Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2015 | Nov. 04, 2015 | |
Document Information [Line Items] | ||
Entity Registrant Name | TALLGRASS ENERGY GP, LP | |
Entity Central Index Key | 1,633,651 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus (Q1,Q2,Q3,FY) | Q3 | |
Trading Symbol | TEGP | |
Amendment Flag | false | |
Capital Unit, Class A | ||
Document Information [Line Items] | ||
Entity Common Stock, Shares Outstanding | 47,725,000 | |
Capital Unit, Class B | ||
Document Information [Line Items] | ||
Entity Common Stock, Shares Outstanding | 109,504,440 |
CONDENSED BALANCE SHEETS (UNAU
CONDENSED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Current Assets: | ||
Cash and cash equivalents | $ 19,009 | $ 867 |
Accounts receivable, net | 52,926 | 39,768 |
Receivable from related party | 0 | 73,393 |
Gas imbalances | 862 | 2,442 |
Inventories | 14,132 | 13,045 |
Derivative assets at fair value | 218 | 0 |
Prepayments and other current assets | 3,678 | 2,766 |
Total Current Assets | 90,825 | 132,281 |
Property, plant and equipment, net | 1,948,821 | 1,853,081 |
Goodwill | 343,288 | 343,288 |
Intangible asset, net | 98,502 | 104,538 |
Deferred tax asset | 441,528 | 0 |
Deferred financing costs, net | 6,114 | 5,528 |
Deferred charges and other assets | 15,649 | 18,481 |
Total Assets | 2,944,727 | 2,457,197 |
Current Liabilities: | ||
Accounts payable (including $8,132 and $45,534, respectively, related to VIEs) | 19,627 | 62,329 |
Accounts payable to related parties | 3,581 | 3,915 |
Gas imbalances | 2,629 | 3,611 |
Accrued taxes | 16,624 | 3,989 |
Accrued liabilities | 8,924 | 9,384 |
Deferred revenue | 19,786 | 5,468 |
Other current liabilities | 3,664 | 7,872 |
Total Current Liabilities | 74,835 | 96,568 |
Long-term debt (including $148,000 and $0, respectively, related to VIEs) | 844,000 | 559,000 |
Other long-term liabilities and deferred credits | 5,461 | 6,478 |
Total Long-term Liabilities | $ 849,461 | $ 565,478 |
Commitments and Contingencies | ||
Equity [Abstract] | ||
Total Partners' Capital | $ 410,906 | $ 146,866 |
Noncontrolling interests | 1,609,525 | 1,648,285 |
Total Equity | 2,020,431 | 1,795,151 |
Total Liabilities and Equity | 2,944,727 | 2,457,197 |
Predecessor [Member] | ||
Equity [Abstract] | ||
Total Partners' Capital | 0 | 146,866 |
Common Class A [Member] | ||
Equity [Abstract] | ||
Total Partners' Capital | 410,906 | 0 |
Common Class B [Member] | ||
Equity [Abstract] | ||
Total Partners' Capital | $ 0 | $ 0 |
CONDENSED BALANCE SHEETS CONDEN
CONDENSED BALANCE SHEETS CONDENSED BALANCE SHEETS (UNAUDITED) (Parenthetical) - USD ($) | Sep. 30, 2015 | Dec. 31, 2014 |
Accounts payable (including $8,132 and $45,534, respectively, related to VIEs) | $ 19,627,000 | $ 62,329,000 |
Long-term debt (including $148,000 and $0, respectively, related to VIEs) | $ 844,000,000 | $ 559,000,000 |
Common Class A [Member] | ||
Limited Partners' Capital Account, Units Outstanding | 47,725,000 | 0 |
Common Class B [Member] | ||
Limited Partners' Capital Account, Units Outstanding | 109,504,440 | 0 |
Variable Interest Entity, Primary Beneficiary [Member] | ||
Accounts payable (including $8,132 and $45,534, respectively, related to VIEs) | $ 8,132,000 | $ 45,534,000 |
Long-term debt (including $148,000 and $0, respectively, related to VIEs) | $ 148,000,000 | $ 0 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Revenues: | ||||
Sales of natural gas, NGLs, and crude oil | $ 20,252 | $ 49,130 | $ 62,132 | $ 141,887 |
Natural gas transportation services | 29,431 | 30,745 | 90,620 | 95,418 |
Crude oil transportation services | 81,928 | 0 | 206,331 | 0 |
Processing and other revenues | 6,557 | 10,078 | 26,730 | 24,747 |
Total Revenues | 138,168 | 89,953 | 385,813 | 262,052 |
Operating Costs and Expenses: | ||||
Cost of sales (exclusive of depreciation and amortization shown below) | 18,186 | 45,767 | 54,959 | 131,187 |
Cost of transportation services (exclusive of depreciation and amortization shown below) | 14,862 | 3,329 | 39,069 | 13,734 |
Operations and maintenance | 14,071 | 9,961 | 36,054 | 28,029 |
Depreciation and amortization | 20,802 | 10,071 | 61,762 | 27,905 |
General and administrative | 12,321 | 7,448 | 38,711 | 21,221 |
Taxes, other than income taxes | 5,521 | 1,797 | 16,547 | 5,392 |
Loss on sale of assets | 0 | 0 | 4,483 | 0 |
Total Operating Costs and Expenses | 85,763 | 78,373 | 251,585 | 227,468 |
Operating Income | 52,405 | 11,580 | 134,228 | 34,584 |
Other (Expense) Income: | ||||
Interest expense, net | (4,982) | (1,058) | (12,901) | (4,492) |
Gain on remeasurement of unconsolidated investment | 0 | 0 | 0 | 9,388 |
Equity in earnings of unconsolidated investment | 0 | 0 | 0 | 717 |
Other income, net | 502 | 731 | 1,983 | 2,400 |
Total Other (Expense) Income | (4,480) | (327) | (10,918) | 8,013 |
Net income before tax | 47,925 | 11,253 | 123,310 | 42,597 |
Deferred income tax expense | (1,828) | 0 | (3,600) | 0 |
Net income | 46,097 | 11,253 | 119,710 | 42,597 |
Net income attributable to noncontrolling interests | (41,674) | (9,623) | (105,431) | (35,897) |
Net income attributable to TEGP | 4,423 | $ 1,630 | 14,279 | $ 6,700 |
Net income attributable to TEGP from the beginning of the period to May 11, 2015 | 0 | 7,393 | ||
Net income attributable to TEGP from May 12, 2015 to September 30, 2015 | $ 4,423 | $ 6,886 | ||
Earnings Per Share, Basic | $ 0.09 | $ 0.14 | ||
Diluted net income per Class A share | $ 0.09 | $ 0.14 | ||
Weighted Average Number of Shares Outstanding, Basic | 47,725 | 47,725 | ||
Diluted average number of Class A shares outstanding | 47,808 | 47,812 |
CONDENSED CONSOLIDATED STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Cash Flows from Operating Activities: | ||
Net income | $ 119,710,000 | $ 42,597,000 |
Adjustments to reconcile net income to net cash flows from operating activities: | ||
Depreciation and amortization | 64,755,000 | 28,946,000 |
Deferred tax expense | 3,600,000 | 0 |
Gain on remeasurement of unconsolidated investment | 0 | 9,388,000 |
Noncash compensation expense | 4,183,000 | 3,724,000 |
Loss on sale of assets | 4,483,000 | 0 |
Changes in components of working capital: | ||
Accounts receivable and other | (11,538,000) | 2,592,000 |
Inventories | (5,265,000) | (4,661,000) |
Accounts payable and accrued liabilities | 6,883,000 | (14,990,000) |
Deferred revenue | 13,995,000 | 1,459,000 |
Other operating, net | (5,359,000) | (3,035,000) |
Net Cash Provided by Operating Activities | (195,447,000) | (47,244,000) |
Cash Flows from Investing Activities: | ||
Capital expenditures | (65,146,000) | (642,216,000) |
Acquisition of membership interest in Pony Express | (700,000,000) | (27,000,000) |
Acquisition of Trailblazer | 0 | (150,000,000) |
Acquisition of additional equity interests in Water Solutions | 0 | (7,600,000) |
Issuance of related party loan | 0 | (270,000,000) |
Other investing, net | (4,625,000) | (2,268,000) |
Net Cash Used in Investing Activities | 769,771,000 | 1,099,084,000 |
Net Cash Provided by Financing Activities | ||
Proceeds from initial public offering of Class A shares, net | 1,314,741,000 | 0 |
Acquisition of Acquired TEP Units | (953,600,000) | 0 |
Proceeds from public offering of TEP common units, net | 551,243,000 | 319,588,000 |
Distribution of Excess Proceeds to Exchange Right Holders | (334,068,000) | 0 |
Proceeds from revolver borrowings, net | 285,000,000 | 433,000,000 |
Acquisition of additional Tallgrass Equity units | (171,948,000) | 0 |
Distributions to TEP unitholders | (74,843,000) | (23,766,000) |
Contribution from Noncontrolling Interest | 19,303,000 | 0 |
Payments of Ordinary Dividends, Noncontrolling Interest | 12,969,000 | 0 |
(Distributions to) Contributions from TEGP Predecessor, net | (13,533,000) | 289,437,000 |
Distribution Made to Limited Partner, Cash Distributions Paid | 3,484,000 | 0 |
Contribution from TD | 0 | 27,488,000 |
Other financing, net | (13,376,000) | 6,978,000 |
Net Cash Provided by Financing Activities | 592,466,000 | 1,052,725,000 |
Net Change in Cash and Cash Equivalents | ||
Net Change in Cash and Cash Equivalents | 18,142,000 | 885,000 |
Cash and Cash Equivalents, beginning of period | 867,000 | 0 |
Cash and Cash Equivalents, end of period | 19,009,000 | 885,000 |
Supplemental Disclosures: | ||
Property, plant and equipment acquired via the cash management agreement with TD | 120,254,000 | 32,479,000 |
Contributions from noncontrolling interests settled via the cash management agreement with TD | 43,401,000 | 0 |
Distribution to noncontrolling interests settled via the cash management agreement with TD | 44,142,000 | 0 |
Increase in accrual for payment of property, plant and equipment | $ 0 | $ 2,903,000 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (UNAUDITED) - USD ($) $ in Thousands | Total | Tallgrass Energy Partners [Member] | Noncontrolling Interest [Member] | Noncontrolling Interest [Member]Trailblazer [Member] | Noncontrolling Interest [Member]Pony Express Pipeline [Member] | Noncontrolling Interest [Member]Water Solutions [Member] | Noncontrolling Interest [Member]Tallgrass Energy GP, LP (TEGP) [Member] | Noncontrolling Interest [Member]Tallgrass Energy Partners [Member] | Noncontrolling Interest [Member]Tallgrass Energy Partners [Member]Water Solutions [Member] | Noncontrolling Interest [Member]Tallgrass Equity, LLC [Member] | Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member]Trailblazer [Member] | Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member]Pony Express Pipeline [Member] | Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member]Water Solutions [Member] | Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member]Tallgrass Energy GP, LP (TEGP) [Member] | Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member]Tallgrass Energy Partners [Member] | Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member]Tallgrass Energy Partners [Member]Water Solutions [Member] | Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member]Tallgrass Equity, LLC [Member] | Common Class A [Member] | Common Class A [Member]Trailblazer [Member] | Common Class A [Member]Pony Express Pipeline [Member] | Common Class A [Member]Water Solutions [Member] | Common Class A [Member]Tallgrass Energy GP, LP (TEGP) [Member] | Common Class A [Member]Tallgrass Energy Partners [Member] | Common Class A [Member]Tallgrass Energy Partners [Member]Water Solutions [Member] | Common Class A [Member]Tallgrass Equity, LLC [Member] | Common Class B [Member] | Common Class B [Member]Trailblazer [Member] | Common Class B [Member]Pony Express Pipeline [Member] | Common Class B [Member]Water Solutions [Member] | Common Class B [Member]Tallgrass Energy GP, LP (TEGP) [Member] | Common Class B [Member]Tallgrass Energy Partners [Member] | Common Class B [Member]Tallgrass Energy Partners [Member]Water Solutions [Member] | Common Class B [Member]Tallgrass Equity, LLC [Member] | Tallgrass Energy GP, LP Predecessor [Member] | Tallgrass Energy GP, LP Predecessor [Member]Trailblazer [Member] | Tallgrass Energy GP, LP Predecessor [Member]Pony Express Pipeline [Member] | Tallgrass Energy GP, LP Predecessor [Member]Water Solutions [Member] | Tallgrass Energy GP, LP Predecessor [Member]Tallgrass Energy GP, LP (TEGP) [Member] | Tallgrass Energy GP, LP Predecessor [Member]Tallgrass Energy Partners [Member] | Tallgrass Energy GP, LP Predecessor [Member]Tallgrass Energy Partners [Member]Water Solutions [Member] | Tallgrass Energy GP, LP Predecessor [Member]Tallgrass Equity, LLC [Member] |
Increase (Decrease) in Partners' Capital [Roll Forward] | ||||||||||||||||||||||||||||||||||||||||||
Partners' Capital | $ 1,158,230 | $ 1,309,101 | $ 0 | $ 0 | $ 150,871 | |||||||||||||||||||||||||||||||||||||
Net income | $ 42,597 | 35,897 | 42,597 | 0 | 0 | 6,700 | ||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Public Sale of Units Net of Offering Costs | $ 274,226 | $ 319,588 | $ 0 | $ 0 | $ 45,362 | |||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Acquisitions | $ (116,629) | $ (16,125) | $ 1,400 | $ (150,000) | $ (27,000) | $ 1,400 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ (33,371) | $ (10,875) | $ 0 | |||||||||||||||||||||||||||
Acquisition of Acquired TEP Units from TD | 0 | |||||||||||||||||||||||||||||||||||||||||
Distribution of excess Offering proceeds to Exchange Right Holders | 0 | |||||||||||||||||||||||||||||||||||||||||
Acquisition of additional equity interests | 0 | |||||||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Distributions | (23,766) | (23,766) | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||
Noncash compensation expense | 7,443 | 7,443 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||
Contribution from Noncontrolling Interest | 0 | 5,429 | 5,429 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders | 37 | 37 | 37 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||
Payments of Ordinary Dividends, Noncontrolling Interest | 0 | |||||||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | 0 | |||||||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Sale of Units | 183 | 263 | 0 | 0 | 80 | |||||||||||||||||||||||||||||||||||||
Contribution from TD | (27,488) | (19,144) | 27,488 | 0 | 0 | (8,344) | ||||||||||||||||||||||||||||||||||||
(Distributions to) Contributions from TEGP Predecessor, net | (289,437) | (310,534) | (289,437) | 0 | 0 | (21,097) | ||||||||||||||||||||||||||||||||||||
Partners' Capital | 1,655,929 | 1,801,943 | 0 | 0 | 146,014 | |||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Distributions | $ (28,294) | |||||||||||||||||||||||||||||||||||||||||
Partners' Capital | 146,866 | 1,648,285 | 1,795,151 | 0 | 0 | 146,866 | ||||||||||||||||||||||||||||||||||||
Net income | 119,710 | |||||||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Public Sale of Units Net of Offering Costs | $ 0 | 487,766 | $ 1,314,741 | 551,243 | $ 1,314,741 | 0 | $ 0 | 0 | $ 0 | 63,477 | ||||||||||||||||||||||||||||||||
Partners' Capital Account, Acquisitions | $ (601,554) | $ (700,000) | $ 0 | $ 0 | $ (98,446) | |||||||||||||||||||||||||||||||||||||
Distribution to Predecessor | (9,425) | (13,533) | 0 | 13,500 | 0 | (4,108) | ||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Exchanges and Conversions | 0 | 0 | 115,182 | 0 | (115,182) | |||||||||||||||||||||||||||||||||||||
Acquisition of Acquired TEP Units from TD | 953,600 | 0 | (953,600) | (953,600) | 0 | 0 | ||||||||||||||||||||||||||||||||||||
Distribution of excess Offering proceeds to Exchange Right Holders | 334,068 | 0 | (334,068) | (334,068) | 0 | 0 | ||||||||||||||||||||||||||||||||||||
Acquisition of additional equity interests | 171,948 | 0 | $ (600) | (171,948) | $ (600) | (171,948) | $ 0 | 0 | $ 0 | 0 | $ 0 | |||||||||||||||||||||||||||||||
Deferred Tax Asset | 0 | 445,128 | 445,128 | 0 | 0 | |||||||||||||||||||||||||||||||||||||
Issuance of common units under TEP LTIP plan | (5,901) | (6,562) | (661) | 0 | 0 | |||||||||||||||||||||||||||||||||||||
Partners' Capital Account, Distributions | $ 0 | $ (74,843) | $ (7,465) | $ (74,843) | $ (7,465) | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | ||||||||||||||||||||||||||||||||
Noncash compensation expense | 7,325 | 7,520 | 195 | 0 | 0 | |||||||||||||||||||||||||||||||||||||
Contribution from Noncontrolling Interest | 19,303 | (110,553) | (110,553) | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders | 44,543 | 44,543 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||
Payments of Ordinary Dividends, Noncontrolling Interest | 12,969 | $ 12,969 | $ 12,969 | $ 0 | $ 0 | $ 0 | ||||||||||||||||||||||||||||||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | 3,484 | 0 | 3,484 | 3,484 | 0 | 0 | ||||||||||||||||||||||||||||||||||||
Contribution from TD | 0 | |||||||||||||||||||||||||||||||||||||||||
(Distributions to) Contributions from TEGP Predecessor, net | 13,533 | |||||||||||||||||||||||||||||||||||||||||
Partners' Capital | $ 410,906 | $ 1,609,525 | $ 2,020,431 | $ 410,906 | $ 0 | $ 0 |
Description of Business
Description of Business | 9 Months Ended |
Sep. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of Business | Tallgrass Energy GP, LP ("TEGP" or the "Partnership") is a limited partnership that has elected to be treated as a corporation for U.S. federal income tax purposes. TEGP was formed as part of the reorganization of entities controlled by Tallgrass Equity, LLC ("Tallgrass Equity") to effect the initial public offering of Class A shares of TEGP (the "Offering"), which was completed on May 12, 2015. Prior to closing the Offering, Tallgrass Equity held a 100% membership interest in Tallgrass Energy Holdings, LLC ("Holdings"). Holdings, in turn, held a 100% limited partner interest in TEGP and a 100% membership interest in TEGP Management, LLC ("TEGP Management"), the general partner of TEGP. In connection with the closing of the Offering on May 12, 2015, the following transactions (the “Reorganization Transactions”) occurred: • Tallgrass Equity distributed its membership interest in Holdings to its members, pro rata, and Holdings distributed its 100% limited partner interest in TEGP, respectively, to its members, pro rata, which are referred to as the “Exchange Right Holders”; • TEGP issued 47,725,000 Class A shares to the public for net proceeds of approximately $1.3 billion , including 6,225,000 Class A shares issued in connection with the underwriters' exercise of the overallotment option; • The existing limited partner interests in TEGP held by the Exchange Right Holders were converted into 115,729,440 Class B shares, 6,225,000 of which were automatically canceled in connection with the underwriters’ exercise of the overallotment option, resulting in the Exchange Right Holders owning 109,504,440 Class B shares; • Tallgrass Equity issued 41,500,000 Tallgrass Equity units to TEGP in exchange for approximately $1.1 billion in net proceeds from the issuance of TEGP’s Class A shares to the public and amended the limited liability company agreement of Tallgrass Equity to, among other things, provide that TEGP is the managing member of Tallgrass Equity; • TEGP used the net proceeds from the purchase of the 6,225,000 overallotment option shares to purchase Tallgrass Equity units from the Exchange Right Holders; and • Tallgrass Equity entered into a $150 million revolving credit facility and borrowed $150 million thereunder, using the aggregate proceeds from such borrowings together with the net proceeds from the Offering that Tallgrass Equity received from TEGP, to purchase 20,000,000 common units, representing limited partner interests in Tallgrass Energy Partners, LP ("TEP"), from Tallgrass Development, LP ("TD") at $47.68 per TEP common unit (the “Acquired TEP Units”) and pay offering expenses and other transaction costs. Tallgrass Equity distributed substantially all of the remaining proceeds (the "Excess Proceeds") to the Exchange Right Holders, retaining approximately $3 million for short term working capital needs, which will ultimately be distributed to the Exchange Right Holders to the extent not used to pay offering expenses and other transaction costs. TEGP's sole cash-generating asset is an approximate 30.35% controlling interest in Tallgrass Equity. Tallgrass Equity's sole cash-generating assets consist of direct and indirect partnership interests in TEP, described below, that were historically owned by entities controlled by Tallgrass Equity, including TD: • 100% of the outstanding membership interests in Tallgrass MLP GP, LLC ("TEP GP"), which owns the general partner interest in TEP as well as all of the TEP incentive distribution rights ("IDRs"). The general partner interest in TEP is represented by 834,391 general partner units, representing a 1.36% general partner interest in TEP at September 30, 2015 . • The Acquired TEP Units, representing an approximately 32.57% limited partner interest in TEP at September 30, 2015 . The term "TEGP Predecessor" refers to TEGP, as recast to show the effects of the Reorganization Transactions, for the periods prior to completion of the Offering on May 12, 2015. "We," "us," "our" and similar terms refer to TEGP together with its consolidated subsidiaries or to TEGP Predecessor together with its consolidated subsidiaries, as the context requires, including, in both cases, Tallgrass Equity and TEP (and their respective subsidiaries). |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2015 | |
Accounting Policies [Abstract] | |
