Transportation segment is engaged in the ownership and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale, Denver-Julesburg and Powder River Basins, and other nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado and was placed in service in the second quarter of 2015. Gathering, Processing & Terminalling The Gathering, Processing & Terminalling segment is engaged in the ownership and operation of natural gas gathering and processing facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets, including the Douglas Gathering System acquired on June 5, 2017, as well as water business services provided primarily to the oil and gas exploration and production industry and the transportation of NGLs. The Gathering, Processing & Terminalling segment also includes Stanchion as well as our 100% membership interest in Terminals acquired effective January 1, 2017 and the PRB Crude System acquired on August 3, 2017. Corporate and Other Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with our revolving credit facility and the 2024 and 2028 Notes, public company costs, and equity-based compensation expense. These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for their respective operations. We consider Adjusted EBITDA our primary segment performance measure as we believe it is the most meaningful measure to assess our financial condition and results of operations as a public entity. We define Adjusted EBITDA, a non-GAAP measure, as net income excluding the impact of interest, income taxes, depreciation and amortization, non-cash income or loss related to derivative instruments, non-cash long-term compensation expense, impairment losses, gains or losses on asset or business disposals or acquisitions, gains or losses on the repurchase, redemption or early retirement of debt, and earnings from unconsolidated investments, but including the impact of distributions from unconsolidated investments. The following tables set forth our segment information for the periods indicated: Year Ended December 31, 2017 2016 2015 Revenue: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 141,021 $ (6,694 ) $ 134,327 $ 135,097 $ (5,641 ) $ 129,456 $ 137,988 $ (5,384 ) $ 132,604 Crude Oil Transportation 364,574 (10,676 ) 353,898 380,503 (370 ) 380,133 304,227 — 304,227 Gathering, Processing & Terminalling 186,211 (18,538 ) 167,673 113,533 (11,460 ) 102,073 113,387 (7,557 ) 105,830 Corporate and Other — — — — — — — — — Total revenue $ 691,806 $ (35,908 ) $ 655,898 $ 629,133 $ (17,471 ) $ 611,662 $ 555,602 $ (12,941 ) $ 542,661 Year Ended December 31, 2017 2016 2015 Adjusted EBITDA: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 392,394 $ (7,709 ) $ 384,685 $ 154,850 $ (5,641 ) $ 149,209 $ 73,699 $ (5,384 ) $ 68,315 Crude Oil Transportation 243,106 17,263 260,369 264,391 16,843 281,234 165,204 12,941 178,145 Gathering, Processing & Terminalling 50,970 (9,554 ) 41,416 17,928 (11,202 ) 6,726 32,243 (7,557 ) 24,686 Corporate and Other (8,463 ) — (8,463 ) (4,622 ) — (4,622 ) (2,979 ) — (2,979 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investments 237,110 54,531 2,759 Gain on remeasurement of unconsolidated investment 9,728 — — Non-cash loss allocated to noncontrolling interest — — 9,377 Less: Interest expense, net of noncontrolling interest (83,542 ) (40,688 ) (15,517 ) Depreciation and amortization expense, net of noncontrolling interest (92,455 ) (88,122 ) (77,111 ) Distributions from unconsolidated investments (306,626 ) (78,568 ) (4,648 ) Non-cash loss related to derivative instruments, net of noncontrolling interests (226 ) (1,547 ) — Non-cash compensation expense (8,660 ) (5,780 ) (5,103 ) Gain (loss) on disposal of assets, net of noncontrolling interests 654 (1,849 ) (4,795 ) Loss on extinguishment of debt — — (226 ) Net income attributable to partners $ 433,990 $ 270,524 $ 172,903 Year Ended December 31, Capital Expenditures: 2017 2016 2015 (in thousands) Natural Gas Transportation $ 16,705 $ 28,475 $ 10,478 Crude Oil Transportation 57,022 29,893 38,802 Gathering, Processing & Terminalling 71,417 26,123 71,438 Corporate and Other — — — Total capital expenditures $ 145,144 $ 84,491 $ 120,718 Unconsolidated Investments: December 31, 2017 December 31, 2016 (in thousands) Natural Gas Transportation $ 895,873 $ 461,915 Crude Oil Transportation — — Gathering, Processing & Terminalling 13,658 13,710 Corporate and Other — — Total unconsolidated investments $ 909,531 $ 475,625 Assets: December 31, 2017 December 31, 2016 (in thousands) Natural Gas Transportation $ 1,606,666 $ 1,176,147 Crude Oil Transportation 1,407,758 1,410,695 Gathering, Processing & Terminalling 943,340 495,170 Corporate and Other 19,589 20,201 Total assets $ 3,977,353 $ 3,102,213 |
Selected Quarterly Financial Da
Selected Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Selected Quarterly Financial Data (Unaudited) [Abstract] | |
Quarterly Financial Information | The following tables summarize our unaudited quarterly financial data for 2017 and 2016 : Quarter Ended 2017 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 144,400 $ 160,863 $ 175,869 $ 174,766 Operating income $ 63,780 $ 67,504 $ 74,567 $ 68,236 Net income $ 71,784 $ 90,829 $ 185,503 $ 92,373 Net income attributable to partners $ 70,905 $ 89,880 $ 184,090 $ 89,115 Net income available to common unitholders $ 40,322 $ 52,579 $ 144,281 $ 48,985 Basic net income per limited partner unit $ 0.56 $ 0.72 $ 1.97 $ 0.67 Diluted net income per limited partner unit $ 0.55 $ 0.72 $ 1.96 $ 0.67 During the third quarter of 2017, we recognized equity in earnings relating to our proportionate share of the Ultra settlement discussed in Note 17 – Legal and Environmental Matters . Quarter Ended 2016 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 147,168 $ 149,015 $ 153,268 $ 162,211 Operating income $ 63,966 $ 55,307 $ 67,511 $ 73,830 Net income $ 48,796 $ 89,270 $ 65,429 $ 71,394 Net income attributable to partners $ 47,755 $ 88,160 $ 64,345 $ 70,264 Net income available to common unitholders $ 23,717 $ 66,728 $ 33,060 $ 37,559 Basic net income per limited partner unit $ 0.35 $ 0.93 $ 0.45 $ 0.52 Diluted net income per limited partner unit $ 0.35 $ 0.92 $ 0.45 $ 0.51 |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events | Deeprock North Acquisition and Merger with Deeprock Development On January 2, 2018, Terminals acquired an approximate 38% membership interest in Deeprock North, LLC ("Deeprock North") from Kinder Morgan Deeprock North Holdco LLC for cash consideration of $19.5 million . Immediately following the acquisition, Deeprock North was merged into Deeprock Development. After the acquisition and merger, Terminals owns an approximately 60% membership interest in the combined entity. BNN North Dakota Acquisition In January 2018, Water Solutions closed the acquisition of a 100% membership interest in Buckhorn Energy Services, LLC and Buckhorn SWD Solutions, LLC (collectively, "BNN North Dakota") for cash consideration of approximately $95.0 million , subject to working capital adjustments. BNN North Dakota owns a produced water gathering and disposal system in the Bakken basin with approximately 133,000 acres under dedication. Potential Acquisition of Pawnee Terminal On January 2, 2018, Terminals entered into an agreement to acquire a 51% membership interest in the Pawnee, Colorado crude oil terminal (“Pawnee Terminal”) from Zenith Energy Terminals Holdings, LLC for cash consideration of approximately $31 million , subject to working capital adjustments. Terminals expects the transaction to close in the first quarter of 2018, subject to certain closing conditions. Acquisition of Additional Interest in Pony Express Effective February 1, 2018, we acquired the remaining 2% membership interest in Pony Express, along with administrative assets consisting primarily of information technology assets, from Tallgrass Development for cash consideration of approximately $60 million , bringing our aggregate membership interest in Pony Express to 100% . Potential Joint Venture and Sale of TCG On February 6, 2018, we entered into an agreement with an affiliate of Silver Creek Midstream, LLC ("Silver Creek") to form Iron Horse Pipeline, a new joint venture pipeline to transport crude oil from the Powder River Basin. In addition to forming the joint venture, we also agreed to sell to Silver Creek our 100% membership interest in TCG, which owns a 50 -mile crude oil gathering system in the Powder River Basin. We expect to close the sale of TCG and the formation of the joint venture in February 2018. Seneca Lateral On January 31, 2018, Rockies Express experienced an operational disruption on its Seneca Lateral due to a pipe rupture and natural gas release in a rural area in Noble County, Ohio. There were no injuries reported and no evacuations, however, the release required Rockies Express to shut off the flow through the segment. Repairs are underway to return the segment to service as soon as possible and a root cause investigation is ongoing. |
Summary of Significant Accoun27
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying consolidated financial statements and related notes were prepared in conformity with accounting principles generally accepted in the United States of America ("GAAP"). 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. |
Consolidation | As further discussed in Note 3 – Acquisitions , TEP closed the acquisition of Terminals and NatGas effective January 1, 2017. As the acquisitions of Terminals and NatGas are considered transactions between entities under common control, and a change in reporting entity, the financial information presented has been recast to include Terminals and NatGas for all periods presented. Net equity contributions of the Predecessor Entities included in the consolidated financial statements represent transfers of cash as a result of TD's centralized cash management system prior to January 1, 2017 for Terminals and NatGas, under which cash balances were swept daily and recorded as loans from the subsidiaries of TD. These loans were then periodically recorded as equity distributions. The accompanying consolidated financial statements of TEP include historical cost-basis accounts of the assets of Terminals and NatGas for the periods prior to January 1, 2017, the date TEP acquired Terminals and NatGas from TD, and include charges from TD for direct costs and allocations of indirect corporate overhead. Management believes that the allocation methods are reasonable, and that the allocations are representative of costs that would have been incurred on a stand-alone basis. TEP and the Predecessor Entities are all considered "entities under common control" as defined under GAAP and, as such, the transfers between the entities of the assets and liabilities have been recorded by TEP at historical cost. 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. Prior to January 1, 2016, Pony Express participated in a cash management agreement with TD, which currently holds a 2.0% common membership interest in Pony Express, under which cash balances were swept periodically and recorded as loans from Pony Express to TD. Effective January 1, 2016, Pony Express entered into a cash management agreement with TEP. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEP is attributed to TEP and noncontrolling interests. This is done in accordance with substantive profit sharing arrangements, which generally follow the allocation of cash distributions and may not follow the respective ownership percentages held by TEP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Pony Express effective September 1, 2014, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million through the quarter ended September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ended December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 are attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests. A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity's economic performance. Pony Express was considered to be a VIE under the applicable authoritative guidance prior to our acquisition of an additional 31.3% membership interest effective January 1, 2016. Effective January 1, 2016, Pony Express is no longer considered to be a VIE. We continue to consolidate our membership interest in Pony Express. |
Use of Estimates | Use of Estimates Certain amounts included in or affecting these 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. Net equity contributions 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 January 1, 2017 for Terminals and NatGas, 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. |
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 $0.5 million and $0.6 million at December 31, 2017 and 2016 , 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 and net realizable value 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 and net realizable value 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 $2.6 million and $2.9 million included in "Prepayments and other current assets" and "Deferred charges and other assets" in the consolidated balance sheets at December 31, 2017 and 2016 , respectively. Regulatory assets at December 31, 2017 and December 31, 2016 were primarily attributable to costs associated with both TIGT's 2015 Rate Case Filing and Trailblazer's 2013 Rate Case Filing as well as fuel tracker assets at our regulated natural gas pipelines . We recorded regulatory liabilities of approximately $2.3 million and $1.7 million included in "Other current liabilities" in the consolidated balance sheets at December 31, 2017 and 2016 , respectively, related to fuel tracker liabilities at our regulated natural gas pipelines. For further information regarding our rate case filings and fuel tracker balances, see 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 and/or the negative salvage liability discussed under "Depreciation and Amortization" below, as appropriate, 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 establish identifiable intangible assets when they meet either the separability criterion or the contractual-legal criterion. 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. Other intangible assets include customer contracts amortized on a straight-line basis over a period of 2 to 8 years , based on the remaining term of the contracts at the time of acquisition. |
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 asset 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 or asset group to its carrying amount. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the asset or asset group 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 and net realizable value. |
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 depreciation rates for our regulated natural gas pipeline assets include two components, one based on economic service life (capital recovery) and one based on net costs of removal (negative salvage). The accumulated liability related to negative salvage is classified as "Other long-term liabilities and deferred credits" in our consolidated balance sheets. 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 - 5.0% Gathering & processing assets 2.2 - 5.0% Water business assets 2.3 - 20.0% Terminal assets 1.8 - 2.8% Replacement Gas Facilities (1) 10.0% General & other 2.5 - 25.0% (1) Represents costs incurred by TIGT, and reimbursed by Pony Express, for the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System after having sold approximately 433 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013. |
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. Deferred financing costs associated with long-term debt are presented as a reduction to the corresponding debt in our consolidated balance sheets. Deferred financing costs associated with our revolving credit facility are presented as noncurrent assets in our consolidated balance sheets. |
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 fair value over carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31. We evaluate goodwill for impairment at the reporting unit level, which is the same as, or one level below, an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or proceeding directly to the quantitative impairment test 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, then goodwill is not considered impaired. When goodwill is evaluated for impairment using the quantitative impairment test, the carrying amount of the reporting unit is compared to its fair value. If the fair value exceeds the carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the reporting unit's fair value, then the reporting unit should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. See Note 7 – Goodwill and Other Intangible Assets for additional information regarding impairment testing performed during 2017. |
Investment in Unconsolidated Affiliates | Investment in Unconsolidated Affiliates We use the equity method to account for investments in 20% or greater 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. See Note 8 – Investments in Unconsolidated Affiliates for additional information regarding our investment in unconsolidated affiliates. |
