Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2016 | |
Document And Entity Information [Abstract] | |
Entity Registrant Name | Targa Resources Partners LP |
Entity Central Index Key | 1,379,661 |
Current Fiscal Year End Date | --12-31 |
Entity Well-known Seasoned Issuer | Yes |
Entity Voluntary Filers | No |
Entity Current Reporting Status | Yes |
Entity Filer Category | Non-accelerated Filer |
Document Fiscal Year Focus | 2,016 |
Document Fiscal Period Focus | FY |
Document Type | 10-K |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2016 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 68 | $ 135.4 |
Trade receivables, net of allowances of $0.9 and $0.1 million at December 31, 2016 and 2015 | 673.2 | 514.8 |
Inventories | 137.7 | 141 |
Assets from risk management activities | 16.8 | 92.2 |
Other current assets | 31.5 | 10 |
Total current assets | 927.2 | 893.4 |
Property, plant and equipment | 12,511.9 | 11,928.2 |
Accumulated depreciation | (2,821) | (2,225.6) |
Property, plant and equipment, net | 9,690.9 | 9,702.6 |
Intangible assets, net | 1,654 | 1,810.1 |
Goodwill, net | 210 | 417 |
Long-term assets from risk management activities | 5.1 | 34.9 |
Investments in unconsolidated affiliates | 240.8 | 258.9 |
Other long-term assets | 16.9 | 9.9 |
Total assets | 12,744.9 | 13,126.8 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 773.9 | 629.1 |
Accounts payable to Targa Resources Corp. | 61 | 30.1 |
Liabilities from risk management activities | 49.1 | 5.2 |
Accounts receivable securitization facility | 275 | 219.3 |
Total current liabilities | 1,159 | 883.7 |
Long-term debt | 4,177 | 5,125.7 |
Long-term liabilities from risk management activities | 26.1 | 2.4 |
Deferred income taxes, net | 26.9 | 27.2 |
Other long-term liabilities | 205.3 | 184.9 |
Contingencies (see Note 17) | ||
Owners' equity: | ||
Series A preferred limited partners (5,000,000 and 5,000,000 units issued and 5,000,000 and 5,000,000 outstanding as of December 31, 2016 and December 31, 2015) | 120.6 | 120.6 |
Common limited partners (243,520,639 and 185,083,420 units issued and 243,520,639 and 184,870,693 outstanding as of December 31, 2016 and December 31, 2015) | 5,939.9 | 4,550.4 |
General partner (4,969,807 and 3,772,871 units issued and 4,969,807 and 3,772,871 outstanding as of December 31, 2016 and December 31, 2015) | 796.7 | 1,735.3 |
Accumulated other comprehensive income (loss) | (61.8) | 86.8 |
Treasury units at cost (0 units and 212,727 units as of December 31, 2016 and December 31, 2015) | (10.3) | |
Partners' Capital | 6,795.4 | 6,482.8 |
Noncontrolling interests in subsidiaries | 355.2 | 420.1 |
Total owners' equity | 7,150.6 | 6,902.9 |
Total liabilities and owners' equity | $ 12,744.9 | $ 13,126.8 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Trade receivables, allowances | $ 0.9 | $ 0.1 |
Owners' equity: | ||
Series A preferred limited partners units outstanding (in units) | 5,000,000 | |
Common limited partners units issued (in units) | 275,168,410 | 185,083,420 |
Common limited partners units outstanding (in units) | 275,168,410 | 184,870,693 |
General partner units issued (in units) | 5,629,136 | 3,772,871 |
General partner units outstanding (in units) | 5,629,136 | 3,772,871 |
Treasury units (in units) | 0 | 212,727 |
Series A Preferred Limited Partner Units [Member] | ||
Owners' equity: | ||
Series A preferred limited partners units issued (in units) | 5,000,000 | 5,000,000 |
Series A preferred limited partners units outstanding (in units) | 5,000,000 | 5,000,000 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Revenues: | |||||
Sales of commodities | $ 5,626.8 | $ 5,465.4 | $ 7,595.2 | ||
Fees from midstream services | 1,064.1 | 1,193.2 | 1,021.3 | ||
Total revenues | 6,690.9 | 6,658.6 | 8,616.5 | ||
Costs and expenses: | |||||
Product purchases | 4,922.9 | 4,837.6 | 6,992.6 | ||
Operating expenses | 553.6 | 540 | 487.3 | ||
Depreciation and amortization expenses | 757.7 | 677.1 | 346.5 | ||
General and administrative expenses | 177.1 | 153.6 | 139.8 | ||
Goodwill impairment | 207 | 290 | 0 | ||
Other operating (income) expense | 6.6 | (7.1) | (3) | ||
Income from operations | 66 | [1],[2] | 167.4 | [3],[4] | 653.3 |
Other income (expense): | |||||
Interest expense, net | (233.5) | (207.8) | (143.8) | ||
Equity earnings (loss) | (14.3) | (2.5) | 18 | ||
Gain (loss) from financing activities | (48.2) | 2.8 | (12.4) | ||
Other | 1 | (18.6) | (5.2) | ||
Income (loss) before income taxes | (229) | (58.7) | 509.9 | ||
Income tax (expense) benefit | 0.3 | (0.6) | (4.8) | ||
Net income (loss) | (228.7) | (59.3) | 505.1 | ||
Less: Net income (loss) attributable to noncontrolling interests | 20.7 | (31.9) | 37.4 | ||
Net income (loss) attributable to Targa Resources Partners LP | (249.4) | (27.4) | 467.7 | ||
Net income attributable to preferred limited partners | 11.3 | 2.4 | 0 | ||
Net income attributable to general partner | 63.4 | 167.7 | 148.7 | ||
Net income (loss) attributable to common limited partners | (324.1) | (197.5) | 319 | ||
Net income (loss) attributable to Targa Resources Partners LP | $ (249.4) | $ (27.4) | $ 467.7 | ||
[1] | Includes a goodwill impairment of $183.0 million in the fourth quarter of 2016. See Note 7 – Goodwill | ||||
[2] | Includes an additional goodwill impairment of $24.0 million in the first quarter of 2016. See Note 7 – Goodwill. | ||||
[3] | Includes $32.6 million of impairment losses in the fourth quarter of 2015. See Note 6 – Property, Plant and Equipment and Intangible Assets. | ||||
[4] | Includes a provisional goodwill impairment of $290.0 million in the fourth quarter of 2015. See Note 7 – Goodwill. |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Net income (loss) | $ (228.7) | $ (59.3) | $ 505.1 |
Commodity hedging contracts: | |||
Change in fair value | 112.7 | ||
Other comprehensive income (loss) | (148.6) | 26.4 | 66.4 |
Comprehensive income (loss) | (377.3) | (32.9) | 571.5 |
Less: Comprehensive income attributable to noncontrolling interests | 20.7 | (31.9) | 37.4 |
Comprehensive income (loss) attributable to Targa Resources Partners LP | (398) | (1) | 534.1 |
Commodity Contracts [Member] | |||
Commodity hedging contracts: | |||
Change in fair value | (103.6) | 112.7 | 59.8 |
Settlements reclassified to revenues | (45) | (86.3) | 4.2 |
Interest Rate Swap [Member] | |||
Commodity hedging contracts: | |||
Change in fair value | 0 | 0 | 0 |
Settlements reclassified to revenues | $ 0 | $ 0 | $ 2.4 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY - USD ($) shares in Thousands, $ in Millions | Total | Limited Partner Preferred [Member] | Limited Partners Common [Member] | General Partner Units [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Treasury Units [Member] | Receivables from Unit Issuances [Member] | Non-controlling Interests [Member] |
Balance at Dec. 31, 2013 | $ 2,218.4 | $ 0 | $ 2,001.9 | $ 62 | $ (6.1) | $ 0 | $ 0 | $ 160.6 |
Balance (in units) at Dec. 31, 2013 | 0 | 111,263 | 2,271 | 0 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Compensation on equity grants | 9.2 | $ 0 | $ 9.2 | $ 0 | 0 | $ 0 | 0 | 0 |
Compensation on equity grants (in units) | 0 | 0 | 0 | |||||
Distribution equivalent rights | (1.4) | $ 0 | (1.4) | $ 0 | 0 | $ 0 | 0 | 0 |
Issuance of common units under compensation program | 0 | $ 0 | $ 0 | $ 0 | 0 | $ 0 | 0 | 0 |
Issuance of common units under compensation program (in units) | 0 | 215 | 0 | 0 | ||||
Units tendered for tax withholding obligations | (4.8) | $ 0 | $ 0 | $ 0 | 0 | $ (4.8) | 0 | 0 |
Units tendered for tax withholding obligations (in units) | 0 | (67) | 0 | 67 | ||||
Equity offerings | 408.4 | $ 0 | $ 408.4 | $ 0 | 0 | $ 0 | 0 | 0 |
Equity offerings (in units) | 0 | 7,175 | 0 | 0 | ||||
Contributions from Targa Resources Corp. | 7.7 | $ 0 | $ 0 | $ 8.7 | 0 | $ 0 | (1) | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 149 | 0 | ||||
Distributions to noncontrolling interests | (26.8) | $ 0 | $ 0 | $ 0 | 0 | $ 0 | 0 | (26.8) |
Other comprehensive income (loss) | 66.4 | 0 | 0 | 0 | 66.4 | 0 | 0 | 0 |
Net income (loss) | 505.1 | 0 | 319 | 148.7 | 0 | 0 | 0 | 37.4 |
Distributions | (493.8) | 0 | (353) | (140.8) | 0 | 0 | 0 | 0 |
Balance at Dec. 31, 2014 | 2,688.4 | $ 0 | $ 2,384.1 | $ 78.6 | 60.3 | $ (4.8) | (1) | 171.2 |
Balance (in units) at Dec. 31, 2014 | 0 | 118,586 | 2,420 | 67 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Compensation on equity grants | 16.6 | $ 0 | $ 16.6 | $ 0 | 0 | $ 0 | 0 | 0 |
Compensation on equity grants (in units) | 0 | 0 | 0 | 0 | ||||
Distribution equivalent rights | (1.6) | $ 0 | $ (1.6) | $ 0 | 0 | $ 0 | 0 | 0 |
Issuance of common units under compensation program | 0 | $ 0 | $ 0 | $ 0 | 0 | $ 0 | 0 | 0 |
Issuance of common units under compensation program (in units) | 0 | 439 | 0 | 0 | ||||
Units tendered for tax withholding obligations | (5.5) | $ 0 | $ 0 | $ 0 | 0 | $ (5.5) | 0 | 0 |
Units tendered for tax withholding obligations (in units) | 0 | (145) | 0 | 145 | ||||
Equity offerings | 436 | $ 120.6 | $ 315.4 | $ 0 | 0 | $ 0 | 0 | 0 |
Equity offerings (in units) | 5,000 | 7,377 | 0 | 0 | ||||
Cancellation of treasury units | $ 0 | |||||||
Contributions from Targa Resources Corp. | 60.1 | $ 0 | $ 0 | $ 59.1 | 0 | $ 0 | 1 | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 1,353 | 0 | ||||
Acquisition of APL | 2,799.8 | $ 0 | $ 2,583 | $ 0 | 0 | $ 0 | 0 | 216.8 |
Acquisition of APL (in units) | 0 | 58,614 | 0 | 0 | ||||
Contributions from noncontrolling interests | 78.4 | $ 0 | $ 0 | $ 0 | 0 | $ 0 | 0 | 78.4 |
Distributions to noncontrolling interests | (14.4) | 0 | 0 | 0 | 0 | 0 | 0 | (14.4) |
Targa contribution - Special General Partner Interest | 1,612.4 | 0 | 0 | 1,612.4 | 0 | 0 | 0 | 0 |
Other comprehensive income (loss) | 26.4 | |||||||
Other comprehensive income (loss) | 26.5 | 0 | 0 | 0 | 26.5 | 0 | 0 | 0 |
Net income (loss) | (59.3) | 2.4 | (197.5) | 167.7 | 0 | 0 | 0 | (31.9) |
Distributions | (733.6) | (1.5) | (549.6) | (182.5) | 0 | 0 | 0 | 0 |
Distributions payable to preferred unit holders | (0.9) | (0.9) | 0 | 0 | 0 | 0 | 0 | 0 |
Balance at Dec. 31, 2015 | 6,902.9 | $ 120.6 | $ 4,550.4 | $ 1,735.3 | 86.8 | $ (10.3) | 0 | 420.1 |
Balance (in units) at Dec. 31, 2015 | 5,000 | 184,871 | 3,773 | 212 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Compensation on equity grants | 2.2 | $ 0 | $ 2.2 | $ 0 | 0 | $ 0 | 0 | 0 |
Compensation on equity grants (in units) | 0 | 0 | 0 | 0 | ||||
Distribution equivalent rights | (0.2) | $ 0 | $ (0.2) | $ 0 | 0 | $ 0 | 0 | 0 |
Issuance of common units under compensation program | 0 | $ 0 | $ 0 | $ 0 | 0 | $ 0 | 0 | 0 |
Issuance of common units under compensation program (in units) | 0 | 30 | 0 | 0 | ||||
Units tendered for tax withholding obligations | (0.1) | $ 0 | $ 0 | $ 0 | $ 0 | $ (0.1) | $ 0 | 0 |
Units tendered for tax withholding obligations (in units) | 0 | (1) | 0 | 1 | ||||
Cancellation of treasury units | $ (10.2) | $ (0.2) | $ 10.4 | |||||
Cancellation of treasury units (in units) | 0 | (213) | 0 | |||||
Contributions from Targa Resources Corp. | 1,381 | $ 0 | $ 1,353.4 | $ 27.6 | $ 0 | $ 0 | $ 0 | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 58,621 | 1,197 | 0 | ||||
Purchase of noncontrolling interests in subsidiary | (37.2) | $ 63.7 | $ 1.3 | (102.2) | ||||
Contributions from noncontrolling interests | 43.3 | $ 0 | 0 | 0 | 0 | $ 0 | 0 | 43.3 |
Distributions to noncontrolling interests | (26.7) | 0 | 0 | 0 | 0 | 0 | 0 | (26.7) |
Other comprehensive income (loss) | (148.6) | 0 | 0 | 0 | (148.6) | 0 | 0 | 0 |
Net income (loss) | (228.7) | 11.3 | (324.1) | 63.4 | 0 | 0 | 0 | 20.7 |
Distributions | (737.3) | (11.3) | (598.9) | (127.1) | 0 | 0 | 0 | 0 |
Exchange of Incentive Distribution Rights and special general partner interest for units | 0 | $ 0 | $ 903.6 | $ (903.6) | 0 | $ 0 | 0 | 0 |
Exchange of Incentive Distribution Rights and special general partner interest for units (in units) | 0 | 31,647 | 659 | 0 | ||||
Balance at Dec. 31, 2016 | $ 7,150.6 | $ 120.6 | $ 5,939.9 | $ 796.7 | $ (61.8) | $ 0 | $ 0 | $ 355.2 |
Balance (in units) at Dec. 31, 2016 | 5,000 | 275,168 | 5,629 | 0 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Cash flows from operating activities | |||
Net income (loss) | $ (228.7) | $ (59.3) | $ 505.1 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Amortization in interest expense | 11.9 | 12.6 | 11.2 |
Compensation on equity grants | 2.2 | 16.6 | 9.2 |
Depreciation and amortization expense | 757.7 | 677.1 | 346.5 |
Goodwill impairment | 207 | 290 | 0 |
Accretion of asset retirement obligations | 4.6 | 5.3 | 4.4 |
Increase (decrease) in redemption value of mandatorily redeemable preferred interests | (15.2) | (30.6) | 0 |
Deferred income tax expense (benefit) | (0.3) | (0.2) | 1.6 |
Equity (earnings) loss of unconsolidated affiliates | 14.3 | 2.5 | (18) |
Distributions of earnings received from unconsolidated affiliates | 4.1 | 13.8 | 18 |
Risk management activities | 38.8 | 71.1 | 4.7 |
(Gain) loss on sale or disposition of assets | 6.1 | (8) | (4.8) |
(Gain) loss from financing activities | 48.2 | (2.8) | 12.4 |
Changes in operating assets and liabilities, net of business acquisitions: | |||
Receivables and other assets | (184.7) | 236.1 | 94.5 |
Inventories | (15.9) | 41.4 | (35.9) |
Accounts payable and other liabilities | 188.3 | (181.7) | (110.4) |
Net cash provided by operating activities | 838.4 | 1,083.9 | 838.5 |
Cash flows from investing activities | |||
Outlays for property, plant and equipment | (562.1) | (817.2) | (762.2) |
Outlays for business acquisition, net of cash acquired | 0 | (828.7) | 0 |
Investments in unconsolidated affiliates | (4.4) | (11.7) | 0 |
Return of capital from unconsolidated affiliates | 4.1 | 1.2 | 5.7 |
Other, net | 3.8 | 2.5 | 5.1 |
Net cash used in investing activities | (558.6) | (1,653.9) | (751.4) |
Debt obligations: | |||
Proceeds from borrowings under credit facility | 1,710 | 1,996 | 1,600 |
Repayments of credit facility | (1,840) | (1,716) | (1,995) |
Proceeds from borrowings under accounts receivable securitization facility | 171.4 | 391.6 | 381.9 |
Repayments of accounts receivable securitization facility | (115.7) | (355.1) | (478.8) |
Proceeds from issuance of senior notes | 1,000 | 1,700 | 800 |
Redemption of senior notes | (1,852.2) | (14.3) | (259.8) |
Redemption of TPL senior notes | (13.3) | (1,168.8) | 0 |
Proceeds from sale of common and preferred units | 0 | 443.6 | 412.7 |
Costs incurred in connection with financing arrangements | (30.1) | (26.1) | (14) |
Repurchase of common units under compensation plans | (0.1) | (5.5) | (4.8) |
Purchase of noncontrolling interests in subsidiary | (37.2) | 0 | 0 |
Contributions from general partner | 27.6 | 60.1 | 7.7 |
Contributions from TRC | 1,353.4 | 0 | 0 |
Contributions from noncontrolling interests | 43.3 | 78.4 | 0 |
Distributions to noncontrolling interests | (26.7) | (14.4) | (26.8) |
Distributions to unitholders | (737.3) | (733.6) | (493.8) |
Payments of distribution equivalent rights | (0.3) | (2.8) | (1.6) |
Net cash provided by (used in) financing activities | (347.2) | 633.1 | (72.3) |
Net change in cash and cash equivalents | (67.4) | 63.1 | 14.8 |
Cash and cash equivalents, beginning of period | 135.4 | 72.3 | 57.5 |
Cash and cash equivalents, end of period | $ 68 | $ 135.4 | $ 72.3 |
Organization and Operations