Basis of Presentation and Significant Accounting Policies [Text Block] | Basis of Presentation These unaudited condensed consolidated financial statements and related notes for the three and nine months ended September 30, 2015 and 2014 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2015 and 2014 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair presentation of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Our financial results for the three and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2015. The accompanying unaudited condensed consolidated interim financial statements should be read in conjunction with our final prospectus dated May 6, 2015 (the “Prospectus”) included in our Registration Statement on Form S-1, as amended (SEC File No. 333-202258) and filed with the United States Securities and Exchange Commission (the “SEC”) pursuant to Rule 424 on May 7, 2015. The unaudited condensed consolidated financial statements of TEGP as of December 31, 2014 and for the three and nine months ended September 30, 2014 , include historical cost basis accounts of the assets of TEGP and were prepared in contemplation of TEGP’s initial public offering of Class A shares completed on May 12, 2015 and the acquisition of an approximately 30.35% interest in Tallgrass Equity as described in Note 1 – Description of Business , which was accounted for as a transaction between entities under common control in accordance with ASC 805. Significant intra-entity items have been eliminated in the presentation. Both TEGP and TEGP Predecessor are considered entities under common control and, as such, the transfer between the entities of the assets and liabilities has been recorded by TEGP at historical cost. TEGP, as used herein, refers to the consolidated financial results and operations for TEGP Predecessor prior to the completion of the Offering and to TEGP thereafter. Net income or loss from consolidated subsidiaries that are not wholly-owned by TEGP are attributed to TEGP 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 TEGP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express") effective September 1, 2014, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million (prorated to approximately $5.4 million for the quarter ended September 30, 2014) through the quarter ended September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ending December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 will be attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests. A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity’s economic performance. We have presented separately in our condensed consolidated balance sheets, to the extent material, the assets of our consolidated VIEs that can only be used to settle specific obligations of the consolidated VIEs, and the liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Tallgrass Equity and Pony Express are considered to be VIEs under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, we have determined that we have the power to direct matters that most significantly impact the activities of Tallgrass Equity and Pony Express and have the right to receive benefits of Tallgrass Equity and Pony Express that could potentially be significant to the respective entities. We have consolidated Tallgrass Equity as we are the primary beneficiary. We also consolidate Pony Express through our indirect investment in TEP, as TEP is the primary beneficiary of Pony Express. For additional information see Note 3 – Variable Interest Entities . Use of Estimates Certain amounts included in or affecting these condensed consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts reported for assets, liabilities, revenues, and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Management evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from these estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. 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 and distributions included in the condensed consolidated statements of cash flows represent transfers of cash as a result of TD’s centralized cash management systems prior to April 1, 2014 for Trailblazer Pipeline Company LLC ("Trailblazer") and September 1, 2014 for Pony Express, under which cash balances were swept periodically and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions. Pony Express participates in a cash management agreement with TD, which holds a 33.3% common membership interest in Pony Express, under which cash balances are swept daily and recorded as loans from Pony Express to TD. All payable and receivable balances between TEGP and TD are cash settled with the exception of certain balances payable from Pony Express to TD, which have been settled against the receivable from TD via the Pony Express cash management agreement discussed in the prior paragraph. 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 $0.7 million and $0.5 million at September 30, 2015 and December 31, 2014 . Inventories Inventories primarily consist of gas in underground storage, materials and supplies, natural gas liquids and crude oil. Gas in underground storage, sometimes referred to as working gas, and natural gas liquids are recorded at the lower of historical cost or market using the average cost method. As discussed further under " Revenue Recognition " below, a loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil, which we can then sell. As pipeline allowance oil is accumulated, it is recorded as inventory at the lower of historical cost or market using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence. For additional information, see " Gas in Underground Storage " below. Accounting for Regulatory Activities Regulated activities are accounted for in accordance with the "Regulated Operations" Topic of the Codification. This Topic prescribes the circumstances in which the application of GAAP is affected by the economic effects of regulation. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. We had recorded regulatory assets of approximately $1.2 million and $1.4 million included in "Deferred charges and other assets" in the condensed consolidated balance sheets at September 30, 2015 and December 31, 2014 , respectively. Regulatory assets at September 30, 2015 and December 31, 2014 were primarily attributable to costs associated with Trailblazer’s 2013 Rate Case Filing as more fully described in Note 13 – 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 directly related to the construction of assets, including internal labor costs, interest and engineering costs. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred. Intangible Assets We account for intangible assets in accordance with ASC 805, which established that an intangible asset is identifiable if it meets either the separability criterion or the contractual-legal criterion. Further, in accordance with ASC 805, contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of the Tallgrass Interstate Gas Transmission, LLC ("TIGT") natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years , the period of expected future benefit. Intangible assets arose at BNN Redtail, LLC ("Redtail") as a result of a significant customer contract with favorable market terms which was acquired as part of the BNN Water Solutions, LLC ("Water Solutions") transaction discussed in Note 4 – Acquisitions . This intangible asset is amortized on a straight-line basis over a period of 1.6 years , the remaining term of the contract 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 may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset’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 is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Examples of long-lived asset impairment indicators include: • a significant decrease in the market value of a long-lived asset or group; • a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition; • a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process; • an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group; • a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and • a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. When an impairment indicator is present, we first assesses the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset to the carrying amount of the asset. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the assets is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized. Gas in Underground Storage Gas in underground storage represents the cost of base gas, which refers to the volumes necessary to maintain pressure and deliverability requirements in our storage facilities. We record base gas as a component of property, plant and equipment. We maintain working gas in our underground storage facilities on behalf of certain third parties. We receive a fee for our storage services but do not reflect the value of third party gas in the accompanying condensed consolidated financial statements. We occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost or market. Depreciation and Amortization - Regulated Assets For our regulated assets at TIGT and Trailblazer, we have elected to compute depreciation using a composite method employed by applying a single, FERC approved depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. The annualized rate of depreciation ranges from 0.70% to 12.00% for the various classes of depreciable, regulated assets. Depreciation and Amortization - Non-regulated Assets For non-regulated assets, we have elected to use the straight-line method of depreciation. The useful lives for the various classes of non-regulated depreciable assets are as follows: Range of Useful Lives (in years) Crude oil pipelines 35 Processing & Treating 30 Natural gas pipelines (1) 10 General & Other 3-13 1/3 (1) Includes the Replacement Gas Facilities as discussed in Note 5 – Related Party Transactions and Note 13 – Regulatory Matters . Gas Imbalances Gas imbalances receivable and payable represent the difference between customer nominations and actual gas receipts from, and gas deliveries to, interconnecting pipelines under various operational balancing and imbalance agreements. Gas imbalances are either made up in-kind or settled in cash, subject to the terms and valuations of the various agreements. Imbalances are valued at applicable average market index prices. Deferred Financing Costs Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method. Goodwill We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of the fair value over the carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31st. We evaluate goodwill for impairment at the reporting unit level, which is an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or the two-step test approach depending on facts and circumstances of the reporting unit. If we, after performing the qualitative assessment, determine it is "more likely than not" that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. When goodwill is evaluated for impairment using the two-step test, the carrying amount of the reporting unit is compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit’s fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss. We did not elect to apply the qualitative assessment option during our 2015 annual goodwill impairment testing, instead we proceeded directly to the two-step quantitative test. In Step 1 of the two-step quantitative test, we compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the Step 1 impairment analysis indicated no potential impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, Step 2 of the impairment analysis was not necessary as part of the annual impairment analysis in 2015. 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. Investment in Unconsolidated Affiliates We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where we have the ability to exercise significant influence. We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary. Our investment in Grasslands Water Services I, LLC ("GWSI"), which owns a water transportation pipeline, was initially recorded under the equity method of accounting as we had the ability to exercise significant influence, but not control, over this investment. There was $0.7 million equity in earnings recognized for the nine months ended September 30, 2014 . There were no equity in earnings recognized for the three months ended September 30, 2014 and the three and nine months ended September 30, 2015 . As discussed in Note 4 – Acquisitions , during the year ended December 31, 2014, TEGP acquired a controlling interest in GWSI, which was subsequently renamed BNN Redtail, LLC ("Redtail"), and consolidated its investment in Redtail as of May 13, 2014 accordingly. Revenue Recognition We recognize revenues as services are rendered or goods are sold to a purchaser at a fixed and determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. We provide various types of natural gas storage and transportation services and crude oil transportation services to our customers in which the commodity remains the property of these customers at all times. Natural gas liquids sales occur in the Processing & Logistics segment and consist of the sale of outputs from our processing plants and the marketing of natural gas liquids that are delivered by our suppliers under either fee-based arrangements or percent-of-proceeds arrangements. Under these arrangements, we treat and process the natural gas delivered by our suppliers, and then sell the resulting NGLs and condensate based on published index market prices. We remit to the producers an agreed-upon percentage of the actual proceeds that we receive from our sales of the NGLs and condensate. We keep the difference between the proceeds received and the amount remitted back to the producer. We generally report gross revenues in the condensed consolidated statements of income, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Processing and other revenues primarily represent fees for processing, treating and fractionation of natural gas and NGLs earned under fee-based arrangements and revenue from water services earned in the Processing & Logistics segment. Natural gas sales occur in both the Natural Gas Transportation & Logistics segment and in the Processing & Logistics segment. In the Natural Gas Transportation & Logistics segment, transportation services revenue is recognized when a portion of the natural gas transported by customers is collected as a contractual fee to compensate us for fuel consumed by pipeline and storage operations. We take title and record revenue at market prices when the volumes included in the contractual fee are delivered from the customer and injected into our storage facility. When the excess volumes are eventually sold we record natural gas sales revenue at the contractual sales price and cost of sales at average cost. In addition, when operational conditions allow, we occasionally sell "base gas," which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Processing & Logistics segment, we purchase natural gas primarily for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased that exceed our business needs. Natural gas transportation and storage services occur in the Natural Gas Transportation & Logistics segment. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fee-based component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to "firm" and "interruptible" transportation services, we also provide natural gas park and loan services to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized as services are provided, based on the terms negotiated under these contracts. Crude oil transportation services occur in the Crude Oil Transportation & Logistics segment. We provide various types of crude oil transportation services to our customers and, other than pipeline allowance oil, do not take title to the crude oil and do not incur the risks and rewards of ownership. In many cases the customer has committed to ship a fixed quantity of oil barrels per month. For barrels physically received by us and delivered to the customers’ agreed upon destination point, revenue is recognized in the period the service is provided. Shipper deficiencies, or barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers’ agreed upon destination point, are charged at the committed tariff rate per barrel and recorded as a deferred liability until the barrels are physically transported and delivered. In the case of non-committed shippers, revenue is recognized in the same manner utilized for the barrels physically transported and delivered. A loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil. Any pipeline allowance oil that remains after replacing losses in transit can be sold. We take title and record revenue at market prices when the volumes included in the pipeline loss allowance are delivered from the customer. When pipeline loss allowance oil is eventually sold we record revenue at the contractual sales price and cost of sales at average cost as discussed in "Inventories" above. During the three and nine months ended September 30, 2015 , we recognized revenue of $1.3 million and $2.5 million on the sale of pipeline allowance oil, which is included in "Sales of natural gas, NGLs, and crude oil" in the condensed consolidated statements of income. 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 |
Variable Interest Entity (Notes
Variable Interest Entity (Notes) | 9 Months Ended |
Sep. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Variable Interest Entity Disclosure [Text Block] | TEGP, as the managing member of Tallgrass Equity, has voting rights disproportionate to its ownership interest. As a result, we have determined that Tallgrass Equity is a VIE of which we are the primary beneficiary and we consolidate Tallgrass Equity accordingly. We have not provided any additional financial support to Tallgrass Equity other than our initial capital contribution and have no contractual commitments or obligations to provide additional financial support. We also consolidate Pony Express through our indirect ownership of TEP. TEP does not have the obligation to absorb losses from Pony Express during the preference period as a result of the minimum quarterly preference payments as discussed in Note 4 – Acquisitions . In addition, for the period from our acquisition of the initial 33.3% membership interest effective September 1, 2014 to our acquisition of an additional 33.3% membership interest effective March 1, 2015, TEP, as the managing member of Pony Express, had voting rights disproportionate to its ownership interest. As a result, we determined that Pony Express is a VIE of which TEP is the primary beneficiary and consolidated Pony Express accordingly. TEP has not provided any additional financial support to Pony Express other than its initial capital contribution of $570 million and has no contractual commitments or obligations to provide additional financial support. In the event that the costs of construction of the Pony Express System's mainline and its lateral in Northeast Colorado exceed the $270 million retained by Pony Express as discussed in Note 4 – Acquisitions , TD is obligated to fund the remaining costs. As of September 30, 2015 , the costs to complete construction have exceeded the amount retained, and as such TD will continue to fund any remaining costs associated with construction of the mainline and lateral in Northeast Colorado. Although TEP has no obligation to provide further financial support to Pony Express, it is expected that future capital projects would be funded by TEP and TD on a pro rata basis in accordance with the Pony Express LLC Agreement. The carrying amounts and classifications of the Tallgrass Equity consolidated assets and liabilities, including the assets and liabilities of Pony Express, included in our condensed consolidated balance sheets at September 30, 2015 and December 31, 2014 are as follows: September 30, 2015 December 31, 2014 (in thousands) Current assets $ 90,824 $ 132,281 Noncurrent assets 2,412,376 2,324,916 Total assets $ 2,503,200 $ 2,457,197 Current liabilities $ 74,835 $ 96,568 Noncurrent liabilities 849,461 565,478 Total liabilities $ 924,296 $ 662,046 |
Acquisitions
Acquisitions | 9 Months Ended |
Sep. 30, 2015 | |
Business Combinations [Abstract] | |
Acquisitions | TEP Acquisition of Trailblazer On April 1, 2014 , TEP closed the acquisition of Trailblazer from a wholly owned subsidiary of TD for total consideration valued at approximately $164 million , consisting of $150 million in cash and the issuance of 385,140 TEP common units (valued at approximately $14 million based on the March 31, 2014 closing price of TEP’s common units). On that same date, the general partner contributed additional capital in the amount of approximately $263,000 in exchange for the issuance of 7,860 TEP general partner units in order to maintain its 2% general partner interest. The acquisition of Trailblazer represents a change in reporting entity and a transaction between entities under common control. The excess purchase price over the net book value of Trailblazer's assets and liabilities was accounted for as a deemed distribution to TEP GP. TEP Acquisitions of 66.7% of Pony Express Effective September 1, 2014 , TEP acquired a controlling 33.3% membership interest in Pony Express for total consideration of approximately $600 million . At closing, Pony Express, TD, and TEP entered into the Second Amended Pony Express LLC Agreement, which set forth the relative rights of TD and TEP as the owners of Pony Express. Of the total consideration of $600 million , TEP directly paid TD $30 million , consisting of $27 million in cash and 70,340 TEP common units with an aggregate fair value of approximately $3 million , in exchange for the transfer by TD to TEP of a 1.9585% membership interest in Pony Express (computed before giving effect to the issuance of the new membership interest by Pony Express to TEP). TEP also contributed cash of $570 million to Pony Express in exchange for a newly issued membership interest which, when combined with the membership interest transferred from TD and the parties' entry at closing into the Second Amended Pony Express LLC Agreement, constituted TEP's 33.3% membership interest in Pony Express, which represented 100% of the preferred membership units issued by Pony Express. Of the $570 million cash consideration received by Pony Express, $300 million was immediately distributed to TD at closing and $270 million was retained by Pony Express to fund the estimated remaining costs of construction for the Pony Express System and the lateral in Northeast Colorado. The $270 million cash balance was subsequently swept to TD under a cash management agreement between Pony Express and TD and was recorded as a related party loan which bears interest at TD's incremental borrowing rate. There was no remaining balance outstanding on the related party loan at September 30, 2015. The terms of TEP's first acquisition of a 33.3% membership interest in Pony Express provided TEP a minimum quarterly preference payment of $16.65 million through the quarter ended September 30, 2015 (prorated to approximately $5.4 million for the quarter ended September 30, 2014) with distributions thereafter shared in accordance with the terms of the Second Amended Pony Express LLC Agreement. At the effective date of that transaction, TEP determined that Pony Express was a VIE of which TEP was the primary beneficiary, and consolidated Pony Express accordingly. For additional discussion and disclosure, see Note 3 – Variable Interest Entities . The acquisition of the initial 33.3% membership interest in Pony Express represented a transaction between entities under common control and a change in reporting entity. Effective March 1, 2015 , TEP acquired an additional 33.3% membership interest in Pony Express for cash consideration of $700 million . At closing, Pony Express, TD, and TEP entered into the Pony Express LLC Agreement, which sets forth the relative rights of TD and TEP as the owners of Pony Express. The terms of the transaction increased the minimum quarterly preference payment provided to TEP to $36.65 million through the quarter ending December 31, 2015 (prorated to approximately $23.5 million for the quarter ended March 31, 2015) with distributions thereafter shared in accordance with the terms of the Pony Express LLC Agreement. Upon the effective date of the second acquisition, TEP reevaluated its VIE assessment and determined that Pony Express continues 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. Formation of BNN Water Solutions, LLC On November 26, 2013, TEP, through its wholly-owned subsidiary Tallgrass Energy Investments, LLC ("TEI"), entered into a joint venture agreement with BNN Energy LLC ("BNN") to form Grasslands Water Services I, LLC ("GWSI"), which subsequently built and began operating an intrastate water pipeline in Colorado. TEP accounted for its 50% equity interest in GWSI as an equity method investment. On May 13, 2014, TEI entered into a contribution agreement with BNN and several other parties to form a new entity known as Water Solutions. Under the terms of the contribution agreement, TEI agreed to contribute its existing 50% interest in GWSI, along with $7.6 million cash, in exchange for an 80% membership interest in Water Solutions. As part of the transaction, GWSI was renamed BNN Redtail, LLC ("Redtail"), became a subsidiary of Water Solutions, and issued preferred equity interests to TEI. Among the assets contributed by BNN and the other parties to the transaction were the other 50% interest in Redtail and a 100% equity interest in Alpha Reclaim Technology, LLC ("Alpha"), a company which sources treated wastewater from municipalities in Texas. Alpha is wholly-owned by Redtail. Upon closing of the transaction, TEP obtained a controlling financial interest in Water Solutions and accordingly has accounted for the transaction as a step acquisition under ASC 805. On the acquisition date, TEP remeasured its previously held 50% equity interest in Redtail to its fair value of $11.9 million , recognized a gain of $9.4 million , and consolidated Water Solutions. The 20% equity interest in Water Solutions held by noncontrolling interests was recorded at its acquisition date fair value of $1.4 million . The fair values of the previously held equity interest and the noncontrolling interest were determined using a discounted cash flow analysis. These fair value measurements are based on significant inputs that are not observable in the market and thus represent fair value measurements categorized within Level 3 of the fair value hierarchy under ASC 820. At December 31, 2014, the assets acquired and liabilities assumed in the acquisition were recorded at provisional amounts based on the preliminary purchase price allocation. During the three months ended June 30, 2015, the preliminary purchase price allocation with respect to Water Solutions was finalized with no material adjustments. On May 20, 2015, TEP acquired an additional 12% equity interest in Water Solutions from NR2, LLC for cash consideration of $600,000 , which was accounted for as an acquisition of noncontrolling interest. As of September 30, 2015 , TEP's aggregate membership interest in Water Solutions was 92% . |