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 transportation and storage services and crude oil transportation services to our customers in which the commodity remains the property of these customers at all times. Natural gas transportation and storage services occur in the Natural Gas Transportation 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. Crude oil transportation services occur in the Crude Oil Transportation 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 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 liquids sales occur in the Gathering, Processing & Terminalling 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 Gathering, Processing & Terminalling segment. Natural gas sales occur in both the Natural Gas Transportation segment and in the Gathering, Processing & Terminalling segment. In the Natural Gas Transportation 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. As of the date of the TIGT rate case settlement in 2016, all of our regulated gas pipelines operate under fuel tracker mechanisms, as discussed under "Accounting for Regulatory Activities" above, and as a result our regulated gas pipelines no longer recognize revenue associated with volumes retained from the customer. 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 Gathering, Processing & Terminalling 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 crude oil and 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 TEP is comprised primarily of limited liability companies that are considered flow-through entities (partnerships or disregarded entities) for income tax purposes. 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. In addition, during the year ended December 31, 2015, we formed Tallgrass Energy Finance Corp., a wholly owned subsidiary that has no material assets and was formed for the sole purpose of being a co-issuer of our senior notes as discussed in Note 10 – Long-term Debt . On September 29, 2017, TEP, through its membership interest in TIGT, formed a new C corporation, Cheyenne Connector Pipeline, Inc. ("Cheyenne Connector"), for the purpose of the construction of a pipeline lateral in Northeast Colorado that would interconnect with Rockies Express Pipeline's Cheyenne Hub. Cheyenne Connector has not yet commenced operations or generated any income. Accordingly, no provision for federal or state income taxes has been recorded in our consolidated financial statements. |
Business Combinations | Business Combinations We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill or gain from a bargain purchase. For material acquisitions, management typically engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, noncontrolling interest, if any, and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, we will record any material adjustments to the initial estimate based on new information obtained about facts and circumstances that existed as of the acquisition date. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired, liabilities assumed, and noncontrolling interest, if any, in a business combination. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, which rely on management’s estimates of volumes, commodity prices, revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. See Note 3 – Acquisitions for additional information regarding our business combinations. |
Accounting Pronouncements Issued But Not Yet Effective | Accounting Pronouncements Recently Adopted ASU No. 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" In January 2017, the FASB issued Accounting Standards Update ("ASU") No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. The ASU also narrows the definition of the term "output" so that the term is consistent with how outputs are described under the revenue recognition guidance in Topic 606. The amendments in ASU 2017-01 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2017. Early adoption is permitted in certain circumstances. We elected to adopt the guidance in ASU 2017-01 effective April 1, 2017. As a result of the early adoption of ASU 2017-01, our acquisition of the Douglas Gathering System, as discussed in Note 3 – Acquisitions , was accounted for as an asset acquisition. ASU No. 2017-04, "Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment" In January 2017, the FASB issued ASU No. 2017-04, which simplifies the subsequent measurement of goodwill by eliminating "Step 2" from the goodwill impairment test, which involved calculating the implied fair value of goodwill by determining the fair value at the impairment testing date of a reporting unit's assets and liabilities. Instead, under the simplified test approach, an entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The amendments in ASU 2017-04 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We elected to adopt the guidance in ASU 2017-04 effective April 1, 2017, and as a result applied the new guidance to our annual goodwill impairment tests performed as of August 31, 2017. ASU No. 2016-09, "Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting" In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Among other changes, ASU 2016-09 allows an entity to make an entity-wide accounting policy election to either estimate the number of awards expected to vest (consistent with current GAAP) or account for forfeitures when they occur. The amendments in ASU 2016-09 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We adopted the guidance in ASU 2016-09 effective January 1, 2017 and made a policy election to account for forfeitures when they occur. The adoption of ASU 2016-09 did not have a material impact on our consolidated financial statements. Accounting Pronouncements Not Yet Adopted Revenue Recognition In May 2014, the FASB issued 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. Subsequent to issuing ASU 2014-09, the FASB has issued a series of subsequent updates to the revenue recognition guidance in Topic 606, including ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, and ASU No. 2017-13, Revenue Recognition (Topic 605), Revenue from Contracts with Customers (Topic 606), Leases (Topic 840), and Leases (Topic 842): Amendments to SEC Paragraphs Pursuant to the Staff Announcement at the July 20, 2017 EITF Meeting and Rescission of Prior SEC Staff Announcements and Observer Comments. The amendments in ASU 2014-09, ASU 2016-08, ASU 2016-10, ASU 2016-12, ASU 2016-20, and ASU 2017-13 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Management has completed its evaluation and implemented the revised guidance using the modified retrospective method as of January 1, 2018. This approach allows us to apply the new standard to (i) all new contracts entered into after January 1, 2018 and (ii) all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of January 1, 2018 through a cumulative adjustment to members' equity. Consolidated revenues presented in the comparative consolidated financial statements for periods prior to January 1, 2018 will not be revised. On January 1, 2018, we recorded a cumulative effect adjustment to equity of $44.1 million , increased the carrying amount of our investment in Rockies Express by $42.8 million , and recognized a receivable from Rockies Express of $1.3 million . These adjustments relate to the cumulative effect adjustment recorded by Rockies Express of $125.2 million upon adoption of ASC 606. The cumulative effect adjustment at Rockies Express arose as a result of the allocation of the transaction price to a series of individual performance obligations in certain long-term transportation contracts with tiered-pricing arrangements. The adjustment increases the carrying amount of our investment in Rockies Express to reflect increased equity in earnings and establishes a receivable for the increased management fee revenue that would have been earned by NatGas during the periods prior to implementation. Through our review process, we also identified the following changes to our revenue recognition policies that did not result in a cumulative effect adjustment on January 1, 2018: • Gathering & Processing. We have determined that a number of our gathering & processing contracts at TMID do not represent customer arrangements under ASC 606. Instead, arrangements deemed to represent wellhead purchases of raw gas will be accounted for as supply arrangements pursuant to ASC 705. As a result, gathering & processing fees previously recognized in revenue will be reported as a reduction to cost of sales under ASC 606. • Pipeline Loss Allowance. We have determined that pipeline loss allowance, or PLA, collected under certain crude oil transportation arrangements is a component of the transaction price where the PLA both significantly exceeds actual losses and was negotiated with the intent of providing a revenue stream to TEP. Under ASC 606, PLA barrels retained from customers will be subject to the guidance for noncash consideration and recognized in revenue at their contract inception fair value. We anticipate significant changes to our disclosures based on the additional requirements prescribed by the standard. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is (or will be) recognized and data related to contract assets and liabilities. Additionally, we are continuing to provide internal training and awareness related to the revised guidance to key stakeholders throughout our organization and evaluate our business processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirements under the new revenue guidance. ASU No. 2016-02, "Leases (Topic 842)" In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). ASU 2016-02 provides a comprehensive update to the lease accounting topic in the Codification intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The amendments in ASU 2016-02 include a revised definition of a lease as well as certain scope exceptions. The changes primarily impact lessee accounting, while lessor accounting is largely unchanged from previous GAAP. Management is currently evaluating the impact of our pending adoption of ASC 842. The status of our implementation is as follows: • Management has formed an implementation team that meets to discuss implementation challenges, technical interpretations, industry-specific treatment of certain contract types, and project status. • Management is in the process of gathering data and reviewing contracts in order to identify all impacted contracts. • Management is evaluating the potential information technology and internal control changes that will be required for adoption based on the findings from its contract review process. • Management plans to provide internal training and awareness related to the revised guidance to the key stakeholders throughout its organization. The amendments in ASU 2016-02 are effective for public entities for annual reporting periods beginning after December 15, 2018, and for interim periods within that reporting period. Early application is permitted. We are currently evaluating the impact of ASU 2016-02. |
Description of Business - Sched
Description of Business - Schedule of Other Ownership Interests (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Schedule of Other Ownership Interests [Abstract] | |
Schedule of Other Ownership Interests | The table below summarizes our equity ownership as of December 31, 2017 : Unit holder Limited Partner Common Units General Partner Units Percentage of Outstanding Limited Partner Common Units Percentage of Outstanding Common and General Partner Units Public Unitholders 47,580,535 — 65.00 % 64.27 % Tallgrass Equity, LLC 20,000,000 — 27.32 % 27.01 % Tallgrass Development, LP (1) 5,619,218 — 7.68 % 7.59 % Tallgrass MLP GP, LLC (2) — 834,391 — % 1.13 % Total 73,199,753 834,391 100.00 % 100.00 % (1) Effective February 7, 2018, Tallgrass Equity, LLC ("Tallgrass Equity") acquired the 5,619,218 common units held by TD in connection with the merger of TD into Tallgrass Development Holdings, LLC, a wholly-owned subsidiary of Tallgrass Equity ("Tallgrass Development Holdings"). (2) Tallgrass MLP GP, LLC (the "general partner") also holds all of TEP's incentive distribution rights. |
Summary of Significant Accoun29
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Schedule Of Estimated Useful Life | 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 - 5.0% Gathering & processing assets 2.2 - 5.0% Water business assets 2.3 - 20.0% Terminal assets 1.8 - 2.8% Replacement Gas Facilities (1) 10.0% General & other 2.5 - 25.0% (1) Represents costs incurred by TIGT, and reimbursed by Pony Express, for the construction of certain gas facilities necessary to maintain existing natural gas service on the TIGT System after having sold approximately 433 miles of natural gas pipeline, and associated rights of way and certain other equipment, to Pony Express in 2013. |
Acquisitions - Business Combina
Acquisitions - Business Combinations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Business Acquisition [Line Items] | |
Business Acquisition, Pro Forma Information [Table Text Block] | Unaudited pro forma revenue and net income attributable to TEP for the years ended December 31, 2017 and 2016 is presented below as if the acquisitions of TCG and Deeprock Development had been completed on January 1, 2016. Unaudited pro forma revenue and net income attributable to TEP for the year ended December 31, 2015 is presented below as if the acquisition of Western had been completed on January 1, 2015. Year Ended December 31, 2017 2016 2015 (in thousands) Revenue $ 667,391 $ 632,528 $ 544,497 Net income attributable to partners $ 427,522 $ 275,506 $ 173,542 |
Impact of Adjustments Related to Transaction Among Entities Under Common Control, Balance Sheet [Table Text Block] | The results of our acquisitions of Terminals and NatGas are included in the consolidated balance sheets as of December 31, 2017 and December 31, 2016 . The following table presents our previously reported December 31, 2016 consolidated balance sheet, adjusted for the acquisitions of Terminals and NatGas: December 31, 2016 TEP (As previously reported) Consolidate Terminals Consolidate NatGas TEP (As currently reported) (in thousands) ASSETS Current Assets: Cash and cash equivalents $ 1,873 $ — $ — $ 1,873 Accounts receivable, net 59,469 38 29 59,536 Gas imbalances 1,597 — — 1,597 Inventories 12,805 288 — 13,093 Derivative assets 10,967 — — 10,967 Prepayments and other current assets 6,820 808 — 7,628 Total Current Assets 93,531 1,134 29 94,694 Property, plant and equipment, net 2,012,263 66,969 — 2,079,232 Goodwill 343,288 — — 343,288 Intangible assets, net 93,522 — — 93,522 Unconsolidated investments 461,915 13,710 — 475,625 Deferred financing costs, net 4,815 — — 4,815 Deferred charges and other assets 9,637 1,400 — 11,037 Total Assets $ 3,018,971 $ 83,213 $ 29 $ 3,102,213 LIABILITIES AND EQUITY Current Liabilities: Accounts payable $ 24,076 $ 46 $ — $ 24,122 Accounts payable to related parties 5,879 56 — 5,935 Gas imbalances 1,239 — — 1,239 Derivative liabilities 556 — — 556 Accrued taxes 16,328 668 — 16,996 Accrued liabilities 16,525 177 — 16,702 Deferred revenue 60,757 — — 60,757 Other current liabilities 6,446 — — 6,446 Total Current Liabilities 131,806 947 — 132,753 Long-term debt, net 1,407,981 — — 1,407,981 Other long-term liabilities and deferred credits 7,063 — — 7,063 Total Long-term Liabilities 1,415,044 — — 1,415,044 Equity: Net Equity 1,472,121 82,266 29 1,554,416 Total Equity 1,472,121 82,266 29 1,554,416 Total Liabilities and Equity $ 3,018,971 $ 83,213 $ 29 $ 3,102,213 |
Impact of Adjustments Related to Transaction Among Entities Under Common Control, Income Statement [Table Text Block] | The results of our acquisitions of Terminals and NatGas are included in the consolidated statements of income for the years ended December 31, 2017 , 2016 , and 2015 . The following tables present the previously reported consolidated statements of income for the years ended December 31, 2016 and 2015 , adjusted for the acquisitions of Terminals and NatGas: Year Ended December 31, 2016 TEP (As previously reported) Consolidate Terminals Consolidate NatGas Elimination TEP (As currently reported) (in thousands) Revenues: Crude oil transportation services $ 374,949 $ — $ — $ — $ 374,949 Natural gas transportation services 119,962 — — — 119,962 Sales of natural gas, NGLs, and crude oil 77,394 99 — (370 ) (1) 77,123 Processing and other revenues 32,817 12,043 6,228 (11,460 ) (2) 39,628 Total Revenues 605,122 12,142 6,228 (11,830 ) 611,662 Operating Costs and Expenses: Cost of sales 71,920 100 — (370 ) (1) 71,650 Cost of transportation services 58,341 788 — (11,460 ) (2) 47,669 Operations and maintenance 53,386 1,684 — — 55,070 Depreciation and amortization 84,896 1,351 — — 86,247 General and administrative 53,633 1,469 — — 55,102 Taxes, other than income taxes 24,727 673 — — 25,400 Contract termination — 8,061 (3) — — 8,061 Loss on disposal of assets 1,849 — — — 1,849 Total Operating Costs and Expenses 348,752 14,126 — (11,830 ) 351,048 Operating Income (Expense) 256,370 (1,984 ) 6,228 — 260,614 Other Income (Expense): Interest expense, net (40,688 ) — — — (40,688 ) Unrealized loss on derivative instrument (1,291 ) — — — (1,291 ) Equity in earnings of unconsolidated investments 51,780 2,751 — — 54,531 Other income, net 1,723 — — — 1,723 Total Other Income 11,524 2,751 — — 14,275 Net income 267,894 767 6,228 — 274,889 Net income attributable to noncontrolling interests (4,365 ) — — — (4,365 ) Net income attributable to partners $ 263,529 $ 767 $ 6,228 $ — $ 270,524 Year Ended December 31, 2015 TEP (As previously reported) Consolidate Terminals Consolidate NatGas Elimination TEP (As currently reported) (in thousands) Revenues: Crude oil transportation services $ 300,436 $ — $ — $ — $ 300,436 Natural gas transportation services 119,895 — — — 119,895 Sales of natural gas, NGLs, and crude oil 82,133 — — — 82,133 Processing and other revenues 33,733 7,689 6,332 (7,557 ) (2) 40,197 Total Revenues 536,197 7,689 6,332 (7,557 ) 542,661 Operating Costs and Expenses: Cost of sales 75,285 — — — 75,285 Cost of transportation services 53,597 800 — (7,557 ) (2) 46,840 Operations and maintenance 49,138 1,685 — — 50,823 Depreciation and amortization 83,476 782 — — 84,258 General and administrative 50,195 1,156 — — 51,351 Taxes, other than income taxes 21,796 — — — 21,796 Loss on disposal of assets 4,795 — — — 4,795 Total Operating Costs and Expenses 338,282 4,423 — (7,557 ) 335,148 Operating Income 197,915 3,266 6,332 — 207,513 Other Income (Expense): Interest expense, net (15,514 ) — — — (15,514 ) Equity in earnings of unconsolidated investments — 2,759 — — 2,759 Other income, net 2,413 — — — 2,413 Total Other (Expense) Income (13,101 ) 2,759 — — (10,342 ) Net income 184,814 6,025 6,332 — 197,171 Net income attributable to noncontrolling interests (24,268 ) — — — (24,268 ) Net income attributable to partners $ 160,546 $ 6,025 $ 6,332 $ — $ 172,903 (1) Represents the elimination of revenue and cost of sales associated with the purchase of crude oil from Pony Express by Terminals. (2) Represents the elimination of revenue and cost of transportation services associated with the lease of the Sterling Terminal facilities by Pony Express. (3) Represents a one-time charge related to the termination of an operating agreement at the Sterling Terminal. |