Organization and Operations | 12 Months Ended |
Dec. 31, 2016 | |
Limited Liability Company Or Limited Partnership Business Organization And Operations [Abstract] | |
Organization and Operations | Note 1 — Organization and Operations Our Organization Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. On February 17, 2016, TRC completed the previously announced transactions contemplated pursuant to the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transaction, the “TRC/TRP Merger”), by and among us, Targa Resources GP LLC (our “general partner” or “TRP GP”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”), pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units. At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares. Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.” On October 19, 2016, we executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&R Partnership Agreement”), which became effective as of December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the incentive distribution rights (“IDRs”) held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special General Partner Interest (the “Special GP Interest” as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit (as defined in the Third A&R Partnership Agreement) provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable. Our Operations We are engaged in the business of: • gathering, compressing, treating, processing and selling natural gas; • storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters; • gathering, storing and terminaling crude oil; and • storing, terminaling and selling refined petroleum products. See Note 23 – Segment Information for certain financial information regarding our business segments. The employees supporting our operations are employed by Targa. Our consolidated financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services. |
Basis of Presentation
Basis of Presentation | 12 Months Ended |
Dec. 31, 2016 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Basis of Presentation | Note 2 — Basis of Presentation These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2016 and 2015, and the results of operations, comprehensive income, cash flows, and changes in owners’ equity for the years ended December 31, 2016, 2015 and 2014. We have prepared these consolidated financial statements in accordance with GAAP. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation. As described in Note 4 – Business Acquisitions, the February 27, 2015 Atlas mergers involved two separate legal transactions involving different groups of equity holders. For GAAP reporting purposes, these two mergers are viewed as a single integrated transaction. As such, the financial effects of the Targa consideration related to the ATLS merger have been reflected in these financial statements. As further described in Note 4 – Business Acquisitions, our partnership agreement (the “Partnership Agreement”) was amended to provide for the issuance of the Special GP Interest in us equal to the tax basis of the APL GP Interests acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation. On December 1, 2016, the Special GP Interest was eliminated with an amendment to the Partnership Agreement. See Note 14 – Partnership Units and Related Matters. Change in Reportable Segments Concurrent with the TRC/TRP Merger in February 2016, management reevaluated our reportable segments. See “Segment Information” included in Note 23 for a presentation of financial results by reportable segment, which have been recast to reflect our change in reporting segments for all periods presented. Purchase of Versado Membership Interest On October 31, 2016, we executed a Membership Interest Sale and Purchase Agreement with Chevron U.S.A. Inc. to acquire the remaining 37% membership interest in our consolidated subsidiary Versado Gas Processors, L.L.C. (“Versado”). As we continue to control Versado, the change in our ownership interest was accounted for as an equity transaction representing the acquisition of a noncontrolling interest and no gain or loss was recognized in our Consolidated Statements of Operations as a result. See Note 17 – Contingencies. Revisions of Previously Reported Activity in our Consolidated Statements of Comprehensive Income (Loss) During the first quarter of 2016 we concluded that activity related to our commodity hedge contracts was not reported properly in our Consolidated Statements of Comprehensive Income (Loss) during 2015. The errors resulted in misstatements of the statement caption “Change in fair value” and equal offsetting misstatements of the caption “Settlements reclassified to revenues.” Related income tax effects were also misstated. The reported beginning and ending balance sheet values of Accumulated Other Comprehensive Income were unaffected. We concluded that these misstatements were not material to any of the periods affected, as reported “Total Other Comprehensive Income” is unchanged. However, we have revised previous Consolidated Statements of Comprehensive Income (Loss) reported during 2015 to properly reflect changes in fair value and settlements reclassified to revenues. There is no impact on previously reported net income, total comprehensive income, cash flows, financial position or other profitability measures. The following table displays the impact of these revisions to activity reported in our Consolidated Statements of Comprehensive Income (Loss) during the year ended December 31, 2015. Year Ended December 31, 2015 December 31, 2015 As Reported As Corrected Commodity hedging contracts: Change in fair value $ 81.2 $ 112.7 Settlements reclassified to revenues (54.8 ) (86.3 ) Other comprehensive income (loss) $ 26.4 $ 26.4 |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | Note 3 — Significant Accounting Policies Consolidation Policy Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests. We follow the equity method of accounting when we do not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing goodwill and long-lived assets for possible impairment, (4) estimating the useful lives of assets, (5) determining amounts to accrue for contingencies, guarantees and indemnifications and (6) estimating redemption value of mandatorily redeemable preferred interests. Actual results, therefore, could differ materially from estimated amounts. Cash and Cash Equivalents Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. Checks outstanding at the end of a period are reclassified to accounts payable, as we extinguish liabilities when the creditor receives our payment and we are relieved of our obligation (which generally occurs when our bank honors that check). Comprehensive Income Comprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as cash flow hedges. Allowance for Doubtful Accounts Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required. Inventories Our inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of cost or market using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are classified as Property, Plant and Equipment. Inventories also include materials and supplies required for our Badlands expansion activities in North Dakota, which are valued at cost using the specific identification method. Product Exchanges Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities. Gas Processing Imbalances Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs. Derivative Instruments We utilize derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which under GAAP, are not accounted for as derivatives. As a result, the revenues and expenses associated with such contracts are recognized during the period when volumes are physically delivered or received. If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense. If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss resulting from the change in fair value on the derivative is recognized currently in earnings as a component of revenues. We formally document all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the gain or loss related to the change in fair value to earnings in the current period. We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately. For balance sheet classification purposes, we analyze the fair values of the derivative instruments on a contract by contract basis and report the related fair values and any related collateral by counterparty on a gross basis. Property, Plant and Equipment Property, plant and equipment are stated at acquisition value less accumulated depreciation. All of our property, plant and equipment purchased from Targa from 2007 to 2010 in drop-down transactions were stated at historical cost in the transactions recorded under common control accounting. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination 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. The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset (asset group) with the asset’s (asset group’s) expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize increased depreciation expense equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of additional depreciation expense due to impairment. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations. Goodwill Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Goodwill must be assigned to reporting units for the purpose of impairment testing. A reporting unit is an operating segment or one level below an operating segment (also known as a component). Our annual goodwill impairment test is performed as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not that the fair value of the reporting unit is less than the carrying amount. Prior to us conducting the goodwill impairment test, to the extent triggering events exist, we complete a review of the carrying values of our long-lived assets, including property, plant and equipment and other intangible assets, and if it is determined that the carrying values are not recoverable, we reduce the carrying values of the long-lived assets pursuant to our policy on property, plant and equipment. The annual goodwill impairment test typically entails performing a two-step goodwill impairment test. However, we are permitted to first assess qualitative factors to determine if the two-step goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or otherwise determine that a two-step goodwill impairment test is required, the first step involves comparing the estimated fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of a reporting unit exceeds its fair value, the second step is required and involves comparing the implied fair value of goodwill to the carrying value of goodwill for that reporting unit. The implied fair value of goodwill is determined by assigning the reporting unit’s fair value to its individual assets and liabilities. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of goodwill, the excess of the carrying value over the implied fair value is recognized as a goodwill impairment loss on our Consolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets. Intangible Assets Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with business acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Amortization expense attributable to these assets is recorded on a straight-line basis or, where more appropriate, in a manner that closely resembles the expected pattern in which we benefit from services provided to customers. Asset Retirement Obligations We record the fair value of estimated asset retirement obligations (“AROs”) associated with tangible long-lived assets. Retirement obligations associated with long-lived assets are recognized for those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction. These obligations, which are estimated based on discounted cash flow estimates, are accreted to full value over time as a period cost. In addition, asset retirement costs are capitalized as part of the related asset’s carrying value and are depreciated over the asset’s respective useful life. At least annually, we review the projected timing and amount of asset retirement obligations. Changes resulting from revisions to the timing or the amount of the undiscounted cash flows are recognized as an increase or decrease in the carrying amount of the retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. Upon settlement, any difference between the recorded amount and the actual settlement cost will be recognized at a gain or loss. Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Debt issuance costs related to revolving credit facilities are presented as other long-term assets and debt issuance costs related to other long-term debt are reflected as a deduction from the carrying amount of other long-term debt in the Consolidated Balance Sheets. Accounts Receivable Securitization Facility Proceeds from the sale or contribution of certain receivables under the accounts receivable securitization facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities on our Consolidated Statements of Cash Flows. Environmental Liabilities and Other Loss Contingencies Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Income Taxes We generally are not subject to federal income taxes. For federal income tax purposes, our earnings or losses are included in the tax returns of our separate partners. The taxable income or loss passed through to our partners may vary substantially from the net income or net loss we report in the Consolidated Statements of Operations. As part of the APL merger, we acquired TPL Arkoma, Inc. a corporate subsidiary subject to federal and state income tax. The Partnership’s corporate subsidiary accounts for income taxes under the asset and liability method and provides deferred income taxes for all significant temporary differences. As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes for our taxable corporate subsidiary. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheets. We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we establish a valuation allowance. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies. We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize deferred tax assets, and therefore no valuation allowance has been established. The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are generally not subject to federal and state income taxes at the Partnership level. We are also subject to the Texas margin tax, consisting generally of a 0.75% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas. See Note 19 for discussion of the Partnership’s federal and state income tax expense (benefits) of its taxable subsidiary as well as the Partnership’s net deferred income tax assets (liabilities). Noncontrolling Interests Third-party ownership in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of our Consolidated Balance Sheets. In the Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income, noncontrolling interests reflects the attribution of results to third-party investors. Mandatorily Redeemable Preferred Interests Mandatorily redeemable preferred interests are included in other long term liabilities (or assets) on our Consolidated Balance Sheets. Mandatorily redeemable preferred interests with multiple or indeterminate redemption dates are reported at their estimated redemption value as of the reporting date. This point-in-time value does not represent the amount that ultimately would become payable (or receivable) in the future when the interests are redeemed. Changes in the redemption value are recorded in interest expense, net on our Consolidated Statements of Operations. Revenue Recognition Our operating revenues are primarily derived from the following activities: • sales of natural gas, NGLs, condensate, crude oil and petroleum products; • services related to compressing, gathering, treating, and processing of natural gas; and • services related to NGL fractionation, terminaling and storage, transportation and treating. We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. For natural gas processing activities, we receive either fees and/or a percentage of proceeds from commodity sales as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Typically, our percent-of-proceeds contracts also include a fee-based component. We generally report sales revenues gross in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another are reported as a single transaction on a combined net basis. We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized as revenue during the periods that services will be provided. Deferred revenue is included in Other long-term liabilities on our Consolidated Balance Sheets. Unit-Based and Share-Based Compensation Prior to the TRC/TRP Merger, we awarded unit-based compensation to employees of Targa and to directors and non-management directors of our General Partner in the form of restricted common units and performance units. We withheld units to satisfy employees’ tax withholding obligations on vested awards. The withheld shares were recorded as treasury units at cost. Recent Accounting Pronouncements Revenue from Contracts with Customers In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Other Assets and Deferred Costs – Contracts with Customers With the issuance in August 2015 of ASU 2015-14 , Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers We expect to adopt this new revenue recognition standard on January 1, 2018, presenting a cumulative effect adjustment in the period the standard is adopted. We also anticipate electing the practical expedient to apply the guidance retrospectively to only those contracts that are not completed contracts at the date of initial application. We are continuing to evaluate the effect of the standard on our , including accounting associated with contracts containing noncash consideration and variable consideration, the effect of ASU 2016-20 on our disclosure requirements, and how the standard would impact our current revenue recognition and disclosure policies upon adoption. Consolidation In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis Presentation of Debt Issuance Costs In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs Leases In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases. Share-Based Compensation In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. Cash Flow Classification In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) Recognition of Intra-Entity Transfers of Assets Other than Inventory In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory Business Combinations In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business Goodwill Impairment In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment |
Business Acquisitions
Business Acquisitions | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Business Acquisitions | Note 4 – Business Acquisitions 2015 Acquisition Atlas Mergers On February 27, 2015, Targa completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”), by and among (i) Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly-owned subsidiary of Targa (“GP Merger Sub”), Atlas Energy L.P., a Delaware limited partnership (“ATLS”) and Atlas Energy GP, LLC, a Delaware limited liability company and the general partner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the transactions contemplated by the Agreement and Plan of Merger (the “APL Merger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, the Partnership’s general partner, Trident MLP Merger Sub LLC, a Delaware limited liability company and a wholly-owned subsidiary of the Partnership (“MLP Merger Sub”), ATLS, Atlas Pipeline Partners L.P., a Delaware limited partnership (“APL”) and Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL (“APL GP”). Pursuant to the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged (the “ATLS merger”) with and into ATLS, with ATLS continuing as the surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth in the APL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APL continuing as the surviving entity and as a subsidiary of the Partnership. While the Atlas mergers were two separate legal transactions, for GAAP reporting purposes, they are viewed as a single integrated transaction. As such, the financial effects of the ATLS Merger Consideration (as defined below) paid by Targa have been reflected in these financial statements. In connection with the Atlas mergers, APL changed its name to “Targa Pipeline Partners LP,” which we refer to as TPL, and ATLS changed its name to “Targa Energy LP.” In addition, prior to the completion of the Atlas mergers, ATLS, pursuant to a separation and distribution agreement entered into by and among ATLS, ATLS GP and Atlas Energy Group, LLC, a Delaware limited liability company (“AEG”), on February 27, 2015, (i) transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro rata distribution to the ATLS unitholders of AEG common units representing a 100% interest in AEG (collectively, the “Spin-Off” and, together with the Atlas mergers, the “Atlas Transactions”). On February 27, 2015, the Partnership Agreement was amended to provide for the issuance of the Special GP Interest representing the contribution to the Partnership of the APL GP interest acquired in the ATLS merger totaling $1.6 billion, which is reflected within General partner equity on the Consolidated Balance Sheets. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation. On December 1, 2016, the Special GP Interest was eliminated with an amendment to the Partnership Agreement. See Note 12 – Partnership Units and Related Matters. We acquired all of the outstanding units of APL for a total purchase price of approximately $5.3 billion (including $1.8 billion of acquired debt and all other assumed liabilities). Of the $1.8 billion of debt acquired and other liabilities assumed, approximately $1.2 billion of the acquired debt was tendered and settled upon the closing of the Atlas mergers via our January 2015 cash tender offers. These tender offers were in connection with, and conditioned upon, the consummation of the merger with APL. The merger with APL, however, was not conditioned on the consummation of the tender offers. On that same date, Targa acquired ATLS for a total purchase price of approximately $1.6 billion (including all assumed liabilities). Pursuant to the APL Merger Agreement, our general partner entered into an amendment to our Partnership Agreement, which we refer to as the IDR Giveback Amendment, in order to reduce aggregate distributions to TRC, as the holder of the Partnership’s IDRs TPL is a provider of natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale in South Texas. The Atlas mergers added TPL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing operations. In total, TPL added 2,053 MMcf/d of processing capacity and 12,220 miles of additional pipeline. The operating results of TPL are reported in our Gathering and Processing segment. The APL merger was a unit-for-unit transaction with an exchange ratio of 0.5846 of our common units (the “APL Unit Consideration”) and $1.26 in cash for each APL common unit (the “APL Cash Consideration” and, with the APL Unit Consideration, the “APL Merger Consideration”), a $128.0 million total cash payment, of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion of retained employees’ APL phantom awards. We issued 58,614,157 of our common units and awarded 629,231 replacement phantom unit awards with a combined value of approximately $2.6 billion as consideration for the APL merger (based on the $43.82 closing market price of a common unit on the NYSE on February 27, 2015). The cash component of the APL merger also included $701.4 million for the mandatory repayment and extinguishment at closing of the APL Senior Secured Revolving Credit Facility that was to mature in May 2017 (the “APL Revolver”), $28.8 million of payments related to change of control and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March 2015, Targa contributed $52.4 million to us to maintain its 2% general partner interest. In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the effective time of the APL merger. The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS Stock Consideration”), and $9.12 in cash for each ATLS common unit (the ATLS Cash Consideration” and, with the ATLS Stock Consideration, the “ATLS Merger Consideration”), (a $514.7 million total cash payment). Targa issued 10,126,532 of its common shares and awarded 81,740 replacement restricted stock units with a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSE on February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million of payments related to change of control and cash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for reimbursement of certain transaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vesting of a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date. ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Targa’s acquisition of ATLS resulted in Targa acquiring these common units (converted to 3,363,935 of our common units) valued at approximately $147.4 million (based on the $43.82 closing market price of our common units on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, which reduced the consolidated purchase price by approximately $154.7 million. All outstanding ATLS equity awards, whether vested or unvested, were adjusted in connection with the Spin-Off on the terms and conditions set forth in an Employee Matters Agreement entered into by ATLS, ATLS GP and AEG on February 27, 2015. Following the Spin-Off-related adjustment and at the effective time of the ATLS merger, each outstanding ATLS option and ATLS phantom unit award, whether vested or unvested, held by a person who became an employee of AEG became fully vested (to the extent not vested) and was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). Each outstanding vested ATLS option held by an employee of APL who became an employee of Targa in connection with the Atlas Transactions (a “Midstream Employee”) was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the vested ATLS option, net of the applicable exercise price. Each outstanding unvested ATLS option and each outstanding ATLS phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the ATLS Cash Consideration in respect of each ATLS common unit underlying such ATLS option or phantom unit award and (2) a TRC restricted stock unit award with respect to a number of shares of TRC Common Stock equal to the product of the ATLS Stock Consideration multiplied by the number of ATLS common units underlying such ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). In connection with the APL merger, each outstanding APL phantom unit award held by an employee of AEG became fully vested and was cancelled and converted into the right to receive the APL Merger Consideration in respect of each APL common unit underlying the APL phantom unit award. Each outstanding APL phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the APL Cash Consideration in respect of each APL common unit underlying such APL phantom unit award and (2) a Partnership phantom unit award with respect to a number of our common units equal to the product of the APL Unit Consideration multiplied by the number of APL common units underlying such APL phantom unit award. The acquired business contributed revenues of $1,459.3 million and a net loss of $30.1 million to us for the period from February 27, 2015 to December 31, 2015, and is reported in our Gathering and Processing segment. Cumulative acquisition-related costs totaled $19.3 million. These expenses are included in other expense in our Consolidated Statements of Operations. Pro Forma Impact of Atlas Mergers on Consolidated Statement of Operations The following summarized unaudited pro forma Consolidated Statement of Operations information for the year ended December 31, 2015 assumes that our acquisition of APL and Targa’s acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed the APL merger as of January 1, 2014, or that the results that will be attained in the future. Amounts presented below are in millions: December 31, 2015 Pro Forma Revenues $ 6,947.3 Net income (62.2 ) The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making adjustments to: • Reflect the change in amortization expense resulting from the difference between the historical balances of APL’s intangible assets, net, and the fair value of intangible assets acquired. • Reflect the change in depreciation expense resulting from the difference between the historical balances of APL’s property, plant and equipment, net, and the fair value of property, plant and equipment acquired. • Reflect the change in interest expense resulting from our financing activities directly related to the Atlas mergers as compared to APL’s historical interest expense. • Reflect the changes in stock-based compensation expense related to the fair value of the unvested portion of replacement Partnership Long Term Incentive Plan (“LTIP”) awards that were issued in connection with the acquisition to APL phantom unitholders who continue to provide service as Targa employees following the completion of the APL merger. • Remove the results of operations attributable to the February 2015 transfer to Atlas Resource Partners, L.P. of 100% of APL’s interest in gas gathering assets located in the Appalachian Basin of Tennessee. • Exclude $19.3 million of acquisition-related costs incurred as of December 31, 2015 from pro forma net income for the year ended December 31, 2015. • Reflect the change in APL’s revenues and product purchases to report plant sales of Y-grade at contractual net values to conform to our accounting policy. The following table summarizes the consideration transferred to acquire ATLS and APL, which are viewed together as a single integrated transaction for GAAP reporting purposes: Fair Cash paid, net of cash acquired (1) $ 745.7 Common shares of TRC 1,008.5 Replacement restricted stock units awarded (3) 5.2 Less: value of APL common units owned by ATLS (147.4 ) Total $ 1,612.0 Fair Value of Consideration Transferred by Targa for APL: Cash paid, net of cash acquired (2) $ 828.7 Common units of TRP 2,568.5 Replacement phantom units awarded (3) 15.0 Total $ 3,412.2 Total fair value of consideration transferred $ 5,024.2 (1) Targa acquired $5.5 million of cash. (2) We acquired $35.3 million of cash. (3) The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. Our final fair value determination related to the Atlas mergers was as follows: Fair value determination: February Trade and other current receivables, net $ 181.1 Other current assets 24.4 Assets from risk management