Related Party Transactions
Related Party Transactions | 9 Months Ended |
Sep. 30, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | We have no employees. TD, through its wholly-owned subsidiary Tallgrass Operations, LLC ("Tallgrass Operations"), provided and charged us for direct and indirect costs of services provided to us or incurred on our behalf including employee labor costs, information technology services, employee health and retirement benefits, and all other expenses necessary or appropriate to the conduct of our business. We recorded these costs on the accrual basis in the period in which TD incurred them. On May 17, 2013, in connection with the closing of TEP’s initial public offering, TEP and its general partner entered into an Omnibus Agreement with TD and certain of its affiliates, including Tallgrass Operations (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provides that, among other things, TEP will reimburse TD and its affiliates for all expenses they incur and payments they make on TEP’s behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by TD, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the closing of the Offering, TEGP entered into an Omnibus Agreement (the “TEGP Omnibus Agreement”) with TEGP Management, LLC, Tallgrass Equity and Holdings (which acts as the general partner of TD). TEP’s general and administrative costs under the TEP Omnibus Agreement were $5.2 million and $16.1 million for the three and nine months ended September 30, 2015 , respectively, excluding costs attributable to Pony Express. Pony Express had general and administrative costs of $5.2 million and $15.5 million for the three and nine months ended September 30, 2015 , respectively. TEP also pays a quarterly reimbursement to TD for costs associated with being a public company, which was $635,000 for the third quarter of 2015 . Pursuant to the TEGP Omnibus Agreement, Tallgrass Equity pays a reimbursement to TD for costs associated with TEGP being a public company beginning in the second quarter of 2015, which was $500,000 for the third quarter of 2015 . These amounts will be periodically reviewed and adjusted as necessary to continue to reflect reasonable allocation of costs to TEP and TEGP, respectively. Due to the cash management agreements discussed in Note 2 – Summary of Significant Accounting Policies , intercompany balances were periodically settled and treated as equity distributions prior to April 1, 2014 for Trailblazer and prior to September 1, 2014 for Pony Express. Balances lent to TD under the Pony Express cash management agreement effective September 1, 2014 are classified as related party receivables in the condensed consolidated balance sheets. During the nine months ended September 30, 2015 and 2014 we recognized interest income from TD of $0.4 million and $0.5 million , respectively, on the receivable balance under the Pony Express cash management agreement. Totals of transactions with affiliated companies are as follows: Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Cost of transportation services $ 7,180 $ — $ 17,771 $ — Charges to TEGP: (1) Property, plant and equipment, net $ 958 $ 7,926 $ 3,859 $ 14,534 Operation and maintenance $ 6,077 $ 4,701 $ 17,325 $ 13,657 General and administrative $ 10,041 $ 5,783 $ 28,862 $ 14,670 (1) Charges to TEGP, inclusive of Tallgrass Equity, TEP, and Pony Express, include directly charged wages and salaries, other compensation and benefits, and shared services. Details of balances with affiliates included in "Receivable from related party" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows: September 30, 2015 December 31, 2014 (in thousands) Receivable from related party: Tallgrass Operations, LLC $ — $ 73,393 Total receivable from related party $ — $ 73,393 Accounts payable to related parties: Tallgrass Operations, LLC $ 3,561 $ 3,894 Rockies Express Pipeline LLC 20 21 Total accounts payable to related parties $ 3,581 $ 3,915 Balances of gas imbalances with affiliated shippers are as follows: September 30, 2015 December 31, 2014 (in thousands) Affiliate gas balance receivables $ — $ 275 Affiliate gas balance payables $ 269 $ 455 |
Inventory
Inventory | 9 Months Ended |
Sep. 30, 2015 | |
Inventory Disclosure [Abstract] | |
Inventory | The components of inventory at September 30, 2015 and December 31, 2014 consisted of the following: September 30, 2015 December 31, 2014 (in thousands) Crude oil $ 2,534 $ 581 Materials and supplies 5,852 3,049 Natural gas liquids 345 519 Gas in underground storage 5,401 8,896 Total inventory $ 14,132 $ 13,045 |
Property, Plant and Equipment
Property, Plant and Equipment | 9 Months Ended |
Sep. 30, 2015 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | A summary of net property, plant and equipment by classification is as follows: September 30, 2015 December 31, 2014 (in thousands) Crude oil pipelines $ 1,159,002 $ 939,536 Natural gas pipelines 556,924 548,482 Processing and treating assets 238,356 241,671 General and other 63,910 42,719 Construction work in progress 45,051 139,873 Accumulated depreciation and amortization (114,422 ) (59,200 ) Total property, plant and equipment, net $ 1,948,821 $ 1,853,081 |
Risk Management
Risk Management | 9 Months Ended |
Sep. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management | We occasionally enter into derivative contracts with third parties for the purpose of hedging exposures that accompany our normal business activities. Our normal business activities directly and indirectly expose us to risks associated with changes in the market price of crude oil and natural gas, among other commodities. For example, the risks associated with changes in the market price of natural gas include, among others (i) pre-existing or anticipated physical natural gas sales, (ii) natural gas purchases and (iii) natural gas system use and storage. We have elected not to apply hedge accounting and changes in the fair value of all derivative contracts are recorded in earnings in the period in which the change occurs. Fair Value of Derivative Contracts The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets: Balance Sheet September 30, 2015 December 31, 2014 (in thousands) Energy commodity derivative contracts Current assets $ 218 $ — As of September 30, 2015 , the fair value shown for commodity contracts was comprised of derivative volumes for short natural gas fixed-price swaps totaling 0.6 Bcf. As of December 31, 2014 there were no derivative contracts outstanding. Effect of Derivative Contracts in the Statements of Income The following table summarizes the impact of derivative contracts for the three and nine months ended September 30, 2015 and 2014 : Amount of Gain (Loss) Recognized in Income on Derivatives Location of gain (loss) recognized Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Derivatives not designated as hedging contracts: Energy commodity derivative contracts Sales of natural gas, NGLs, and crude oil $ 252 $ 9 $ 211 $ (449 ) Credit Risk We have counterparty credit risk as a result of our use of derivative contracts. Our counterparties consist of major financial institutions. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. We maintain credit policies that we believe minimize our overall credit risk. These policies include (i) evaluation of potential counterparties’ financial condition (including credit ratings), (ii) collateral requirements under certain circumstances and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty. Based on our policies and exposure, we do not currently anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance. Our over-the-counter swaps are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges. These contracts are with financial institutions with investment grade credit ratings. While we enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future. The maximum potential exposure to credit losses on TEP's derivative contracts at September 30, 2015 was: Asset Position (in thousands) Gross $ 218 Netting agreement impact — Cash collateral held — Net Exposure $ 218 In addition, when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. Accordingly, entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability position with each counterparty. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account current credit spreads for its comparative industry sector, as well as any change in such spreads since the last measurement date. As of September 30, 2015 and December 31, 2014 , we did not have any outstanding letters of credit or cash in margin accounts in support of our hedging of commodity price risks associated with the sale of natural gas nor did we have margin deposits with counterparties associated with energy commodity contract positions. Fair Value Derivative assets and liabilities are measured and reported at fair value. Derivative contracts can be exchange-traded or over-the-counter ("OTC"). Exchange-traded derivative contracts typically fall within Level 1 of the fair value hierarchy if they are traded in an active market. We value exchange-traded derivative contracts using quoted market prices for identical securities. OTC derivatives are valued using models utilizing a variety of inputs including contractual terms and commodity and interest rate curves. The selection of a particular model and particular inputs to value an OTC derivative contract depends upon the contractual terms of the instrument as well as the availability of pricing information in the market. We use similar models to value similar instruments. For OTC derivative contracts that trade in liquid markets, such as generic forwards and swaps, model inputs can generally be verified and model selection does not involve significant management judgment. Such contracts are typically classified within Level 2 of the fair value hierarchy. Certain OTC derivative contracts trade in less liquid markets with limited pricing information; as such, the determination of fair value for these derivative contracts is inherently more difficult. Such contracts are classified within Level 3 of the fair value hierarchy. The valuations of these less liquid OTC derivatives are typically impacted by Level 1 and/or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Use of a different valuation model or different valuation input values could produce a significantly different estimate of fair value. However, derivative contracts valued using inputs unobservable in active markets are generally not material to our financial statements. When appropriate, valuations are adjusted for various factors including credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. The following table summarizes the fair value measurements of our energy commodity derivative contracts as of September 30, 2015 based on the fair value hierarchy established by the Codification: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of September 30, 2015 Energy commodity derivative contracts $ 218 $ — $ 218 $ — |
Long-term Debt
Long-term Debt | 9 Months Ended |
Sep. 30, 2015 | |
Debt Disclosure [Abstract] | |
Long-term Debt | Tallgrass Equity Credit Facility The following table sets forth the available borrowing capacity under the Tallgrass Equity revolving credit facility as of September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 (in thousands) Total capacity under the Tallgrass Equity revolving credit facility $ 150,000 $ — Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility (148,000 ) — Available capacity under the Tallgrass Equity revolving credit facility $ 2,000 $ — In connection with the Offering, Tallgrass Equity entered into a $150 million senior secured revolving credit facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders, which will mature on May 12, 2020. The Tallgrass Equity credit facility includes a $10 million sublimit for letters of credit and a $10 million sublimit for swing line loans. The Tallgrass Equity revolving credit facility may be used (i) to pay transaction costs and any fees and expenses incurred in connection with the revolving credit facility and certain transactions relating to the Offering, (ii) to fund the purchase of the Acquired TEP Units and (iii) for general Partnership purposes, including distributions. The Tallgrass Equity revolving credit facility also contains an accordion feature whereby Tallgrass Equity can increase the size of the credit facility to an aggregate of $200 million , subject to receiving increased or new commitments from lenders and the satisfaction of certain other conditions precedent. In addition, Tallgrass Equity is required to maintain a total leverage ratio of not more than 3.00 to 1.00. As of September 30, 2015 , Tallgrass Equity was in compliance with the covenants required under the revolving credit facility. Upon the close of the Offering, Tallgrass Equity had $150 million in outstanding borrowings under the credit facility, of which $3 million was subsequently repaid using proceeds from the Offering retained from the distribution of Excess Proceeds to the Exchange Right Holders for short term working capital needs, which will ultimately be distributed to the Exchange Right Holders to the extent not used to pay offering expenses and other transaction costs. An additional $1.0 million was borrowed during the three months ended September 30, 2015, leaving $2 million in remaining capacity available for future borrowings or letter of credit issuances as of September 30, 2015 . The initial borrowings under the credit facility were used to fund a portion of the purchase of the Acquired TEP Units and to pay origination and arrangement fees associated with the new revolving credit facility and transaction costs associated with the Offering. Tallgrass Equity’s obligations under the revolving credit facility are secured by a first priority lien on all of the present and after acquired equity interests held by Tallgrass Equity in TEP GP and TEP. Borrowings under the credit facility bear interest, at Tallgrass Equity’s option, at either (a) a base rate, which will be a rate equal to the greatest of (i) the prime rate, (ii) the U.S. federal funds rate plus 0.5% and (iii) a one-month reserve adjusted Eurodollar rate plus 1.00% or (b) a reserve adjusted Eurodollar rate, plus, in each case, an applicable margin. For loans bearing interest based on the base rate, the applicable margin is 1.50% , and for loans bearing interest based on the reserve adjusted Eurodollar rate, the applicable margin is 2.50% . The unused portion of the revolving credit facility is subject to a commitment fee of 0.50% . As of September 30, 2015 , the weighted average interest rate on outstanding borrowings was 2.71% . TEP Credit Facility The following table sets forth the available borrowing capacity under the TEP revolving credit facility as of September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 (in thousands) Total capacity under the TEP revolving credit facility $ 850,000 $ 850,000 Less: Outstanding borrowings under the TEP revolving credit facility (696,000 ) (559,000 ) Available capacity under the TEP revolving credit facility $ 154,000 $ 291,000 The TEP revolving credit facility contains various covenants and restrictive provisions that, among other things, limit or restrict TEP’s ability (as well as the ability of TEP’s restricted subsidiaries) to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of TEP’s 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, TEP is required to maintain a consolidated leverage ratio of not more than 4.75 to 1.00 (which will be increased to 5.25 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and a consolidated interest coverage ratio of not less than 2.50 to 1.00. As of September 30, 2015 , TEP is in compliance with the covenants required under the TEP revolving credit facility. The unused portion of the revolving credit facility is subject to a commitment fee, which ranges from 0.300% to 0.500% , based on TEP’s total leverage ratio. As of September 30, 2015 , the weighted average interest rate on outstanding borrowings was 1.97% . Fair Value The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) September 30, 2015 $ — $ 844,000 $ — $ 844,000 $ 844,000 December 31, 2014 $ — $ 559,000 $ — $ 559,000 $ 559,000 The long-term debt borrowed under the revolving credit facility is carried at amortized cost. As of September 30, 2015 and December 31, 2014 , the fair value approximates the carrying amount for the borrowings under our revolving credit facilities using a discounted cash flow analysis. We are not aware of any factors that would significantly affect the estimated fair value subsequent to September 30, 2015 . |
Partnership Equity and Distribu
Partnership Equity and Distributions | 9 Months Ended |
Sep. 30, 2015 | |
Equity [Abstract] | |
Partnership Equity and Distributions | TEP February Public Offering On February 27, 2015, TEP 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 paid by TEP. TEP used the net proceeds from the offering to fund a portion of the consideration for the acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions . Pursuant to the underwriters' option to purchase additional units, TEP 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 paid by TEP. TEP used the net proceeds from this additional purchase of common units to reduce borrowings under its revolving credit facility, a portion of which were used to fund the March 2015 acquisition of an additional 33.3% membership interest in Pony Express as discussed in Note 4 – Acquisitions . TEGP Partnership Agreement and Distributions to Holders of Class A Shares On May 12, 2015, TEGP closed the Offering and completed the Reorganization Transactions as outlined in Note 1 – Description of Business . In connection with the Offering, TEGP entered into an amended and restated partnership agreement on May 12, 2015. The partnership agreement requires TEGP to distribute its available cash to Class A shareholders on a quarterly basis, subject to certain terms and conditions, beginning with the quarter ended June 30, 2015. The following table details the distributions paid by TEGP during the nine months ended September 30, 2015 : Three Months Ended Date Paid Distributions to Class A Shareholders Distributions per Class A Share (in thousands) September 30, 2015 November 13, 2015 (1) $ 6,872 $ 0.144 June 30, 2015 August 17, 2015 3,484 0.073 (2) (1) The distribution for the third quarter of 2015 will be paid on November 13, 2015 to Class A shareholders of record at the close of business on October 30, 2015. (2) The first quarterly distribution declared on July 15, 2015 was prorated for the number of days between the closing of TEGP’s initial public offering on May 12, 2015 and the end of the second quarter. Exchange Rights The Exchange Right Holders and any permitted transferees of their Tallgrass Equity units each have the right to exchange all or a portion of their Tallgrass Equity units for Class A shares at an exchange ratio of one Class A share for each Tallgrass Equity unit exchanged, which we refer to as the Exchange Right. The Exchange Right may be exercised only if, simultaneously therewith, an equal number of our Class B shares are transferred by the exercising party to us. Upon such exchange, we will cancel the Class B shares received from the exercising party. Noncontrolling Interests As of September 30, 2015 , noncontrolling interests in our subsidiaries consisted of a 69.65% interest in Tallgrass Equity held by the Exchange Right Holders, the 66.07% limited partner interest in TEP held by TD and the public TEP unitholders, the 33.3% membership interest in Pony Express held by TD, and an 8% membership interest in Water Solutions. During the nine months ended September 30, 2015 , we recognized contributions to and distributions from TEP's noncontrolling interests of $110.6 million and $44.5 million , respectively, consisting primarily of contributions and distributions between Pony Express and TD. Subsidiary Distributions TEP Distributions . The following table details the distributions paid by TEP during the nine months ended September 30, 2015 : Distributions Limited Partner Units General Partner Distributions Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) September 30, 2015 November 13, 2015 (1) $ 36,347 $ 11,567 $ 660 $ 48,574 $ 0.6000 June 30, 2015 August 14, 2015 35,135 10,418 627 46,180 0.5800 March 31, 2015 May 14, 2015 31,322 6,934 530 38,786 0.5200 December 31, 2014 February 13, 2015 23,782 4,039 473 28,294 0.4850 (1) The distribution for the third quarter of 2015 will be paid on November 13, 2015 to unitholders of record at the close of business on October 30, 2015. Other Contributions and Distributions During the nine months ended September 30, 2015 , we distributed $334.1 million of Excess Proceeds from the Offering to the Exchange Right Holders as part of the Reorganization Transactions and distributed $13.5 million to the TEGP Predecessor. In addition, we received $7.5 million of TEP general partner and IDR distributions related to periods prior to the Offering which were distributed to the previous TEP GP Members, and $13.0 million of TEP distributions received which were distributed by Tallgrass Equity to the Exchange Right Holders. Also during the nine months ended September 30, 2015 , we received contributions from and made distributions to TEP's noncontrolling interests of $110.6 million and $44.5 million , respectively. During the nine months ended September 30, 2014 , we recognized net contributions from the TEGP Predecessor of $289.4 million . This activity represents transfers of cash as a result of TD’s centralized cash management systems as discussed in Note 1 – Description of Business , as well as the TEP distributions paid on the Acquired TEP Units and distributions paid for excess offering proceeds. We also recognized a $27.5 million contribution from TD representing the difference between the carrying amount of the Replacement Gas Facilities required as part of the Pony Express Abandonment, as discussed in Note 13 – Regulatory Matters , and the proceeds received from TD as reimbursement for the costs to construct those assets. Also during the nine months ended September 30, 2014 , we received contributions from and made distributions to noncontrolling interests of $5.4 million and $37,000 , respectively. |