Tallgrass Crude Gathering, LLC | |
Business Acquisition [Line Items] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | The following represents the fair value of assets acquired and liabilities assumed at August 3, 2017 (in thousands): Accounts receivable $ 117 Property, plant and equipment 29,306 Intangible asset 6,694 (1) Accounts payable and accrued liabilities (87 ) Net identifiable assets acquired $ 36,030 (1) The $6.7 million intangible asset acquired represents a major customer contract. This intangible asset is amortized on a straight-line basis over a period of 8 years , the remaining term of the contract at the time of acquisition. |
Deeprock Development, LLC | |
Business Acquisition [Line Items] | |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | The following represents the fair value of assets acquired and liabilities assumed at July 20, 2017 (in thousands): Accounts receivable $ 968 Other current assets 598 Property, plant and equipment 70,148 Accounts payable (712 ) Deferred revenue (6,546 ) Net identifiable assets acquired 64,456 Goodwill 61,550 Net assets acquired (excluding cash) $ 126,006 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Schedule of Transactions with Affiliated Companies | Totals of transactions with affiliated companies, excluding transactions disclosed elsewhere in these notes, are as follows: Year Ended December 31, 2017 2016 2015 (in thousands) Processing and other revenues (1) $ 8,516 $ 6,228 $ 6,331 Cost of transportation services (2) $ 10,476 $ 18,585 $ 18,288 Charges to TEP: (3) Property, plant and equipment, net $ 2,679 $ 3,084 $ 4,342 Other deferred charges $ 25 $ 44 $ 7 Operations and maintenance $ 29,881 $ 25,431 $ 23,658 General and administrative $ 41,032 $ 39,574 $ 33,820 (1) Reflects the fee that NatGas receives as the operator of the Rockies Express Pipeline. (2) Reflects rent expense for the crude oil storage at the Deeprock Terminal prior to our consolidation of Deeprock Development during the third quarter of 2017, as discussed in Note 3 – Acquisitions . (3) Charges to TEP include directly charged wages and salaries, other compensation and benefits, and shared services. |
Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets | Details of balances with affiliates included in "Accounts receivable, net" and "Accounts payable to related parties" in the consolidated balance sheets are as follows: December 31, 2017 December 31, 2016 (in thousands) Receivable from related parties: Rockies Express Pipeline LLC $ 1,340 $ 590 Total receivable from related parties $ 1,340 $ 590 Accounts payable to related parties: Tallgrass Operations, LLC $ 5,381 $ 5,854 Tallgrass Equity, LLC 80 68 Deeprock Development, LLC — 13 Total accounts payable to related parties $ 5,461 $ 5,935 |
Schedule of Balances of Gas Imbalance with Affiliated Shippers | Gas imbalances with affiliated shippers are as follows: December 31, 2017 December 31, 2016 (in thousands) Affiliate gas imbalance receivables $ 18 $ 177 Affiliate gas imbalance payables $ 442 $ — |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Inventory Disclosure [Abstract] | |
Schedule of Components of Inventory | The components of inventory at December 31, 2017 and 2016 consisted of the following: December 31, 2017 December 31, 2016 (in thousands) Crude oil $ 12,792 $ 5,462 Materials and supplies 5,891 6,383 Natural gas liquids 942 265 Gas in underground storage 1,984 983 Total inventory $ 21,609 $ 13,093 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Components of Property Plant and Equipment | A summary of net property, plant and equipment by classification is as follows: December 31, 2017 December 31, 2016 (in thousands) Crude oil pipelines $ 1,220,379 $ 1,202,125 Gathering, processing and terminalling assets (1) 675,092 397,701 Natural gas pipelines 581,400 572,150 General and other 98,680 82,510 Construction work in progress 97,978 20,606 Accumulated depreciation and amortization (279,192 ) (195,860 ) Total property, plant and equipment, net (2) $ 2,394,337 $ 2,079,232 (1) Includes approximately $138.2 million of assets associated with the Douglas Gathering System acquired in June 2017, approximately $68.4 million of assets associated with the acquisition of the aggregate additional 49% membership interest in Deeprock Development in July 2017, and approximately $29.3 million of assets associated with the PRB Crude System acquired in August 2017. (2) Property, plant and equipment, net includes approximately $431.6 million of assets at our regulated natural gas pipelines at December 31, 2017 . |
Schedule of Future Minimum Rental Payments for Operating Leases | As of December 31, 2017 , future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands): Year Total 2018 $ 4,575 2019 4,590 2020 3,978 2021 3,773 2022 3,773 Thereafter 11,127 Total $ 31,816 At December 31, 2017 , future minimum rental commitments under major, non-cancelable operating leases were as follows (in thousands): Year Total 2018 $ 1,226 2019 1,351 2020 1,414 2021 1,093 2022 828 Thereafter 4,394 Total $ 10,306 |
Goodwill and Intangible Assets
Goodwill and Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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 periods indicated: Year Ended December 31, 2017 Year Ended December 31, 2016 Natural Gas Transportation Gathering, Processing & Terminalling Total Natural Gas Transportation Gathering, Processing & Terminalling Total (in thousands) Balance at beginning of period $ 255,558 $ 87,730 $ 343,288 $ 255,558 $ 87,730 $ 343,288 Goodwill acquired — 61,550 (1) 61,550 — — — Balance at end of period $ 255,558 $ 149,280 $ 404,838 $ 255,558 $ 87,730 $ 343,288 (1) The $61.6 million of goodwill was recorded in connection with the acquisition of a controlling interest in Deeprock Development on July 20, 2017 as discussed further in Note 3 – Acquisitions . |
Schedule of Finite-Lived Intangible Assets | A summary of amortized intangible assets is as follows: December 31, 2017 December 31, 2016 (in thousands) Pony Express oil conversion use rights $ 105,973 $ 105,973 Customer contracts 8,064 — Accumulated amortization (16,306 ) (12,451 ) Intangible assets, net $ 97,731 $ 93,522 |
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense | Estimated future amortization for the intangible assets is as follows (in thousands): Year Total 2018 $ 4,581 2019 4,048 2020 3,868 2021 3,868 2022 3,868 Thereafter 77,498 Total $ 97,731 |
Investments in Unconsolidated35
Investments in Unconsolidated Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Schedule of Equity Method Investments [Line Items] | |
Equity Method Investments [Table Text Block] | Combined summarized financial information for all our unconsolidated affiliates is shown in the tables below. Summarized financial information for Deeprock Development is presented from January 1, 2015 to July 20, 2017, the date TEP acquired a controlling interest in Deeprock Development. Summarized financial information for Rockies Express is presented from the date of the initial acquisition of May 6, 2016 to December 31, 2017. Summarized financial information for BNN Colorado is presented from the date of the acquisition, June 23, 2017 to December 31, 2017. December 31, 2017 December 31, 2016 (in thousands) Current assets $ 122,362 $ 199,958 Noncurrent assets $ 5,974,926 $ 6,148,203 Current liabilities $ 714,037 $ 197,305 Noncurrent liabilities $ 2,049,189 $ 2,656,836 Members' equity $ 3,334,062 $ 3,494,020 Year Ended December 31, 2017 2016 2015 (in thousands) Revenue $ 860,115 $ 440,838 $ 18,646 Operating income $ 480,337 $ 203,801 $ 13,794 Net income to Members $ 465,592 $ 184,314 $ 13,794 |
Rockies Express Pipeline LLC | |
Schedule of Equity Method Investments [Line Items] | |
Equity Method Investments [Table Text Block] | At December 31, 2017 , the basis difference for the membership interests acquired in May 2016 and March 2017 were allocated as follows: Basis Difference Amortization Period (in thousands) Long-term debt $ 29,458 2 - 25 years Property, plant and equipment (788,631 ) 35 years Total basis difference $ (759,173 ) |
Risk Management (Tables)
Risk Management (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Fair Value of Derivative Contracts | The following table summarizes the fair values of our derivative contracts included in the consolidated balance sheets: Balance Sheet December 31, 2017 December 31, 2016 (in thousands) Call option derivative (1) Current assets $ — $ 10,676 Natural gas derivative contracts (2) Current assets $ — $ 291 Crude oil derivative contracts (3) Current liabilities $ 2,368 $ 440 Natural gas derivative contracts (2) Current liabilities $ — $ 116 (1) As discussed below, in conjunction with our acquisition of an additional 31.3% membership interest in Pony Express effective January 1, 2016, TD granted us an 18 month call option covering the 6,518,000 common units issued to TD. As of February 1, 2017, no common units remained subject to the call option. (2) As of December 31, 2017 , there were no natural gas derivative contracts outstanding. As of December 31, 2016 , the fair value shown for natural gas derivative contracts was comprised of derivative volumes for short and long natural gas fixed-price swaps totaling 0.3 Bcf and 0.4 Bcf, respectively. (3) As of December 31, 2017 , the fair value shown for crude oil derivative contracts represents the forward sale of 356,000 barrels which will settle throughout the first quarter of 2018. As of December 31, 2016 , the fair value shown for crude oil derivative contracts represents the sale of 125,000 barrels of crude oil which settled throughout 2017. |
Derivative Contracts Included in Consolidated Statements of Income | The following table summarizes the impact of derivative contracts not designated as hedging contracts for the years ended December 31, 2017 , 2016 and 2015 : Location of Amount of gain (loss) recognized in income on derivatives Year Ended December 31, 2017 2016 2015 (in thousands) Derivatives not designated as hedging contracts: Crude oil derivative contracts Sales of natural gas, NGLs, and crude oil $ 39 $ (40 ) $ — Natural gas derivative contracts Sales of natural gas, NGLs, and crude oil $ 75 $ 74 $ 427 Call option derivative Unrealized gain (loss) on derivative instrument $ 1,885 $ (1,291 ) $ — |
Schedule Of Derivative Assets And Liabilities At Fair Value Table | The following table summarizes the fair value measurements of our derivative contracts as of December 31, 2017 and 2016 , based on the fair value hierarchy: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2016: Call option derivative $ 10,676 $ — $ 10,676 $ — Natural gas derivative contracts $ 291 $ — $ 291 $ — Liability Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of December 31, 2017: Crude oil derivative contracts $ 2,368 $ — $ 2,368 $ — As of December 31, 2016: Crude oil derivative contracts $ 440 $ — $ 440 $ — Natural gas derivative contracts $ 116 $ — $ 116 $ — |
Long-term Debt (Tables)
Long-term Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Schedule of Debt | Long-term debt consisted of the following at December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 (in thousands) Revolving credit facility $ 661,000 $ 1,015,000 5.50% senior notes due September 15, 2024 750,000 400,000 5.50% senior notes due January 15, 2028 750,000 — Less: Deferred financing costs, net (1) (17,737 ) (7,019 ) Plus: Unamortized premium on 2028 Notes 3,730 — Total long-term debt, net $ 2,146,993 $ 1,407,981 (1) Deferred financing costs, net as presented above relate solely to the 2024 and 2028 Notes. Deferred financing costs associated with our revolving credit facility are presented in noncurrent assets on our consolidated balance sheets. |
Schedule of Line of Credit Facilities | The following table sets forth the available borrowing capacity under the revolving credit facility as of December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 (in thousands) Total capacity under the revolving credit facility $ 1,750,000 $ 1,750,000 Less: Outstanding borrowings under the revolving credit facility (661,000 ) (1,015,000 ) Less: Letters of credit issued under the revolving credit facility (94 ) — Available capacity under the revolving credit facility $ 1,088,906 $ 735,000 |
Carrying Amount and Fair value of TEP's Long-term Debt | The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the consolidated balance sheets as of December 31, 2017 and 2016 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) As of December 31, 2017: Revolving credit facility $ — $ 661,000 $ — $ 661,000 $ 661,000 2024 Notes $ — $ 771,645 $ — $ 771,645 $ 739,824 2028 Notes $ — $ 758,168 $ — $ 758,168 $ 746,169 As of December 31, 2016: Revolving credit facility $ — $ 1,015,000 $ — $ 1,015,000 $ 1,015,000 2024 Notes $ — $ 398,000 $ — $ 398,000 $ 392,981 |
Partnership Equity and Distri38
Partnership Equity and Distributions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Summary of Distributions | The following table shows the distributions for the periods indicated: Distributions Distribution per Limited Partner Common 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, 2017 February 14, 2018 (1) $ 70,638 $ 39,125 $ 1,251 $ 111,014 $ 0.9650 September 30, 2017 November 14, 2017 69,174 37,744 1,219 108,137 0.9450 June 30, 2017 August 14, 2017 67,671 36,342 1,186 105,199 0.9250 March 31, 2017 May 15, 2017 60,486 29,840 1,040 91,366 0.8350 December 31, 2016 February 14, 2017 58,793 28,358 1,008 88,159 0.8150 September 30, 2016 November 14, 2016 57,332 26,987 976 85,295 0.7950 June 30, 2016 August 12, 2016 54,442 24,262 911 79,615 0.7550 March 31, 2016 May 13, 2016 48,238 19,816 830 68,884 0.7050 December 31, 2015 February 12, 2016 42,984 15,332 724 59,040 0.6400 September 30, 2015 November 13, 2015 36,347 11,567 660 48,574 0.6000 June 30, 2015 August 14, 2015 35,135 10,418 627 46,180 0.5800 March 31, 2015 May 14, 2015 31,322 6,934 530 38,786 0.5200 (1) The distribution announced on January 8, 2018 for the fourth quarter of 2017 will be paid on February 14, 2018 to unitholders of record at the close of business on January 31, 2018. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Future Minimum Rental Payments for Operating Leases | As of December 31, 2017 , future minimum rental income under non-cancelable operating leases as the lessor were as follows (in thousands): Year Total 2018 $ 4,575 2019 4,590 2020 3,978 2021 3,773 2022 3,773 Thereafter 11,127 Total $ 31,816 At December 31, 2017 , future minimum rental commitments under major, non-cancelable operating leases were as follows (in thousands): Year Total 2018 $ 1,226 2019 1,351 2020 1,414 2021 1,093 2022 828 Thereafter 4,394 Total $ 10,306 |
Other Commitments | At December 31, 2017 , future minimum commitments under long-term, non-cancelable contracts for other purchase obligations were as follows (in thousands): Year Total 2018 $ 2,084 2019 2,091 2020 2,070 2021 20 2022 20 Thereafter 48 Total $ 6,333 |
Net Income per Limited Partne40
Net Income per Limited Partner Unit (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Summary of Net Income Per Limited Partner Unit | The following table illustrates the calculation of net income per common unit for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands, except per unit amounts) Net income $ 440,489 $ 274,889 $ 197,171 Net income attributable to noncontrolling interests (6,499 ) (4,365 ) (24,268 ) Net income attributable to partners 433,990 270,524 172,903 Predecessor operations interest in net income — (6,995 ) (12,357 ) General partner interest in net income (147,823 ) (102,465 ) (46,478 ) Net income available to common unitholders $ 286,167 $ 161,064 $ 114,068 Basic net income per common unit $ 3.93 $ 2.26 $ 1.95 Diluted net income per common unit $ 3.90 $ 2.23 $ 1.91 Basic average number of common units outstanding 72,876 71,150 58,597 Equity Participation Unit equivalent units 582 957 978 Diluted average number of common units outstanding 73,458 72,107 59,575 |