activities 102.1 Property, plant and equipment 4,616.9 Investments in unconsolidated affiliates 214.5 Intangible assets 1,354.9 Other long-term assets 5.5 Current liabilities (258.8 ) Long-term debt (1,573.3 ) Deferred income tax liabilities, net (13.6 ) Other long-term liabilities (119.1 ) Total identifiable net assets 4,534.6 Noncontrolling interest in subsidiaries (216.9 ) Current liabilities retained by Targa (0.5 ) Goodwill 707.0 Total fair value of consideration transferred $ 5,024.2 The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 14 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation. The excess of the fair value of the consideration transferred over the fair value of net assets acquired was approximately $707.0 million which was recorded as goodwill. The determination of goodwill is attributable to the workforce of the acquired business and the expected synergies with us and Targa. Goodwill was attributed to the WestTX, SouthTX and SouthOK reporting units in our Gathering and Processing segment. The goodwill is amortizable over 15 years for tax purposes. See Note 7 – Goodwill. The fair value of assets acquired included trade receivables of $178.1 million. The gross amount due under contracts was $178.1 million, all of which was expected to be collectible. The fair value of assets acquired included other receivables of $3.0 million reported in current receivables and $4.5 million reported in other long-term assets related to a contractual settlement with a counterparty. Mandatorily Redeemable Preferred Interests Other long-term liabilities acquired included $109.3 million related to mandatorily redeemable preferred interests held by our partner in two joint ventures. See Note 11 – Other Long-Term Liabilities. Contingent Consideration A liability arising from the contingent consideration for APL’s previous acquisition of a gas gathering system and related assets has been recognized at fair value. APL agreed to pay up to an additional $6.0 million if certain volumes are achieved on the acquired gathering system within a specified time period. The acquisition date fair value of the remaining contingent payment of $4.2 million was recorded within other long term liabilities on our Consolidated Balance Sheets. Subsequent changes in the fair value of this liability are included in earnings. Replacement Phantom Units In connection with the Atlas mergers, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained unchanged from the existing APL awards, and vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 33% per year over the original three year term. Each replacement phantom unit will entitle the grantee a common unit of TRP on the vesting date and is an equity-settled award. The replacement phantom units include distribution equivalent rights (“DERs”). When we declare and pay cash distributions, the holders of replacement phantom units are entitled within 60 days to receive cash payment of DERs in an amount equal to the cash distributions the holders would have received if they were the holders of record on the record date of the number of our common units related to the replacement phantom units. The fair value of the replacement phantom units was based on the closing price of our units at the close of trading on February 27, 2015. The fair value was allocated between the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award. See Note 22 – Compensation Plans for discussion of the impact of the TRC/TRP Merger on the replacement phantom units. Subsequent Events On January 22, 2017, we entered into definitive agreements to purchase 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “Outrigger Delaware”) and Outrigger Midland Operating, LLC (“Outrigger Midland” and together with “Outrigger Delaware”, “Outrigger”) (the “Permian Acquisition”). We will pay $475 million in cash at closing and $90 million within 90 days of closing. Subject to certain performance-linked measures and other conditions, additional cash of up to $935 million may be received by the owners of Outrigger Delaware and Outrigger Midland in potential earn-out payments that may occur in 2018 and 2019. The potential earn-out payments will be based upon a multiple of realized gross margin from existing contracts. We currently expect to close the transaction during the first quarter of 2017, subject to customary regulatory approvals and closing conditions. Outrigger Delaware’s gas gathering and processing and crude gathering systems are located in Loving, Winkler and Ward counties. The operations are backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14 years. Outrigger Delaware’s assets include 70 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Delaware system. Outrigger Midland’s gas gathering and processing and crude gathering systems are located in Howard, Martin and Borden counties. The operations are backed by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years. Outrigger Midland currently has 10 MMcf/d of processing capacity. Currently, there is 40,000 Bbl/d of crude gathering capacity on the Outrigger Midland system. We anticipate connecting Outrigger Delaware to our existing Sand Hills system and Outrigger Midland to our existing WestTX system during 2017, creating operational and capital synergies. On January 26, 2017, Targa completed a public offering of 9,200,000 shares of common stock (including underwriters’ overallotment option) at a price of $57.65, providing net proceeds of $524.1 million. Targa intends to use the net proceeds from this public offering to fund a portion of the $565 million initial purchase price of the Permian Acquisition We expect that the remaining portion of the purchase price and related fees and expenses will be funded with borrowings under our senior secured revolving credit facility or, subject to market conditions, proceeds from the issuance of private or public securities. Prior to funding the Permian Acquisition, or if we do not complete the pending Permian Acquisition, Targa may use the net proceeds from its offering for general corporate purposes, which may include, among other things, repayment of Targa’s indebtedness (including our indebtedness), acquisitions, capital expenditures, additions to working capital and redeeming or repurchasing some of our outstanding notes. |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2016 | |
Inventory Disclosure [Abstract] | |
Inventories | Note 5 — Inventories December 31, 2016 December 31, 2015 Commodities $ 126.9 $ 128.3 Materials and supplies 10.8 12.7 $ 137.7 $ 141.0 |
Property, Plant and Equipment a
Property, Plant and Equipment and Intangible Assets | 12 Months Ended |
Dec. 31, 2016 | |
Property Plant And Equipment And Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | Note 6 — Property, Plant and Equipment and Intangible Assets Property, Plant and Equipment December 31, 2016 December 31, 2015 Estimated Useful Lives (In Years) Gathering systems $ 6,626.9 $ 6,304.5 5 to 20 Processing and fractionation facilities 3,383.6 2,988.5 5 to 25 Terminaling and storage facilities 1,205.0 1,115.0 5 to 25 Transportation assets 451.4 454.0 10 to 25 Other property, plant and equipment 274.0 220.9 3 to 25 Land 121.2 108.8 — Construction in progress 449.8 736.5 — Property, plant and equipment 12,511.9 11,928.2 Accumulated depreciation (2,821.0 ) (2,225.6 ) Property, plant and equipment, net $ 9,690.9 $ 9,702.6 Intangible assets $ 2,036.6 $ 2,036.6 20 Accumulated amortization (382.6 ) (226.5 ) Intangible assets, net $ 1,654.0 $ 1,810.1 For each of the years ended December 31, 2016, 2015, and 2014 depreciation expense for property, plant and equipment was $601.5 million, $540.5 million and $285.0 million. We recorded non-cash pre-tax impairment charges of $32.6 million in 2015 and $3.2 million in 2014 due to the impairment of certain gas processing facilities and gathering systems associated with our Coastal and Big Lake operations. The impairments are a result of reduced forecasted gas processing volumes due to market conditions and processing spreads in Louisiana in the fourth quarter of 2015 and 2014. We measured the impairment of property, plant and equipment using discounted estimated future cash flows representative of a Level 3 fair value measurement. These carrying value adjustments are included in depreciation and amortization expenses on our Consolidated Statements of Operations. Intangible Assets Intangible assets consist of customer contracts and customer relationships acquired in the Atlas mergers in 2015 and our Badlands business acquisition in 2012. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate. The fair values of intangible assets acquired in the Atlas mergers were recorded at a fair value of $1,354.9 million and are being amortized over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation over a 20-year life. The changes in our intangible assets are as follows: December 31, 2016 December 31, 2015 Beginning of period $ 1,810.1 $ 591.9 Additions from acquisition — 1,354.9 Amortization (156.1 ) (136.7 ) Intangible assets, net $ 1,654.0 $ 1,810.1 For each of the years ended December 31, 2016, 2015, and 2014 amortization expense for our intangible assets was $156.1 million, $136.7 million and $61.5 million. The estimated annual amortization expense for intangible assets is approximately $149.4 million, $135.7 million, $124.7 million, $112.5 million and $102.6 million for each of the years 2017 through 2021. As of December 31, 2016 the weighted average amortization period for our intangible assets was approximately 17.6 years. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill And Intangible Assets Disclosure [Abstract] | |
Goodwill | Note 7 — Goodwill We recognized goodwill of approximately $707.0 million when we acquired Atlas on February 27, 2015. This goodwill was attributed to the WestTX, SouthTX and SouthOK reporting units in our Gathering and Processing segment. The future cash flows and resulting fair values of these reporting units are sensitive to changes in oil, gas and NGL prices. The direct and indirect effects of significant declines in commodity prices from the date of acquisition would likely cause the fair values of these reporting units to fall below their carrying values, and could result in an impairment of goodwill. As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. As of December 31, 2015, we had not completed our November 30, 2015 impairment assessment. Based on the results of that preliminary evaluation, we recorded a provisional goodwill impairment of $290.0 million during the fourth quarter of 2015. The provisional goodwill impairment reduced the carrying value of goodwill to $417.0 million on our Consolidated Balance Sheets as of December 31, 2015. During the first quarter of 2016, we finalized our evaluation of goodwill for impairment and recorded additional impairment expense of $24.0 million in our Consolidated Statement of Operations and reduced the carrying value of goodwill to $393.0 million on our Consolidated Balance Sheets as of March 31, 2016. The impairment of goodwill was primarily due to the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas. Our annual evaluation of goodwill for impairment was completed in the fourth quarter of 2016 and we recorded impairment expense of $183.0 million in our Consolidated Statement of Operations and reduced the carrying value of goodwill to $210.0 million on our Consolidated Balance Sheets. The additional impairment of goodwill during the fourth quarter of 2016 was primarily due to the impact of lower forecasted commodity prices and a refinement in the valuation methodology used to determine fair values of our reporting units Our annual evaluations utilized an income approach including a terminal value to estimate the fair values of our reporting units based on a discounted cash flow (“DCF”) analysis . The refinement of the valuation methodology reflects . The fair value measurements utilized for the evaluation of goodwill for impairment are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 14 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation. Changes in the gross amounts of our goodwill are as follows: WestTX SouthTX SouthOK Total Balance at January 1, 2015 $ — $ — $ — $ — Acquisition, February 27, 2015 364.5 160.3 182.2 707.0 Provisional impairment for 2015 annual assessment (37.6 ) (70.2 ) (182.2 ) (290.0 ) Balance at December 31, 2015 326.9 90.1 — 417.0 Additional impairment for 2015 annual assessment (14.4 ) (9.6 ) — (24.0 ) Impairment for 2016 annual assessment (137.8 ) (45.2 ) — (183.0 ) Balance at December 31, 2016 $ 174.7 $ 35.3 $ — $ 210.0 Should energy industry conditions deteriorate, there is a possibility that reporting unit fair values could deteriorate further and goodwill may be impaired in a future period. Further, upon our adoption of ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 12 Months Ended |
Dec. 31, 2016 | |
Equity Method Investments And Joint Ventures [Abstract] | |
Investments in Unconsolidated Affiliates | Note 8 — Investments in Unconsolidated Affiliates Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: 75% interest in T2 LaSalle; 50% interest in T2 Eagle Ford; and 50% interest in T2 EF Cogen (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting. Our maximum exposure to loss as a result of our involvement with the T2 Joint Ventures includes our equity investment, any additional capital contribution commitments, and our share of any operating expenses incurred by the T2 Joint Ventures. The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 EF Cogen Total Balance at December 31, 2013 $ 55.9 $ — $ — $ — $ 55.9 Equity earnings (loss) 18.0 — — — 18.0 Cash distributions (1) (23.7 ) — — — (23.7 ) Balance at December 31, 2014 $ 50.2 $ — $ — $ — $ 50.2 Fair value of T2 Joint Ventures acquired — 67.5 126.7 20.3 214.5 Equity earnings (loss) 13.8 (3.9 ) (9.4 ) (3.0 ) (2.5 ) Cash distributions (1) (14.5 ) — — (0.5 ) (15.0 ) Cash calls for expansion projects — — 6.5 5.2 11.7 Balance at December 31, 2015 $ 49.5 $ 63.6 $ 123.8 $ 22.0 $ 258.9 Equity earnings (loss) 4.1 (5.2 ) (9.4 ) (3.8 ) (14.3 ) Cash distributions (1) (7.5 ) — — (0.7 ) (8.2 ) Cash calls for expansion projects — 0.2 4.2 — 4.4 Balance at December 31, 2016 $ 46.1 $ 58.6 $ 118.6 $ 17.5 $ 240.8 (1) Includes $4.1 million and $1.2 million in distributions received from GCF and the T2 Joint Ventures in excess of our share of cumulative earnings for the years ended December 31, 2016 and 2015. Includes $5.7 million in distributions from GCF in excess of our share of cumulative earnings for the year ended December 31, 2014. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows. The recorded value of the T2 Joint Ventures is based on fair values at the date of acquisition which results in an excess fair value of $36.2 million over the book value of the joint venture capital accounts as of December 31, 2016. This basis difference is attributable to depreciable tangible assets and is being amortized over the estimated useful lives of the underlying assets of 20 years on a straight-line basis and is included as a component of equity earnings. See Note 4 – Business Acquisitions for further information regarding the fair value determinations related to the Atlas mergers. |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Payables And Accruals [Abstract] | |