Net Income per Class A Share Ne
Net Income per Class A Share Net Income per Class A Share | 9 Months Ended |
Sep. 30, 2015 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share, Basic, by Common Class, Including Two Class Method [Table Text Block] | Basic net income per Class A share is determined by dividing net income attributable to TEGP by the weighted average number of outstanding Class A shares during the period. Class B shares do not share in the earnings of the Partnership. Accordingly, basic and diluted net income per Class B share has not been presented. Diluted net income per Class A share is determined by dividing net income attributable to TEGP by the weighted average number of outstanding diluted Class A shares during the period. For purposes of calculating diluted net income per Class A share, we considered the impact of possible future exercises of the Exchange Right by the Exchange Right Holders on both net income attributable to TEGP and the diluted weighted average number of Class A shares outstanding. Pursuant to the TEGP partnership agreement and the Tallgrass Equity limited liability company agreement, our capital structure and the capital structure of Tallgrass Equity will generally replicate one another in order to maintain the one-for-one exchange ratio between the Tallgrass Equity units and Class B shares, on the one hand, and our Class A shares, on the other hand. As a result, the potential exchange of any Class B shares does not have a dilutive effect on basic net income per Class A share. For the three and nine months ended September 30, 2015 the possible exchange of any TEGP Equity Participation units would have had a dilutive effect on basic net income per Class A share. Net income per Class A share is not presented for the three and nine months ended September 30, 2014 as there were no Class A shares outstanding during those periods. The Offering became effective during the second quarter of 2015. As a result, no income from the period from January 1, 2015 through May 11, 2015 is allocated to the Class A shares that were issued on May 12, 2015. The following table illustrates the calculation of basic and diluted net income per Class A share for the three and nine months ended September 30, 2015 (in thousands, except per share data): Three Months Ended September 30, 2015 Nine Months Ended September 30, 2015 (in thousands, except per unit amounts) Basic Net Income per Class A Share: Net income attributable to TEGP $ 4,423 $ 14,279 Net income attributable to TEGP from the beginning of the period to May 11, 2015 — 7,393 Net income attributable to TEGP from May 12, 2015 to September 30, 2015 $ 4,423 $ 6,886 Basic weighted average Class A Shares outstanding 47,725 47,725 Basic net income per Class A share $ 0.09 $ 0.14 Diluted Net Income per Class A Share: Net income attributable to TEGP from May 12, 2015 to September 30, 2015 $ 4,423 $ 6,886 Incremental net income attributable to TEGP including the effect of the assumed issuance of Equity Participation Shares from May 12, 2015 to September 30, 2015 2 2 Net income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares from May 12, 2015 to September 30, 2015 $ 4,425 $ 6,888 Basic weighted average Class A Shares outstanding 47,725 47,725 Equity Participation Shares equivalent shares 83 87 Diluted weighted average Class A Shares outstanding 47,808 47,812 Diluted net income per Class A Share $ 0.09 $ 0.14 |
Equity-Based Compensation Equit
Equity-Based Compensation Equity-Based Compensation | 9 Months Ended |
Sep. 30, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Disclosure of Compensation Related Costs, Share-based Payments [Text Block] | 12. Equity-Based Compensation Long-Term Incentive Plan Effective May 12, 2015, our general partner adopted the TEGP Management, LLC Long-Term Incentive Plan (“LTIP”) on our behalf for (i) the employees of our general partner and its affiliates who perform services for us, (ii) the non-employee directors of our general partner and (iii) the consultants who perform services for us. Awards under the LTIP will consist of unrestricted shares, restricted shares, equity participation shares, options and share appreciation rights. The LTIP will limit the number of shares that may be delivered pursuant to awards to 3,144,589 Class A shares (subject to any adjustment due to recapitalization, reorganization or a similar event permitted under the LTIP). Shares that are forfeited or withheld to satisfy exercise price or tax withholding obligations are available for delivery pursuant to other awards. Equity Participation Shares On May 12, 2015, the board of directors of our general partner approved the grant of up to 3,144,589 Class A shares (subject to any adjustment due to recapitalization, reorganization or a similar event permitted under the LTIP) under the LTIP. Effective August 1, 2015, 160,000 Equity Participation Shares were granted to employees. Vesting of the Equity Participation Shares is contingent on certain service and performance conditions. The Equity Participation Shares vest on the later to occur of the Distribution Achievement Date (the first date on which TEGP pays a regular quarterly distribution of at least $0.35 for any full quarter ending on or after the Grant Date), or May 12, 2019. If the Distribution Achievement Date has not occurred by May 12, 2020, the Equity Participation Shares will expire and terminate and no vesting will occur. The Equity Participation Shares are non-participating, as such participants are not entitled to receive any distributions with respect to the Equity Participation Shares unless the participant receives a separate grant of Distribution Equivalent Rights. At this time no grants of Distribution Equivalent Rights have been made. The Equity Participation Share grants were measured at their grant date fair value of $27.97 per Equity Participation Share. The Equity Participation Shares are non-participating, therefore the grant date fair value is discounted from the grant date fair value of TEGP's Class A shares for the present value of the expected future dividends during the vesting period. Equity-based compensation cost related to the Equity Participation Share grants of approximately $0.2 million was recognized during the three and nine months ended September 30, 2015 . As of September 30, 2015 , $4.3 million of compensation cost related to non-vested Equity Participation Shares is expected to be recognized over a weighted-average period of 3.8 years . The compensation expense recognized is allocated between TEGP, inclusive of TEP, and TD. |
Regulatory Matters
Regulatory Matters | 9 Months Ended |
Sep. 30, 2015 | |
Regulatory Matters [Abstract] | |
Regulatory Matters | There are currently no proceedings challenging the currently effective rates of Pony Express, TIGT, or Trailblazer. Regulators, as well as shippers, do have rights, under circumstances prescribed by applicable regulations, to challenge the rates that we charge at our regulated entities. Further, the statute governing service by Pony Express allows parties having standing to file complaints in regard to existing tariff rates and provisions. If the complaint is not resolved, the FERC may conduct a hearing and order a crude oil pipeline to make reparations going back for up to two years prior to the date on which a complaint was filed if a rate is found to be unjust and unreasonable. We can provide no assurance that current rates will remain unchallenged. Any successful challenge could have a material, adverse effect on our future earnings and cash flows. TIGT Pony Express Abandonment – FERC Docket CP12-495 On August 6, 2012, TIGT filed an application to: (1) abandon for FERC purposes approximately 433 miles of mainline natural gas pipeline facilities, along with associated rights of way and other related equipment (collectively, the "Pony Express Assets"), and the natural gas service therefrom, by transferring those assets to Pony Express, which subsequently converted the Pony Express Assets into crude oil pipeline facilities; and (2) construct and operate certain replacement-type facilities necessary to continue service to existing natural gas firm transportation customers following the conversion, which we refer to as the Replacement Gas Facilities. This project is referred to as the "Pony Express Abandonment." The FERC abandonment does not constitute an abandonment for accounting purposes. Pursuant to the terms of the Purchase and Sale Agreement filed with the FERC and cited by the FERC in approving the Pony Express Abandonment, Pony Express is required to reimburse TIGT for the net book value of the Pony Express Assets plus other TIGT incurred costs required to construct the Replacement Gas Facilities and to arrange substitute gas transportation services to certain TIGT shippers. The Pony Express Abandonment and completion of the Pony Express Project by Pony Express re-deployed existing pipeline assets to meet the growing market need to transport oil supplies while at the same time continuing to operate TIGT’s natural gas transportation facilities to meet all current and expected needs of its natural gas customers. By a FERC order issued September 12, 2013, TIGT was granted authorization to abandon the Pony Express Assets and construct the Replacement Gas Facilities. On October 7, 2013 TIGT commenced the mobilization of personnel and equipment for the construction of the Replacement Gas Facilities necessary to complete the Pony Express Abandonment to continue service to existing TIGT customers. In December 2013, TIGT removed the Pony Express Assets from gas service and sold those assets to Pony Express. On May 1, 2014, TIGT commenced commercial service through all of the Replacement Gas Facilities, with the exception of Units 3 and 4 at the Tescott Compressor Station. Service through Units 3 and 4 at the Tescott Compressor Station commenced on May 30, 2014. Cost and Revenue Study – FERC Docket RP11-1494 On October 3, 2015, TIGT submitted a cost and revenue study in compliance with Article IV of the Stipulation and Agreement of Settlement filed on May 5, 2011 in FERC Docket No. RP11-1494 (“2011 Settlement”) and approved by the FERC on September 22, 2011. Consistent with the 2011 Settlement, the cost and revenue study demonstrates that TIGT is under-recovering its cost of service. The study was based on the unadjusted actual costs, revenues and volumes for a 12-month base period ended June 30, 2015, that complies with Section 154.303(a)(1) of the FERC’s regulations. The cost and revenue study did not propose any change to TIGT’s currently effective rates. Instead, TIGT has filed a general rate case under Section 4 of the Natural Gas Act, as discussed further below. General Rate Case Filing – FERC Docket RP16-137 On October 30, 2015, TIGT filed a general rate case with the FERC pursuant to section 4 of the Natural Gas Act. The rate case proposes a general system-wide increase in the maximum tariff rates for all firm and interruptible services offered by TIGT. In addition, TIGT proposed certain changes to the transportation rate design of its system to replace the current rate zone structure with a single “postage stamp” rate. TIGT also proposed new charges, including (i) a charge for deliveries made to points without certain electronic flow measurement equipment, and (ii) a charge to completely or partially reimburse TIGT for certain integrity related expenses and costs it incurs to comply with anticipated new PHMSA and EPA regulations. TIGT also proposed to replace its fixed fuel and lost and unaccounted for (“FL&U”) charge with a FL&U tracker that would compensate TIGT for its actual FL&U expenses and adjust each year to reflect the previous period’s under or over collection and the forecasted FL&U expense for the upcoming period. Finally, TIGT proposed certain revisions to its FERC Gas Tariff addressing a number of other rate and non-rate matters. Under the NGA and the FERC’s regulations, TIGT’s shippers and other interested parties, including the FERC’s Trial Staff, have a right to challenge any aspect of TIGT’s rate case filing or raise other issues under Section 5 of the Natural Gas Act for which only prospective relief is available. Trailblazer 2013 Rate Case Filing - Docket No. RP13-1031 On January 22, 2014, Trailblazer, the FERC’s Trial Staff, and the active parties in the pipeline’s general rate case finalized a settlement in principle resolving the pending rate issues, including: (i) establishing transportation rates, as well as fuel and lost and unaccounted for charges; (ii) providing a limited profit sharing arrangement for certain revenues earned from interruptible and short-term firm transport; and (iii) setting the minimum and maximum time that can elapse before Trailblazer’s next rate case at the FERC. Trailblazer filed a motion with the FERC’s Chief Administrative Law Judge to accept the settlement rates on an interim basis ("Interim Rates") while the participants finalized a definitive settlement. The Chief Administrative Law Judge accepted the Interim Rates effective February 1, 2014. On February 24, 2014, Trailblazer filed an uncontested offer of settlement ("Stipulation and Agreement") among active party shippers. The Stipulation and Agreement established the Interim Rates as final settlement rates effective February 1, 2014, subject to the issuance of refunds to certain shippers for January 2014 transportation services and revised fuel and lost and unaccounted for rates, effective July 1, 2014. On March 11, 2014, the Presiding Administrative Law Judge certified the Stipulation and Agreement. On May 29, 2014, the FERC approved the Stipulation and Agreement. On June 30, 2014, Trailblazer filed tariff sheets to implement the Stipulation and Agreement effective July 1, 2014. Estimated refunds were reserved from revenues recorded in January 2014. On July 1, 2014, Trailblazer submitted refunds to its customers for amounts collected in excess of amounts that would have been collected under the Settlement Rates, with interest, and on July 18, 2014, filed a report of refunds with the FERC. The FERC issued orders accepting the tariff sheets with the requested effective date of July 1, 2014 and accepting the refund report filing on July 25, 2014 and August 7, 2014, respectively. 2015 Annual Fuel Tracker Filing - Docket No. RP15-841-000 On April 1, 2015, Trailblazer made its annual fuel tracker filing with a proposed effective date of May 1, 2015 in Docket No. RP15-841-000. This filing incorporates the revised fuel tracker and power cost tracker mechanisms agreed to in the 2013 Rate Case Filing settlement, which resolves all outstanding issues related to Trailblazer fuel recoveries. The FERC approved this filing on April 23, 2015. Pony Express On September 19, 2014, Pony Express filed with the FERC to adopt a tariff for initial local non-contract rates as well as initial Rules and Regulations in accordance with the Interstate Commerce Act to be effective starting on October 1, 2014. Local Contract Tariff rates were filed with the FERC on October 29, 2014 to be effective starting November 1, 2014. Joint Contract Tariff rates for oil received into the Pony Express System from the Belle Fourche Pipeline were filed on October 16, 2014 to be effective starting November 1, 2014. Joint Contract Tariff rates for oil received into the Pony Express pipeline system from Hiland Pipeline Company were filed on February 27, 2015 and effective April 1, 2015. On May 18, 2015, Pony Express filed with the FERC to implement tariff contract rates for Pony Express’ newly constructed lateral in Northeast Colorado effective June 1, 2015. On May 29, 2015, tariff filings were made with the FERC in Docket No. IS15-492-000 to increase the Pony Express local contract rates for service from the Guernsey origin, and for local non-contract rates from all origins, by amounts reflecting the FERC annual index adjustment of approximately 4.6% effective July 1, 2015. A tariff filing was also made in Docket No. IS15-493-000 on that date to increase joint tariff contract rates for service on Pony Express, Belle Fourche Pipeline Company, and Bridger Pipeline, LLC by approximately 4.6% effective July 1, 2015. On October 29, 2015, Pony Express made a tariff filing with the FERC in Docket No. IS16-42-000 to increase the contract rates under its Local Pipeline Tariff for transportation from receipt points on its lateral in Northeast Colorado to various delivery points in Oklahoma, by an amount reflecting the most recent FERC annual index adjustment of approximately 4.6% effective December 1, 2015. |
Legal and Environmental Matters
Legal and Environmental Matters | 9 Months Ended |
Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Legal and Environmental Matters | Legal In addition to the matters discussed below, we are a defendant in various lawsuits arising from the day-to-day operations of our business. Although no assurance can be given, we believe, based on our experiences to date, that the ultimate resolution of such routine items will not have a material adverse impact on our business, financial position, results of operations or cash flows. We have evaluated claims in accordance with the accounting guidance for contingencies that we deem both probable and reasonably estimable and, accordingly, had reserves for legal claims of approximately $0.8 million and $0.6 million as of September 30, 2015 and December 31, 2014 , respectively. Prairie Horizon On July 3, 2014, Prairie Horizon Agri-Energy LLC ("Prairie Horizon") filed an action in the District Court of Phillips County, Kansas against TIGT seeking damages from an alleged intrusion of foreign material and oil from TIGT into Prairie Horizon's ethanol plant. The matter was removed to the US District Court for the District of Kansas. Prairie Horizon asserted that this intrusion caused substantial damage to Prairie Horizon's ethanol production facilities and resulted in corresponding business income losses. Prairie Horizon also claimed that the intrusion was a violation of TIGT's FERC gas tariff. On September 25, 2015, TIGT and Prairie Horizon reached a settlement agreeing to dismiss all claims with prejudice and releasing TIGT from any further liability. Environmental, Health and Safety We are subject to a variety of federal, state and local laws that regulate permitted activities relating to air and water quality, waste disposal, and other environmental matters. We believe that compliance with these laws will not have a material adverse impact on our business, cash flows, financial position or results of operations. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development of new facts or conditions will not cause us to incur significant costs. We had environmental reserves of $5.0 million and $5.3 million at September 30, 2015 and December 31, 2014 , respectively. TMID Casper Plant, U.S. EPA Notice of Violation In August 2011, the U.S. EPA and the Wyoming Department of Environmental Quality ("WDEQ") conducted an inspection of the Leak Detection and Repair ("LDAR") Program at the Casper Gas Plant in Wyoming. In September 2011, Tallgrass Midstream, LLC ("TMID") received a letter from the U.S. EPA alleging violations of the Standards of Performance of Equipment Leaks for Onshore Natural Gas Processing Plant requirements under the Clean Air Act. TMID received a letter from the U.S. EPA concerning settlement of this matter in April 2013 and received additional settlement communications from the U.S. EPA and Department of Justice beginning in July 2014. Settlement negotiations are continuing, including attempted resolution of more recently identified LDAR issues and the possible inclusion of TIGT as a party to any possible settlement as a result of TIGT owning a compressor that is located adjacent to the Casper Gas Plant site. Casper Mystery Bridge Superfund Site The Casper Gas Plant is part of the Mystery Bridge Road/U.S. Highway 20 Superfund Site also known as Casper Mystery Bridge Superfund Site. Remediation work at the Casper Gas Plant has been completed and we have requested that the portion of the site attributable to us be delisted from the National Priorities List. Casper Gas Plant On November 25, 2014, WDEQ issued a Notice of Violation for violations of Part 60 Subpart OOOO related to the Depropanizer project (wv-14388, issued 7/9/13) in Docket No. 5506-14. TMID had discussed the issues in a meeting with WDEQ in Cheyenne on November 17, 2014, and submitted a disclosure on November 20, 2014 detailing the regulatory issues and potential violations. The project triggered a modification of Subpart OOOO for the entire plant. The project equipment as well as plant equipment subjected to Subpart OOOO was not monitored timely, and initial notification was not made timely. Settlement negotiations with WDEQ are currently ongoing. TIGT System Failure On June 13, 2013, a failure occurred on a segment of the TIGT pipeline system in Goshen County, Wyoming, resulting in the release of natural gas and the issuance of a Corrective Action Order ("CAO") by PHMSA. The line was promptly brought back into service and the failure did not cause any known injuries, fatalities, fires or evacuations. Pursuant to a letter dated August 14, 2015, PHMSA informed TIGT that it had complied with the terms of the CAO and declared the case closed. We do not believe the total cost to complete the remediation activities will be material. Trailblazer Pipeline Integrity Management Program Trailblazer recently completed smart tool surveys and preliminary analysis on segments of its natural gas pipeline to evaluate the growth rate of corrosion downstream of compressor stations. Trailblazer currently believes that approximately 25 - 35 miles of pipe will likely need to be repaired or replaced in order for the pipeline to operate at its maximum allowable operating pressure of 1,000 pounds per square inch, or psig. Such repair or replacement may occur over a period of years, depending upon final assessment of corrosion growth rates and the remediation and repair plan adopted by Trailblazer. Until then, Trailblazer is operating at a reduced pressure, public notice of which was first provided in June 2014. The current pressure reduction is not expected to prevent Trailblazer from fulfilling its firm service obligations at existing subscription levels and to date it has not had a material adverse financial impact on TEP. During 2015, Trailblazer completed 23 excavation digs at an aggregate cost of approximately $1.1 million (all of which was included in Trailblazer’s 2015 budget) based on preliminary analysis of the smart tool surveys performed in 2014. Segments of the Trailblazer Pipeline that require full replacement are currently expected to cost in the range of approximately $2.2 million to $2.7 million per mile. Repair costs on sections of the pipeline that do not require full replacement are expected to be less on a per mile basis. Trailblazer is currently devising a remediation and repair plan, which involves, among other things, finalizing cost recovery options, establishing project scope and timing and setting an overall project budget. Trailblazer is currently exploring all possible cost recovery options. It may not ultimately be able to recover any or all of such out of pocket costs unless and until Trailblazer recovers them through a general rate increase or other FERC-approved recovery mechanism, or through negotiated rate agreements with its customers. In connection with TEP’s acquisition of the Trailblazer Pipeline, TD agreed to contractually indemnify TEP for any out of pocket costs TEP incurs between April 1, 2014 and April 1, 2017 related to repairing or remediating the Trailblazer Pipeline, to the extent that such actions are necessitated by external corrosion caused by the pipeline’s disbonded Hi-Melt CTE coating. The contractual indemnity provided to TEP by TD is currently capped at $20 million and is subject to TEP’s first paying an annual $1.5 million deductible. Pony Express System Failures On August 31, 2014, a leak occurred at the Sterling Pump Station on the Pony Express System in Logan County, Colorado, which resulted in a release of approximately 200 bbls of crude oil. The spill was entirely contained on our property and the costs to remediate were not material. In April 2015, PHSMA granted our request to consider the Sterling Pump Station incident closed with no further action. On March 12, 2015, an event occurred at the Yoder Pump Station in Goshen County, Wyoming, related to repair and replacement activities resulting in a spill of approximately 300 bbls of crude oil. We have presented our incident investigation findings to PHMSA and are currently working with PHMSA to resolve the matter. We do not believe the cost of anticipated remediation activities will be material. |