Major Customers and Concentra41
Major Customers and Concentration of Credit Risk (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Risks and Uncertainties [Abstract] | |
Schedules of Concentration of Risk | For the year ended December 31, 2017 , the percentage of segment revenues from the top ten non-affiliated customers for each segment was as follows: Percentage of Segment Revenue Natural Gas Transportation 56% Crude Oil Transportation 91% Gathering, Processing & Terminalling 75% |
Equity-Based Compensation (Tabl
Equity-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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 years ended December 31, 2017 , 2016 and 2015 : Equity Participation Units Weighted Average Outstanding at January 1, 2015 1,525,750 $ 18.75 Granted 338,591 40.01 Vested (1) (480,555 ) (19.39 ) Forfeited (58,825 ) (16.98 ) Outstanding at December 31, 2015 1,324,961 24.11 Granted 94,750 35.12 Vested (1) (35,998 ) (23.74 ) Forfeited (43,829 ) (20.08 ) Outstanding at December 31, 2016 1,339,884 24.92 Granted 621,400 38.58 Vested (1) (941,858 ) (19.70 ) Forfeited (30,033 ) (39.08 ) Outstanding at December 31, 2017 989,393 $ 38.58 (1) During the years ended December 31, 2017 , 2016 , and 2015 , approximately 683,304 , 24,933 , and 344,383 common units (net of tax withholding of approximately 258,554 , 11,065 , and 136,172 common units) were issued in connection with the settlement of vested awards, respectively. |
Reporting Segments (Tables)
Reporting Segments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Summary of TEP's Segment Information of Revenue | The following tables set forth our segment information for the periods indicated: Year Ended December 31, 2017 2016 2015 Revenue: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 141,021 $ (6,694 ) $ 134,327 $ 135,097 $ (5,641 ) $ 129,456 $ 137,988 $ (5,384 ) $ 132,604 Crude Oil Transportation 364,574 (10,676 ) 353,898 380,503 (370 ) 380,133 304,227 — 304,227 Gathering, Processing & Terminalling 186,211 (18,538 ) 167,673 113,533 (11,460 ) 102,073 113,387 (7,557 ) 105,830 Corporate and Other — — — — — — — — — Total revenue $ 691,806 $ (35,908 ) $ 655,898 $ 629,133 $ (17,471 ) $ 611,662 $ 555,602 $ (12,941 ) $ 542,661 |
Summary of TEP's Segment Information of Earnings | Year Ended December 31, 2017 2016 2015 Adjusted EBITDA: Total Inter- External Total Inter- External Total Inter- External (in thousands) Natural Gas Transportation $ 392,394 $ (7,709 ) $ 384,685 $ 154,850 $ (5,641 ) $ 149,209 $ 73,699 $ (5,384 ) $ 68,315 Crude Oil Transportation 243,106 17,263 260,369 264,391 16,843 281,234 165,204 12,941 178,145 Gathering, Processing & Terminalling 50,970 (9,554 ) 41,416 17,928 (11,202 ) 6,726 32,243 (7,557 ) 24,686 Corporate and Other (8,463 ) — (8,463 ) (4,622 ) — (4,622 ) (2,979 ) — (2,979 ) Reconciliation to Net Income: Add: Equity in earnings of unconsolidated investments 237,110 54,531 2,759 Gain on remeasurement of unconsolidated investment 9,728 — — Non-cash loss allocated to noncontrolling interest — — 9,377 Less: Interest expense, net of noncontrolling interest (83,542 ) (40,688 ) (15,517 ) Depreciation and amortization expense, net of noncontrolling interest (92,455 ) (88,122 ) (77,111 ) Distributions from unconsolidated investments (306,626 ) (78,568 ) (4,648 ) Non-cash loss related to derivative instruments, net of noncontrolling interests (226 ) (1,547 ) — Non-cash compensation expense (8,660 ) (5,780 ) (5,103 ) Gain (loss) on disposal of assets, net of noncontrolling interests 654 (1,849 ) (4,795 ) Loss on extinguishment of debt — — (226 ) Net income attributable to partners $ 433,990 $ 270,524 $ 172,903 Year Ended December 31, Capital Expenditures: 2017 2016 2015 (in thousands) Natural Gas Transportation $ 16,705 $ 28,475 $ 10,478 Crude Oil Transportation 57,022 29,893 38,802 Gathering, Processing & Terminalling 71,417 26,123 71,438 Corporate and Other — — — Total capital expenditures $ 145,144 $ 84,491 $ 120,718 |
Summary of TEP's Segment Information for Payments to Acquire Plant, Property and Equipment | Year Ended December 31, Capital Expenditures: 2017 2016 2015 (in thousands) Natural Gas Transportation $ 16,705 $ 28,475 $ 10,478 Crude Oil Transportation 57,022 29,893 38,802 Gathering, Processing & Terminalling 71,417 26,123 71,438 Corporate and Other — — — Total capital expenditures $ 145,144 $ 84,491 $ 120,718 |
Summary of TEP's Segment Information of Unconsolidated Investments | Unconsolidated Investments: December 31, 2017 December 31, 2016 (in thousands) Natural Gas Transportation $ 895,873 $ 461,915 Crude Oil Transportation — — Gathering, Processing & Terminalling 13,658 13,710 Corporate and Other — — Total unconsolidated investments $ 909,531 $ 475,625 |
Summary of TEP's Segment Information of Assets | Assets: December 31, 2017 December 31, 2016 (in thousands) Natural Gas Transportation $ 1,606,666 $ 1,176,147 Crude Oil Transportation 1,407,758 1,410,695 Gathering, Processing & Terminalling 943,340 495,170 Corporate and Other 19,589 20,201 Total assets $ 3,977,353 $ 3,102,213 |
Selected Quarterly Financial 44
Selected Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Selected Quarterly Financial Data (Unaudited) [Abstract] | |
Schedule of Quarterly Financial Information | The following tables summarize our unaudited quarterly financial data for 2017 and 2016 : Quarter Ended 2017 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 144,400 $ 160,863 $ 175,869 $ 174,766 Operating income $ 63,780 $ 67,504 $ 74,567 $ 68,236 Net income $ 71,784 $ 90,829 $ 185,503 $ 92,373 Net income attributable to partners $ 70,905 $ 89,880 $ 184,090 $ 89,115 Net income available to common unitholders $ 40,322 $ 52,579 $ 144,281 $ 48,985 Basic net income per limited partner unit $ 0.56 $ 0.72 $ 1.97 $ 0.67 Diluted net income per limited partner unit $ 0.55 $ 0.72 $ 1.96 $ 0.67 During the third quarter of 2017, we recognized equity in earnings relating to our proportionate share of the Ultra settlement discussed in Note 17 – Legal and Environmental Matters . Quarter Ended 2016 First Second Third Fourth (in thousands, except per unit amounts) Total revenues $ 147,168 $ 149,015 $ 153,268 $ 162,211 Operating income $ 63,966 $ 55,307 $ 67,511 $ 73,830 Net income $ 48,796 $ 89,270 $ 65,429 $ 71,394 Net income attributable to partners $ 47,755 $ 88,160 $ 64,345 $ 70,264 Net income available to common unitholders $ 23,717 $ 66,728 $ 33,060 $ 37,559 Basic net income per limited partner unit $ 0.35 $ 0.93 $ 0.45 $ 0.52 Diluted net income per limited partner unit $ 0.35 $ 0.92 $ 0.45 $ 0.51 |
Description of Business - Sch45
Description of Business - Schedule of Other Ownership Interests (Detail) - shares | Dec. 31, 2017 | Dec. 31, 2016 |
Organization [Line Items] | ||
Limited Partner Common Units | 73,199,753 | 72,485,954 |
General Partner Units | 834,391 | 834,391 |
Ownership Percentage Of Aggregate Partnership Equity Excluding General Partner Units | 100.00% | |
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units | 100.00% | |
Ownership Interests Held By Public | ||
Organization [Line Items] | ||
Limited Partner Common Units | 47,580,535 | |
General Partner Units | 0 | |
Ownership Percentage Of Aggregate Partnership Equity Excluding General Partner Units | 65.00% | |
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units | 64.00% | |
Ownership Interests Held By Tallgrass Equity, LLC | ||
Organization [Line Items] | ||
Limited Partner Common Units | 20,000,000 | |
General Partner Units | 0 | |
Ownership Percentage Of Aggregate Partnership Equity Excluding General Partner Units | 27.00% | |
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units | 27.00% | |
Ownership Interests Held By Tallgrass Development | ||
Organization [Line Items] | ||
Limited Partner Common Units | 5,619,218 | |
General Partner Units | 0 | |
Ownership Percentage Of Aggregate Partnership Equity Excluding General Partner Units | 7.68% | |
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units | 7.59% | |
Ownership Interests Held By Tallgrass MLP GP, LLC | ||
Organization [Line Items] | ||
Limited Partner Common Units | 0 | |
General Partner Units | 834,391 | |
Ownership Percentage Of Aggregate Partnership Equity Excluding General Partner Units | 0.00% | |
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units | 1.00% |
Description of Business - Addit
Description of Business - Additional Information (Details) - shares | Jan. 02, 2018 | Dec. 31, 2017 | Dec. 31, 2017 | Feb. 07, 2018 | Jan. 12, 2018 | Jul. 21, 2017 | Mar. 31, 2017 | Jan. 01, 2017 | May 06, 2016 |
Organization [Line Items] | |||||||||
Equity Method Investment, Ownership Percentage | 20.00% | 20.00% | |||||||
Tallgrass NatGas Operator, LLC | |||||||||
Organization [Line Items] | |||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | ||||||||
Tallgrass Terminals, LLC | |||||||||
Organization [Line Items] | |||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | ||||||||
Deeprock Development, LLC | |||||||||
Organization [Line Items] | |||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 49.00% | ||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 69.00% | 69.00% | |||||||
Rockies Express Pipeline LLC | |||||||||
Organization [Line Items] | |||||||||
Equity Method Investment, Ownership Percentage | 49.99% | 49.99% | 25.00% | ||||||
Tallgrass Development LP | Rockies Express Pipeline LLC | |||||||||
Organization [Line Items] | |||||||||
Equity Method Investment, Ownership Percentage | 24.99% | ||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 24.99% | ||||||||
Subsequent Event | Deeprock Development, LLC | |||||||||
Organization [Line Items] | |||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 60.00% | ||||||||
Subsequent Event | Deeprock North, LLC | |||||||||
Organization [Line Items] | |||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 38.00% | ||||||||
Subsequent Event | BNN North Dakota | |||||||||
Organization [Line Items] | |||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | ||||||||
Tallgrass Equity, LLC | Subsequent Event | Tallgrass Development LP | |||||||||
Organization [Line Items] | |||||||||
Units Acquired | 5,619,218 |
Summary of Significant Accoun47
Summary of Significant Accounting Policies (Details) $ in Thousands | Sep. 01, 2014 | Mar. 31, 2015USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Feb. 01, 2018 | Jan. 01, 2018USD ($) | Dec. 31, 2016USD ($) | May 06, 2016 | Jan. 01, 2016 | Mar. 01, 2015 | Aug. 06, 2012mi |
Business Acquisition [Line Items] | ||||||||||||
Allowance for Doubtful Accounts Receivable | $ 500 | $ 600 | ||||||||||
Regulatory Assets | 2,600 | 2,900 | ||||||||||
Regulatory Liabilities | $ 2,300 | 1,700 | ||||||||||
Equity Method Investment, Ownership Percentage | 20.00% | |||||||||||
Unconsolidated investments | $ 909,531 | 475,625 | ||||||||||
Accounts receivable, net | $ 119,955 | $ 59,536 | ||||||||||
Crude oil pipelines | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.80% | |||||||||||
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 | 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 | Processing & treating | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.20% | |||||||||||
Minimum | Water business assets | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.30% | |||||||||||
Minimum | Terminal business assets | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 1.80% | |||||||||||
Minimum | General and other | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.50% | |||||||||||
Maximum | Natural gas pipelines | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 5.00% | |||||||||||
Maximum | Processing & treating | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 5.00% | |||||||||||
Maximum | 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 | Terminal business assets | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.80% | |||||||||||
Maximum | General and other | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 25.00% | |||||||||||
Use Rights | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Finite-Lived Intangible Asset, Useful Life | 35 years | |||||||||||
Customer Contracts | Minimum | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Finite-Lived Intangible Asset, Useful Life | 2 years | |||||||||||
Customer Contracts | Maximum | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Finite-Lived Intangible Asset, Useful Life | 8 years | |||||||||||
Pony Express Pipeline | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | |||||||||||
Minimum Quarterly Distribution Required by Partnership Agreement | $ 36,650 | $ 16,650 | ||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 31.30% | 33.30% | ||||||||||
Prorated Minimum Quarterly Distribution Required by Partnership Agreement | $ 23,500 | |||||||||||
Tallgrass Interstate Gas Transmission, LLC (TIGT) | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Gas Transmission Lines Owned | mi | 433 | |||||||||||
Pony Express Pipeline | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 2.00% | |||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | |||||||||||
Tallgrass Colorado Pipeline, Inc. | Pony Express Pipeline | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 99.80% | |||||||||||
Tallgrass Colorado Pipeline, Inc. | Tallgrass Energy Partners | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 0.20% | |||||||||||
Rockies Express Pipeline LLC | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.90% | |||||||||||
Equity Method Investment, Ownership Percentage | 49.99% | 25.00% | ||||||||||
Subsequent Event | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Cumulative Effect of New Accounting Principle in Period of Adoption | $ 44,100 | |||||||||||
Subsequent Event | Pony Express Pipeline | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 2.00% | |||||||||||
Subsequent Event | Rockies Express Pipeline LLC | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Cumulative Effect of New Accounting Principle in Period of Adoption | 125,200 | |||||||||||
Accounts receivable, net | 1,300 | |||||||||||
Subsequent Event | Rockies Express Pipeline LLC | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Unconsolidated investments | $ 42,800 |
Acquisitions - TCG Acquisition,
Acquisitions - TCG Acquisition, Assets Acquired & Liabilities Assumed (Details) - USD ($) $ in Thousands | Aug. 03, 2017 | Dec. 31, 2017 | Dec. 31, 2016 |
Business Acquisition [Line Items] | |||
Property, plant and equipment, net | $ 2,394,337 | $ 2,079,232 | |
Intangible assets, net | $ 97,731 | $ 93,522 | |
Finite-Lived Intangible Assets, Remaining Amortization Period | 8 years | ||
Tallgrass Crude Gathering, LLC | |||
Business Acquisition [Line Items] | |||
Accounts receivable | $ 117 | ||
Property, plant and equipment, net | 29,306 | ||
Intangible assets, net | 6,694 | ||
Accounts payable and accrued liabilities | (87) | ||
Net identifiable assets acquired | $ 36,030 |
Acquisitions - DRD Acquisition,
Acquisitions - DRD Acquisition, Assets Acquired & Liabilities Assumed (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Jul. 20, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Business Acquisition [Line Items] | ||||
Property, plant and equipment, net | $ 2,394,337 | $ 2,079,232 | ||
Goodwill | $ 404,838 | $ 343,288 | $ 343,288 | |
Deeprock Development, LLC | ||||
Business Acquisition [Line Items] | ||||
Accounts receivable | $ 968 | |||
Other Assets, Current | 598 | |||
Property, plant and equipment, net | 70,148 | |||
Accounts payable | (712) | |||
Deferred Revenue | (6,546) | |||
Net identifiable assets acquired | 64,456 | |||
Goodwill | 61,550 | |||
Net identifiable assets acquired (excluding cash) | $ 126,006 |
Acquisitions - Pro Forma Infor
Acquisitions - Pro Forma Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Business Combinations [Abstract] | |||
Business Acquisition, Pro Forma Revenue | $ 667,391 | $ 632,528 | $ 544,497 |
Business Acquisition, Pro Forma Net Income (Loss) | $ 427,522 | $ 275,506 | $ 173,542 |
Acquisitions - Impact of Acquis
Acquisitions - Impact of Acquisition, Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Business Acquisition [Line Items] | ||||
Cash and cash equivalents | $ 1,809 | $ 1,873 | $ 1,611 | $ 867 |
Accounts receivable, net | 119,955 | 59,536 | ||
Gas imbalances | 1,990 | 1,597 | ||
Inventories | 21,609 | 13,093 | ||
Derivative assets | 0 | 10,967 | ||
Prepayments and other current assets | 11,175 | 7,628 | ||
Assets, Current | 156,538 | 94,694 | ||
Property, plant and equipment, net | 2,394,337 | 2,079,232 | ||
Goodwill | 404,838 | 343,288 | $ 343,288 | |
Intangible assets, net | 97,731 | 93,522 | ||
Unconsolidated investments | 909,531 | 475,625 | ||
Deferred financing costs, net | 11,684 | 4,815 | ||
Deferred charges and other assets | 2,694 | 11,037 | ||
Assets | 3,977,353 | 3,102,213 | ||
Accounts payable | 98,882 | 24,122 | ||
Accounts payable to related parties | 5,461 | 5,935 | ||
Gas imbalances | 1,663 | 1,239 | ||
Derivative liabilities | 2,368 | 556 | ||
Accrued taxes | 19,272 | 16,996 | ||
Accrued liabilities | 35,659 | 16,702 | ||
Deferred revenue | 88,471 | 60,757 | ||