Accounts Payable and Accrued Liabilities | Note 9 — Accounts Payable and Accrued Liabilities December 31, 2016 December 31, 2015 Commodities $ 574.5 $ 378.7 Other goods and services 113.4 141.3 Interest 52.2 80.3 Compensation and benefits — 0.4 Income and other taxes 19.1 10.4 Other 14.7 18.0 $ 773.9 $ 629.1 Accounts payable and accrued liabilities includes $30.2 million and $34.0 million of liabilities to creditors to whom we have issued checks that remain outstanding as of December 31, 2016 and December 31, 2015. |
Debt Obligations
Debt Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Debt Obligations | Note 10 — Debt Obligations December 31, 2016 December 31, 2015 Current: Accounts receivable securitization facility, due December 2017 $ 275.0 $ 219.3 Long-term: Senior secured revolving credit facility, variable rate, due October 2020 (1) 150.0 280.0 Senior unsecured notes: 5% fixed rate, due January 2018 250.5 1,100.0 4 ⅛ 749.4 800.0 6 ⅝ — 342.1 Unamortized premium — 5.0 6 ⅞ — 483.6 Unamortized discount — (22.1 ) 6 ⅜ 278.7 300.0 5 ¼ 559.6 583.7 4¼% fixed rate, due November 2023 583.9 623.5 6¾% fixed rate, due March 2024 580.1 600.0 5⅛ % fixed rate, due February 2025 500.0 — 5⅜ % fixed rate, due February 2027 500.0 — TPL notes, 6 ⅝ — 12.9 Unamortized premium — 0.2 TPL notes, 4¾% fixed rate, due November 2021 (2) 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 (2) 48.1 48.1 Unamortized premium 0.5 0.5 4,207.3 5,164.0 Debt issuance costs, net of amortization (30.3 ) (38.3 ) Total long-term debt 4,177.0 5,125.7 Total debt obligations $ 4,452.0 $ 5,345.0 Irrevocable standby letters of credit outstanding $ 13.2 $ 12.9 (1) As of December 31, 2016, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,436.8 million. (2) TPL notes are not guaranteed by us. The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2016, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2017 2018 2019 2020 2021 After 2021 (in millions) TRP Revolver $ 150.0 $ — $ — $ — $ 150.0 $ — $ — Senior unsecured notes 4,056.8 — 250.5 749.4 — 6.5 3,050.4 Accounts receivable securitization facility 275.0 275.0 — — — — — Total $ 4,481.8 $ 275.0 $ 250.5 $ 749.4 $ 150.0 $ 6.5 $ 3,050.4 The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2016: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 2.4% - 5.3% 2.8% Accounts receivable securitization facility 1.2% - 1.8% 1.3% Compliance with Debt Covenants As of December 31, 2016, we were in compliance with the covenants contained in our various debt agreements. Debt Obligations Revolving Credit Facility In October 2016, we entered into the Second Amendment and Restatement Agreement (the “Restatement”) to effectuate the Third Amended and Restated Credit Agreement (the “TRP Credit Agreement”). The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity date from October 2017 to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while our ability to request additional commitments increased from up to $300.0 million to up to $500.0 million. The TRP Credit Agreement designates TPL and certain of its subsidiaries as Restricted Subsidiaries and provides for certain changes to occur upon the Partnership receiving an investment grade credit rating from Moody’s or S&P, including the release of the security interests in all collateral at the request of the Partnership. As a result of the TRP Credit Agreement, during the fourth quarter of 2016, we recorded a partial write-off of $0.9 million of debt issuance costs associated with the TRP Revolver as a result of a change in syndicate members under the TRP Revolver. The remaining debt issuance costs associated with the TRP Revolver along with debt issuance costs incurred with this amendment will be amortized on a straight-line basis over the life of the TRP Revolver. In 2015, we used proceeds from borrowings under the TRP Revolver to fund some of the cash components of the APL merger, including $701.4 million for the repayments of the APL Revolver and $28.8 million related to change of control payments. The TRP Revolver bears interest, at our option, either at the base rate or the Eurodollar rate. The base rate is equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin ranging from 0.75% to 1.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA). The Eurodollar rate is equal to LIBOR rate plus an applicable margin ranging from 1.75% to 2.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA). We are required to pay a commitment fee equal to an applicable rate ranging from 0.3% to 0.5% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA) times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable rate ranging from 1.75% to 2.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA). The TRP Revolver is collateralized by a majority of our assets. Borrowings are guaranteed by our restricted subsidiaries. The TRP Revolver restricts our ability to make distributions of available cash to unitholders if a default or an event of default (as defined in the TRP Revolver) exists or would result from such distribution. The TRP Revolver requires us to maintain a ratio of consolidated funded indebtedness to consolidated adjusted EBITDA of no more than 5.50 to 1.00. The TRP Revolver also requires us to maintain a ratio of consolidated EBITDA to consolidated interest expense of no less than 2.25 to 1.00. In addition, the TRP Revolver contains various covenants that may limit, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates (in each case, subject to our right to incur indebtedness or grant liens in connection with, and convey accounts receivable as part of, a permitted receivables financing). Accounts Receivable Securitization Facility The Securitization Facility provides up to $275.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 8, 2017. Under the Securitization Facility, Partnership subsidiaries sell or contribute certain qualifying receivables, without recourse, to another of its consolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of the Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to third-party financial institutions. Sold receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of the selling subsidiaries or the Partnership. Any excess receivables are eligible to satisfy the claims. As of December 31, 2016, total funding under the Securitization Facility was $275.0 million. Senior Unsecured Notes All issues of unsecured senior notes are pari passu with existing and future senior indebtedness, including indebtedness under the TRP Revolver. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by us and our restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the TRP Revolver, which is secured by substantially all of our assets and the Securitization Facility, which is secured by accounts receivable pledged under the facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears. Our senior unsecured notes and associated indenture agreements restrict our ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Corporation (“S&P’) We may redeem up to 35% of the aggregate principal amount of the notes in the table below at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 180 days of the date of the closing of such equity offering. Note Issue Any Date Prior To Price 4 ⅛% Notes November 15, 2017 104.125% 6 ¾% Notes September 15, 2018 106.750% 5 ⅛% Notes February 1, 2020 105.125% 5 ⅜% Notes February 1, 2022 105.375% We may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed. Note Redemption Date Year Price 4 ⅛% Notes November 15 2016 102.063 % 2017 101.031 % 2018 and thereafter 100 % 6 ⅜% Notes February 1 2017 103.188 % 2018 102.125 % 2019 101.063 % 2020 and thereafter 100 % 5 ¼% Notes November 1 2017 102.625 % 2018 101.750 % 2019 100.875 % 2020 and thereafter 100 % 4 ¼% Notes May 15 2018 102.125 % 2019 101.417 % 2020 100.708 % 2021 and thereafter 100 % 6 ¾% Notes September 15 2019 103.375 % 2020 101.688 % 2021 and thereafter 100 % 5 ⅛% Notes February 1 2020 103.844 % 2021 102.563 % 2022 101.281 % 2023 and thereafter 100 % 5 ⅜% Notes February 1 2022 102.688 % 2023 101.792 % 2024 100.896 % 2025 and thereafter 100 % TPL 4 ¾% Notes May 15 2017 102.375 % 2018 101.188 % 2019 and thereafter 100 % TPL 5 ⅞% Notes February 1 2018 102.938 % 2019 101.958 % 2020 100.979 % 2021 and thereafter 100 % Senior Notes Issuances In October 2014, the Partnership and Targa Resources Partners Finance Corporation (collectively, the “Partnership Issuers”) issued $800.0 million in aggregate principal amount of 4 ⅛ ⅛ ⅛ In January 2015, the Partnership Issuers issued $1.1 billion in aggregate principal amount of 5% Senior Notes due 2018 (the “5% Notes”). The 5% Notes resulted in approximately $1,089.8 million of net proceeds after costs, which were used with borrowings under the TRP Revolver to fund the TPL Notes Tender Offers and the Change of Control Offer (each as defined below). The 5% Notes are unsecured senior obligations that have substantially the same terms and covenants as our other senior notes. In September 2015, the Partnership Issuers issued $600 million in aggregate principal amount of 6 ¾ ¾ ¾ ¾ In October 2016, the Partnership Issuers issued $500.0 million of 5⅛% 5⅜% Shelf Registrations April 2013 Shelf In April 2013, we filed with the SEC a universal shelf registration statement (the “April 2013 Shelf”), which provided us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The April 2013 Shelf expired in April 2016. There was no activity under the April 2013 Shelf during the years ended December 31, 2016, 2015 and 2014. July 2013 Shelf In July 2013, we filed with the SEC a universal shelf registration statement that allowed us to issue up to an aggregate of $800.0 million of debt or equity securities (the “July 2013 Shelf”). The July 2013 Shelf expired in August 2016. April 2015 Shelf In April 2015, we filed with the SEC a universal shelf registration statement that allows us to issue up to an aggregate of $1.0 billion of debt or equity securities (the “April 2015 Shelf”). The April 2015 Shelf expires in April 2018. Debt Repurchases & Extinguishments In November 2014, we redeemed the outstanding 7 ⅞ In December 2015, we repurchased on the open market a portion of our outstanding Senior Notes as follows: Debt Repurchased Book Value Payment Gain/(Loss) Write-off of Debt Issuance Costs Net Gain/(Loss) 5¼% Senior Notes $ 16.3 $ (13.0 ) $ 3.3 $ (0.1 ) $ 3.2 4¼% Senior Notes 1.5 (1.2 ) 0.3 — 0.3 6⅝% Senior Notes 0.1 (0.1 ) — — — $ 17.9 $ (14.3 ) $ 3.6 $ (0.1 ) $ 3.5 The December 2015 Senior Note repurchases resulted in a $3.6 million gain on debt repurchases and a write-off of $0.1 million in related debt issuance costs. During the year ended December 31, 2016, we repurchased on the open market a portion of our outstanding senior notes as follows: Debt Repurchased Book Value Payment Gain/(Loss) Write-off of Debt Issuance Costs Net Gain/(Loss) 5¼% Senior Notes $ 24.1 $ (20.1 ) $ 4.0 $ (0.2 ) $ 3.8 4¼% Senior Notes 39.5 (31.8 ) 7.7 (0.3 ) 7.4 6⅞% Senior Notes 4.8 (4.3 ) 0.5 (0.1 ) 0.4 6⅝% Senior Notes 32.6 (29.5 ) 3.1 — 3.1 6⅜% Senior Notes 21.3 (18.7 ) 2.6 (0.2 ) 2.4 6¾% Senior Notes 19.9 (17.5 ) 2.4 (0.2 ) 2.2 5% Senior Notes 366.4 (368.2 ) (1.8 ) (2.1 ) (3.9 ) 4⅛% Senior Notes 50.6 (44.2 ) 6.4 (0.4 ) 6.0 $ 559.2 $ (534.3 ) $ 24.9 $ (3.5 ) $ 21.4 We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Senior Notes Tender Offers Concurrently with the October 2016 Offering, we commenced tender offers (the “Tender Offers”) to purchase for cash, subject to certain conditions, up to specified aggregate maximum purchase amounts of our 5% Senior Notes due January 2018 (the “5% Notes”), 6 ⅝ ⅝ ⅞ ⅞ ⅝ The results of the Tender Offers, which closed in October 2016, were: Debt Tendered Outstanding Note Balance Prior to Tender Offers Amount Tendered Premium Paid Accrued Interest Paid Total Tender Offer Payments Note Balance After Tender Offers 5% Senior Notes $ 733.6 $ 483.1 $ 16.9 $ 5.4 $ 505.4 $ 250.5 6⅝% Senior Notes 309.9 281.7 10.5 0.3 292.5 28.2 6⅞% Senior Notes 478.6 373.5 14.4 4.6 392.5 105.1 Total $ 1,522.1 $ 1,138.3 $ 41.8 $ 10.3 $ 1,190.4 $ 383.8 As a result of the Tender Offers, we recorded during the fourth quarter of 2016 a loss due to debt extinguishment of approximately $59.2 million comprised of the $41.8 million premium paid, the write-off of $5.8 million of debt issuance costs, $15.1 million of debt discounts less $3.5 million of debt premiums. Note Redemptions Subsequent to the closing of the Tender Offers in October 2016, we issued notices of full redemption (the “Note Redemptions”) to the trustees and noteholders of the 6⅝% Notes ⅞ 6⅝% Notes and the 6⅝% ⅞ TPL Senior Notes Tender Offers In January 2015, we commenced cash tender offers for any and all of the outstanding fixed rate senior secured notes to be acquired in the APL merger (the “TPL Notes Tender Offers”), which totaled $1.55 billion. The results of the TPL Notes Tender Offers were: Debt Tendered Outstanding Note Balance Prior to Tender Offers Amount Tendered Premium Paid Accrued Interest Paid Total Tender Offer Payments % Tendered Note Balance After Tender Offers 6⅝% Senior Notes $ 500.0 $ 140.1 $ 2.1 $ 3.7 $ 145.9 28.02 % $ 359.9 4¾% Senior Notes 400.0 393.5 5.9 5.3 404.7 98.38 % 6.5 5⅞% Senior Notes 650.0 601.9 8.7 2.6 613.2 92.60 % 48.1 Total $ 1,550.0 $ 1,135.5 $ 16.7 $ 11.6 $ 1,163.8 $ 414.5 In connection with the TPL Notes Tender Offers, on February 27, 2015, the supplemental indentures governing the 4 3 4 7 8 Not having achieved the minimum tender condition on the 6 5 8 Payments made under the TPL Notes Tender Offers and Change of Control Offer totaling $1,168.8 million are presented as financing activities in the Consolidated Statements of Cash Flows. Exchange Offer and Consent Solicitation On April 13, 2015, the Partnership Issuers commenced an offer to exchange (the “Exchange Offer”) any and all of the outstanding 2020 TPL Notes, for an equal amount of new unsecured 6 5 8 5 8 5 8 In May 2015, upon the closing of the Exchange Offer, the Partnership Issuers issued $342.1 million aggregate principal amount of the TRP 6 5 8 5 8 Debt Repurchases Summary The following table summarizes the debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2016 2015 2014 Premium over face value paid upon redemption: 5% Senior Notes $ 16.9 $ — $ — 6⅝% Senior Notes 11.5 — — 6⅞% Senior Notes 18.0 — — 6⅝% TPL Notes 0.4 — — 7⅞% Senior Notes — — 9.9 Recognition of unamortized discount: 6⅞% Senior Notes 19.5 — — Recognition of unamortized premium: 6⅝% Senior Notes (4.3 ) — — 6⅝% TPL Notes (0.2 ) — — Loss (gain) on repurchase of debt: 5% Senior Notes 1.8 — — 4⅛% Senior Notes (6.4 ) — — 6⅝% Senior Notes (2.8 ) — — 6⅞% Senior Notes (0.8 ) — — 6⅜% Senior Notes (2.6 ) — — 5¼% Senior Notes (4.0 ) (3.3 ) — 4¼% Senior Notes (7.7 ) (0.3 ) — 6¾% Senior Notes (2.4 ) — — Loss from financing with Exchange Offer: 6⅝% Senior Notes — 0.7 — Write-off of debt issuance costs: TRP Revolver 0.9 — — 5% Senior Notes 4.2 — — 4⅛% Senior Notes 0.4 — — 6⅞% Senior Notes 4.9 — — 6⅜% Senior Notes 0.2 — — 5¼% Senior Notes 0.2 0.1 — 4¼% Senior Notes 0.3 — — 6¾% Senior Notes 0.2 — — 7⅞% Senior Notes — — 2.5 Loss (gain) from financing activities $ 48.2 $ (2.8 ) $ 12.4 |
Other Long-term Liabilities
Other Long-term Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Other Liabilities Noncurrent [Abstract] | |