Reporting Segments
Reporting Segments | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
Reporting Segments | Our operations are located in the United States. We are organized into three reporting segments: (1) Natural Gas Transportation & Logistics, (2) Crude Oil Transportation & Logistics, and (3) Processing & Logistics. Natural Gas Transportation & Logistics The Natural Gas Transportation & Logistics segment is engaged in ownership and operation of FERC-regulated interstate natural gas pipelines and integrated natural gas storage facilities that provide services to on-system customers (such as third-party LDCs), industrial users and other shippers. As discussed in Note 2 – Summary of Significant Accounting Policies , results for prior periods have been recast to reflect the operations of Trailblazer. Crude Oil Transportation & Logistics The Crude Oil Transportation & Logistics segment is engaged in ownership, construction, and operation of the Pony Express System, which is a FERC-regulated crude oil pipeline serving the Bakken Shale and other nearby oil producing basins. The mainline portion of the Pony Express System was placed in service in October 2014. The Pony Express System also includes a lateral pipeline in Northeast Colorado, which interconnects with the Pony Express System just east of Sterling, Colorado and was placed in service in April 2015. As discussed in Note 2 – Summary of Significant Accounting Policies , results for prior periods have been recast to reflect the operations of Pony Express. Processing & Logistics The Processing & Logistics segment is engaged in ownership and operation of natural gas processing, treating and fractionation facilities that produce NGLs and residue gas that is sold in local wholesale markets or delivered into pipelines for transportation to additional end markets, as well as water business services provided primarily to the oil and gas exploration and production industry. Corporate and Other Corporate and Other includes corporate overhead costs that are not directly associated with the operations of our reportable segments, such as interest and fees associated with our revolving credit facilities, public company costs reimbursed to TD, and equity-based compensation expense. These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for their respective operations. We measure segment profit using Operating Income. The following tables set forth our segment information for the periods indicated: Three Months Ended September 30, 2015 Three Months Ended September 30, 2014 Revenue: Total Inter- External Total Inter- External (in thousands) (in thousands) Natural Gas Transportation & Logistics $ 33,636 $ (1,346 ) $ 32,290 $ 33,520 $ (1,430 ) $ 32,090 Crude Oil Transportation & Logistics 83,272 — 83,272 — — — Processing & Logistics 22,606 — 22,606 57,863 — 57,863 Total Revenue $ 139,514 $ (1,346 ) $ 138,168 $ 91,383 $ (1,430 ) $ 89,953 Nine Months Ended September 30, 2015 Nine Months Ended September 30, 2014 Revenue: Total Inter- External Total Inter- External (in thousands) (in thousands) Natural Gas Transportation & Logistics $ 98,215 $ (4,036 ) $ 94,179 $ 107,091 $ (4,015 ) $ 103,076 Crude Oil Transportation & Logistics 208,872 — 208,872 — — — Processing & Logistics 82,762 — 82,762 158,976 — 158,976 Total Revenue $ 389,849 $ (4,036 ) $ 385,813 $ 266,067 $ (4,015 ) $ 262,052 Three Months Ended September 30, 2015 Three Months Ended September 30, 2014 Operating Income: Total Inter- External Total Inter- External (in thousands) (in thousands) Natural Gas Transportation & Logistics $ 10,499 $ (1,346 ) $ 9,153 $ 10,791 $ (1,430 ) $ 9,361 Crude Oil Transportation & Logistics 44,069 1,346 45,415 (822 ) — $ (822 ) Processing & Logistics (212 ) — (212 ) 5,141 — $ 5,141 Corporate and Other (1,951 ) — (1,951 ) (2,100 ) — $ (2,100 ) Total Operating Income $ 52,405 $ — $ 52,405 $ 13,010 $ (1,430 ) $ 11,580 Reconciliation to Net Income: Interest expense, net (4,982 ) (1,058 ) Other income, net 502 731 Net Income before income tax $ 47,925 $ 11,253 Nine Months Ended September 30, 2015 Nine Months Ended September 30, 2014 Operating Income: Total Inter- External Total Inter- External (in thousands) (in thousands) Natural Gas Transportation & Logistics $ 32,989 $ (4,036 ) $ 28,953 $ 32,075 $ (4,015 ) $ 28,060 Crude Oil Transportation & Logistics 103,857 4,036 $ 107,893 (2,336 ) — $ (2,336 ) Processing & Logistics 4,508 — $ 4,508 14,459 — $ 14,459 Corporate and Other (7,126 ) — $ (7,126 ) (5,599 ) — $ (5,599 ) Total Operating Income $ 134,228 $ — $ 134,228 $ 38,599 $ (4,015 ) $ 34,584 Reconciliation to Net Income: Interest expense, net (12,901 ) (4,492 ) Gain on remeasurement of unconsolidated investment — 9,388 Equity in earnings of unconsolidated investment — 717 Other income, net 1,983 2,400 Net Income before income tax $ 123,310 $ 42,597 Nine Months Ended September 30, Capital Expenditures: 2015 2014 (in thousands) Natural Gas Transportation & Logistics $ 10,858 $ 16,616 Crude Oil Transportation & Logistics 40,579 617,687 Processing & Logistics 13,709 7,913 Total capital expenditures $ 65,146 $ 642,216 Assets: September 30, 2015 December 31, 2014 (in thousands) Natural Gas Transportation & Logistics $ 713,754 $ 716,106 Crude Oil Transportation & Logistics 1,444,231 1,394,793 Processing & Logistics 337,522 340,620 Corporate and Other 449,220 5,678 Total assets $ 2,944,727 $ 2,457,197 |
Summary of Significant Accoun22
Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation These unaudited condensed consolidated financial statements and related notes for the three and nine months ended September 30, 2015 and 2014 were prepared in accordance with the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2015 and 2014 include all normal, recurring adjustments and disclosures that we believe are necessary for a fair presentation of the results for the interim periods. In this report, the Financial Accounting Standards Board is referred to as the FASB and the FASB Accounting Standards Codification is referred to as the Codification or ASC. Our financial results for the three and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2015. The accompanying unaudited condensed consolidated interim financial statements should be read in conjunction with our final prospectus dated May 6, 2015 (the “Prospectus”) included in our Registration Statement on Form S-1, as amended (SEC File No. 333-202258) and filed with the United States Securities and Exchange Commission (the “SEC”) pursuant to Rule 424 on May 7, 2015. The unaudited condensed consolidated financial statements of TEGP as of December 31, 2014 and for the three and nine months ended September 30, 2014 , include historical cost basis accounts of the assets of TEGP and were prepared in contemplation of TEGP’s initial public offering of Class A shares completed on May 12, 2015 and the acquisition of an approximately 30.35% interest in Tallgrass Equity as described in Note 1 – Description of Business , which was accounted for as a transaction between entities under common control in accordance with ASC 805. Significant intra-entity items have been eliminated in the presentation. Both TEGP and TEGP Predecessor are considered entities under common control and, as such, the transfer between the entities of the assets and liabilities has been recorded by TEGP at historical cost. TEGP, as used herein, refers to the consolidated financial results and operations for TEGP Predecessor prior to the completion of the Offering and to TEGP thereafter. |
Consolidation | Net income or loss from consolidated subsidiaries that are not wholly-owned by TEGP are attributed to TEGP 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 TEGP. Concurrent with TEP's acquisition of an initial 33.3% membership interest in Tallgrass Pony Express Pipeline, LLC ("Pony Express") effective September 1, 2014, TEP, TD, and Pony Express entered into the Second Amended and Restated Limited Liability Agreement of Tallgrass Pony Express Pipeline, LLC ("the Second Amended Pony Express LLC Agreement"), which provided TEP a minimum quarterly preference payment of $16.65 million (prorated to approximately $5.4 million for the quarter ended September 30, 2014) through the quarter ended September 30, 2015. Effective March 1, 2015 with TEP's acquisition of an additional 33.3% membership interest in Pony Express, the Second Amended Pony Express LLC Agreement was further amended (as amended, "the Pony Express LLC Agreement") to increase the minimum quarterly preference payment to $36.65 million (prorated to approximately $23.5 million for the quarter ended March 31, 2015) and extend the term of the preference period through the quarter ending December 31, 2015. The Pony Express LLC Agreement provides that the net income or loss of Pony Express be allocated, to the extent possible, consistent with the allocation of Pony Express cash distributions. Under the terms of the Pony Express LLC Agreement, Pony Express distributions and net income for periods beginning after December 31, 2015 will be attributed to TEP and its noncontrolling interests in accordance with the respective ownership interests. A variable interest entity ("VIE") is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has a variable interest that could be significant to the VIE and the power to direct the activities that most significantly impact the entity’s economic performance. We have presented separately in our condensed consolidated balance sheets, to the extent material, the assets of our consolidated VIEs that can only be used to settle specific obligations of the consolidated VIEs, and the liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit. Tallgrass Equity and Pony Express are considered to be VIEs under the applicable authoritative guidance. Based on a qualitative analysis in accordance with the applicable authoritative guidance, we have determined that we have the power to direct matters that most significantly impact the activities of Tallgrass Equity and Pony Express and have the right to receive benefits of Tallgrass Equity and Pony Express that could potentially be significant to the respective entities. We have consolidated Tallgrass Equity as we are the primary beneficiary. We also consolidate Pony Express through our indirect investment in TEP, as TEP is the primary beneficiary of Pony Express. For additional information see Note 3 – Variable Interest Entities . |
Use of Estimates | Use of Estimates Certain amounts included in or affecting these condensed consolidated financial statements and related disclosures must be estimated, requiring management to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts reported for assets, liabilities, revenues, and expenses during the reporting period, and the disclosure of contingent assets and liabilities at the date of the financial statements. Management evaluates these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods it considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from these estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. |
Cash and Cash Equivalents, Policy [Policy Text Block] | 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 and distributions included in the condensed consolidated statements of cash flows represent transfers of cash as a result of TD’s centralized cash management systems prior to April 1, 2014 for Trailblazer Pipeline Company LLC ("Trailblazer") and September 1, 2014 for Pony Express, under which cash balances were swept periodically and recorded as loans from the subsidiaries to TD. These loans were then periodically recorded as equity distributions. Pony Express participates in a cash management agreement with TD, which holds a 33.3% common membership interest in Pony Express, under which cash balances are swept daily and recorded as loans from Pony Express to TD. All payable and receivable balances between TEGP and TD are cash settled with the exception of certain balances payable from Pony Express to TD, which have been settled against the receivable from TD via the Pony Express cash management agreement discussed in the prior paragraph. |
Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block] | 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 $0.7 million and $0.5 million at September 30, 2015 and December 31, 2014 . |
Inventory, Policy [Policy Text Block] | Inventories Inventories primarily consist of gas in underground storage, materials and supplies, natural gas liquids and crude oil. Gas in underground storage, sometimes referred to as working gas, and natural gas liquids are recorded at the lower of historical cost or market using the average cost method. As discussed further under " Revenue Recognition " below, a loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil, which we can then sell. As pipeline allowance oil is accumulated, it is recorded as inventory at the lower of historical cost or market using the average cost method. Materials and supplies are valued at weighted average cost and periodically reviewed for physical deterioration and obsolescence. For additional information, see " Gas in Underground Storage " below. |
Accounting for Regulatory Activities [Policy Text Block] | 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 had recorded regulatory assets of approximately $1.2 million and $1.4 million included in "Deferred charges and other assets" in the condensed consolidated balance sheets at September 30, 2015 and December 31, 2014 , respectively. Regulatory assets at September 30, 2015 and December 31, 2014 were primarily attributable to costs associated with Trailblazer’s 2013 Rate Case Filing as more fully described in Note 13 – Regulatory Matters . |
Property, Plant and Equipment, Policy [Policy Text Block] | 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 directly related to the construction of assets, including internal labor costs, interest and engineering costs. Routine maintenance, repairs and renewal costs are expensed as incurred. The cost of normal retirements of the regulated depreciable utility property, plant and equipment, plus the cost of removal less salvage value and any gain or loss recognized, is recorded in accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of non-regulated or regulated property, plant and equipment constituting an operating unit or system, and land, when sold or abandoned and costs of removal or salvage are expensed when incurred. |
Intangible Assets, Finite-Lived, Policy [Policy Text Block] | Intangible Assets We account for intangible assets in accordance with ASC 805, which established that an intangible asset is identifiable if it meets either the separability criterion or the contractual-legal criterion. Further, in accordance with ASC 805, contract-based intangible assets represent the value of rights that arise from contractual arrangements. Use rights such as drilling, water, air, timber cutting, and route authorities are an example of contract-based intangible assets. Intangible assets arose at Pony Express from the acquisition of rights associated with the ability and regulatory permissions to convert a section of the Tallgrass Interstate Gas Transmission, LLC ("TIGT") natural gas pipeline, which was subsequently purchased by Pony Express, to crude oil and includes the operational and financial benefits that accrue due to those rights and the ability to make that asset more valuable ("the Pony Express oil conversion use rights"). These intangible assets are amortized on a straight-line basis over a period of 35 years , the period of expected future benefit. Intangible assets arose at BNN Redtail, LLC ("Redtail") as a result of a significant customer contract with favorable market terms which was acquired as part of the BNN Water Solutions, LLC ("Water Solutions") transaction discussed in Note 4 – Acquisitions . This intangible asset is amortized on a straight-line basis over a period of 1.6 years , the remaining term of the contract at the time of acquisition. |
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block] | 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 may not be recoverable. An impairment loss results when the estimated undiscounted future net cash flows expected to result from the asset’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 is tested for impairment whenever events or changes in circumstances indicate its carrying amount may exceed its fair value. Examples of long-lived asset impairment indicators include: • a significant decrease in the market value of a long-lived asset or group; • a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition; • a significant adverse change in legal factors or in the business climate could affect the value of long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process; • an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the long-lived asset or asset group; • a current period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and • a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. When an impairment indicator is present, we first assesses the recoverability of the long-lived assets by comparing the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset to the carrying amount of the asset. If the carrying amount is higher than the undiscounted future cash flows, the fair value of the assets is assessed using a discounted cash flow analysis and used to determine the amount of impairment, if any, to be recognized. |
Oil and Gas Properties Policy [Policy Text Block] | 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 condensed consolidated financial statements. We occasionally acquire volumes of working gas for our own account. These volumes of working gas are recorded as natural gas inventory at the lower of cost or market. |
Depreciation, Depletion, and Amortization [Policy Text Block] | Depreciation and Amortization - Regulated Assets For our regulated assets at TIGT and Trailblazer, we have elected to compute depreciation using a composite method employed by applying a single, FERC approved depreciation rate to a group of assets with similar economic characteristics. This composite method of depreciation approximates a straight-line method of depreciation. The annualized rate of depreciation ranges from 0.70% to 12.00% for the various classes of depreciable, regulated assets. Depreciation and Amortization - Non-regulated Assets For non-regulated assets, we have elected to use the straight-line method of depreciation. The useful lives for the various classes of non-regulated depreciable assets are as follows: Range of Useful Lives (in years) Crude oil pipelines 35 Processing & Treating 30 Natural gas pipelines (1) 10 General & Other 3-13 1/3 (1) Includes the Replacement Gas Facilities as discussed in Note 5 – Related Party Transactions and Note 13 – Regulatory Matters . |
Gas Balancing, Policy [Policy Text Block] | 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 Charges, Policy [Policy Text Block] | Deferred Financing Costs Costs incurred in connection with the issuance of long-term debt are deferred and amortized over the related financing period using the effective interest method. |
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block] | Goodwill We evaluate goodwill for impairment on an annual basis and whenever events or changes in circumstances necessitate an evaluation for impairment. Examples of such facts and circumstances include changes in the magnitude of the excess of the fair value over the carrying amount in the last valuation or changes in the business environment. Our annual impairment testing date is August 31st. We evaluate goodwill for impairment at the reporting unit level, which is an operating segment as defined in the segment reporting guidance of the Codification, using either the qualitative assessment option or the two-step test approach depending on facts and circumstances of the reporting unit. If we, after performing the qualitative assessment, determine it is "more likely than not" that the fair value of a reporting unit is greater than its carrying amount, the two-step impairment test is unnecessary. When goodwill is evaluated for impairment using the two-step test, the carrying amount of the reporting unit is compared to its fair value in Step 1 and if the fair value exceeds the carrying amount, Step 2 is unnecessary. If the carrying amount exceeds the reporting unit’s fair value, this could indicate potential impairment and Step 2 of the goodwill evaluation process is required to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any. When Step 2 is necessary, the fair value of individual assets and liabilities is determined using valuations, or other observable sources of fair value, as appropriate. If the carrying amount of goodwill exceeds its implied fair value, the excess is recognized as an impairment loss. We did not elect to apply the qualitative assessment option during our 2015 annual goodwill impairment testing, instead we proceeded directly to the two-step quantitative test. In Step 1 of the two-step quantitative test, we compared the fair value of each reporting unit with its respective book value, including goodwill, by using an income approach based on a discounted cash flow analysis. For the purpose of goodwill impairment testing, goodwill was allocated to our reporting units based on the enterprise value of each reporting unit at the date of acquisition. The fair value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and included a sensitivity analysis of the impact of changes in various assumptions. This approach required us to make long-term forecasts of future operating results and various other assumptions and estimates, the most significant of which are gross margin, operating expenses, general and administrative expenses, long-term growth rates and the weighted average cost of capital. The fair value of the reporting units was determined using significant unobservable inputs, considered Level 3 under the fair value hierarchy in the Codification. For each reporting unit, the results of the Step 1 impairment analysis indicated no potential impairment as the fair value of the reporting units was greater than their respective book values. As a result, in accordance with the Codification guidance, Step 2 of the impairment analysis was not necessary as part of the annual impairment analysis in 2015. 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. |