Other current liabilities | 7,171 | 6,446 | ||
Liabilities, Current | 258,947 | 132,753 | ||
Long-term debt, net | 2,146,993 | 1,407,981 | ||
Other long-term liabilities and deferred credits | 18,965 | 7,063 | ||
Liabilities, Noncurrent | 2,165,958 | 1,415,044 | ||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | 1,552,448 | 1,554,416 | ||
Liabilities and Equity | $ 3,977,353 | 3,102,213 | ||
Tallgrass Energy Partners | ||||
Business Acquisition [Line Items] | ||||
Cash and cash equivalents | 1,873 | |||
Accounts receivable, net | 59,469 | |||
Gas imbalances | 1,597 | |||
Inventories | 12,805 | |||
Derivative assets | 10,967 | |||
Prepayments and other current assets | 6,820 | |||
Assets, Current | 93,531 | |||
Property, plant and equipment, net | 2,012,263 | |||
Goodwill | 343,288 | |||
Intangible assets, net | 93,522 | |||
Unconsolidated investments | 461,915 | |||
Deferred financing costs, net | 4,815 | |||
Deferred charges and other assets | 9,637 | |||
Assets | 3,018,971 | |||
Accounts payable | 24,076 | |||
Accounts payable to related parties | 5,879 | |||
Gas imbalances | 1,239 | |||
Derivative liabilities | 556 | |||
Accrued taxes | 16,328 | |||
Accrued liabilities | 16,525 | |||
Deferred revenue | 60,757 | |||
Other current liabilities | 6,446 | |||
Liabilities, Current | 131,806 | |||
Long-term debt, net | 1,407,981 | |||
Other long-term liabilities and deferred credits | 7,063 | |||
Liabilities, Noncurrent | 1,415,044 | |||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | 1,472,121 | |||
Liabilities and Equity | 3,018,971 | |||
Tallgrass Terminals, LLC | ||||
Business Acquisition [Line Items] | ||||
Cash and cash equivalents | 0 | |||
Accounts receivable, net | 38 | |||
Gas imbalances | 0 | |||
Inventories | 288 | |||
Derivative assets | 0 | |||
Prepayments and other current assets | 808 | |||
Assets, Current | 1,134 | |||
Property, plant and equipment, net | 66,969 | |||
Goodwill | 0 | |||
Intangible assets, net | 0 | |||
Unconsolidated investments | 13,710 | |||
Deferred financing costs, net | 0 | |||
Deferred charges and other assets | 1,400 | |||
Assets | 83,213 | |||
Accounts payable | 46 | |||
Accounts payable to related parties | 56 | |||
Gas imbalances | 0 | |||
Derivative liabilities | 0 | |||
Accrued taxes | 668 | |||
Accrued liabilities | 177 | |||
Deferred revenue | 0 | |||
Other current liabilities | 0 | |||
Liabilities, Current | 947 | |||
Long-term debt, net | 0 | |||
Other long-term liabilities and deferred credits | 0 | |||
Liabilities, Noncurrent | 0 | |||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | 82,266 | |||
Liabilities and Equity | 83,213 | |||
Tallgrass NatGas Operator, LLC | ||||
Business Acquisition [Line Items] | ||||
Cash and cash equivalents | 0 | |||
Accounts receivable, net | 29 | |||
Gas imbalances | 0 | |||
Inventories | 0 | |||
Derivative assets | 0 | |||
Prepayments and other current assets | 0 | |||
Assets, Current | 29 | |||
Property, plant and equipment, net | 0 | |||
Goodwill | 0 | |||
Intangible assets, net | 0 | |||
Unconsolidated investments | 0 | |||
Deferred financing costs, net | 0 | |||
Deferred charges and other assets | 0 | |||
Assets | 29 | |||
Accounts payable | 0 | |||
Accounts payable to related parties | 0 | |||
Gas imbalances | 0 | |||
Derivative liabilities | 0 | |||
Accrued taxes | 0 | |||
Accrued liabilities | 0 | |||
Deferred revenue | 0 | |||
Other current liabilities | 0 | |||
Liabilities, Current | 0 | |||
Long-term debt, net | 0 | |||
Other long-term liabilities and deferred credits | 0 | |||
Liabilities, Noncurrent | 0 | |||
Partners' Capital, Including Portion Attributable to Noncontrolling Interest | 29 | |||
Liabilities and Equity | $ 29 |
Acquisitions - Impact of Acqu52
Acquisitions - Impact of Acquisition, Income Statement (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Business Acquisition [Line Items] | |||||||||||
Crude oil transportation services | $ 345,733 | $ 374,949 | $ 300,436 | ||||||||
Natural gas transportation services | 122,364 | 119,962 | 119,895 | ||||||||
Sales of natural gas, NGLs, and crude oil | 108,503 | 77,123 | 82,133 | ||||||||
Processing and other revenues | 79,298 | 39,628 | 40,197 | ||||||||
Total revenues | $ 174,766 | $ 175,869 | $ 160,863 | $ 144,400 | $ 162,211 | $ 153,268 | $ 149,015 | $ 147,168 | 655,898 | 611,662 | 542,661 |
Cost of sales | 91,213 | 71,650 | 75,285 | ||||||||
Cost of transportation services | 46,200 | 47,669 | 46,840 | ||||||||
Operations and maintenance | 62,069 | 55,070 | 50,823 | ||||||||
Depreciation and amortization | 90,800 | 86,247 | 84,258 | ||||||||
General and administrative | 63,296 | 55,102 | 51,351 | ||||||||
Taxes, other than income taxes | 28,832 | 25,400 | 21,796 | ||||||||
Contract termination | 0 | 8,061 | 0 | ||||||||
(Gain) loss on disposal of assets | 599 | (1,849) | (4,795) | ||||||||
Costs and Expenses | 381,811 | 351,048 | 335,148 | ||||||||
Operating income | 68,236 | 74,567 | 67,504 | 63,780 | 73,830 | 67,511 | 55,307 | 63,966 | 274,087 | 260,614 | 207,513 |
Interest expense, net | (83,542) | (40,688) | (15,514) | ||||||||
Unrealized gain (loss) on derivative instrument | 1,885 | (1,291) | 0 | ||||||||
Equity in earnings of unconsolidated investments | 237,110 | 54,531 | 2,759 | ||||||||
Other income, net | 1,221 | 1,723 | 2,413 | ||||||||
Nonoperating Income (Expense) | 166,402 | 14,275 | (10,342) | ||||||||
Net income | 440,489 | 274,889 | 197,171 | ||||||||
Net income attributable to noncontrolling interests | (6,499) | (4,365) | (24,268) | ||||||||
Net income attributable to partners | $ 89,115 | $ 184,090 | $ 89,880 | $ 70,905 | $ 70,264 | $ 64,345 | $ 88,160 | $ 47,755 | $ 433,990 | 270,524 | 172,903 |
Tallgrass Energy Partners | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Crude oil transportation services | 374,949 | 300,436 | |||||||||
Natural gas transportation services | 119,962 | 119,895 | |||||||||
Sales of natural gas, NGLs, and crude oil | 77,394 | 82,133 | |||||||||
Processing and other revenues | 32,817 | 33,733 | |||||||||
Total revenues | 605,122 | 536,197 | |||||||||
Cost of sales | 71,920 | 75,285 | |||||||||
Cost of transportation services | 58,341 | 53,597 | |||||||||
Operations and maintenance | 53,386 | 49,138 | |||||||||
Depreciation and amortization | 84,896 | 83,476 | |||||||||
General and administrative | 53,633 | 50,195 | |||||||||
Taxes, other than income taxes | 24,727 | 21,796 | |||||||||
Contract termination | 0 | ||||||||||
(Gain) loss on disposal of assets | (1,849) | (4,795) | |||||||||
Costs and Expenses | 348,752 | 338,282 | |||||||||
Operating income | 256,370 | 197,915 | |||||||||
Interest expense, net | (40,688) | (15,514) | |||||||||
Unrealized gain (loss) on derivative instrument | (1,291) | ||||||||||
Equity in earnings of unconsolidated investments | 51,780 | 0 | |||||||||
Other income, net | 1,723 | 2,413 | |||||||||
Nonoperating Income (Expense) | 11,524 | (13,101) | |||||||||
Net income | 267,894 | 184,814 | |||||||||
Net income attributable to noncontrolling interests | (4,365) | (24,268) | |||||||||
Net income attributable to partners | 263,529 | 160,546 | |||||||||
Tallgrass Terminals, LLC | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Crude oil transportation services | 0 | 0 | |||||||||
Natural gas transportation services | 0 | 0 | |||||||||
Sales of natural gas, NGLs, and crude oil | 99 | 0 | |||||||||
Processing and other revenues | 12,043 | 7,689 | |||||||||
Total revenues | 12,142 | 7,689 | |||||||||
Cost of sales | 100 | 0 | |||||||||
Cost of transportation services | 788 | 800 | |||||||||
Operations and maintenance | 1,684 | 1,685 | |||||||||
Depreciation and amortization | 1,351 | 782 | |||||||||
General and administrative | 1,469 | 1,156 | |||||||||
Taxes, other than income taxes | 673 | 0 | |||||||||
Contract termination | 8,061 | ||||||||||
(Gain) loss on disposal of assets | 0 | 0 | |||||||||
Costs and Expenses | 14,126 | 4,423 | |||||||||
Operating income | (1,984) | 3,266 | |||||||||
Interest expense, net | 0 | 0 | |||||||||
Unrealized gain (loss) on derivative instrument | 0 | ||||||||||
Equity in earnings of unconsolidated investments | 2,751 | 2,759 | |||||||||
Other income, net | 0 | 0 | |||||||||
Nonoperating Income (Expense) | 2,751 | 2,759 | |||||||||
Net income | 767 | 6,025 | |||||||||
Net income attributable to noncontrolling interests | 0 | 0 | |||||||||
Net income attributable to partners | 767 | 6,025 | |||||||||
Tallgrass NatGas Operator, LLC | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Crude oil transportation services | 0 | 0 | |||||||||
Natural gas transportation services | 0 | 0 | |||||||||
Sales of natural gas, NGLs, and crude oil | 0 | 0 | |||||||||
Processing and other revenues | 6,228 | 6,332 | |||||||||
Total revenues | 6,228 | 6,332 | |||||||||
Cost of sales | 0 | 0 | |||||||||
Cost of transportation services | 0 | 0 | |||||||||
Operations and maintenance | 0 | 0 | |||||||||
Depreciation and amortization | 0 | 0 | |||||||||
General and administrative | 0 | 0 | |||||||||
Taxes, other than income taxes | 0 | 0 | |||||||||
Contract termination | 0 | ||||||||||
(Gain) loss on disposal of assets | 0 | 0 | |||||||||
Costs and Expenses | 0 | 0 | |||||||||
Operating income | 6,228 | 6,332 | |||||||||
Interest expense, net | 0 | 0 | |||||||||
Unrealized gain (loss) on derivative instrument | 0 | ||||||||||
Equity in earnings of unconsolidated investments | 0 | 0 | |||||||||
Other income, net | 0 | 0 | |||||||||
Nonoperating Income (Expense) | 0 | 0 | |||||||||
Net income | 6,228 | 6,332 | |||||||||
Net income attributable to noncontrolling interests | 0 | 0 | |||||||||
Net income attributable to partners | 6,228 | 6,332 | |||||||||
Consolidation, Eliminations | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Crude oil transportation services | 0 | 0 | |||||||||
Natural gas transportation services | 0 | 0 | |||||||||
Sales of natural gas, NGLs, and crude oil | (370) | 0 | |||||||||
Processing and other revenues | (11,460) | (7,557) | |||||||||
Total revenues | (11,830) | (7,557) | |||||||||
Cost of sales | (370) | 0 | |||||||||
Cost of transportation services | (11,460) | (7,557) | |||||||||
Operations and maintenance | 0 | 0 | |||||||||
Depreciation and amortization | 0 | 0 | |||||||||
General and administrative | 0 | 0 | |||||||||
Taxes, other than income taxes | 0 | 0 | |||||||||
Contract termination | 0 | ||||||||||
(Gain) loss on disposal of assets | 0 | 0 | |||||||||
Costs and Expenses | (11,830) | (7,557) | |||||||||
Operating income | 0 | 0 | |||||||||
Interest expense, net | 0 | 0 | |||||||||
Unrealized gain (loss) on derivative instrument | 0 | ||||||||||
Equity in earnings of unconsolidated investments | 0 | 0 | |||||||||
Other income, net | 0 | 0 | |||||||||
Nonoperating Income (Expense) | 0 | 0 | |||||||||
Net income | 0 | 0 | |||||||||
Net income attributable to noncontrolling interests | 0 | 0 | |||||||||
Net income attributable to partners | $ 0 | $ 0 |
Acquisitions - Additional Infor
Acquisitions - Additional Information (Details) | Feb. 06, 2018mi | Feb. 01, 2018USD ($) | Jan. 02, 2018 | Aug. 03, 2017USD ($)ami | Jul. 21, 2017USD ($)shares | Jul. 20, 2017USD ($) | Jun. 05, 2017USD ($)mi | Feb. 01, 2017shares | Jan. 01, 2017USD ($) | Oct. 31, 2016shares | Jul. 21, 2016shares | Jan. 01, 2016USD ($)$ / sharesshares | Sep. 01, 2014USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Mar. 31, 2017 | Sep. 01, 2016USD ($) | May 06, 2016 | Dec. 16, 2015mi | Mar. 01, 2015 |
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Equity Method Investment, Ownership Percentage | 20.00% | 20.00% | 20.00% | ||||||||||||||||||||||
Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain | $ 9,728,000 | $ 0 | $ 0 | ||||||||||||||||||||||
Goodwill | $ 404,838,000 | $ 404,838,000 | 404,838,000 | 343,288,000 | 343,288,000 | ||||||||||||||||||||
Payments to Acquire Assets | 128,526,000 | 0 | 0 | ||||||||||||||||||||||
Acquisition of Rockies Express membership interest | 400,000,000 | 436,022,000 | 0 | ||||||||||||||||||||||
Acquisition of Pony Express membership interest | $ 0 | 49,118,000 | 700,000,000 | ||||||||||||||||||||||
Derivative asset at fair value | $ 46,000,000 | ||||||||||||||||||||||||
Partners' Capital Account, Units, Treasury Units Purchased | shares | 736,262 | ||||||||||||||||||||||||
Miles of water pipeline | mi | 62 | ||||||||||||||||||||||||
Fresh Water Service Contract | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Lessor, Operating Lease, Term of Contract | 5 years | ||||||||||||||||||||||||
Gathering and Disposal Contract | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Lessor, Operating Lease, Term of Contract | 9 years | ||||||||||||||||||||||||
Equity Option | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Partners' Capital Account, Units, Treasury Units Purchased | shares | 1,703,094 | 1,251,760 | 3,563,146 | ||||||||||||||||||||||
General Partner | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Distributions to noncontrolling interests | $ 0 | 0 | 0 | ||||||||||||||||||||||
Partial exercise of call option | (12,561,000) | (33,993,000) | |||||||||||||||||||||||
Tallgrass Crude Gathering, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | ||||||||||||||||||||||||
Miles of gathering pipeline | mi | 34 | ||||||||||||||||||||||||
Acres for Crude Oil gathering system | a | 150,000 | ||||||||||||||||||||||||
Payments to Acquire Businesses | $ 36,030,000 | 0 | 0 | ||||||||||||||||||||||
Tallgrass Terminals, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | ||||||||||||||||||||||||
Tallgrass NatGas Operator, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | ||||||||||||||||||||||||
Rockies Express Pipeline LLC | Tallgrass Development LP | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 24.99% | ||||||||||||||||||||||||
Equity Method Investment, Ownership Percentage | 24.99% | ||||||||||||||||||||||||
Rockies Express Pipeline LLC | Sempra U.S. Gas and Power | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 25.00% | ||||||||||||||||||||||||
Pony Express Pipeline | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 31.30% | 33.30% | |||||||||||||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 98.00% | ||||||||||||||||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | ||||||||||||||||||||||||
Total consideration | $ 743,600,000 | $ 600,000,000 | |||||||||||||||||||||||
Minimum Quarterly Distribution Required by Partnership Agreement | 36,650,000 | $ 16,650,000 | |||||||||||||||||||||||
Acquisition of Pony Express membership interest | 700,000,000 | ||||||||||||||||||||||||
Prorated Minimum Quarterly Distribution Required by Partnership Agreement | $ 23,500,000 | ||||||||||||||||||||||||
Distributions to noncontrolling interests | 475,000,000 | ||||||||||||||||||||||||
Common Unit, Issuance Value | $ 268,600,000 | ||||||||||||||||||||||||
Option Indexed to Issuer's Equity, Strike Price | $ / shares | $ 42.50 | ||||||||||||||||||||||||
Pony Express Pipeline | Equity Option | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 6,518,000 | ||||||||||||||||||||||||
Derivative, Term of Contract | 18 months | ||||||||||||||||||||||||
BNN Western, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | ||||||||||||||||||||||||
Acquisitions | 75,000,000 | ||||||||||||||||||||||||
Deeprock Development, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 49.00% | ||||||||||||||||||||||||
Payments to Acquire Businesses, Net of Cash Acquired | $ 57,202,000 | 0 | 0 | ||||||||||||||||||||||
Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value | $ 22,900,000 | ||||||||||||||||||||||||
Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain | $ 9,700,000 | ||||||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 40.00% | ||||||||||||||||||||||||
Business Combination, Acquisition of Less than 100 Percent, Noncontrolling Interest, Fair Value | $ 45,900,000 | ||||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 128,790 | ||||||||||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned | $ 6,700,000 | ||||||||||||||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 69.00% | 69.00% | |||||||||||||||||||||||
Deeprock Development, LLC | Deeprock Energy Resources, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 9.00% | ||||||||||||||||||||||||
Deeprock Development, LLC | Kinder Morgan Cushing, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 40.00% | ||||||||||||||||||||||||
Tallgrass Midstream Gathering LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Miles of gathering pipeline | mi | 1,500 | ||||||||||||||||||||||||
Tallgrass Midstream Gathering LLC | DCP Assets Holding, LP | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | ||||||||||||||||||||||||
Terminals and NatGas | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Payments to Acquire Businesses | $ 140,000,000 | 0 | 0 | ||||||||||||||||||||||
Tallgrass Crude Gathering, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | 1,000,000 | ||||||||||||||||||||||||
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual | $ 1,000,000 | ||||||||||||||||||||||||
Deeprock Development, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | $ 10,500,000 | ||||||||||||||||||||||||
Goodwill | $ 61,550,000 | ||||||||||||||||||||||||
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual | $ 8,500,000 | ||||||||||||||||||||||||
Deeprock Development, LLC | General Partner | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Acquisition of Pony Express membership interest | 0 | ||||||||||||||||||||||||