Other Long-term Liabilities | Note 11 — Other Long-term Liabilities Other long-term liabilities are comprised of the following obligations: December 31, 2016 December 31, 2015 Asset retirement obligations $ 64.1 $ 69.9 Mandatorily redeemable preferred interests 68.5 82.9 Deferred revenue 69.8 27.7 Other liabilities 2.9 4.4 Total long-term liabilities $ 205.3 $ 184.9 Asset Retirement Obligations Our asset retirement obligations (“ARO”) primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows: 2016 2015 Beginning of period $ 69.9 $ 56.8 Fair value of ARO acquired with APL merger — 4.0 Change in cash flow estimate (9.1 ) 3.8 Accretion expense 4.6 5.3 Retirement of ARO (1.3 ) — End of period $ 64.1 $ 69.9 Mandatorily Redeemable Preferred Interests Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037. The joint ventures, collectively, hold $1.9 billion face value in notes receivable from our partner, which are due July 2042. The interest rate payable under the notes receivable is a variable LIBOR-based rate. For the periods ending on December 31, 2016, and December 31, 2015, interest earned on the notes receivable of $10.5 million, and $8.9 million, exclusive of the priority return payable to our partner, is reflected within Interest expense, net on our Consolidated Statements of Operations. We have accounted for the notes receivable at fair value. Upon redemption: (i) the distributable value of our partner’s interest in each joint venture is required to be adjusted by mutual agreement or under a valuation procedure outlined in each joint venture agreement based, among other things, on changes in the market value of the joint venture’s assets allocable to our partner (including the value of the notes receivable); and (ii) the parties are obligated to set off the value of the notes receivable from our partner against the value of our partner’s interest in the applicable joint venture. For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. Because redemption will not be required until at least 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of redemption value as of December 31, 2016. The aggregate fair values of the notes receivable and the estimated redemption values of our partner’s interest in the joint ventures as of the reporting date are presented on the Consolidated Balance Sheets on a net basis. The following table shows the changes attributable to mandatorily redeemable preferred interests: 2016 2015 Beginning of period $ 82.9 $ — Acquired mandatorily redeemable preferred interests — 109.3 Income attributable to mandatorily redeemable preferred interests 0.8 2.8 Change in estimated redemption value included in interest expense (15.2 ) (30.6 ) Other activity, net — 1.4 End of period $ 68.5 $ 82.9 Deferred Revenue We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided. Deferred revenue includes consideration received related to the construction and operation of a crude oil and condensate splitter. On December 27, 2015, Targa Terminals LLC and Noble Americas Corp., a subsidiary of Noble Group Ltd. (“Noble”) entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we will build and operate a 35,000 barrel per day crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 barrels of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 barrels per day of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter project is expected to be completed by early 2018, and has an estimated total cost of approximately $140 million. The first annual advance payment due under the Splitter Agreement was received in October 2016 and has been recorded as deferred revenue, as the Splitter Agreement Deferred revenue also includes consideration received in a 2015 amendment to a gas gathering and processing agreement. We measured the estimated fair value of the assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. The consideration paid for the contract amendment will require future performance by Targa which has resulted in the deferred revenue. The deferred revenue related to this amendment is being recognized on a straight-line basis through the end of the agreement’s term in 2030. Deferred revenue also includes consideration received for other construction activities of facilities connected to our systems. The deferred revenue related to these other construction activities will be recognized over the periods that future performance will be provided, which extend through 2023. For the years ended December 31, 2016, 2015 and 2014, we recognized approximately $3.1 million, $2.7 million and $0.1 million of revenue for these transactions. The following table shows the components of deferred revenue: December 31, 2016 December 31, 2015 Splitter agreement $ 43.0 $ — Gas contract amendment 19.7 21.1 Other deferred revenue 7.1 6.6 Total deferred revenue $ 69.8 $ 27.7 The following table shows the changes in deferred revenue: 2016 2015 Beginning of period $ 27.7 $ 4.1 Additions 45.2 26.3 Revenue recognized (3.1 ) (2.7 ) End of period $ 69.8 $ 27.7 |
Partnership Units and Related M
Partnership Units and Related Matters | 12 Months Ended |
Dec. 31, 2016 | |
Partners Capital [Abstract] | |
Partnership Units and Related Matters | Note 12 — Partnership Units and Related Matters Common Units Equity Offerings In May 2014, we entered into an equity distribution agreement (“EDA”) under our July 2013 Shelf (the “May 2014 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregate of $400 million of our common units. During the year ended 2014, pursuant to the August 2013 EDA and the May 2014 EDA, we issued a total of 7,175,096 common units representing total net proceeds of $408.4 million, (net of commissions up to 1% of gross proceeds to our sales agent), which were used to reduce borrowings under the TRP Revolver and for general partnership purposes. Targa contributed $8.4 million to us to maintain its 2% general partner interest. As part of the Atlas merger in February 2015, we issued 58,614,157 common units to former APL unitholders as consideration for the APL merger, of which 3,363,935 common units represented ATLS’s common unit ownership in APL and were issued to Targa. Targa contributed $52.4 million to us to maintain its 2% general partner interest. In May 2015, we entered into the May 2015 EDA under the April 2015 Shelf pursuant to which we may sell through our sales agents, at our option, up to an aggregate of $1.0 billion of our common units. As of December 31, 2015, we issued 7,377,380 common units under our EDAs, receiving net proceeds of $316.1 million. As of December 31, 2015, approximately $4.2 million of capacity and $835.6 million of capacity remained under the May 2014 and May 2015 EDAs. Targa contributed $6.5 million to us to maintain its 2% general partner interest. Since January 2016, no units have been issued from any of the EDAs. TRC/TRP Merger On February 17, 2016, TRC completed the TRC/TRP Merger, indirectly acquiring all of the outstanding common units not already owned by TRC and its subsidiaries. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units. At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of TRC shares. TRC issued 104,525,775 shares of its common stock to third-party unitholders of our common units in exchange for all of our 168,590,009 outstanding common units that TRC previously did not own. No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares. Pursuant to the TRC/TRP Merger Agreement, our common units were delisted from the NYSE and deregistered under the Exchange Act and our common units are no longer publicly traded. Our 5,000,000 Preferred Units remain outstanding as preferred limited partner interests in us and continue to trade on the NYSE. Distributions As a result of the TRC/TRP Merger, TRC is entitled to receive all available Partnership distributions after payment of preferred distributions each quarter. We have discretion under the Third A&R Partnership Agreement, The following details the distributions declared or paid by the Partnership during 2016, 2015 and 2014: Three Months Date Paid Total Distributions Targa Ended Or to Be Paid Distributions Corp. 2016 December 31, 2016 February 10, 2017 $ 198.1 $ 195.3 September 30, 2016 November 11, 2016 194.7 191.9 June 30, 2016 August 11, 2016 181.7 178.9 March 31, 2016 May 12, 2016 157.6 154.8 2015 December 31, 2015 February 9, 2016 $ 200.4 $ 61.4 September 30, 2015 November 13, 2015 200.4 61.4 June 30, 2015 August 14, 2015 200.4 61.4 March 31, 2015 May 15, 2015 193.9 59.0 2014 December 31, 2014 February 13, 2015 $ 137.4 $ 51.6 September 30, 2014 November 14, 2014 130.9 48.9 June 30, 2014 August 14, 2014 125.7 46.3 March 31, 2014 May 15, 2014 121.3 44.0 Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDRs of $9.375 million were reallocated to common unitholders for each of the four quarters of 2015. The IDR Giveback Amendment covered sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015. The IDR Giveback resulted in reallocation of IDR payments to common unitholders of $6.25 million for each of the first three quarters of 2016. On October 19, 2016, we executed the Third A&R Partnership Agreement, which became effective on December 1, 2016. The Third A&R Partnership Agreement amendments include among other things (i) eliminating the IDRs held by the general partner, and related distribution and allocation provisions, (ii) eliminating the Special GP Interest (as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the ability to declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v) eliminating the Class B Unit provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisions that are no longer applicable. As a result of the Third A&R Partnership Agreement, the reallocations of IDRs under the IDR Giveback Amendment ceased in the fourth quarter of 2016. On December 1, 2016, we issued to the General Partner (i) 20,380,286 common units and 424,590 General Partner units in exchange for the elimination of the IDRs and (ii) 11,267,485 common units and 234,739 General Partner units in exchange for the elimination of the Special GP Interest in connection with the Third A&R Partnership Agreement. Contributions During 2016, Targa made total capital contributions to us of $1,381.0 million. 58,621,036 common units and 1,196,346 general partner units were issued for Targa’s contributions of $1,191.0 million. Subsequent to the effective date of the Third A&R Partnership Agreement, no units will be issued for capital contributions but all capital contributions will continue to be allocated 98% to the limited partner and 2% to the general partner. In December 2016, Targa made a $190.0 million capital contribution to us which was allocated accordingly. Preferred Units In October 2015, under the April 2013 Shelf, we completed an offering of 4,400,000 Preferred Units at a price of $25.00 per unit. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 600,000 Preferred Units at a price of $25.00 per unit. We received net proceeds after costs of approximately $121.1 million. We used the net proceeds from this offering to reduce borrowings under our senior secured credit facility and for general partnership purposes. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.” Distributions on our 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on our Preferred Units are payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on our Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. The Preferred Units, with respect to anticipated monthly distributions, rank: • senior to our common units and to each other class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is not expressly made senior to or pari passu with the Preferred Units as to the payment of distributions; • pari passu with any class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is not expressly made senior or subordinated to the Preferred Units as to the payment of distributions; • junior to all of our existing and future indebtedness (including (i) indebtedness outstanding under the TRP Revolver, (ii) our senior notes and (iii) indebtedness outstanding under the Securitization Facility and other liabilities with respect to assets available to satisfy claims against us; and • junior to each other class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is expressly made senior to the Preferred Units as to the payment of distributions. At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. If we do not (or a third party with our prior written consent does not) exercise this option, then the holders of the Preferred Units (“Preferred Unitholders”) have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our Partnership Agreement. If we exercise (or a third party with our prior written consent exercises) our redemption rights relating to any Preferred Units, the holders of those Preferred Units will not have the conversion right described above with respect to the Preferred Units called for redemption. Holders of Preferred Units have no voting rights except for certain exceptions set forth in our Partnership Agreement. As of December 31, 2016, we have 5,000,000 Preferred Units outstanding. We paid $11.3 million and $1.5 million of distributions to the holders of preferred units (“Preferred Unitholders”) during 2016 and 2015. The Preferred Units are reported as noncontrolling interests in our financial statements. In January and February 2017, the board of directors of our general partner declared a cash distribution of $0.9 million each month for $0.1875 per Preferred Unit. The distributions declared in January were paid on February 15, 2017 and the distributions declared in February will be paid on March 15, 2017. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Note 13 — Derivative Instruments and Hedging Activities The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Gathering and Processing segment that result from percent-of-proceeds processing arrangements. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flow hedges for accounting purposes. The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations. We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes. As part of the Atlas mergers, outstanding APL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to us and included in the acquisition date fair value of assets acquired. We received derivative settlements of $26.6 million for the year ended December 31, 2016, and $67.9 million for the year ended December 31, 2015, related to these novated contracts. These settlements were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired and had no effect on results of operations. The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Additionally, we recorded ineffectiveness losses of $0.9 million for the year ended December 31, 2015, related to otherwise qualifying APL derivatives, which are primarily natural gas swaps. There were no ineffectiveness losses on these derivatives for the year ended December 31, 2016. We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cash settlements to revenues. At December 31, 2016, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2017 2018 2019 Natural Gas Swaps MMBtu/d 133,448 84,800 45,683 Natural Gas Basis Swaps MMBtu/d 72,219 - - Natural Gas Options MMBtu/d 22,900 9,486 - NGL Swaps Bbl/d 9,635 4,688 3,369 NGL Futures Bbl/d 6,118 959 - NGL Options Bbl/d 1,468 1,676 - Condensate Swaps Bbl/d 2,270 1,770 643 Condensate Options Bbl/d 1,380 691 590 Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of December 31, 2016 Fair Value as of December 31, 2015 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 16.7 $ 48.6 $ 92.1 $ 2.1 Long-term 5.1 26.1 34.9 2.4 Total derivatives designated as hedging instruments $ 21.8 $ 74.7 $ 127.0 $ 4.5 Derivatives not designated as hedging instruments Commodity contracts Current $ 0.1 $ 0.5 $ 0.1 $ 3.1 Total derivatives not designated as hedging instruments $ 0.1 $ 0.5 $ 0.1 $ 3.1 Total current position $ 16.8 $ 49.1 $ 92.2 $ 5.2 Total long-term position 5.1 26.1 34.9 2.4 Total derivatives $ 21.9 $ 75.2 $ 127.1 $ 7.6 The pro forma impact of reporting derivatives in our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro forma net presentation December 31, 2016 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 16.8 $ (46.1 ) $ 7.0 $ 5.7 $ (28.0 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (3.0 ) - - (3.0 ) 16.8 (49.1 ) 7.0 5.7 (31.0 ) Long Term Position Counterparties with offsetting positions or collateral 5.1 (18.7 ) - - (13.