Investment, Policy [Policy Text Block] | Investment in Unconsolidated Affiliates We use the equity method to account for investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and for investments in less than 20% owned affiliates where we have the ability to exercise significant influence. We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models. The difference between the carrying amount of the unconsolidated affiliates and their estimated fair value is recognized as an impairment loss when the loss in value is deemed to be other-than-temporary. Our investment in Grasslands Water Services I, LLC ("GWSI"), which owns a water transportation pipeline, was initially recorded under the equity method of accounting as we had the ability to exercise significant influence, but not control, over this investment. There was $0.7 million equity in earnings recognized for the nine months ended September 30, 2014 . There were no equity in earnings recognized for the three months ended September 30, 2014 and the three and nine months ended September 30, 2015 . As discussed in Note 4 – Acquisitions , during the year ended December 31, 2014, TEGP acquired a controlling interest in GWSI, which was subsequently renamed BNN Redtail, LLC ("Redtail"), and consolidated its investment in Redtail as of May 13, 2014 accordingly. |
Revenue Recognition, Policy [Policy Text Block] | Revenue Recognition We recognize revenues as services are rendered or goods are sold to a purchaser at a fixed and determinable price, delivery has occurred, title has transferred and collectability is reasonably assured. We provide various types of natural gas storage and transportation services and crude oil transportation services to our customers in which the commodity remains the property of these customers at all times. Natural gas liquids sales occur in the Processing & Logistics segment and consist of the sale of outputs from our processing plants and the marketing of natural gas liquids that are delivered by our suppliers under either fee-based arrangements or percent-of-proceeds arrangements. Under these arrangements, we treat and process the natural gas delivered by our suppliers, and then sell the resulting NGLs and condensate based on published index market prices. We remit to the producers an agreed-upon percentage of the actual proceeds that we receive from our sales of the NGLs and condensate. We keep the difference between the proceeds received and the amount remitted back to the producer. We generally report gross revenues in the condensed consolidated statements of income, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Processing and other revenues primarily represent fees for processing, treating and fractionation of natural gas and NGLs earned under fee-based arrangements and revenue from water services earned in the Processing & Logistics segment. Natural gas sales occur in both the Natural Gas Transportation & Logistics segment and in the Processing & Logistics segment. In the Natural Gas Transportation & Logistics segment, transportation services revenue is recognized when a portion of the natural gas transported by customers is collected as a contractual fee to compensate us for fuel consumed by pipeline and storage operations. We take title and record revenue at market prices when the volumes included in the contractual fee are delivered from the customer and injected into our storage facility. When the excess volumes are eventually sold we record natural gas sales revenue at the contractual sales price and cost of sales at average cost. In addition, when operational conditions allow, we occasionally sell "base gas," which refers to the minimum volume of natural gas required in order to operate the storage facility. In the Processing & Logistics segment, we purchase natural gas primarily for use in our operations and for meeting contractual requirements to deliver natural gas to certain customers. In addition, some of our contractual arrangements allow us to keep a portion of the processed natural gas as compensation for processing services. We generate revenue by selling the volumes of natural gas received or purchased that exceed our business needs. Natural gas transportation and storage services occur in the Natural Gas Transportation & Logistics segment. In many cases (generally described as "firm service"), the customer pays a two-part rate that includes (i) a fee reserving the right to transport or store natural gas in our facilities and (ii) a per-unit rate for volumes actually transported or injected into/withdrawn from storage. The fee-based component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are delivered to the customers’ agreed upon delivery point, or when the volumes are injected into/withdrawn from our storage facilities. In other cases (generally described as "interruptible service"), there is no fixed fee associated with the services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have purchased firm service. In the case of interruptible service, revenue is recognized in the same manner utilized for the per-unit rate for volumes actually transported under firm service agreements. In addition to "firm" and "interruptible" transportation services, we also provide natural gas park and loan services to assist customers in managing short-term gas surpluses or deficits. Revenues are recognized as services are provided, based on the terms negotiated under these contracts. Crude oil transportation services occur in the Crude Oil Transportation & Logistics segment. We provide various types of crude oil transportation services to our customers and, other than pipeline allowance oil, do not take title to the crude oil and do not incur the risks and rewards of ownership. In many cases the customer has committed to ship a fixed quantity of oil barrels per month. For barrels physically received by us and delivered to the customers’ agreed upon destination point, revenue is recognized in the period the service is provided. Shipper deficiencies, or barrels committed by the customer to be transported in a month but not physically received by us for transport or delivered to the customers’ agreed upon destination point, are charged at the committed tariff rate per barrel and recorded as a deferred liability until the barrels are physically transported and delivered. In the case of non-committed shippers, revenue is recognized in the same manner utilized for the barrels physically transported and delivered. A loss allowance is factored into the crude oil tariffs to offset losses in transit. As crude oil is transported, we earn oil for our services as pipeline allowance oil. Any pipeline allowance oil that remains after replacing losses in transit can be sold. We take title and record revenue at market prices when the volumes included in the pipeline loss allowance are delivered from the customer. When pipeline loss allowance oil is eventually sold we record revenue at the contractual sales price and cost of sales at average cost as discussed in "Inventories" above. During the three and nine months ended September 30, 2015 , we recognized revenue of $1.3 million and $2.5 million on the sale of pipeline allowance oil, which is included in "Sales of natural gas, NGLs, and crude oil" in the condensed consolidated statements of income. |
Commitments and Contingencies, Policy [Policy Text Block] | 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, Policy [Policy Text Block] | 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 Measurement, Policy [Policy Text Block] | 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 8 – Risk Management . For information regarding the fair value of financial instruments not measured at fair value in the condensed consolidated balance sheets, see Note 9 – Long-term Debt . |
Derivatives, Policy [Policy Text Block] | Risk Management Activities We utilize energy derivatives for the purpose of mitigating our risk resulting from fluctuations in the market price of natural gas. We record derivative contracts at their estimated fair values as of each reporting date. For more information on our risk management activities, see Note 8 – Risk Management . |
Compensation Related Costs, Policy [Policy Text Block] | 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. A portion of the expense recognized relating to equity-based compensation grants is charged to TD. |
Income Tax, Policy [Policy Text Block] | Income Taxes Prior to the completion of the Offering on May 12, 2015, TEGP Predecessor was comprised solely of limited liability companies that elected to be treated as partnerships for income tax purposes. Accordingly, no provision for federal or state income taxes was recorded in the financial statements of TEGP Predecessor and the tax effects of our activities accrued to their respective partners and members for periods prior May 12, 2015. Subsequent to May 12, 2015, TEGP's consolidated subsidiaries consist primarily of entities that have elected to be treated as partnerships for income tax purposes. On September 14, 2015, TEGP, 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. Although TEGP is organized as a limited partnership, we have elected to be treated as a corporation for U.S. federal income tax purposes and are therefore subject to both U.S. federal and state income taxes for periods beginning May 12, 2015. We recognized a deferred tax asset of $445.1 million as a result of the Reorganization Transactions in connection with the Offering, $3.6 million of which was recognized as deferred income tax expense during the period from May 12, 2015 to September 30, 2015 . We estimate an annual effective income tax rate based on projected results for the year and apply this rate to income before taxes to calculate income tax expense. All earnings from TEGP's consolidated subsidiaries are included in our net income, however we are not required to record income tax expense with respect to the portion of our earnings allocated to noncontrolling interests, which reduces our effective tax rate. Our effective income tax rate for the period from May 12, 2015 to September 30, 2015 was 4.30% . We are projecting a tax loss for both U.S. Federal and State income taxes for the year ended December 31, 2015. As a result, there is no current provision for income taxes for the three and nine months ended September 30, 2015 . Pursuant to the applicable guidance related to accounting for uncertainty in income taxes, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of three and nine months ended September 30, 2015 , we had not recognized any material amounts in connection with uncertainty in income taxes. |
Accounting Pronouncements Issued But Not Yet Effective | Accounting Pronouncements Issued But Not Yet Effective Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers (Topic 606)" In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 provides a comprehensive and converged set of principles-based revenue recognition guidelines which supersede the existing industry and transaction-specific standards. The core principle of the new guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, entities must apply a five step process to (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also mandates disclosure of sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The disclosure requirements include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. The amendments in ASU 2014-09 are effective for public entities for annual reporting periods beginning after December 15, 2017, and for interim periods within that reporting period. Early application is permitted for annual reporting periods beginning after December 15, 2016. We are currently evaluating the impact of ASU 2014-09. ASU No. 2014-12, "Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period" In June 2014, the FASB issued ASU No. 2014-12, Compensation - Stock Compensation (Topic 718), Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period. ASU 2014-12 provides explicit guidance on accounting for share-based payments requiring a specific performance target to be achieved in order for employees to become eligible to vest in the awards when that performance target may be achieved after the requisite service period for the award. The ASU requires that such performance targets be treated as a performance condition, and should not be reflected in the estimate of the grant-date fair value of the award. Instead, compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. ASU 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early adoption is permitted. The adoption of ASU 2014-12 is not expected to have a material impact on our financial position and results of operations. ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis" In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810) - Amendments to the Consolidation Analysis. ASU 2015-02 will change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. ASU 2015-02 will modify the evaluation of whether limited partnerships and other similar legal entities are considered VIEs or voting interest entities, eliminate the presumption that a general partner should consolidate a limited partnership, and change certain aspects of the consolidation analysis for reporting entities that are involved with VIEs, particularly for those with fee arrangements and related party relationships. The amendments in ASU 2015-02 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2015. Early application is permitted, including adoption in an interim period. We are currently evaluating the impact of ASU 2015-02. ASU No. 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory" In July 2015, the FASB issued ASU No. 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory. ASU 2015-11 establishes a "lower of cost and net realizable value" model for the measurement of most inventory balances. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The amendments in ASU 2015-11 are effective for public entities for annual periods and interim periods within those annual periods beginning after December 15, 2016. Early adoption is permitted. We are currently evaluating the impact of ASU 2015-11. |
Summary of Significant Accoun23
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Accounting Policies [Abstract] | |
ScheduleOfEstimatedUsefulLife [Table Text Block] | The useful lives for the various classes of non-regulated depreciable assets are as follows: Range of Useful Lives (in years) Crude oil pipelines 35 Processing & Treating 30 Natural gas pipelines (1) 10 General & Other 3-13 1/3 (1) Includes the Replacement Gas Facilities as discussed in Note 5 – Related Party Transactions and Note 13 – Regulatory Matters . |
Variable Interest Entity (Table
Variable Interest Entity (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Variable Interest Entities [Table Text Block] | The carrying amounts and classifications of the Tallgrass Equity consolidated assets and liabilities, including the assets and liabilities of Pony Express, included in our condensed consolidated balance sheets at September 30, 2015 and December 31, 2014 are as follows: September 30, 2015 December 31, 2014 (in thousands) Current assets $ 90,824 $ 132,281 Noncurrent assets 2,412,376 2,324,916 Total assets $ 2,503,200 $ 2,457,197 Current liabilities $ 74,835 $ 96,568 Noncurrent liabilities 849,461 565,478 Total liabilities $ 924,296 $ 662,046 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Related Party Transactions [Abstract] | |
Schedule of Transactions with Affiliated Companies | Totals of transactions with affiliated companies are as follows: Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Cost of transportation services $ 7,180 $ — $ 17,771 $ — Charges to TEGP: (1) Property, plant and equipment, net $ 958 $ 7,926 $ 3,859 $ 14,534 Operation and maintenance $ 6,077 $ 4,701 $ 17,325 $ 13,657 General and administrative $ 10,041 $ 5,783 $ 28,862 $ 14,670 (1) Charges to TEGP, inclusive of Tallgrass Equity, TEP, and Pony Express, include directly charged wages and salaries, other compensation and benefits, and shared services. |
Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets | Details of balances with affiliates included in "Receivable from related party" and "Accounts payable to related parties" in the condensed consolidated balance sheets are as follows: September 30, 2015 December 31, 2014 (in thousands) Receivable from related party: Tallgrass Operations, LLC $ — $ 73,393 Total receivable from related party $ — $ 73,393 Accounts payable to related parties: Tallgrass Operations, LLC $ 3,561 $ 3,894 Rockies Express Pipeline LLC 20 21 Total accounts payable to related parties $ 3,581 $ 3,915 |
Schedule of Balances of Gas Imbalance with Affiliated Shippers | Balances of gas imbalances with affiliated shippers are as follows: September 30, 2015 December 31, 2014 (in thousands) Affiliate gas balance receivables $ — $ 275 Affiliate gas balance payables $ 269 $ 455 |
Inventory (Tables)
Inventory (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Inventory Disclosure [Abstract] | |
Schedule of Components of Inventory | The components of inventory at September 30, 2015 and December 31, 2014 consisted of the following: September 30, 2015 December 31, 2014 (in thousands) Crude oil $ 2,534 $ 581 Materials and supplies 5,852 3,049 Natural gas liquids 345 519 Gas in underground storage 5,401 8,896 Total inventory $ 14,132 $ 13,045 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Property, Plant and Equipment [Abstract] | |
Components of Property Plant and Equipment | A summary of net property, plant and equipment by classification is as follows: September 30, 2015 December 31, 2014 (in thousands) Crude oil pipelines $ 1,159,002 $ 939,536 Natural gas pipelines 556,924 548,482 Processing and treating assets 238,356 241,671 General and other 63,910 42,719 Construction work in progress 45,051 139,873 Accumulated depreciation and amortization (114,422 ) (59,200 ) Total property, plant and equipment, net $ 1,948,821 $ 1,853,081 |
Risk Management (Tables)
Risk Management (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Fair Value of Derivative Contracts | The following table summarizes the fair values of our derivative contracts included in the condensed consolidated balance sheets: Balance Sheet September 30, 2015 December 31, 2014 (in thousands) Energy commodity derivative contracts Current assets $ 218 $ — |
Derivative Contracts Included in Consolidated Statements of Income | The following table summarizes the impact of derivative contracts for the three and nine months ended September 30, 2015 and 2014 : Amount of Gain (Loss) Recognized in Income on Derivatives Location of gain (loss) recognized Three Months Ended September 30, Nine Months Ended September 30, 2015 2014 2015 2014 (in thousands) Derivatives not designated as hedging contracts: Energy commodity derivative contracts Sales of natural gas, NGLs, and crude oil $ 252 $ 9 $ 211 $ (449 ) |
Derivative Instruments Maximum Potential Exposure To Credit Loss [Table Text Block] | The maximum potential exposure to credit losses on TEP's derivative contracts at September 30, 2015 was: Asset Position (in thousands) Gross $ 218 Netting agreement impact — Cash collateral held — Net Exposure $ 218 |
Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification | The following table summarizes the fair value measurements of our energy commodity derivative contracts as of September 30, 2015 based on the fair value hierarchy established by the Codification: Asset Fair Value Measurements Using Total Quoted prices in Significant Significant (in thousands) As of September 30, 2015 Energy commodity derivative contracts $ 218 $ — $ 218 $ — |
Long-term Debt (Tables)
Long-term Debt (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Line of Credit Facility [Line Items] | |
Carrying Amount and Fair value of TEP's Long-term Debt | The following table sets forth the carrying amount and fair value of our long-term debt, which is not measured at fair value in the condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 , but for which fair value is disclosed: Fair Value Quoted prices Significant Significant Total Carrying (in thousands) September 30, 2015 $ — $ 844,000 $ — $ 844,000 $ 844,000 December 31, 2014 $ — $ 559,000 $ — $ 559,000 $ 559,000 |
Tallgrass Equity, LLC [Member] | |
Line of Credit Facility [Line Items] | |
Schedule of Line of Credit Facilities | The following table sets forth the available borrowing capacity under the Tallgrass Equity revolving credit facility as of September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 (in thousands) Total capacity under the Tallgrass Equity revolving credit facility $ 150,000 $ — Less: Outstanding borrowings under the Tallgrass Equity revolving credit facility (148,000 ) — Available capacity under the Tallgrass Equity revolving credit facility $ 2,000 $ — |
Tallgrass Energy Partners [Member] | |
Line of Credit Facility [Line Items] | |
Schedule of Line of Credit Facilities | The following table sets forth the available borrowing capacity under the TEP revolving credit facility as of September 30, 2015 and December 31, 2014 : September 30, 2015 December 31, 2014 (in thousands) Total capacity under the TEP revolving credit facility $ 850,000 $ 850,000 Less: Outstanding borrowings under the TEP revolving credit facility (696,000 ) (559,000 ) Available capacity under the TEP revolving credit facility $ 154,000 $ 291,000 |
Partnership Equity and Distri30
Partnership Equity and Distributions Partnership and Equity and Distributions (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Tallgrass Energy GP, LP [Member] | |