Acquisitions | $ 0 | ||||||||||||||||||||||||
Pony Express Pipeline | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 2.00% | 2.00% | 2.00% | ||||||||||||||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | ||||||||||||||||||||||||
Distributions to noncontrolling interests | $ 0 | 425,882,000 | 0 | ||||||||||||||||||||||
Pony Express Pipeline | General Partner | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Acquisitions | (279,967,000) | $ (324,328,000) | |||||||||||||||||||||||
Tallgrass Energy Partners | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Goodwill | 343,288,000 | ||||||||||||||||||||||||
Tallgrass Energy Partners | Tallgrass Crude Gathering, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Payments to Acquire Businesses | $ 36,000,000 | ||||||||||||||||||||||||
Tallgrass Energy Partners | Rockies Express Pipeline LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Acquisition of Rockies Express membership interest | $ 400,000,000 | $ 436,000,000 | |||||||||||||||||||||||
Tallgrass Energy Partners | Deeprock Development, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Payments to Acquire Businesses | $ 6,400,000 | ||||||||||||||||||||||||
Payments to Acquire Businesses, Net of Cash Acquired | $ 57,200,000 | ||||||||||||||||||||||||
Business Combination, Consideration Transferred | $ 13,100,000 | ||||||||||||||||||||||||
Tallgrass Energy Partners | Tallgrass Midstream Gathering LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Payments to Acquire Assets | $ 128,500,000 | ||||||||||||||||||||||||
Tallgrass Energy Partners | Terminals and NatGas | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Payments to Acquire Businesses | $ 140,000,000 | ||||||||||||||||||||||||
Deeprock Development, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Equity Method Investment, Ownership Percentage | 20.00% | ||||||||||||||||||||||||
Rockies Express Pipeline LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Equity Method Investment, Ownership Percentage | 49.99% | 49.99% | 49.99% | 25.00% | |||||||||||||||||||||
Subsequent Event | Pony Express Pipeline | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 2.00% | ||||||||||||||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||||||||||||||||||||||
Subsequent Event | Deeprock Development, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 60.00% | ||||||||||||||||||||||||
Subsequent Event | Tallgrass Crude Gathering, LLC | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Miles of gathering pipeline | mi | 50 | ||||||||||||||||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||||||||||||||||||||||
Subsequent Event | Tallgrass Energy Partners | Pony Express Pipeline | |||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||
Acquisition of Rockies Express membership interest | $ 60,000,000 |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | |||
Revenue from Related Parties | $ 8,516 | $ 6,228 | $ 6,331 |
Cost of transportation services with related parties | 10,476 | 18,585 | 18,288 |
Other Deferred Charges | |||
Related Party Transaction [Line Items] | |||
Expenses related to transactions with related parties | 25 | 44 | 7 |
Operations and maintenance | |||
Related Party Transaction [Line Items] | |||
Expenses related to transactions with related parties | 29,881 | 25,431 | 23,658 |
General and administrative | |||
Related Party Transaction [Line Items] | |||
Expenses related to transactions with related parties | 41,032 | 39,574 | 33,820 |
Property, Plant and Equipment | |||
Related Party Transaction [Line Items] | |||
Costs capitalized from transactions with related parties | $ 2,679 | $ 3,084 | $ 4,342 |
Related Party Transactions - 55
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, 2017 | Dec. 31, 2016 |
Related Party Transaction [Line Items] | ||
Accounts receivable from related parties | $ (1,340) | $ (590) |
Accounts payable to related parties | 5,461 | 5,935 |
Rockies Express Pipeline LLC | ||
Related Party Transaction [Line Items] | ||
Accounts receivable from related parties | (1,340) | (590) |
Tallgrass Operations, LLC | ||
Related Party Transaction [Line Items] | ||
Accounts payable to related parties | 5,381 | 5,854 |
Tallgrass Equity, LLC | ||
Related Party Transaction [Line Items] | ||
Accounts payable to related parties | 80 | 68 |
Deeprock Development, LLC | ||
Related Party Transaction [Line Items] | ||
Accounts payable to related parties | $ 0 | $ 13 |
Related Party Transactions - 56
Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Related Party Transaction [Line Items] | ||
Affiliate gas imbalance receivables | $ 18 | $ 177 |
Affiliate gas imbalance payables | $ 442 | $ 0 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Related Party Transactions [Abstract] | |
Interest Income, Related Party | $ 0.4 |
Inventory - Schedule of Compone
Inventory - Schedule of Components of Inventory (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Inventory Disclosure [Abstract] | ||
Crude oil | $ 12,792 | $ 5,462 |
Materials and supplies | 5,891 | 6,383 |
Natural gas liquids | 942 | 265 |
Gas in underground storage | 1,984 | 983 |
Total inventory | $ 21,609 | $ 13,093 |
Property, Plant and Equipment -
Property, Plant and Equipment - Components of Property, Plant and Equipment (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Jul. 21, 2017 | Dec. 31, 2016 |
Property, Plant and Equipment [Line Items] | |||
Accumulated depreciation and amortization | $ 279,192 | $ 195,860 | |
Property, plant and equipment, net | 2,394,337 | 2,079,232 | |
Crude oil pipelines | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | 1,220,379 | 1,202,125 | |
Gathering, processing and terminalling assets (1) | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | 675,092 | 397,701 | |
Natural gas pipelines | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | 581,400 | 572,150 | |
Property, plant and equipment, net | 431,600 | ||
General and other | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | 98,680 | 82,510 | |
Construction work in progress | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | 97,978 | $ 20,606 | |
Tallgrass Midstream Gathering LLC | Gathering, processing and terminalling assets (1) | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | 138,200 | ||
Deeprock Development, LLC | |||
Property, Plant and Equipment [Line Items] | |||
Business Acquisition, Percentage of Voting Interests Acquired | 49.00% | ||
Deeprock Development, LLC | Gathering, processing and terminalling assets (1) | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | 68,400 | ||
Outrigger Energy, LLC | Gathering, processing and terminalling assets (1) | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | $ 29,300 |
Property, Plant and Equipment60
Property, Plant and Equipment - Future Minimum Rental Income (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Property, Plant and Equipment [Abstract] | |
2,018 | $ 4,575 |
2,019 | 4,590 |
2,020 | 3,978 |
2,021 | 3,773 |
2,022 | 3,773 |
Thereafter | 11,127 |
Total | $ 31,816 |
Property, Plant and Equipment61
Property, Plant and Equipment - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |||
Depreciation expense | $ 86.9 | $ 83.2 | $ 76.3 |
Capitalized interest | 1.1 | 0.6 | 0.9 |
Rental income, operating | 3.8 | 3.2 | 0.8 |
Rental income, nonoperating | $ 0.8 | $ 0.8 | $ 0.8 |
Goodwill and Intangible Asset62
Goodwill and Intangible Assets - Schedule of Goodwill by Segment (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Goodwill [Line Items] | |||
Goodwill | $ 404,838 | $ 343,288 | $ 343,288 |
Goodwill, Acquired During Period | 61,550 | 0 | |
Natural Gas Transportation | |||
Goodwill [Line Items] | |||
Goodwill | 255,558 | 255,558 | 255,558 |
Goodwill, Acquired During Period | 0 | 0 | |
Gathering, Processing & Terminalling | |||
Goodwill [Line Items] | |||
Goodwill | 149,280 | 87,730 | $ 87,730 |
Goodwill, Acquired During Period | $ 61,550 | $ 0 |
Goodwill and Intangible Asset63
Goodwill and Intangible Assets - Intangible Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Acquired Finite-Lived Intangible Assets [Line Items] | ||
Accumulated amortization | $ (16,306) | $ (12,451) |
Intangible assets, net | 97,731 | 93,522 |
Use Rights | ||
Acquired Finite-Lived Intangible Assets [Line Items] | ||
Finite-lived Intangible Assets Acquired | 105,973 | 105,973 |
Customer Contracts | ||
Acquired Finite-Lived Intangible Assets [Line Items] | ||
Finite-lived Intangible Assets Acquired | $ 8,064 | $ 0 |
Goodwill and Intangible Asset64
Goodwill and Intangible Assets - Future Amortization (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract] | |
2,017 | $ 4,581 |
2,018 | 4,048 |
2,019 | 3,868 |
2,020 | 3,868 |
2,021 | 3,868 |
Thereafter | 77,498 |
Total | $ 97,731 |
Goodwill and Intangible Asset65
Goodwill and Intangible Assets - Additional Detail (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |||
Amortization of Intangible Assets | $ 3.8 | $ 3 | $ 8 |
Investment in Unconsolidated Af
Investment in Unconsolidated Affiliates - Equity Method Investments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Schedule of Equity Method Investments [Line Items] | |||
Current assets | $ 122,362 | $ 199,958 | |
Noncurrent assets | 5,974,926 | 6,148,203 | |
Current liabilities | 714,037 | 197,305 | |
Noncurrent liabilities | 2,049,189 | 2,656,836 | |
Members' equity | 3,334,062 | 3,494,020 | |
Revenue | 860,115 | 440,838 | $ 18,646 |
Operating income | 480,337 | 203,801 | 13,794 |
Net income to Members | 465,592 | $ 184,314 | $ 13,794 |
Rockies Express Pipeline LLC | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | $ (759,173) | ||
Basis Difference, Amortization Period | 35 years | ||
Long-term Debt | Rockies Express Pipeline LLC | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | $ 29,458 | ||
Property, Plant and Equipment | Rockies Express Pipeline LLC | |||
Schedule of Equity Method Investments [Line Items] | |||
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | $ (788,631) | ||
Basis Difference, Amortization Period | 35 years | ||
Minimum | Long-term Debt | Rockies Express Pipeline LLC | |||
Schedule of Equity Method Investments [Line Items] | |||
Basis Difference, Amortization Period | 2 years | ||
Maximum | Long-term Debt | Rockies Express Pipeline LLC | |||
Schedule of Equity Method Investments [Line Items] | |||
Basis Difference, Amortization Period | 25 years |
Investment in Unconsolidated 67
Investment in Unconsolidated Affiliates - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jul. 21, 2017 | Jul. 20, 2017 | Mar. 31, 2017 | May 06, 2016 | |
Schedule of Equity Method Investments [Line Items] | |||||||
Unconsolidated investments | $ 909,531 | $ 475,625 | |||||
Equity Method Investment, Ownership Percentage | 20.00% | ||||||
Equity in earnings of unconsolidated investments | $ 237,110 | 54,531 | $ 2,759 | ||||
Payments to Acquire Equity Method Investments | $ (45,948) | (50,076) | (383) | ||||
Rockies Express Pipeline LLC | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity Method Investment, Ownership Percentage | 49.99% | 25.00% | |||||
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | $ (759,173) | ||||||
Basis Difference, Amortization Period | 35 years | ||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 2.90% | ||||||
Equity in earnings of unconsolidated investments | $ 235,600 | ||||||
Cash Dividends Paid to Parent Company by Unconsolidated Subsidiaries | 304,700 | ||||||
Payments to Acquire Equity Method Investments | $ (39,300) | ||||||
Tallgrass Energy Partners | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Unconsolidated investments | 461,915 | ||||||
Equity in earnings of unconsolidated investments | $ 51,780 | $ 0 | |||||
Tallgrass Energy Partners | Rockies Express Pipeline LLC | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Unconsolidated investments | $ 436,000 | ||||||
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | $ 386,800 | $ 404,700 | |||||
Deeprock Development, LLC | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Business Acquisition, Percentage of Voting Interests Acquired | 49.00% | ||||||
Deeprock Development, LLC | Kinder Morgan Cushing, LLC | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Business Acquisition, Percentage of Voting Interests Acquired | 40.00% | ||||||
Rockies Express Pipeline LLC | Tallgrass Development LP | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Equity Method Investment, Ownership Percentage | 24.99% | ||||||
Business Acquisition, Percentage of Voting Interests Acquired | 24.99% |
Risk Management - Schedule of F
Risk Management - Schedule of Fair Value of Derivative Contracts (Details) $ in Thousands | Jan. 01, 2016shares | Dec. 31, 2017USD ($)bbl | Dec. 31, 2016USD ($)bbl | Mar. 01, 2015 |
Pony Express Pipeline | ||||
Derivatives, Fair Value [Line Items] | ||||
Business Acquisition, Percentage of Voting Interests Acquired | 31.30% | 33.30% | ||
Equity Option | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | $ 10,676 | |||
Equity Option | Pony Express Pipeline | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative, Term of Contract | 18 months | |||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 6,518,000 | |||
Equity Option | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | $ 0 | 10,676 | ||
Energy commodity derivative contracts | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 291 | |||
Derivative Asset, Fair Value, Gross Liability | $ 116 | |||
Energy commodity derivative contracts | Short | Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 0.3 | |||
Energy commodity derivative contracts | Long | Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | 0.4 | |||
Energy commodity derivative contracts | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | $ 291 | ||
Energy commodity derivative contracts | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Liability | 0 | 116 | ||
Energy Related Derivative | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Liability | $ 2,368 | $ 440 | ||
Energy Related Derivative | Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative, Nonmonetary Notional Amount | bbl | 356,000 | 125,000 | ||
Energy Related Derivative | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Liability | $ 2,368 | $ 440 |
Risk Management - Derivative Co
Risk Management - Derivative Contracts Included in Consolidated Statement of Income (Detail) - Derivatives not designated as hedging contracts - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Energy Related Derivative | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Amount of gain (loss) recognized in income on derivatives | $ 39 | $ (40) | $ 0 |
Energy commodity derivative contracts | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Amount of gain (loss) recognized in income on derivatives | 75 | 74 | 427 |
Equity Option | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Amount of gain (loss) recognized in income on derivatives | $ 1,885 | $ (1,291) | $ 0 |
Risk Management - Schedule of E
Risk Management - Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Equity Option | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | $ 10,676 | |
Energy commodity derivative contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 291 | |
Derivative Asset, Fair Value, Gross Liability | 116 | |
Energy Related Derivative | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Liability | $ 2,368 | 440 |
Quoted prices in active markets for identical assets (Level 1) | Equity Option | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | |
Quoted prices in active markets for identical assets (Level 1) | Energy commodity derivative contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | |
Derivative Asset, Fair Value, Gross Liability | 0 | |
Quoted prices in active markets for identical assets (Level 1) | Energy Related Derivative | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Liability | 0 | 0 |
Significant other observable inputs (Level 2) | Equity Option | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 10,676 | |
Significant other observable inputs (Level 2) | Energy commodity derivative contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 291 | |
Derivative Asset, Fair Value, Gross Liability | 116 | |
Significant other observable inputs (Level 2) | Energy Related Derivative | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Liability | 2,368 | 440 |
Significant unobservable inputs (Level 3) | Equity Option | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | |
Significant unobservable inputs (Level 3) | Energy commodity derivative contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | |
Derivative Asset, Fair Value, Gross Liability | 0 | |
Significant unobservable inputs (Level 3) | Energy Related Derivative | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Gross Liability | $ 0 | $ 0 |
Risk Management - Additional In
Risk Management - Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands | Dec. 31, 2017 | Feb. 01, 2017 | Oct. 31, 2016 | Jul. 21, 2016 | Jan. 01, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Mar. 01, 2015 |
Derivative [Line Items] | |||||||||
Partners' Capital Account, Units, Treasury Units Purchased | 736,262 | ||||||||
Payments for Repurchase of Common Stock | $ 35,300 | $ 35,335 | $ 0 | $ 0 | |||||
Cash in Margin Accounts and Outstanding Letters of Credit | 3 | ||||||||