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.4 ) - - (7.4 ) 5.1 (26.1 ) - (21.0 ) Total Derivatives Counterparties with offsetting positions or collateral 21.9 (64.8 ) 7.0 5.7 (41.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (10.4 ) - - (10.4 ) $ 21.9 $ (75.2 ) $ 7.0 $ 5.7 $ (52.0 ) Gross Presentation Pro forma net presentation December 31, 2015 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 86.9 $ (5.2 ) $ - $ 81.7 $ - Counterparties without offsetting positions - assets 5.3 - - 5.3 - Counterparties without offsetting positions - liabilities - - - - - 92.2 (5.2 ) - 87.0 - Long Term Position Counterparties with offsetting positions or collateral 34.2 (2.4 ) - 31.8 - Counterparties without offsetting positions - assets 0.7 - - 0.7 - Counterparties without offsetting positions - liabilities - - - - - 34.9 (2.4 ) 32.5 - Total Derivatives Counterparties with offsetting positions or collateral 121.1 (7.6 ) - 113.5 - Counterparties without offsetting positions - assets 6.0 - - 6.0 - Counterparties without offsetting positions - liabilities - - - - - $ 127.1 $ (7.6 ) $ - $ 119.5 $ - Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Some of our hedges are futures contracts executed through a broker that clears the hedges through an exchange. We maintain a margin deposit with the broker in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within other current assets on our Consolidated Balance Sheets and is not offset against the fair values of our derivative instruments. The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of $53.3 million as of December 31, 2016. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment. The following tables reflect amounts recorded in Other Comprehensive Income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated: Derivatives in Cash Flow Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Hedging Relationships 2016 2015 2014 Commodity contracts $ (103.6 ) $ 112.7 $ 59.7 Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2016 2015 2014 Interest expense, net $ — $ — $ (2.4 ) Revenues 45.0 86.3 (4.2 ) $ 45.0 $ 86.3 $ (6.6 ) Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. Derivatives Not Designated Location of Gain Recognized in Gain (Loss) Recognized in Income on Derivatives as Hedging Instruments Income on Derivatives 2016 2015 2014 Commodity contracts Revenue $ 0.9 $ (5.7 ) $ (5.5 ) Based on valuations as of December 31, 2016, we expect to reclassify commodity hedge related deferred losses of $60.7 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2019, with $39.7 million to be reclassified over the next twelve months. See Note 14 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 14 — Fair Value Measurements Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments. Fair Value of Derivative Financial Instruments Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold. The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at December 31, 2016, a net liability position of $53.3 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $107.4 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $14.9 million, ignoring an adjustment for counterparty credit risk. Fair Value of Other Financial Instruments Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows: • The TRP Revolver and the Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and • Senior unsecured notes are based on quoted market prices derived from trades of the debt. We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value. See Note 4 – Business Acquisitions. Fair Value Hierarchy We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value: • Level 1 – observable inputs such as quoted prices in active markets; • Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and • Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions. The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: December 31, 2016 Fair Value Carrying Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 21.0 $ 21.0 $ — $ 19.6 $ 1.4 Liabilities from commodity derivative contracts (1) 74.2 74.2 — 69.3 4.9 TPL contingent consideration (2) 2.6 2.6 — — 2.6 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 68.0 68.0 — — — TRP Revolver 150.0 150.0 — 150.0 — Senior unsecured notes 4,057.3 4,101.6 — 4,101.6 — Accounts receivable securitization facility 275.0 275.0 — 275.0 — December 31, 2015 Fair Value Carrying Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 127.1 $ 127.1 $ — $ 123.1 $ 4.0 Liabilities from commodity derivative contracts (1) 7.6 7.6 — 7.3 0.3 TPL contingent consideration (2) 3.0 3.0 — — 3.0 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 135.4 135.4 — — — TRP Revolver 280.0 280.0 — 280.0 — Senior unsecured notes 4,884.0 4,192.0 — 4,192.0 — Accounts receivable securitization facility 219.3 219.3 — 219.3 — (1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes. (2) See Note 4 – Business Acquisitions. Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable implied volatilities or market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods. The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available. As of December 31, 2016, we had 17 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial. The fair value of the contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. These probability-based inputs are not observable; therefore, the entire valuation of the contingent consideration is categorized in Level 3. Changes in the fair value of this liability are included in Other Income on the Consolidated Statements of Operations. The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts Contingent Asset/(Liability) Liability Balance, December 31, 2015 $ 3.7 $ (3.0 ) Change in fair value of TPL contingent consideration - 0.4 New Level 3 instruments 0.9 - Settlements included in Revenue 0.2 - Unrealized gain/(loss) included in OCI (8.4 ) - Balance, December 31, 2016 $ (3.6 ) $ (2.6 ) For the year ended December 31, 2016, we had no transfers of financial instruments out of Level 3 and into Level 2. Historically, transfers relate to long-term over-the-counter swaps for natural gas and NGL products for which observable market prices became available for substantially their full term. |
Related Party Transactions - Ta
Related Party Transactions - Targa | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions - Targa | Note 15 — Related Party Transactions - Targa Relationship with Targa We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay. The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable. Year Ended December 31, 2016 2015 2014 Targa billings of payroll and related costs included in operating expense $ 171.8 $ 153.8 $ 124.9 Targa allocation of general and administrative expense 159.9 136.2 129.4 Cash distributions to Targa based on IDR, GP and common unit ownership 587.0 233.4 180.7 Cash contributions from Targa related to limited partner ownership (1) 1,353.4 — — Cash contributions from Targa to maintain its 2% general partner ownership 27.6 60.1 7.7 (1) Of the cash contributions from Targa related to limited partner ownership, $1,167.2 million was contributed for the issuance of common units and $186.2 million was contributed after the Third A&R Partnership Agreement. Transactions with Unconsolidated Affiliates For the years ended December 31, 2016, 2015 and 2014, transactions with GCF included in revenues were $0.4 million, $0.5 million and $0.8 million. For the same periods, transactions with GCF included in costs and expenses were $3.2 million, $5.8 million and $7.6 million. The Partnership is subject to paying a deficiency fee in instances where the Partnership does not deliver its minimum volume requirements as outlined in the Partnership and fractionation agreements with GCF. We engage in the purchase and sale of residue gas and condensate with the T2 Joint Ventures. Revenue attributable to sales to T2 Eagle Ford and T2 Cogen were $4.6 million and $0.6 million for the year ended December 31, 2016 and $4.4 million and $1.4 million for the year ended December 31, 2015. Cost of sales attributable to T2 Eagle Ford were $2.6 million and $4.0 million for the years ended December 31, 2016 and 2015. Capacity lease fees paid to T2 Eagle Ford and T2 LaSalle and included in operating expenses were $3.2 million and $0.8 million for the year ended December 31, 2016 and $3.0 million and $1.3 million for the year ended December 31, 2015. These fees are billed to us based on our portion of the cost to operate each respective joint venture. As a result of this activity, we had a receivable balance with T2 Eagle Ford of $0.2 million and $0.4 million at December 31, 2016 and 2015 as well as a receivable balance with T2 Cogen of $0.1 million at December 31, 2015. |
Commitments (Leases)
Commitments (Leases) | 12 Months Ended |
Dec. 31, 2016 | |
Leases [Abstract] | |
Commitments (Leases) | Note 16 — Commitments (Leases) Future lease obligations are presented below in aggregate and for each of the next five fiscal years: In Aggregate 2017 2018 2019 2020 2021 Operating leases (1) $ 35.6 $ 14.6 $ 10.1 $ 5.2 $ 3.6 $ 2.1 Land site lease and right-of-way (2) 14.2 3.2 2.8 2.8 2.7 2.7 $ 49.8 $ 17.8 $ 12.9 $ 8.0 $ 6.3 $ 4.8 (1) Includes minimum payments on lease obligations for office space, railcars and tractors. (2) Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual. Total expenses incurred under the above lease obligations , including short-term leases of compressors and equipment, 2016 2015 2014 Operating leases (1) $ 45.1 $ 42.4 $ 24.4 Land site lease and right-of-way 4.4 4.2 4.1 $ 49.5 $ 46.6 $ 28.5 (1) Includes short-term leases for items such as compressors and equipment. |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Loss Contingency [Abstract] | |
Contingencies | Note 17 – Contingencies Legal Proceedings Litigation related to TRC/TRP Merger On December 16, 2015, two purported unitholders of TRP (the “State Court Plaintiffs”) filed a putative class action and derivative lawsuit challenging the TRC/TRP Merger against TRC, TRP (as a nominal defendant), TRP GP, the members of the board of TRP GP (the “TRP GP Board”) and Merger Sub (collectively, the “State Court Defendants”). This lawsuit was styled Leslie Blumberg et al. v. TRC Resources Corp., et al. th The State Court Plaintiffs alleged several causes of action challenging the TRC/TRP Merger. Generally, the State Court Plaintiffs alleged that (i) the members of the TRP GP Board breached express and/or implied duties under the Partnership Agreement and (ii) TRC, TRP GP, and Merger Sub aided and abetted in these alleged breaches of duties. The State Court Plaintiffs further alleged, in general, that (a) the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair, (e) the TRP GP Board had conflicts of interest due to TRC’s control of TRP GP, (f) the TRP GP Conflicts Committee’s financial advisor was conflicted and conducted flawed analyses, and (g) the joint proxy statement/prospectus filed in connection with the TRC/TRP Merger (the “Proxy”) failed to disclose allegedly material information concerning, among other things, (i) the TRC and TRP projections included in the Proxy, and (ii) the analyses conducted by the TRP GP Conflicts Committee’s financial advisor in connection with the TRC/TRP Merger. Based on these allegations, the State Court Plaintiffs sought damages and attorneys’ fees. On February 26 and 29, 2016, the State Court Defendants filed general denials and asserted affirmative defenses. On August 26, 2016, the State Court Defendants filed Special Exceptions and a Motion for Summary Judgment. On December 5, 2016, the Court granted Defendants’ Motion for Summary Judgment and dismissed the State Court Lawsuit in its entirety with prejudice. Environmental Proceedings On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014. The Monument Gas Plant is owned by Versado Gas Processors, L.L.C., which was a joint venture in which we owned a 63% interest until October 31, 2016, when we acquired the remaining 37% membership interest from Chevron U.S.A Inc. The Partnership has been in discussions with the New Mexico Environment Department to resolve the alleged violations. The New Mexico Environment Department has offered to settle the matter for $29,223. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. |
Significant Risks and Uncertain
Significant Risks and Uncertainties | 12 Months Ended |
Dec. 31, 2016 | |
Risks And Uncertainties [Abstract] | |