Dividends Declared [Table Text Block] | The following table details the distributions paid by TEGP during the nine months ended September 30, 2015 : Three Months Ended Date Paid Distributions to Class A Shareholders Distributions per Class A Share (in thousands) September 30, 2015 November 13, 2015 (1) $ 6,872 $ 0.144 June 30, 2015 August 17, 2015 3,484 0.073 (2) (1) The distribution for the third quarter of 2015 will be paid on November 13, 2015 to Class A shareholders of record at the close of business on October 30, 2015. (2) The first quarterly distribution declared on July 15, 2015 was prorated for the number of days between the closing of TEGP’s initial public offering on May 12, 2015 and the end of the second quarter. |
Tallgrass Energy Partners [Member] | |
Dividends Declared [Table Text Block] | TEP Distributions . The following table details the distributions paid by TEP during the nine months ended September 30, 2015 : Distributions Limited Partner Units General Partner Distributions Three Months Ended Date Paid Incentive Distribution Rights General Partner Units Total (in thousands, except per unit amounts) September 30, 2015 November 13, 2015 (1) $ 36,347 $ 11,567 $ 660 $ 48,574 $ 0.6000 June 30, 2015 August 14, 2015 35,135 10,418 627 46,180 0.5800 March 31, 2015 May 14, 2015 31,322 6,934 530 38,786 0.5200 December 31, 2014 February 13, 2015 23,782 4,039 473 28,294 0.4850 (1) The distribution for the third quarter of 2015 will be paid on November 13, 2015 to unitholders of record at the close of business on October 30, 2015. |
Net Income per Class A Share 31
Net Income per Class A Share Net Income per Class A Share (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | The following table illustrates the calculation of basic and diluted net income per Class A share for the three and nine months ended September 30, 2015 (in thousands, except per share data): Three Months Ended September 30, 2015 Nine Months Ended September 30, 2015 (in thousands, except per unit amounts) Basic Net Income per Class A Share: Net income attributable to TEGP $ 4,423 $ 14,279 Net income attributable to TEGP from the beginning of the period to May 11, 2015 — 7,393 Net income attributable to TEGP from May 12, 2015 to September 30, 2015 $ 4,423 $ 6,886 Basic weighted average Class A Shares outstanding 47,725 47,725 Basic net income per Class A share $ 0.09 $ 0.14 Diluted Net Income per Class A Share: Net income attributable to TEGP from May 12, 2015 to September 30, 2015 $ 4,423 $ 6,886 Incremental net income attributable to TEGP including the effect of the assumed issuance of Equity Participation Shares from May 12, 2015 to September 30, 2015 2 2 Net income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares from May 12, 2015 to September 30, 2015 $ 4,425 $ 6,888 Basic weighted average Class A Shares outstanding 47,725 47,725 Equity Participation Shares equivalent shares 83 87 Diluted weighted average Class A Shares outstanding 47,808 47,812 Diluted net income per Class A Share $ 0.09 $ 0.14 |
Reporting Segments (Tables)
Reporting Segments (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
Summary of TEGP's Segment Information of Revenue | Three Months Ended September 30, 2015 Three Months Ended September 30, 2014 Revenue: Total Inter- External Total Inter- External (in thousands) (in thousands) Natural Gas Transportation & Logistics $ 33,636 $ (1,346 ) $ 32,290 $ 33,520 $ (1,430 ) $ 32,090 Crude Oil Transportation & Logistics 83,272 — 83,272 — — — Processing & Logistics 22,606 — 22,606 57,863 — 57,863 Total Revenue $ 139,514 $ (1,346 ) $ 138,168 $ 91,383 $ (1,430 ) $ 89,953 Nine Months Ended September 30, 2015 Nine Months Ended September 30, 2014 Revenue: Total Inter- External Total Inter- External (in thousands) (in thousands) Natural Gas Transportation & Logistics $ 98,215 $ (4,036 ) $ 94,179 $ 107,091 $ (4,015 ) $ 103,076 Crude Oil Transportation & Logistics 208,872 — 208,872 — — — Processing & Logistics 82,762 — 82,762 158,976 — 158,976 Total Revenue $ 389,849 $ (4,036 ) $ 385,813 $ 266,067 $ (4,015 ) $ 262,052 |
Summary of TEGP's Segment Information of Earnings | Three Months Ended September 30, 2015 Three Months Ended September 30, 2014 Operating Income: Total Inter- External Total Inter- External (in thousands) (in thousands) Natural Gas Transportation & Logistics $ 10,499 $ (1,346 ) $ 9,153 $ 10,791 $ (1,430 ) $ 9,361 Crude Oil Transportation & Logistics 44,069 1,346 45,415 (822 ) — $ (822 ) Processing & Logistics (212 ) — (212 ) 5,141 — $ 5,141 Corporate and Other (1,951 ) — (1,951 ) (2,100 ) — $ (2,100 ) Total Operating Income $ 52,405 $ — $ 52,405 $ 13,010 $ (1,430 ) $ 11,580 Reconciliation to Net Income: Interest expense, net (4,982 ) (1,058 ) Other income, net 502 731 Net Income before income tax $ 47,925 $ 11,253 Nine Months Ended September 30, 2015 Nine Months Ended September 30, 2014 Operating Income: Total Inter- External Total Inter- External (in thousands) (in thousands) Natural Gas Transportation & Logistics $ 32,989 $ (4,036 ) $ 28,953 $ 32,075 $ (4,015 ) $ 28,060 Crude Oil Transportation & Logistics 103,857 4,036 $ 107,893 (2,336 ) — $ (2,336 ) Processing & Logistics 4,508 — $ 4,508 14,459 — $ 14,459 Corporate and Other (7,126 ) — $ (7,126 ) (5,599 ) — $ (5,599 ) Total Operating Income $ 134,228 $ — $ 134,228 $ 38,599 $ (4,015 ) $ 34,584 Reconciliation to Net Income: Interest expense, net (12,901 ) (4,492 ) Gain on remeasurement of unconsolidated investment — 9,388 Equity in earnings of unconsolidated investment — 717 Other income, net 1,983 2,400 Net Income before income tax $ 123,310 $ 42,597 |
Summary of TEGP's Segment Information of Assets | Nine Months Ended September 30, Capital Expenditures: 2015 2014 (in thousands) Natural Gas Transportation & Logistics $ 10,858 $ 16,616 Crude Oil Transportation & Logistics 40,579 617,687 Processing & Logistics 13,709 7,913 Total capital expenditures $ 65,146 $ 642,216 Assets: September 30, 2015 December 31, 2014 (in thousands) Natural Gas Transportation & Logistics $ 713,754 $ 716,106 Crude Oil Transportation & Logistics 1,444,231 1,394,793 Processing & Logistics 337,522 340,620 Corporate and Other 449,220 5,678 Total assets $ 2,944,727 $ 2,457,197 |
Description of Business - Addit
Description of Business - Additional Information (Detail) - USD ($) | May. 12, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 |
Organization [Line Items] | ||||
Proceeds from initial public offering of Class A shares, net | $ 1,300,000,000 | $ 1,314,741,000 | $ 0 | |
Long-term Debt | 844,000,000 | $ 559,000,000 | ||
Repayments of revolver borrowings | $ 285,000,000 | $ 433,000,000 | ||
Tallgrass Energy Holdings, LLC [Domain] | ||||
Organization [Line Items] | ||||
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units | 100.00% | |||
Tallgrass Energy GP, LP (TEGP) [Member] | ||||
Organization [Line Items] | ||||
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units | 100.00% | |||
TEGP Management, LLC [Domain] | ||||
Organization [Line Items] | ||||
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units | 100.00% | |||
Tallgrass Equity, LLC [Member] | ||||
Organization [Line Items] | ||||
Stock Issued During Period, Shares, New Issues | 41,500,000 | |||
Proceeds from Issuance or Sale of Equity | $ 1,100,000,000 | |||
Repayments of revolver borrowings | $ 3,000,000 | |||
Variable Interest Entity, Ownership Percentage | 0.00% | 0.00% | ||
Tallgrass MLP GP, LLC | ||||
Organization [Line Items] | ||||
Limited Liability Company (LLC) or General Partner, Ownership Interest | 100.00% | |||
Tallgrass Energy Partners [Member] | ||||
Organization [Line Items] | ||||
Ownership Percentage Of Aggregate Partnership Equity, Including General Partner Units | 0.00% | |||
Purchase of Stock, Number of Shares Purchased in Transaction | 20,000,000 | |||
Purchase of Stock, Price Per Share | $ 47.68 | |||
Limited Liability Company (LLC) or General Partner, Ownership Interest | 0.00% | |||
General partner units issued | 834,391 | |||
Senior Revolving Credit Facility [Member] | Tallgrass Equity, LLC [Member] | ||||
Organization [Line Items] | ||||
Long-term Debt | $ 148,000,000 | 0 | ||
Senior Revolving Credit Facility [Member] | Tallgrass Energy Partners [Member] | ||||
Organization [Line Items] | ||||
Long-term Debt | 696,000,000 | 559,000,000 | ||
Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | Tallgrass Equity, LLC [Member] | ||||
Organization [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 150,000,000 | 150,000,000 | 0 | |
Long-term Debt | $ 150,000,000 | |||
Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | Tallgrass Energy Partners [Member] | ||||
Organization [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 850,000,000 | $ 850,000,000 | ||
Capital Unit, Class B | ||||
Organization [Line Items] | ||||
Conversion of Stock, Shares Issued | 115,729,440 | |||
Limited Partners' Capital Account, Units Outstanding | 109,504,440 | |||
Limited Partner [Member] | Capital Unit, Class A | Tallgrass Energy GP, LP (TEGP) [Member] | ||||
Organization [Line Items] | ||||
Partners' Capital Account, Units, Sold in Public Offering | 47,725,000 | |||
Conversion of Stock, Shares Issued | 6,225,000 | |||
Limited Partner [Member] | Capital Unit, Class A | Over-Allotment Option | Tallgrass Energy GP, LP (TEGP) [Member] | ||||
Organization [Line Items] | ||||
Partners' Capital Account, Units, Sold in Public Offering | 6,225,000 |
Summary of Significant Accoun34
Summary of Significant Accounting Policies Accounting Policies (Details) - USD ($) $ in Thousands | May. 12, 2015 | Mar. 01, 2015 | Sep. 01, 2014 | Sep. 30, 2014 | Sep. 30, 2015 | Mar. 31, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Dec. 31, 2014 | |
Business Acquisition [Line Items] | |||||||||||||
Allowance for Doubtful Accounts Receivable | $ 700 | $ 700 | $ 700 | $ 700 | $ 500 | ||||||||
Regulatory Assets | $ 1,200 | $ 1,200 | $ 1,200 | $ 1,200 | 1,400 | ||||||||
Equity interest ownership percentage | 20.00% | 20.00% | 20.00% | 20.00% | |||||||||
Equity in earnings of unconsolidated investment | $ 0 | $ 0 | $ 0 | $ 717 | |||||||||
Sales of natural gas, NGLs, and crude oil | 20,252 | 49,130 | 62,132 | 141,887 | |||||||||
Deferred tax asset | $ 445,128 | 441,528 | $ 441,528 | 441,528 | $ 441,528 | $ 0 | |||||||
Deferred income tax expense | $ (1,828) | $ 0 | $ (3,600) | $ 0 | |||||||||
Effective Income Tax Rate Reconciliation, Percent | 0.00% | ||||||||||||
Crude Oil Transportation and Logistics | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Property, Plant and Equipment, Useful Life | 35 years | ||||||||||||
Processing and treating assets | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Property, Plant and Equipment, Useful Life | 30 years | ||||||||||||
Natural gas pipelines | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Property, Plant and Equipment, Useful Life | [1] | 10 years | |||||||||||
Minimum [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 0.70% | ||||||||||||
Minimum [Member] | General and other | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Property, Plant and Equipment, Useful Life | 3 years | ||||||||||||
Maximum [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Public Utilities, Property, Plant and Equipment, Disclosure of Composite Depreciation Rate for Plants in Service | 12.00% | ||||||||||||
Maximum [Member] | General and other | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Property, Plant and Equipment, Useful Life | 13 years 3 months 29 days | ||||||||||||
Contract-Based Intangible Assets [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Finite-Lived Intangible Assets, Remaining Amortization Period | 35 years | ||||||||||||
Customer Contracts [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Finite-Lived Intangible Assets, Remaining Amortization Period | 1 year 7 months 6 days | ||||||||||||
Pony Express Pipeline [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | 66.70% | ||||||||||
Minimum Quarterly Distribution Required by Partnership Agreement | $ 36,650 | $ 16,650 | |||||||||||
Prorated Minimum Quarterly Distribution Required by Partnership Agreement | $ 5,400 | $ 23,500 | |||||||||||
Preferred Membership, Percentage Acquired | 33.30% | 100.00% | |||||||||||
Tallgrass Equity, LLC [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Variable Interest Entity, Ownership Percentage | 0.00% | 0.00% | |||||||||||
Equity interest held by noncontrolling interests | 69.70% | 69.70% | 69.70% | 69.70% | |||||||||
Pony Express Pipeline [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | ||||||||||||
Equity interest held by noncontrolling interests | 33.30% | 33.30% | 33.30% | 33.30% | |||||||||
Crude Oil Transportation & Logistics | Pony Express Pipeline [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Sales of natural gas, NGLs, and crude oil | $ 1,300 | $ 2,500 | |||||||||||
Pony Express Pipeline [Member] | Tallgrass Colorado Pipeline, Inc. [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 99.80% | 99.80% | 99.80% | 99.80% | |||||||||
Tallgrass Energy Partners [Member] | Tallgrass Colorado Pipeline, Inc. [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 0.20% | 0.20% | 0.20% | 0.20% | |||||||||
[1] | (1) Includes the Replacement Gas Facilities as discussed in Note 5 – Related Party Transactions and Note 13 – Regulatory Matters. |
Variable Interest Entity VIE As
Variable Interest Entity VIE Assets and Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Variable Interest Entity [Line Items] | ||
Assets, Current | $ 90,825 | $ 132,281 |
Assets | 2,944,727 | 2,457,197 |
Liabilities, Current | 74,835 | 96,568 |
Liabilities, Noncurrent | 849,461 | 565,478 |
Tallgrass Equity, LLC [Member] | ||
Variable Interest Entity [Line Items] | ||
Assets, Current | 90,824 | 132,281 |
Assets, Noncurrent | 2,412,376 | 2,324,916 |
Assets | 2,503,200 | 2,457,197 |
Liabilities, Current | 74,835 | 96,568 |
Liabilities, Noncurrent | 849,461 | 565,478 |
Liabilities | $ 924,296 | $ 662,046 |
Variable Interest Entity (Detai
Variable Interest Entity (Details) - USD ($) $ in Millions | Mar. 01, 2015 | Sep. 01, 2014 | Sep. 30, 2015 |
Pony Express Pipeline [Member] | |||
Business Acquisition [Line Items] | |||
Variable Interest Entity, Ownership Percentage | 33.30% | ||
Business Combination, Cash Contributed to Variable Interest Entity | $ 570 | ||
Funds Maintained By Variable Interest Entity To Fund Construction | $ 270 | ||
Pony Express Pipeline [Member] | |||
Business Acquisition [Line Items] | |||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | 66.70% |
Preferred Membership, Percentage Acquired | 33.30% | 100.00% | |
Business Combination, Cash Contributed to Variable Interest Entity | $ 570 | ||
Funds Maintained By Variable Interest Entity To Fund Construction | $ 270 |
Acquisitions (Details)
Acquisitions (Details) - USD ($) | May. 20, 2015 | Mar. 01, 2015 | Sep. 01, 2014 | May. 13, 2014 | Apr. 01, 2014 | Sep. 30, 2014 | Sep. 30, 2015 | Mar. 31, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Nov. 26, 2013 |
Business Acquisition [Line Items] | |||||||||||||
Equity interest ownership percentage | 20.00% | 20.00% | 20.00% | ||||||||||
Acquisition of Water Solutions | $ 0 | $ 150,000,000 | |||||||||||
Gain on remeasurement of unconsolidated investment | $ 0 | $ 0 | 0 | 9,388,000 | |||||||||
Acquisition of additional equity interests | $ 171,948,000 | $ 0 | |||||||||||
Trailblazer [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Date of acquisition | Apr. 1, 2014 | ||||||||||||
Total consideration | $ 164,000,000 | ||||||||||||
Acquisitions | $ 150,000,000 | ||||||||||||
Pony Express Pipeline [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Date of acquisition | Mar. 1, 2015 | Sep. 1, 2014 | |||||||||||
Total consideration | $ 600,000,000 | ||||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | 66.70% | ||||||||||
Total Consideration Transferred Directly | $ 30,000,000 | ||||||||||||
Business Combinations, Cash Contributed | $ 700,000,000 | $ 27,000,000 | |||||||||||
Percentage of Membership Interest before Effect of New Membership | 1.9585% | ||||||||||||
Preferred Membership, Percentage Acquired | 33.30% | 100.00% | |||||||||||
Business Combination, Cash Contributed to Variable Interest Entity | $ 570,000,000 | ||||||||||||
Cash contributed as Part of Acquisition | 300,000,000 | ||||||||||||
Funds Maintained By Variable Interest Entity To Fund Construction | 270,000,000 | ||||||||||||
Minimum Quarterly Distribution Required by Partnership Agreement | $ 36,650,000 | $ 16,650,000 | |||||||||||
Prorated Minimum Quarterly Distribution Required by Partnership Agreement | $ 5,400,000 | $ 23,500,000 | |||||||||||
Water Solutions [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Business Acquisition, Percentage of Voting Interests Acquired | 92.00% | 80.00% | |||||||||||
Acquisition of Water Solutions | $ 7,600,000 | ||||||||||||
Equity interest held by noncontrolling interests | 20.00% | ||||||||||||
Acquisition, noncontrolling interest, fair value | $ 1,400,000 | ||||||||||||
Additional Equity Interest Acquired | 12.00% | ||||||||||||
Acquisition of additional equity interests | $ 600,000 | ||||||||||||
Grasslands Water Services I, LLC [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Equity interest ownership percentage | 50.00% | ||||||||||||
Equity interest transferred as part of acquisition | 50.00% | ||||||||||||
Acquisition fair value | $ 11,900,000 | ||||||||||||
Gain on remeasurement of unconsolidated investment | $ 9,400,000 | ||||||||||||
Tallgrass Energy Partners [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
General partner units issued | 834,391 | 834,391 | 834,391 | ||||||||||
Equity interest held by noncontrolling interests | 66.10% | 66.10% | 66.10% | ||||||||||
Tallgrass Energy Partners [Member] | Trailblazer [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Common and subordinated units issued, units | 385,140 | ||||||||||||
Common unit, issuance value | $ 14,000,000 | ||||||||||||
General partner units issued | 7,860 | ||||||||||||
General Partners capital account partnership interest percentage | 2.00% | ||||||||||||
Tallgrass Energy Partners [Member] | Pony Express Pipeline [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Acquisitions | $ (3,000,000) | ||||||||||||
Common and subordinated units issued, units | 70,340 | ||||||||||||
Tallgrass Energy Partners [Member] | General Partner [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Partners' Capital Account, Contributions | $ 263,000 | ||||||||||||
Grasslands Water Services I, LLC [Member] | BNN Energy LLC [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Equity interest transferred as part of acquisition | 50.00% | ||||||||||||
Alpha Reclaim Technology, LLC [Member] | BNN Energy LLC [Member] | |||||||||||||
Business Acquisition [Line Items] | |||||||||||||
Equity interest transferred as part of acquisition | 100.00% |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Transactions with Affiliated Companies (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Related Party Transaction [Line Items] | ||||
Related Party Transactions, Cost of transportation services | $ 7,180 | $ 0 | $ 17,771 | $ 0 |
Operation and maintenance [Member] | ||||
Related Party Transaction [Line Items] | ||||
Expenses related to transactions with affiliated companies | 6,077 | 4,701 | 17,325 | 13,657 |
General and Administrative Expense [Member] | ||||
Related Party Transaction [Line Items] | ||||
Expenses related to transactions with affiliated companies | 10,041 | 5,783 | 28,862 | 14,670 |
Property, Plant and Equipment [Member] | ||||
Related Party Transaction [Line Items] | ||||
Related Party Transaction Costs Capitalized From Transactions With Related Party | $ 958 | $ 7,926 | $ 3,859 | $ 14,534 |
Related Party Transactions - 39
Related Party Transactions - Schedule of Balances with Affiliates Included in Accounts Receivables and Accounts Payable in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | $ 0 | $ 73,393 |
Accounts Payable, Related Parties, Current | 3,581 | 3,915 |
Tallgrass Operations, LLC [Member] | ||
Related Party Transaction [Line Items] | ||
Accounts Receivable, Related Parties, Current | 0 | 73,393 |
Accounts Payable, Related Parties, Current | 3,561 | 3,894 |
Rockies Express Pipeline LLC [Member] | ||
Related Party Transaction [Line Items] | ||
Accounts Payable, Related Parties, Current | $ 20 | $ 21 |
Related Party Transactions - 40
Related Party Transactions - Schedule of Balances of Gas Imbalance with Affiliated Shippers (Detail) - Affiliated Shippers [Member] - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Related Party Transaction [Line Items] | ||
Affiliate gas balance receivables | $ 0 | $ 275 |
Affiliate gas balance payables | $ 269 | $ 455 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) - USD ($) | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | |
Related Party Transaction [Line Items] | |||
Interest Income, Related Party | $ 400,000 | $ 500,000 | |
TEGP | |||
Related Party Transaction [Line Items] | |||
Expected general administrative expense reimbursement | $ 5,200,000 | 16,100,000 | |
Pony Express Pipeline [Member] | |||
Related Party Transaction [Line Items] | |||
Expected general administrative expense reimbursement | 5,200,000 | $ 15,500,000 | |
Public Company Expense [Member] | |||
Related Party Transaction [Line Items] | |||
Expected public company cost reimbursement | 635,000 | ||
Public Company Expense [Member] | Tallgrass Development Lp [Member] | |||
Related Party Transaction [Line Items] | |||
Expected public company cost reimbursement | $ 500,000 |
Inventory Inventory (Details)
Inventory Inventory (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Inventory Disclosure [Abstract] | ||
Crude oil | $ 2,534 | $ 581 |
Materials and supplies | 5,852 | 3,049 |
Natural gas liquids | 345 | 519 |
Gas in underground storage | 5,401 | 8,896 |
Inventory, Net | $ 14,132 | $ 13,045 |
Property Plant and Equipment -
Property Plant and Equipment - Components of Property Plant and Equipment (Detail) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Property, Plant and Equipment [Line Items] | ||
Accumulated depreciation and amortization | $ (114,422) | $ (59,200) |
Property, plant and equipment | 1,948,821 | 1,853,081 |
Crude oil pipelines | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | 1,159,002 | 939,536 |
Natural gas pipelines | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | 556,924 | 548,482 |
Processing and treating assets | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | 238,356 | 241,671 |
General and other | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | 63,910 | 42,719 |
Construction work in progress | ||
Property, Plant and Equipment [Line Items] | ||
Property , plant and equipment | $ 45,051 | $ 139,873 |
Risk Management - Schedule of F
Risk Management - Schedule of Fair Value of Derivative Contracts (Detail) $ in Thousands | Sep. 30, 2015USD ($)Bcf | Dec. 31, 2014USD ($) |
Derivatives, Fair Value [Line Items] | ||
Derivative assets at fair value | $ | $ 218 | $ 0 |
Commodity [Member] | Current Portion of Derivative Notional Amount [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative, Nonmonetary Notional Amount | 0.6 |