Equity Option | |||||||||
Derivative [Line Items] | |||||||||
Partners' Capital Account, Units, Treasury Units Purchased | 1,703,094 | 1,251,760 | 3,563,146 | ||||||
Payments for Repurchase of Common Stock | $ 72,400 | $ 53,200 | $ 151,400 | $ 72,381 | $ 204,634 | $ 0 | |||
Pony Express Pipeline | |||||||||
Derivative [Line Items] | |||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 31.30% | 33.30% | |||||||
Option Indexed to Issuer's Equity, Strike Price | $ 42.50 | ||||||||
Pony Express Pipeline | Equity Option | |||||||||
Derivative [Line Items] | |||||||||
Derivative, Term of Contract | 18 months | ||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 6,518,000 |
Long-term Debt - Schedule of De
Long-term Debt - Schedule of Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Tallgrass Energy Partners | ||
Debt Instrument [Line Items] | ||
Less: Deferred financing costs, net (1) | $ (17,737) | $ (7,019) |
Plus: Unamortized premium on 2028 Notes | 3,730 | 0 |
Total long-term debt, net | 2,146,993 | 1,407,981 |
2024 Senior Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt, net | 739,824 | 392,981 |
2024 Senior Notes | Senior Notes | Tallgrass Energy Partners | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | 750,000 | 400,000 |
2028 Senior Notes | ||
Debt Instrument [Line Items] | ||
Total long-term debt, net | 746,169 | |
2028 Senior Notes | Senior Notes | Tallgrass Energy Partners | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | 750,000 | 0 |
Revolving credit facility | ||
Debt Instrument [Line Items] | ||
Total long-term debt, net | 661,000 | 1,015,000 |
Revolving credit facility | Tallgrass Energy Partners | ||
Debt Instrument [Line Items] | ||
Long-term debt, gross | 661,000 | 1,015,000 |
Total long-term debt, net | $ 661,000 | $ 1,015,000 |
Long- term Debt - Capacity unde
Long- term Debt - Capacity under Revolving Credit Facility (Details) - USD ($) | Dec. 31, 2017 | Jun. 02, 2017 | Dec. 31, 2016 |
Tallgrass Energy Partners | |||
Line of Credit Facility [Line Items] | |||
Less: Outstanding borrowings under the revolving credit facility | $ (2,146,993,000) | $ (1,407,981,000) | |
Revolving credit facility | |||
Line of Credit Facility [Line Items] | |||
Less: Outstanding borrowings under the revolving credit facility | (661,000,000) | (1,015,000,000) | |
Revolving credit facility | Tallgrass Energy Partners | |||
Line of Credit Facility [Line Items] | |||
Less: Outstanding borrowings under the revolving credit facility | (661,000,000) | (1,015,000,000) | |
Letters of Credit Outstanding, Amount | (94,000) | 0 | |
Available capacity under the revolving credit facility | 1,088,906,000 | 735,000,000 | |
Wells Fargo Bank, National Association | Tallgrass Energy Partners | |||
Line of Credit Facility [Line Items] | |||
Total capacity under the revolving credit facility | $ 1,750,000,000 | $ 1,750,000,000 | |
Barclays Bank [Member] | Tallgrass Energy Partners | |||
Line of Credit Facility [Line Items] | |||
Total capacity under the revolving credit facility | $ 1,750,000,000 |
Long-term Debt - Carrying Amoun
Long-term Debt - Carrying Amount and Fair Value of TEP's Long-term Debt (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
2024 Senior Notes | ||
Debt Instrument [Line Items] | ||
Fair Value | $ 771,645 | $ 398,000 |
Long-term debt | 739,824 | 392,981 |
2024 Senior Notes | Quoted prices in active markets for identical assets (Level 1) | ||
Debt Instrument [Line Items] | ||
Fair Value | 0 | 0 |
2024 Senior Notes | Significant other observable inputs (Level 2) | ||
Debt Instrument [Line Items] | ||
Fair Value | 771,645 | 398,000 |
2024 Senior Notes | Significant unobservable inputs (Level 3) | ||
Debt Instrument [Line Items] | ||
Fair Value | 0 | 0 |
2028 Senior Notes | ||
Debt Instrument [Line Items] | ||
Fair Value | 758,168 | |
Long-term debt | 746,169 | |
2028 Senior Notes | Quoted prices in active markets for identical assets (Level 1) | ||
Debt Instrument [Line Items] | ||
Fair Value | 0 | |
2028 Senior Notes | Significant other observable inputs (Level 2) | ||
Debt Instrument [Line Items] | ||
Fair Value | 758,168 | |
2028 Senior Notes | Significant unobservable inputs (Level 3) | ||
Debt Instrument [Line Items] | ||
Fair Value | 0 | |
Revolving credit facility | ||
Debt Instrument [Line Items] | ||
Fair Value | 661,000 | 1,015,000 |
Long-term debt | 661,000 | 1,015,000 |
Revolving credit facility | Quoted prices in active markets for identical assets (Level 1) | ||
Debt Instrument [Line Items] | ||
Fair Value | 0 | 0 |
Revolving credit facility | Significant other observable inputs (Level 2) | ||
Debt Instrument [Line Items] | ||
Fair Value | 661,000 | 1,015,000 |
Revolving credit facility | Significant unobservable inputs (Level 3) | ||
Debt Instrument [Line Items] | ||
Fair Value | $ 0 | $ 0 |
Long-term Debt - Additional Inf
Long-term Debt - Additional Information (Detail) | Dec. 11, 2017USD ($) | Sep. 15, 2017USD ($) | May 16, 2017USD ($) | Sep. 01, 2016USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Jun. 02, 2017USD ($) |
Debt Instrument [Line Items] | ||||||||
Proceeds from issuance of long-term debt | $ 1,103,750,000 | $ 400,000,000 | $ 0 | |||||
Weighted average interest rate on outstanding borrowings | 3.24% | |||||||
Debt Instrument, Interest Rate, Effective Percentage | 3.31% | |||||||
Maximum | ||||||||
Debt Instrument [Line Items] | ||||||||
Credit facility commitment fee | 0.50% | |||||||
Minimum | ||||||||
Debt Instrument [Line Items] | ||||||||
Credit facility commitment fee | 0.25% | |||||||
Revolving credit facility | Maximum | ||||||||
Debt Instrument [Line Items] | ||||||||
Consolidated leverage ratio | 5 | |||||||
Contingent Consolidated Leverage Ratio | 5.50 | |||||||
Consolidated Senior Secured Leverage Ratio One | 3.75 | |||||||
Revolving credit facility | Minimum | ||||||||
Debt Instrument [Line Items] | ||||||||
Consolidated interest coverage ratio | 2.50 | |||||||
Tallgrass Energy Partners | ||||||||
Debt Instrument [Line Items] | ||||||||
Line of Credit Facility, Maximum Potential Accordion Feature | $ 250,000,000 | |||||||
Increase in Swingline Borrowings | 60,000,000 | |||||||
Sublimit for Letters of Credit | 75,000,000 | |||||||
Tallgrass Energy Partners | Wells Fargo Bank, National Association | ||||||||
Debt Instrument [Line Items] | ||||||||
Total capacity under the revolving credit facility | $ 1,750,000,000 | $ 1,750,000,000 | ||||||
Senior Notes | Tallgrass Energy Partners | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.50% | |||||||
2028 Senior Notes | Senior Notes | Tallgrass Energy Partners | ||||||||
Debt Instrument [Line Items] | ||||||||
Proceeds from issuance of long-term debt | $ 250,000,000 | $ 500,000,000 | ||||||
2024 Senior Notes | Senior Notes | Tallgrass Energy Partners | ||||||||
Debt Instrument [Line Items] | ||||||||
Proceeds from issuance of long-term debt | $ 350,000,000 | $ 400,000,000 |
Partnership Equity and Distri76
Partnership Equity and Distributions - Summary of Distributions (Detail) - Tallgrass Energy Partners - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | |||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | |
Distribution Made to Limited Partner [Line Items] | ||||||||||||
Limited Partner Common and Subordinated Distributions | $ 70,638 | $ 69,174 | $ 67,671 | $ 60,486 | $ 58,793 | $ 57,332 | $ 54,442 | $ 48,238 | $ 42,984 | $ 36,347 | $ 35,135 | $ 31,322 |
Incentive Distribution Rights Distributions | 39,125 | 37,744 | 36,342 | 29,840 | 28,358 | 26,987 | 24,262 | 19,816 | 15,332 | 11,567 | 10,418 | 6,934 |
General Partner Distributions | 1,251 | 1,219 | 1,186 | 1,040 | 1,008 | 976 | 911 | 830 | 724 | 660 | 627 | 530 |
Total Distributions | $ 111,014 | $ 108,137 | $ 105,199 | $ 91,366 | $ 88,159 | $ 85,295 | $ 79,615 | $ 68,884 | $ 59,040 | $ 48,574 | $ 46,180 | $ 38,786 |
Distributions per Limited Partner unit | $ 0.9650 | $ 0.9450 | $ 0.9250 | $ 0.8350 | $ 0.8150 | $ 0.7950 | $ 0.7550 | $ 0.7050 | $ 0.6400 | $ 0.6000 | $ 0.5800 | $ 0.5200 |
Partnership Equity and Distri77
Partnership Equity and Distributions - Additional Information (Detail) | Feb. 01, 2017USD ($)$ / sharesshares | Oct. 31, 2016USD ($)shares | Jul. 21, 2016USD ($)shares | Apr. 28, 2016USD ($)shares | Jan. 01, 2016USD ($)shares | Mar. 30, 2015USD ($)shares | Feb. 27, 2015USD ($)$ / sharesshares | Dec. 31, 2017USD ($)$ / sharesshares | Dec. 31, 2016USD ($)$ / sharesshares | Dec. 31, 2015USD ($)$ / sharesshares | Mar. 31, 2017USD ($) | May 17, 2016USD ($) | Feb. 17, 2016USD ($) | May 13, 2015USD ($) | Mar. 01, 2015 | Feb. 17, 2015shares |
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Authorized amount | $ 657,500,000 | $ 100,000,000 | ||||||||||||||
Partners' Capital Account, Units, Sold in Public Offering | shares | 1,200,000 | 10,000,000 | 2,341,061 | 7,696,708 | 65,744 | |||||||||||
SharesIssuedWeightedAveragePricePerShare | $ / shares | $ 48.82 | $ 44.46 | $ 45.58 | |||||||||||||
Issuance of units to public, net of offering costs | $ 337,700,000 | $ 3,000,000 | ||||||||||||||
LimitedPartnerOfferingCosts | $ 1,900,000 | 4,500,000 | 30,000 | |||||||||||||
Partners' Capital Account, Units, Treasury Units Purchased | shares | 736,262 | |||||||||||||||
Payments for Repurchase of Common Stock | $ 35,300,000 | 35,335,000 | 0 | 0 | ||||||||||||
Treasury Stock Acquired, Average Cost Per Share | $ / shares | $ 47.99 | |||||||||||||||
Partners' Capital Account, Private Placement of Units | shares | 2,416,987 | |||||||||||||||
Proceeds from private placement, net of offering costs | $ 90,000,000 | 0 | 90,009,000 | 0 | ||||||||||||
General Partner Equity Purchase Plan, Authorized Amount | $ 100,000,000 | |||||||||||||||
Shares Issued, Price Per Share | $ / shares | $ 50.82 | |||||||||||||||
Shares Issued, Price Per Share, Net of Underwriters Discount | $ / shares | $ 49.29 | |||||||||||||||
Proceeds from public offering, net of offering costs | $ 59,300,000 | $ 492,400,000 | $ 112,420,000 | $ 337,671,000 | 554,084,000 | |||||||||||
General partner interest in TEP | 1.13% | |||||||||||||||
General Partner Units | shares | 834,391 | 834,391 | ||||||||||||||
Pony Express Pipeline | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Distributions to noncontrolling interests | $ 0 | $ 425,882,000 | 0 | |||||||||||||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 2.00% | |||||||||||||||
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 | |||||||||||||||
Ownership Interests Held By Tallgrass MLP GP, LLC | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
General Partner Units | shares | 834,391 | |||||||||||||||
Pony Express Pipeline | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 31.30% | 33.30% | ||||||||||||||
Distributions to noncontrolling interests | $ 475,000,000 | |||||||||||||||
Tallgrass Development LP | Rockies Express Pipeline LLC | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 24.99% | |||||||||||||||
General Partner | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Issuance of units to public, net of offering costs | $ 0 | 0 | 0 | |||||||||||||
Payments for Repurchase of Common Stock | 0 | |||||||||||||||
Proceeds from private placement, net of offering costs | 0 | |||||||||||||||
Partial exercise of call option | (12,561,000) | (33,993,000) | ||||||||||||||
Contributions from TD | 2,301,000 | 17,894,000 | $ 20,000,000 | |||||||||||||
Contributions from noncontrolling interests | 0 | 0 | 0 | |||||||||||||
Distributions to noncontrolling interests | 0 | 0 | 0 | |||||||||||||
General Partner | Pony Express Pipeline | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Acquisitions | (279,967,000) | (324,328,000) | ||||||||||||||
General Partner | Terminals and NatGas | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Acquisitions | (57,705,000) | |||||||||||||||
General Partner | Rockies Express Pipeline LLC | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Acquisitions | $ 63,681,000 | |||||||||||||||
Thereafter | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Percentage of unit holders | 50.00% | |||||||||||||||
Percentage of general partner | 50.00% | |||||||||||||||
Minimum Quarterly Distribution | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Distributions per Limited Partner unit | $ / shares | $ 0.2875 | |||||||||||||||
First Target Distribution | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
General partner interest in TEP | 2.00% | |||||||||||||||
Percentage of unit holders | 98.00% | |||||||||||||||
Percentage of general partner | 2.00% | |||||||||||||||
Incentive distribution per unit | $ / shares | $ 0.3048 | |||||||||||||||
Second Target Distribution | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Increasing incentive distribution right | 13.00% | |||||||||||||||
Percentage of unit holders | 85.00% | |||||||||||||||
Percentage of general partner | 15.00% | |||||||||||||||
Incentive distribution per unit | $ / shares | $ 0.3536 | |||||||||||||||
Third Target Distribution | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Increasing incentive distribution right | 23.00% | |||||||||||||||
Percentage of unit holders | 75.00% | |||||||||||||||
Percentage of general partner | 25.00% | |||||||||||||||
Incentive distribution per unit | $ / shares | $ 0.4313 | |||||||||||||||
Thereafter | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Increasing incentive distribution right | 48.00% | |||||||||||||||
Equity Option | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Partners' Capital Account, Units, Treasury Units Purchased | shares | 1,703,094 | 1,251,760 | 3,563,146 | |||||||||||||
Payments for Repurchase of Common Stock | $ 72,400,000 | $ 53,200,000 | $ 151,400,000 | $ 72,381,000 | $ 204,634,000 | $ 0 | ||||||||||
Equity Option | Pony Express Pipeline | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares | 6,518,000 |
Commitments and Contingencies -
Commitments and Contingencies - Schedule of Future Minimum Rental Payments for Operating Leases (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2,018 | $ 1,226 |
2,019 | 1,351 |
2,020 | 1,414 |
2,021 | 1,093 |
2,022 | 828 |
Thereafter | 4,394 |
Total Rental Commitments | $ 10,306 |
Commitments and Contingencies79
Commitments and Contingencies - Other Commitments (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2,018 | $ 2,084 |
2,019 | 2,091 |
2,020 | 2,070 |
2,021 | 20 |
2,022 | 20 |
Thereafter | 48 |
Total Other Purchase Obligations | $ 6,333 |
Commitments and Contingencies80
Commitments and Contingencies - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Rent Expense | $ 9,500,000 | $ 16,500,000 | $ 16,100,000 |
Commitments for Future Capital Expenditures | 17,300,000 | ||
Other Cost and Expense, Operating | $ 2,500,000 | $ 1,400,000 | $ 4,000 |
Net Income per Limited Partne81
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 | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |||||||||||
Net income | $ 440,489 | $ 274,889 | $ 197,171 | ||||||||
Net income attributable to noncontrolling interests | (6,499) | (4,365) | (24,268) | ||||||||
Net income attributable to partners | $ 89,115 | $ 184,090 | $ 89,880 | $ 70,905 | $ 70,264 | $ 64,345 | $ 88,160 | $ 47,755 | 433,990 | 270,524 | 172,903 |
Predecessor operations interest in net income | 0 | (6,995) | (12,357) | ||||||||
General partner interest in net income | (147,823) | (102,465) | (46,478) | ||||||||
Net income available to common unitholders | $ 48,985 | $ 144,281 | $ 52,579 | $ 40,322 | $ 37,559 | $ 33,060 | $ 66,728 | $ 23,717 | $ 286,167 | $ 161,064 | $ 114,068 |
Basic net income per common unit | $ 0.67 | $ 1.97 | $ 0.72 | $ 0.56 | $ 0.52 | $ 0.45 | $ 0.93 | $ 0.35 | $ 3.93 | $ 2.26 | $ 1.95 |
Diluted net income per common unit | $ 0.67 | $ 1.96 | $ 0.72 | $ 0.55 | $ 0.51 | $ 0.45 | $ 0.92 | $ 0.35 | $ 3.90 | $ 2.23 | $ 1.91 |
Basic average number of common units outstanding | 72,876 | 71,150 | 58,597 | ||||||||
Equity Participation Unit equivalent units | 582 | 957 | 978 | ||||||||
Diluted average number of common units outstanding | 73,458 | 72,107 | 59,575 |
Major Customers and Concentra82
Major Customers and Concentration of Credit Risk- Schedule of Concentration of Risk by Risk Factor (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Natural Gas Transportation | |
Concentration Risk [Line Items] | |
Concentration Risk, Percentage | 56.00% |
Crude Oil Transportation | |
Concentration Risk [Line Items] | |
Concentration Risk, Percentage | 91.00% |
Gathering, Processing & Terminalling | |
Concentration Risk [Line Items] | |
Concentration Risk, Percentage | 75.00% |
Major Customers and Concentra83
Major Customers and Concentration of Credit Risk - Additional Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Concentration Risk [Line Items] | |||||||||||
Total revenues | $ 174,766 | $ 175,869 | $ 160,863 | $ 144,400 | $ 162,211 | $ 153,268 | $ 149,015 | $ 147,168 | $ 655,898 | $ 611,662 | $ 542,661 |
Customer advances and deposits | $ 4,900 | $ 4,900 | 4,900 | 4,900 | |||||||
Continental Resources | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Total revenues | $ 100,200 | $ 97,800 | $ 84,500 | ||||||||
Concentration Risk, Percentage | 15.00% | 16.00% | 16.00% | ||||||||
Shell Trading (US) Company | |||||||||||
Concentration Risk [Line Items] | |||||||||||
Total revenues | $ 76,200 | $ 78,600 | |||||||||
Concentration Risk, Percentage | 12.00% | 14.00% |
Equity Based Compensation - Sum