Risk Management - Derivative Co
Risk Management - Derivative Contracts Included in Consolidated Statement of Income (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Derivatives not designated as hedging contracts [Member] | Energy commodity derivative contracts [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain (Loss) Recognized in Income on Derivatives | $ 252 | $ 9 | $ 211 | $ (449) |
Risk Management Derivative Inst
Risk Management Derivative Instruments Maximum Potential Exposure To Credit Loss (Details) $ in Thousands | Sep. 30, 2015USD ($) |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Credit Derivative Netting Agreement Impact | $ 0 |
Cash Collateral for Borrowed Securities | 0 |
Derivative Asset, Securities Purchased under Agreements to Resell, Securities Borrowed | 218 |
Commodity Contract [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Derivative Asset, Securities Purchased under Agreements to Resell, Securities Borrowed, Gross | $ 218 |
Risk Management - Schedule of E
Risk Management - Schedule of Energy Commodity Derivative Contracts Based on Fair Value Hierarchy Established by Codification (Detail) - Commodity Contract [Member] | Sep. 30, 2015USD ($) |
Derivatives, Fair Value [Line Items] | |
Energy commodity derivative contracts | $ 218,000 |
Quoted prices in active markets for identical assets (Level 1) [Member] | |
Derivatives, Fair Value [Line Items] | |
Energy commodity derivative contracts | 0 |
Significant other observable inputs (Level 2) [Member] | |
Derivatives, Fair Value [Line Items] | |
Energy commodity derivative contracts | 218,000 |
Significant unobservable inputs (Level 3) [Member] | |
Derivatives, Fair Value [Line Items] | |
Energy commodity derivative contracts | $ 0 |
Long-term Debt Capacity under R
Long-term Debt Capacity under Revolving Credit Facility - Tallgrass Equity (Details) - USD ($) | Sep. 30, 2015 | May. 12, 2015 | Dec. 31, 2014 |
Line of Credit Facility [Line Items] | |||
Long-term Debt | $ 844,000,000 | $ 559,000,000 | |
Tallgrass Equity, LLC [Member] | Senior Revolving Credit Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Long-term Debt | 148,000,000 | 0 | |
Line of Credit Facility, Remaining Borrowing Capacity | 2,000,000 | 0 | |
Tallgrass Equity, LLC [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 150,000,000 | $ 150,000,000 | 0 |
Long-term Debt | $ 150,000,000 | ||
Tallgrass Energy Partners [Member] | Senior Revolving Credit Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Long-term Debt | 696,000,000 | 559,000,000 | |
Line of Credit Facility, Remaining Borrowing Capacity | 154,000,000 | 291,000,000 | |
Tallgrass Energy Partners [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | |||
Line of Credit Facility [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 850,000,000 | $ 850,000,000 |
Long-term Debt Capacity under49
Long-term Debt Capacity under Revolving Credit Facility (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Line of Credit Facility [Line Items] | ||
Long-term Debt | $ (844,000) | $ (559,000) |
Tallgrass Energy Partners [Member] | Senior Revolving Credit Facility [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | (696,000) | (559,000) |
Line of Credit Facility, Remaining Borrowing Capacity | 154,000 | 291,000 |
Tallgrass Energy Partners [Member] | Barclays Bank [Member] | Senior Revolving Credit Facility [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 850,000 | $ 850,000 |
Long-term Debt - Carrying Amoun
Long-term Debt - Carrying Amount and Fair Value of TEP's Long-term Debt (Detail) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||
Long-term Debt, Fair Value | $ 844,000 | $ 559,000 |
Long-term Debt | 844,000 | 559,000 |
Quoted prices in active markets for identical assets (Level 1) [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Fair Value | 0 | 0 |
Significant other observable inputs (Level 2) [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Fair Value | 844,000 | 559,000 |
Significant unobservable inputs (Level 3) [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt, Fair Value | 0 | 0 |
Senior Revolving Credit Facility [Member] | Tallgrass Energy Partners [Member] | ||
Debt Instrument [Line Items] | ||
Line of Credit Facility, Remaining Borrowing Capacity | 154,000 | 291,000 |
Long-term Debt | $ 696,000 | $ 559,000 |
Long-term Debt - Additional Inf
Long-term Debt - Additional Information (Detail) | May. 12, 2015USD ($) | Sep. 30, 2015USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2014USD ($) |
Debt Instrument [Line Items] | ||||
Long-term Debt | $ 844,000,000 | $ 844,000,000 | $ 559,000,000 | |
Tallgrass Equity, LLC [Member] | ||||
Debt Instrument [Line Items] | ||||
Repayments of Debt | $ 3,000,000 | |||
Proceeds from Issuance of Debt | $ 1,000,000 | |||
Debt, Weighted Average Interest Rate | 2.71% | 2.71% | ||
Tallgrass Equity, LLC [Member] | Senior Revolving Credit Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt | $ 148,000,000 | $ 148,000,000 | 0 | |
Line of Credit Facility, Remaining Borrowing Capacity | 2,000,000 | 2,000,000 | 0 | |
Tallgrass Equity, LLC [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 150,000,000 | $ 150,000,000 | $ 150,000,000 | 0 |
Sublimit for Letters of Credit | 10,000,000 | |||
Sublimit for Swing Line Loans | 10,000,000 | |||
Line of Credit Facility, Maximum Potential Accordion Feature | 200,000,000 | |||
Long-term Debt | $ 150,000,000 | |||
Credit facility commitment fee | 0.50% | |||
Tallgrass Equity, LLC [Member] | Maximum [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Consolidated leverage ratio | 3 | |||
Tallgrass Energy Partners [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Weighted Average Interest Rate | 1.97% | 1.97% | ||
Tallgrass Energy Partners [Member] | Senior Revolving Credit Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt | $ 696,000,000 | $ 696,000,000 | 559,000,000 | |
Line of Credit Facility, Remaining Borrowing Capacity | 154,000,000 | 154,000,000 | 291,000,000 | |
Tallgrass Energy Partners [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 850,000,000 | $ 850,000,000 | $ 850,000,000 | |
Tallgrass Energy Partners [Member] | Maximum [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Consolidated leverage ratio | 4.75 | |||
Contingent Consolidated Leverage Ratio | 5.25 | |||
Credit facility commitment fee | 0.50% | |||
Tallgrass Energy Partners [Member] | Minimum [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility commitment fee | 0.00% | |||
Consolidated Interest Coverage Ratio One | 2.50 | |||
US Federal Funds Rate [Member] | Tallgrass Equity, LLC [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | |||
Eurodollar [Member] | Tallgrass Equity, LLC [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | |||
Percentage Change in Borrowing Rate | 2.50% | |||
Base Rate [Member] | Tallgrass Equity, LLC [Member] | Senior Revolving Credit Facility [Member] | Barclays Bank [Member] | ||||
Debt Instrument [Line Items] | ||||
Percentage Change in Borrowing Rate | 1.50% |
Partnership Equity and Distri52
Partnership Equity and Distributions Partnership and Equity Distributions - TEGP Summary of Distributions (Details) - Tallgrass Energy GP, LP (TEGP) [Member] - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | |
Sep. 30, 2015 | Jun. 30, 2015 | |
Distribution Made to Limited Partner [Line Items] | ||
Distribution Made to Limited Partner, Distribution Date | Nov. 13, 2015 | Aug. 17, 2015 |
Partners' Capital Account, Distributions | $ 6,872 | $ 3,484 |
Partners' Capital, Distributions Policies | $ 0.1440 | $ 0.0730 |
Partnership Equity and Distri53
Partnership Equity and Distributions Partnership Equity and Distributions - TEP Summary of Distributions (Details) - Tallgrass Energy Partners [Member] - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | |||
Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | |
Distribution Made to Limited Partner [Line Items] | ||||
Distribution Made to Limited Partner, Distribution Date | Nov. 13, 2015 | Aug. 14, 2015 | May 14, 2015 | Feb. 13, 2015 |
Limited Partners' Capital Account, Distribution Amount | $ 36,347 | $ 35,135 | $ 31,322 | $ 23,782 |
Incentive Distribution, Distribution | 11,567 | 10,418 | 6,934 | 4,039 |
General Partner Distributions | 660 | 627 | 530 | 473 |
Partners' Capital Account, Distributions | $ 48,574 | $ 46,180 | $ 38,786 | $ 28,294 |
Partners' Capital, Distributions Policies | $ 0.6000 | $ 0.5800 | $ 0.5200 | $ 0.4850 |
Partnership Equity and Distri54
Partnership Equity and Distributions - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands | May. 12, 2015 | Mar. 30, 2015 | Mar. 01, 2015 | Feb. 27, 2015 | Sep. 01, 2014 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2015 | Sep. 30, 2014 |
Limited Partners' Capital Account [Line Items] | |||||||||||
Proceeds from public offering of TEP common units, net | $ 492,400 | $ 551,243 | $ 319,588 | ||||||||
Distribution of excess Offering proceeds to Exchange Right Holders | 334,068 | 0 | |||||||||
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders | 37 | ||||||||||
Payments of Ordinary Dividends, Noncontrolling Interest | 12,969 | 0 | |||||||||
Contributions from Predecessor | 289,000 | ||||||||||
Contribution from Noncontrolling Interest | $ 19,303 | 0 | |||||||||
Pony Express Pipeline [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | ||||||||||
Equity interest held by noncontrolling interests | 33.30% | 33.30% | |||||||||
Tallgrass Energy GP, LP (TEGP) [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Distribution Made to Limited Partner, Distribution Date | Nov. 13, 2015 | Aug. 17, 2015 | |||||||||
Partners' Capital Account, Distributions | $ (6,872) | $ (3,484) | |||||||||
Tallgrass Energy Partners [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Distribution Made to Limited Partner, Distribution Date | Nov. 13, 2015 | Aug. 14, 2015 | May 14, 2015 | Feb. 13, 2015 | |||||||
Equity interest held by noncontrolling interests | 66.10% | 66.10% | |||||||||
Partners' Capital Account, Distributions | $ (48,574) | $ (46,180) | $ (38,786) | $ (28,294) | |||||||
Tallgrass Equity, LLC [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Variable Interest Entity, Ownership Percentage | 0.00% | 0.00% | |||||||||
Equity interest held by noncontrolling interests | 69.70% | 69.70% | |||||||||
Water Solutions [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Equity interest held by noncontrolling interests | 8.00% | 8.00% | |||||||||
Pony Express Pipeline [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Variable Interest Entity, Ownership Percentage | 33.30% | 33.30% | 66.70% | ||||||||
TEP Common Unitholders [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Partners' Capital Account, Units, Sold in Public Offering | 1,200,000 | 10,000,000 | |||||||||
Shares Issued, Price Per Share | $ 50.82 | ||||||||||
Shares Issued, Price Per Share, Net of Underwriters Discount | $ 49.29 | ||||||||||
Proceeds from public offering of TEP common units, net | $ 59,300 | ||||||||||
Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Distribution of excess Offering proceeds to Exchange Right Holders | $ (334,068) | ||||||||||
Contribution from Noncontrolling Interests | 110,553 | ||||||||||
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders | 44,543 | 37 | |||||||||
Distribution to Predecessor | (13,533) | ||||||||||
Partners' Capital Account, Contributions | 27,488 | ||||||||||
Contribution from Noncontrolling Interest | (110,553) | 5,429 | |||||||||
Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Tallgrass Energy GP, LP (TEGP) [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Partners' Capital Account, Distributions | (7,465) | ||||||||||
Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Tallgrass Energy Partners [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Partners' Capital Account, Distributions | (74,843) | (23,766) | |||||||||
Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | Tallgrass Equity, LLC [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Payments of Ordinary Dividends, Noncontrolling Interest | 12,969 | ||||||||||
Common Class A [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Distribution of excess Offering proceeds to Exchange Right Holders | (334,068) | ||||||||||
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders | 0 | 0 | |||||||||
Distribution to Predecessor | 0 | ||||||||||
Contribution from Noncontrolling Interest | 0 | 0 | |||||||||
Common Class A [Member] | Tallgrass Energy GP, LP (TEGP) [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Distribution to Predecessor | 13,500 | ||||||||||
Partners' Capital Account, Distributions | (7,465) | ||||||||||
Common Class A [Member] | Tallgrass Energy Partners [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Partners' Capital Account, Distributions | 0 | $ 0 | |||||||||
Common Class A [Member] | Tallgrass Equity, LLC [Member] | |||||||||||
Limited Partners' Capital Account [Line Items] | |||||||||||
Payments of Ordinary Dividends, Noncontrolling Interest | $ 0 |
Net Income per Class A Share 55
Net Income per Class A Share Net Income per Class A Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Earnings Per Share [Abstract] | ||||
Net income attributable to TEGP | $ 4,423 | $ 1,630 | $ 14,279 | $ 6,700 |
Net income attributable to TEGP from the beginning of the period to May 11, 2015 | 0 | 7,393 | ||
Net income attributable to TEGP from May 12, 2015 to September 30, 2015 | 4,423 | 6,886 | ||
Incremental net income attributable to TEGP including the effect of the assumed issuance of Equity Participation Shares from May 12, 2015 to September 30, 2015 | 2 | 2 | ||
Net income attributable to TEGP including incremental net income from assumed issuance of Equity Participation Shares from May 12, 2015 to September 30, 2015 | $ 4,425 | $ 6,888 | ||
Weighted Average Number of Shares Outstanding, Basic | 47,725 | 47,725 | ||
Equity Participation Shares equivalent shares | 83 | 87 | ||
Basic net income per Class A share | $ 0.09 | $ 0.14 | ||
Diluted average number of Class A shares outstanding | 47,808 | 47,812 | ||
Diluted net income per Class A share | $ 0.09 | $ 0.14 |
Equity-Based Compensation Equ56
Equity-Based Compensation Equity Based Compensation - Additional Information (Details) - USD ($) | Aug. 01, 2015 | Sep. 30, 2015 | Sep. 30, 2015 | Sep. 30, 2015 | May. 12, 2015 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Equity Participation Shares, Grants in Period | 160,000 | ||||
Partners' Capital, Distributions Policies | $ 0.35 | ||||
Weighted Average Grant Date Fair Value | $ 27.97 | ||||
Share-based compensation expense related to the EPS grants recognized | $ 200,000 | $ 200,000 | |||
Compensation cost related to nonvested EPSs expected to be recognized | $ 4,300,000 | $ 4,300,000 | $ 4,300,000 | ||
Weighted average period in which compensation cost related to nonvested EPSs expected to be recognized | 3 years 9 months | ||||
Maximum [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum Potential Number of Equity Participation Shares | 3,144,589 |
Regulatory Matters Regulatory D
Regulatory Matters Regulatory Details (Details) - mi | Oct. 29, 2015 | Jul. 01, 2015 | Aug. 06, 2012 |
Tallgrass Interstate Gas Transmission, LLC (TIGT) [Member] | |||
Entity Information [Line Items] | |||
Gas transmission lines owned | 433 | ||
Local Non-Contract Rates [Member] | Pony Express Pipeline [Member] | |||
Entity Information [Line Items] | |||
FERC Annual Index Adjustment | 4.60% | ||
Joint Tariff Contract Rates [Member] | Pony Express Pipeline [Member] | |||
Entity Information [Line Items] | |||
FERC Annual Index Adjustment | 4.60% | ||
Subsequent Event [Member] | Pony Express Pipeline [Member] | |||
Entity Information [Line Items] | |||
FERC Annual Index Adjustment | 4.60% |
Legal and Environmental Matte58
Legal and Environmental Matters - Additional Information (Detail) | Mar. 12, 2015bbl | Aug. 31, 2014bbl | Sep. 30, 2015USD ($)ft-lbmi | Dec. 31, 2014USD ($) |
Loss Contingencies [Line Items] | ||||
Aggregate reserves for all claims | $ 800,000 | $ 600,000 | ||
Environmental accruals | $ 5,000,000 | $ 5,300,000 | ||
Crude Oil Spilled or Leaked | bbl | 300 | 200 | ||
Trailblazer [Member] | ||||
Loss Contingencies [Line Items] | ||||
Maximum Allowable Operating Pressure | ft-lb | 144,000 | |||
Excavation Digs | 23 | |||
Aggregate Cost of Excavation Digs | $ 1,100,000 | |||
Tallgrass Energy Partners [Member] | ||||
Loss Contingencies [Line Items] | ||||
Contractual indemnity provided to TEP by TD | 20,000,000 | |||
Annual deductible | $ 1,500,000 | |||
Minimum [Member] | Trailblazer [Member] | ||||
Loss Contingencies [Line Items] | ||||
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi | 25 | |||
Pipeline replacement costs | $ 2,200,000 | |||
Maximum [Member] | Trailblazer [Member] | ||||
Loss Contingencies [Line Items] | ||||
Miles of Natural Gas Pipeline Needing Repair or Replacement | mi | 35 | |||
Pipeline replacement costs | $ 2,700,000 |
Reporting Segments - Summary of
Reporting Segments - Summary of TEGP's Segment Information of Revenue (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Segment Reporting Information [Line Items] | ||||
Revenues | $ 138,168 | $ 89,953 | $ 385,813 | $ 262,052 |
TEGP | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 138,168 | 89,953 | 385,813 | 262,052 |
TEGP | Natural Gas Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 32,290 | 32,090 | 94,179 | 103,076 |
TEGP | Crude Oil Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 83,272 | 0 | 208,872 | 0 |
TEGP | Processing & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 22,606 | 57,863 | 82,762 | 158,976 |
TEGP | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 139,514 | 91,383 | 389,849 | 266,067 |
TEGP | Operating Segments | Natural Gas Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 33,636 | 33,520 | 98,215 | 107,091 |
TEGP | Operating Segments | Crude Oil Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 83,272 | 0 | 208,872 | 0 |
TEGP | Operating Segments | Processing & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 22,606 | 57,863 | 82,762 | 158,976 |
TEGP | Inter-Segment | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | (1,346) | (1,430) | (4,036) | (4,015) |
TEGP | Inter-Segment | Natural Gas Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | (1,346) | (1,430) | (4,036) | (4,015) |
TEGP | Inter-Segment | Crude Oil Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 0 | 0 | 0 | 0 |
TEGP | Inter-Segment | Processing & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | $ 0 | $ 0 | $ 0 | $ 0 |
Reporting Segments - Summary 60
Reporting Segments - Summary of TEGP's Segment Information of Earnings (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | $ 52,405 | $ 11,580 | $ 134,228 | $ 34,584 |
Reconciliation to Net Income: | ||||
Interest expense, net | 4,982 | 1,058 | 12,901 | 4,492 |
Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain | 0 | 0 | 0 | 9,388 |
Equity in earnings of unconsolidated investment | 0 | 0 | 0 | (717) |
Other income, net | 502 | 731 | 1,983 | 2,400 |
Net Income before income tax | 47,925 | 11,253 | 123,310 | 42,597 |
TEGP | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | 52,405 | 11,580 | 134,228 | 34,584 |
Reconciliation to Net Income: | ||||
Net Income before income tax | 47,925 | 11,253 | 123,310 | 42,597 |
TEGP | Natural Gas Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | 9,153 | 9,361 | 28,953 | 28,060 |
TEGP | Crude Oil Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | 45,415 | (822) | 107,893 | (2,336) |
TEGP | Processing & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | (212) | 5,141 | 4,508 | 14,459 |
TEGP | Corporate and Other | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | (1,951) | (2,100) | (7,126) | (5,599) |
TEGP | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | 52,405 | 13,010 | 134,228 | 38,599 |
TEGP | Operating Segments | Natural Gas Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | 10,499 | 10,791 | 32,989 | 32,075 |
TEGP | Operating Segments | Crude Oil Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | 44,069 | (822) | 103,857 | (2,336) |
TEGP | Operating Segments | Processing & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | (212) | 5,141 | 4,508 | 14,459 |
TEGP | Operating Segments | Corporate and Other | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | (1,951) | (2,100) | (7,126) | (5,599) |
TEGP | Inter-Segment | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | 0 | (1,430) | 0 | (4,015) |
TEGP | Inter-Segment | Natural Gas Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | (1,346) | (1,430) | (4,036) | (4,015) |
TEGP | Inter-Segment | Crude Oil Transportation & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | 1,346 | 0 | 4,036 | 0 |
TEGP | Inter-Segment | Processing & Logistics | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | 0 | 0 | 0 | 0 |
TEGP | Inter-Segment | Corporate and Other | ||||
Segment Reporting Information [Line Items] | ||||
Operating Income (Loss) | $ 0 | $ 0 | $ 0 | $ 0 |
Reporting Segments - Summary 61
Reporting Segments - Summary of TEGP's Segment Information of Assets (Detail) - USD ($) $ in Thousands | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Segment Reporting Information [Line Items] | |||
Capital expenditures | $ 65,146 | $ 642,216 | |
Segment assets | 2,944,727 | $ 2,457,197 | |
TEGP | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | 65,146 | 642,216 | |
Segment assets | 2,944,727 | 2,457,197 | |
TEGP | Natural Gas Transportation & Logistics | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | 10,858 | 16,616 | |
Segment assets | 713,754 | 716,106 | |
TEGP | Crude Oil Transportation & Logistics | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | 40,579 | 617,687 | |
Segment assets | 1,444,231 | 1,394,793 | |
TEGP | Processing & Logistics | |||
Segment Reporting Information [Line Items] | |||
Capital expenditures | 13,709 | $ 7,913 | |
Segment assets | 337,522 | 340,620 | |
TEGP | Corporate and Other | |||
Segment Reporting Information [Line Items] | |||
Segment assets | $ 449,220 | $ 5,678 |
Reporting Segments - Additional
Reporting Segments - Additional Information (Detail) | 9 Months Ended |
Sep. 30, 2015Segment | |
Segment Reporting [Abstract] | |
Number of reportable segments | 3 |
Uncategorized Items - tegp-2015
Label | Element | Value |
Tallgrass Energy GP, LP Predecessor [Member] | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | $ 7,393 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 0 |
Common Class A [Member] | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 0 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 6,886 |
Common Class B [Member] | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 0 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 0 |
Noncontrolling Interest [Member] | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 32,196 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 73,235 |
Total Partner Equity Including Portion Attributable to Noncontrolling Interest [Member] | ||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | 39,589 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | us-gaap_ProfitLoss | $ 80,121 |