Equity Based Compensation - Summarized Changes in EPUs Outstanding (Detail) - Equity Participation Unit - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Shares | |||
Beginning of period, Shares | (1,339,884) | (1,324,961) | (1,525,750) |
Granted, Shares | 621,400 | 94,750 | 338,591 |
Vested, Shares | (941,858) | (35,998) | (480,555) |
Forfeited, Shares | (30,033) | (43,829) | (58,825) |
End of period, Shares | (989,393) | (1,339,884) | (1,324,961) |
Weighted Average Grant Date Fair Value | |||
Beginning of period, Weighted Average Grant Date Fair Value | $ 24.92 | $ 24.11 | $ 18.75 |
Granted, Weighted Average Grant Date Fair Value | 38.58 | 35.12 | 40.01 |
Vested, Weighted Average Grant Date Fair Value | (19.70) | (23.74) | (19.39) |
Forfeited, Weighted Average Grant Date Fair Value | (39.08) | (20.08) | (16.98) |
End of period, Weighted Average Grant Date Fair Value | $ 38.58 | $ 24.92 | $ 24.11 |
Stock Issued During Period, Shares, Share-based Compensation, Gross | 700,000 | 0 | 300,000 |
Shares Paid for Tax Withholding for Share Based Compensation | 300,000 | 0 | 100,000 |
Equity Based Compensation - Add
Equity Based Compensation - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | |||
Share-based compensation expense related to the EPU grants recognized | $ 10.4 | $ 7.9 | $ 9.3 |
Compensation cost related to nonvested EPUs expected to be recognized | $ 24.6 | ||
Weighted average period in which compensation cost related to nonvested EPUs expected to be recognized | 2 years 8 months | ||
TEP | |||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | |||
Share-based compensation expense related to the EPU grants recognized | $ 8.7 | $ 5.8 | $ 5.1 |
Equity Participation Unit | Section 16 Officers | |||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | |||
Equity participation units granted | 302,500 | ||
Maximum | |||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | |||
Equity participation units granted | 10,000,000 | ||
Maximum | Equity Participation Unit | |||
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items] | |||
Equity participation units granted | 1,865,000 |
Regulatory Matters (Details)
Regulatory Matters (Details) - Bcf / d | 12 Months Ended | ||
Dec. 31, 2017 | Jul. 01, 2017 | Jul. 01, 2016 | |
Public Utilities, General Disclosures [Line Items] | |||
Capacity Enhancement | 0.8 | ||
Pony Express Pipeline | |||
Public Utilities, General Disclosures [Line Items] | |||
FERC Annual Index Adjustment | 0.00% | 2.00% | |
Pony Express Pipeline | Local Non-Contract Rates | |||
Public Utilities, General Disclosures [Line Items] | |||
FERC Annual Index Adjustment | 98.00% |
Legal and Environmental Matte87
Legal and Environmental Matters (Details) | Jul. 12, 2017USD ($) | Feb. 16, 2017USD ($) | Feb. 02, 2017USD ($) | Jan. 12, 2017USD ($)Bcf / d | May 20, 2016USD ($) | Jun. 17, 2014USD ($) | Jan. 31, 2017bbl | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)Bcf / dmi | Dec. 31, 2015mi | Mar. 31, 2017USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Apr. 14, 2016USD ($) |
Loss Contingencies [Line Items] | ||||||||||||||
Environmental accruals | $ 7,700,000 | $ 4,000,000 | $ 7,700,000 | $ 4,000,000 | ||||||||||
Cost of Services, Environmental Remediation | $ 21,800,000 | |||||||||||||
Remediation costs, Anticipated costs | 20,000,000 | |||||||||||||
Aggregate cost of crack tool runs | 8,200,000 | $ 9,800,000 | ||||||||||||
Crude Oil Spilled or Leaked | bbl | 10,000 | |||||||||||||
Crude oil recovered | bbl | 9,000 | |||||||||||||
Total Remediation costs | 600,000 | |||||||||||||
General Partner | ||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||
Contributions from TD | 2,301,000 | $ 17,894,000 | $ 20,000,000 | |||||||||||
Trailblazer | ||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi | 8 | |||||||||||||
Trailblazer | Minimum | ||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi | 25 | |||||||||||||
Trailblazer | Maximum | ||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi | 35 | |||||||||||||
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 | |||||||||||||
Mineral Management Service Lawsuit | ||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||
Litigation Settlement, Amount Awarded from Other Party | $ 65,000,000 | |||||||||||||
Ultra Resources Complaint | ||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||
Litigation Settlement, Amount Awarded from Other Party | $ 150,000,000 | |||||||||||||
Firm transportation service agreement | Bcf / d | 0.2 | 0.2 | ||||||||||||
Gain Contingency, Unrecorded Amount | $ 303,000,000 | |||||||||||||
Firm Transportation Rate | $ 0.37 | |||||||||||||
Anticipated Annual Revenue | $ 26,800,000 | |||||||||||||
Michels Corporation Complaint | ||||||||||||||
Loss Contingencies [Line Items] | ||||||||||||||
Loss Contingency, Damages Sought, Value | $ 24,200,000 | |||||||||||||
Litigation Settlement, Amount Awarded to Other Party | $ 10,000,000 | $ 10,000,000 | ||||||||||||
Withholding for Liquidated Delay Damages and Excess Completion Costs | $ 5,900,000 |
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, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | $ 174,766 | $ 175,869 | $ 160,863 | $ 144,400 | $ 162,211 | $ 153,268 | $ 149,015 | $ 147,168 | $ 655,898 | $ 611,662 | $ 542,661 |
TEP | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 655,898 | 611,662 | 542,661 | ||||||||
TEP | Natural Gas Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 134,327 | 129,456 | 132,604 | ||||||||
TEP | Crude Oil Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 353,898 | 380,133 | 304,227 | ||||||||
TEP | Gathering, Processing & Terminalling | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 167,673 | 102,073 | 105,830 | ||||||||
TEP | Corporate and Other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 0 | 0 | 0 | ||||||||
TEP | Operating Segments | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 691,806 | 629,133 | 555,602 | ||||||||
TEP | Operating Segments | Natural Gas Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 141,021 | 135,097 | 137,988 | ||||||||
TEP | Operating Segments | Crude Oil Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 364,574 | 380,503 | 304,227 | ||||||||
TEP | Operating Segments | Gathering, Processing & Terminalling | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 186,211 | 113,533 | 113,387 | ||||||||
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 | (35,908) | (17,471) | (12,941) | ||||||||
TEP | Inter-Segment | Natural Gas Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | (6,694) | (5,641) | (5,384) | ||||||||
TEP | Inter-Segment | Crude Oil Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | (10,676) | (370) | 0 | ||||||||
TEP | Inter-Segment | Gathering, Processing & Terminalling | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | (18,538) | (11,460) | (7,557) | ||||||||
TEP | Inter-Segment | Corporate and Other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | $ 0 | $ 0 | $ 0 |
Reporting Segments - Summary 89
Reporting Segments - Summary of TEP's Segment Information of Earnings (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation to Net Income: | |||||||||||
Equity in earnings of unconsolidated investments | $ (237,110) | $ (54,531) | $ (2,759) | ||||||||
Gain on remeasurement of unconsolidated investment | 9,728 | 0 | 0 | ||||||||
Interest expense, net of noncontrolling interest | 83,542 | 40,688 | 15,514 | ||||||||
Depreciation and amortization expense, net of noncontrolling interest | 90,800 | 86,247 | 84,258 | ||||||||
Distributions from unconsolidated investments | 237,192 | 54,449 | 3,096 | ||||||||
Non-cash (gain) loss related to derivative instruments | (1,885) | 1,291 | 0 | ||||||||
Net income attributable to partners | $ 89,115 | $ 184,090 | $ 89,880 | $ 70,905 | $ 70,264 | $ 64,345 | $ 88,160 | $ 47,755 | 433,990 | 270,524 | 172,903 |
TEP | |||||||||||
Reconciliation to Net Income: | |||||||||||
Net income attributable to partners | 433,990 | 270,524 | 172,903 | ||||||||
TEP | Natural Gas Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 384,685 | 149,209 | 68,315 | ||||||||
TEP | Crude Oil Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 260,369 | 281,234 | 178,145 | ||||||||
TEP | Gathering, Processing & Terminalling | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 41,416 | 6,726 | 24,686 | ||||||||
TEP | Corporate and Other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | (8,463) | (4,622) | (2,979) | ||||||||
TEP | Operating Segments | Natural Gas Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 392,394 | 154,850 | 73,699 | ||||||||
TEP | Operating Segments | Crude Oil Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 243,106 | 264,391 | 165,204 | ||||||||
TEP | Operating Segments | Gathering, Processing & Terminalling | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 50,970 | 17,928 | 32,243 | ||||||||
TEP | Operating Segments | Corporate and Other | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | (8,463) | (4,622) | (2,979) | ||||||||
TEP | Inter-Segment | Natural Gas Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | (7,709) | (5,641) | (5,384) | ||||||||
TEP | Inter-Segment | Crude Oil Transportation | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 17,263 | 16,843 | 12,941 | ||||||||
TEP | Inter-Segment | Gathering, Processing & Terminalling | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | (9,554) | (11,202) | (7,557) | ||||||||
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 investments | 237,110 | 54,531 | 2,759 | ||||||||
Gain on remeasurement of unconsolidated investment | 9,728 | 0 | 0 | ||||||||
Non-cash loss allocated to noncontrolling interest | 0 | 0 | (9,377) | ||||||||
Interest expense, net of noncontrolling interest | (83,542) | (40,688) | (15,517) | ||||||||
Depreciation and amortization expense, net of noncontrolling interest | (92,455) | (88,122) | (77,111) | ||||||||
Distributions from unconsolidated investments | (306,626) | (78,568) | (4,648) | ||||||||
Non-cash (gain) loss related to derivative instruments | (226) | (1,547) | 0 | ||||||||
Non-cash compensation expense | (8,660) | (5,780) | (5,103) | ||||||||
Gain (loss) on disposal of assets, net of noncontrolling interests | 654 | (1,849) | (4,795) | ||||||||
Loss on extinguishment of debt | $ 0 | $ 0 | $ (226) |
Reporting Segments - Summary 90
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, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Segment Reporting Information [Line Items] | |||
Capital expenditures | $ 145,144 | $ 84,491 | $ 120,718 |
TEP | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | 145,144 | 84,491 | 120,718 |
TEP | Natural Gas Transportation | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | 16,705 | 28,475 | 10,478 |
TEP | Crude Oil Transportation | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | 57,022 | 29,893 | 38,802 |
TEP | Gathering, Processing & Terminalling | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | 71,417 | 26,123 | 71,438 |
TEP | Corporate and Other | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | $ 0 | $ 0 | $ 0 |
Reporting Segments Reporting Se
Reporting Segments Reporting Segments - Summary of TEP's Segment Information of Unconsolidated Investments (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Segment Reporting Information [Line Items] | ||
Unconsolidated investments | $ 909,531 | $ 475,625 |
TEP | ||
Segment Reporting Information [Line Items] | ||
Unconsolidated investments | 909,531 | 475,625 |
TEP | Natural Gas Transportation | ||
Segment Reporting Information [Line Items] | ||
Unconsolidated investments | 895,873 | 461,915 |
TEP | Crude Oil Transportation | ||
Segment Reporting Information [Line Items] | ||
Unconsolidated investments | 0 | 0 |
TEP | Gathering, Processing & Terminalling | ||
Segment Reporting Information [Line Items] | ||
Unconsolidated investments | 13,658 | 13,710 |
TEP | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Unconsolidated investments | $ 0 | $ 0 |
Reporting Segments - Summary 92
Reporting Segments - Summary of TEP's Segment Information of Assets (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Segment Reporting Information [Line Items] | ||
Assets | $ 3,977,353 | $ 3,102,213 |
TEP | ||
Segment Reporting Information [Line Items] | ||
Assets | 3,977,353 | 3,102,213 |
TEP | Natural Gas Transportation | ||
Segment Reporting Information [Line Items] | ||
Assets | 1,606,666 | 1,176,147 |
TEP | Crude Oil Transportation | ||
Segment Reporting Information [Line Items] | ||
Assets | 1,407,758 | 1,410,695 |
TEP | Gathering, Processing & Terminalling | ||
Segment Reporting Information [Line Items] | ||
Assets | 943,340 | 495,170 |
TEP | Corporate and Other | ||
Segment Reporting Information [Line Items] | ||
Assets | $ 19,589 | $ 20,201 |
Reporting Segments - Additional
Reporting Segments - Additional Information (Detail) - Segment | 12 Months Ended | |||
Dec. 31, 2017 | Mar. 31, 2017 | Jan. 01, 2017 | May 06, 2016 | |
Segment Reporting Information [Line Items] | ||||
Number of reportable segments | 3 | |||
Equity Method Investment, Ownership Percentage | 20.00% | |||
Tallgrass Terminals, LLC | ||||
Segment Reporting Information [Line Items] | ||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | |||
Tallgrass NatGas Operator, LLC | ||||
Segment Reporting Information [Line Items] | ||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | |||
Rockies Express Pipeline LLC | ||||
Segment Reporting Information [Line Items] | ||||
Equity Method Investment, Ownership Percentage | 49.99% | 25.00% | ||
Tallgrass Development LP | Rockies Express Pipeline LLC | ||||
Segment Reporting Information [Line Items] | ||||
Business Acquisition, Percentage of Voting Interests Acquired | 24.99% | |||
Equity Method Investment, Ownership Percentage | 24.99% |
Selected Quarterly Financial 94
Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Selected Quarterly Financial Data (Unaudited) [Abstract] | |||||||||||
Total revenues | $ 174,766 | $ 175,869 | $ 160,863 | $ 144,400 | $ 162,211 | $ 153,268 | $ 149,015 | $ 147,168 | $ 655,898 | $ 611,662 | $ 542,661 |
Operating income | 68,236 | 74,567 | 67,504 | 63,780 | 73,830 | 67,511 | 55,307 | 63,966 | 274,087 | 260,614 | 207,513 |
Net income | 92,373 | 185,503 | 90,829 | 71,784 | 71,394 | 65,429 | 89,270 | 48,796 | |||
Net income attributable to partners | 89,115 | 184,090 | 89,880 | 70,905 | 70,264 | 64,345 | 88,160 | 47,755 | 433,990 | 270,524 | 172,903 |
Net income available to common unitholders | $ 48,985 | $ 144,281 | $ 52,579 | $ 40,322 | $ 37,559 | $ 33,060 | $ 66,728 | $ 23,717 | $ 286,167 | $ 161,064 | $ 114,068 |
Basic net income per common unit | $ 0.67 | $ 1.97 | $ 0.72 | $ 0.56 | $ 0.52 | $ 0.45 | $ 0.93 | $ 0.35 | $ 3.93 | $ 2.26 | $ 1.95 |
Diluted net income per common unit | $ 0.67 | $ 1.96 | $ 0.72 | $ 0.55 | $ 0.51 | $ 0.45 | $ 0.92 | $ 0.35 | $ 3.90 | $ 2.23 | $ 1.91 |
Subsequent Events (Details)
Subsequent Events (Details) $ in Thousands | Feb. 06, 2018mi | Feb. 01, 2018USD ($) | Jan. 12, 2018USD ($)a | Jan. 02, 2018USD ($) | Jul. 21, 2017USD ($) | Dec. 31, 2017 | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Jan. 01, 2016 | Mar. 01, 2015 |
Subsequent Event [Line Items] | |||||||||||
Acquisition of Rockies Express membership interest | $ 400,000 | $ 436,022 | $ 0 | ||||||||
Deeprock North, LLC | Subsequent Event | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 38.00% | ||||||||||
Deeprock Development, LLC | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 49.00% | ||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 69.00% | 69.00% | |||||||||
Deeprock Development, LLC | Subsequent Event | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 60.00% | ||||||||||
BNN North Dakota | Subsequent Event | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 100.00% | ||||||||||
Acres for Water Gathering and Disposal System | a | 133,000 | ||||||||||
Pawnee Terminal | Subsequent Event | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 51.00% | ||||||||||
Pony Express Pipeline | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 31.30% | 33.30% | |||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 98.00% | ||||||||||
Pony Express Pipeline | Subsequent Event | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 2.00% | ||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||||||||
Tallgrass Energy Partners | Deeprock North, LLC | Subsequent Event | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Payments to Acquire Businesses | $ 20,000 | ||||||||||
Tallgrass Energy Partners | Deeprock Development, LLC | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Payments to Acquire Businesses | $ 6,400 | ||||||||||
Tallgrass Energy Partners | BNN North Dakota | Subsequent Event | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Payments to Acquire Businesses | $ 95,000 | ||||||||||
Tallgrass Energy Partners | Pawnee Terminal | Subsequent Event | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Payments to Acquire Businesses | $ 31,000 | ||||||||||
Tallgrass Energy Partners | Pony Express Pipeline | Subsequent Event | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Acquisition of Rockies Express membership interest | $ 60,000 | ||||||||||
Tallgrass Crude Gathering, LLC | Subsequent Event | |||||||||||
Subsequent Event [Line Items] | |||||||||||
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest | 100.00% | ||||||||||
Miles of gathering pipeline | mi | 50 |