Significant Risks and Uncertainties | Note 18 — Significant Risks and Uncertainties Nature of Our Operations in Midstream Energy Industry We operate in the midstream energy industry. Our business activities include gathering, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products and changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. Our profitability could be impacted by a decline in the volume of crude oil, natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration and development activities, or otherwise, could result in a decline in the volume of crude oil, natural gas, NGLs and condensate handled by our facilities. A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position. Our principal market risks are exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, and changes in interest rates. Commodity Price Risk A significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes as payment for services. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. In response to these price risks, we monitor NGL inventory levels in order to mitigate losses related to downward price exposure. In an effort to reduce the variability of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes and future commodity purchases and sales through 2019. Historically, these transactions have included both swaps and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We hedge a higher percentage of our expected equity volumes in the earlier future periods. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGLs and pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. Counterparty Risk – Credit and Concentration Derivative Counterparty Risk Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties. We have master netting provisions in the International Swap Dealers Association agreements with all of our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties, which reduced our maximum loss due to counterparty credit risk by $21.9 million as of December 31, 2016. The range of losses attributable to our individual counterparties would be between $1.3 million and $3.8 million, depending on the counterparty in default. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value, representing expected future receipts, at the reporting date. At such times, these outstanding instruments expose us to losses in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. Customer Credit Risk We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met. Our allowance for doubtful accounts was $0.9 million as of December 31, 2016 and $0.1 million as of December 31, 2015. Significant Commercial Relationship During the years ended December 31, 2016, 2015 and 2014, we did not have any commercial relationships that exceeded 10% of consolidated revenues. During the year ended December 31, 2016, ONEOK Hydrocarbon L.P. and DCP NGL Services LLC each accounted for 11% of our consolidated product purchases. During the year ended December 31, 2015, ONEOK Hydrocarbon L.P. accounted for 12% of our consolidated product purchases. During the year ended December 31, 2014, we did not have any suppliers that exceeded 10% of our consolidated product purchases. Interest Rate Risk We are exposed to changes in interest rates, primarily as a result of our variable rate borrowings under the TRP Revolver and Securitization Facility. Casualty or Other Risks Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverage which is customary for the nature and scope of our operations. The majority of the insurance costs described above is allocated to us by Targa through the Partnership Agreement described in Note 15 – Related Party Transactions. Management believes that Targa has adequate insurance coverage, although insurance may not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles may change overtime, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Targa may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations. Furthermore, even when a business interruption event is covered, it could affect interperiod results as we would not recognize the contingent gain until realized in a period following the incident. |
Other Operating (Income) Expens
Other Operating (Income) Expense | 12 Months Ended |
Dec. 31, 2016 | |
Other Income And Expenses [Abstract] | |
Other Operating (Income) Expense | Note 19 — Other Operating (Income) Expense Other Operating (Income) Expense is comprised of the following: 2016 2015 2014 (Gain) loss on sale or disposal of assets $ 6.1 $ (8.0 ) $ (4.8 ) Casualty (gain) loss - (0.2 ) 0.1 Miscellaneous business tax 0.5 0.5 0.4 Other - 0.6 1.3 $ 6.6 $ (7.1 ) $ (3.0 ) |
Income Tax
Income Tax | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Tax | Note 20 – Income Tax 2016 2015 2014 Current expense $ - $ 0.8 $ 3.2 Deferred expense (benefit) (0.3 ) (0.2 ) 1.6 Total income tax expense (benefit) $ (0.3 ) $ 0.6 $ 4.8 Prior to the TRC/TRP Merger, the Partnership was subject to the Texas margin tax, consisting generally of a 0.75% tax on the amounts by which total revenues exceed cost of goods sold, as apportioned to Texas. After the TRC/TRP Merger, TRC is the reporting company for the combined group. The Partnership still has audit responsibility for the pre-Merger years. As part of the APL merger in 2015, we acquired TPL Arkoma, Inc., a corporate subsidiary subject to federal and state income tax. Our corporate subsidiary accounts for income taxes under the asset and liability method and provides deferred income taxes for all significant temporary differences. Our deferred income tax assets and liabilities at December 31, 2016 and 2015, consisted of differences related to the timing of recognition of certain types of costs as follows: 2016 2015 Deferred tax assets: Net operating loss carryforwards $ 19.8 $ 19.8 Deferred tax liabilities: Property, plant, and equipment (46.7 ) (47.0 ) Net deferred tax asset (liability) $ (26.9 ) $ (27.2 ) As of December 31, 2016, TPL Arkoma, Inc. had net operating loss carry forwards for federal income tax purposes of approximately $51.3 million, which expire at various dates from 2029 to 2036. Management believes it more likely than not that the deferred tax asset will be fully utilized. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Note 21 — Supplemental Cash Flow Information 2016 2015 2014 Cash: Interest paid, net of capitalized interest (1) $ 263.8 $ 193.1 $ 131.0 Income taxes paid, net of refunds 1.3 3.4 2.7 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 17.4 $ 1.2 $ 14.8 Impact of capital expenditure accruals on property, plant and equipment 27.6 43.8 19.0 Transfers from materials and supplies inventory to property, plant and equipment 2.4 3.7 4.6 Change in ARO liability and property, plant and equipment due to revised cash flow estimate (9.1 ) 3.8 2.1 Deferred revenue related to property, plant and equipment received under contract amendment — 22.6 — Non-cash financing activities: Debt additions and retirements related to exchange of TRP 6⅝% Notes for 6⅝% TPL Notes $ — $ 342.1 $ — Cancellation of treasury units 10.4 — Accrued distributions on unvested equity awards under share compensation arrangements 0.2 1.6 1.4 Receivables from equity issuances — — 1.0 Change of accrued distributions of preferred units — 0.9 — Exchange of IDRs and Special GP interest for units 903.6 — — Non-cash balance sheet movements related to the purchase of noncontrolling interests in subsidiary (see Note 4 - Business Acquisitions): Common limited partner units 63.7 — — General partner units 1.3 — — Noncontrolling interests (65.0 ) — — Non-cash balance sheet movements related to the Atlas Merger (See Note 4 - Business Acquisitions): Non-cash merger consideration - common units and replacement equity awards $ — $ 2,583.5 $ — Special GP Interest — 1,612.4 — Current liabilities retained by Targa — (0.4 ) — Net non-cash balance sheet movements excluded from consolidated statements of cash flows — 4,195.5 — Net cash merger consideration included in investing activities — 828.7 Total fair value of consideration transferred $ — $ 5,024.2 $ — _____________ (1) Interest capitalized on major projects was $8.3 million, $13.2 million and $16.1 million for 2016, 2015 and 2014. |
Compensation Plans
Compensation Plans | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Compensation Plans | Note 22 — Compensation Plans TRC Equity Compensation Plan In 2007, both we and Targa adopted Long-Term Incentive Plans (each, an “LTIP”) for employees, consultants, directors and non-employee directors of us and our affiliates who perform services for Targa or its affiliates. The awards under this plan included performance units, phantom units and director grants. Our LTIP (“TRP LTIP”) provided for, among other things, the grant of both cash-settled and equity-settled performance units. In connection with the TRC/TRP Merger, as of February 17, 2016, Targa assumed, adopted, and amended the TRP LTIP, and changed the name of the plan to the Targa Resources Corp. Equity Compensation Plan (as assumed, adopted and amended, the “TRC Equity Compensation Plan” or the “Plan”), and Targa assumed all our obligations associated with the Plan existing prior to the assumption and adoption by us. The TRC Equity Compensation Plan allows for the grant of options, performance shares, restricted stocks, replacement stocks and other stock-based awards. The termination date for this plan was February 7, 2017. Performance Units The performance units granted under the TRP LTIP were linked to the performance of our common units. Performance unit awards granted under either LTIP may also include distribution equivalent rights (“DERs”). The TRP LTIP was administered by the board of directors of the general part of TRP. Total units authorized under the TRP LTIP were 1,680,000. Each performance unit entitled the grantee to the value of our common unit on the vesting date multiplied by a stipulated vesting percentage determined from our ranking in a defined peer group. The performance period for most awards was three years, except for certain awards granted in December 2013, which provided for two, three or four-year vesting periods. The grantee received the vested unit value in cash or common units depending on the terms of the grant. The grantee may also be entitled to the value of any DERs based on the notional distributions accumulated during the vesting period times the vesting percentage. DERs were paid for both cash-settled and equity-settled performance units. Compensation cost for equity-settled performance units was recognized as an expense over the performance period based on fair value at the grant date. Fair value was calculated using a simulated unit price that incorporates peer ranking. DERs associated with equity-settled performance units were accrued over the performance period as a reduction of owners’ equity. We evaluated the grant date fair value using a Monte Carlo simulation model and historical volatility assumption to estimate accruals throughout the vesting period. The weighted average grant date fair value of TRP LTIP performance units granted in 2015 and 2014, were $34.48 and $57.19. Phantom Units In 2015, we granted phantom units under the LTIP to various employees of Targa. These phantom units were denominated with respect to our common units, but not otherwise linked to the performance of our common units. Their vesting periods vary from one year to five years. The DERs of the phantom units were accumulated to be paid in cash at vesting date. In 2015, the Partnership issued 25,162 phantom units with a weighted average grant date fair value of $36.87. Replacement Phantom Units In connection with the APL merger in 2015, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees upon close of the acquisition. The vesting dates and terms remained unchanged from the existing APL awards, and will vest either 25% per year over the original four-year term or 33% per year over the original three-year term. The DERs of the replacement phantom units are paid in cash within 60 days of the payment of distributions. A total of 629,231 replacement phantom unit were granted in 2015 with the weighted average grant date fair value of $43.82. Partnership Director Grants Starting in 2012, the common units granted to our non-management directors vested immediately at the grant date. The weighted average grant date fair values of the director grants granted in 2016, 2015 and 2014 were $10.11, $44.67 and $50.29. The fair values related to the units vested were $0.3 million, $0.5 million and $0.4 million. Impact of TRC/TRP Merger The TRC/TRP Merger did not trigger the acceleration of any time-based vesting of any of our outstanding long-term equity incentive compensation awards under the TRP LTIP. All outstanding performance unit awards previously granted under the TRP LTIP were converted and restated into comparable awards based on Targa’s common shares. Specifically, each outstanding performance unit award was converted and restated, effective as of the effective time of the TRC/TRP Merger, into an award to acquire, pursuant to the same time-based vesting schedule and forfeiture and termination provisions, a comparable number of Targa common shares determined by multiplying the number of performance units subject to each award by the exchange ratio in the TRC/TRP Merger (0.62), rounded down to the nearest whole share, and the performance factor was eliminated. At the time of the TRC/TRP Merger and immediately prior to the assumption and adoption of the Plan, the only outstanding awards under the TRP LTIP were-equity settled performance units and certain phantom units of us. All such outstanding awards were converted into comparable time-based restricted unit awards (RSUs) based on Targa’s common stock. All amounts previously credited as distribution equivalent rights under any outstanding performance unit award continue to remain so credited and will be payable on the payment date set forth in the applicable award agreement, subject to the same time-based vesting schedule previously included in the performance unit award, but without application of any performance factor. The February 17, 2016 conversion of 675,745 equity-settled performance units and 349,541 replacement phantom units outstanding to 418,906 equity-settled performance shares and 216,561 replacement phantom shares was considered modification of awards under ASC 718, Accounting for Stock-Based Compensation In 2016 Targa issued 331,282 restricted stock units under the Plan which will cliff vest three years from the grant date. Of these 2016 grants, 310,809 RSUs were made in lieu of cash bonus for Targa’s non executives. The following table summarizes the restricted stock units for the year ended 2016 under the Plan: Restricted Stock Units Number Weighted-average of shares Grant-Date Fair Value Outstanding as of December 31, 2015 - $ - Converted 635,467 73.68 Granted 331,282 74.01 Forfeited (20,485 ) 26.38 Vested (245,862 ) 62.23 Outstanding as of December 31, 2016 700,402 51.52 TRC Long Term Incentive Plan The TRC LTIP is administered by the compensation committee (the “Committee”) of the Targa board of directors. Prior to the TRC/TRP Merger, the TRC LTIP provided for the grant of cash-settled performance units only. In connection with the TRC/TRP Merger, performance unit grant agreements were amended to convert TRP’s outstanding cash-settled performance unit obligation to cash-settled restricted stock units. On February 17, 2016, as a result of the TRC/TRP Merger, 451,990 of TRP’s outstanding cash-settled performance units were converted to 279,964 cash-settled restricted stock units under the TRC LTIP with performance factors eliminated. All amounts previously credited as distribution equivalent rights under any outstanding performance unit award continue to remain so credited and will be payable on the payment date set forth in the applicable award agreement, subject to the same time-based vesting schedule previously included in the performance unit award, but without application of any performance factor. The February 17, 2016 conversion of outstanding cash-settled performance units to cash-settled restricted stock units was considered modification of awards under ASC 718. The incremental change in fair value between the original grant date fair value and the fair value as of February 17, 2016 resulted in recognition of additional compensation costs during the first quarter of 2016 of $4.8 million. Compensation expense for cash-settled performance units and any related DERs will ultimately be equal to the cash paid to the grantee upon vesting. However, throughout the vesting period Targa must record an accrued expense based on fair value of the stock on the last business day of the quarter. The following table summarizes the cash-settled restricted stock units for the year ended 2016 under the TRC LTIP (in shares and millions of dollars). Program Year 2013 Awards 2014 Awards 2015 Awards Total Outstanding as of December 31, 2015 139,700 119,900 192,390 451,990 After conversion on February 17, 2016 86,538 74,248 119,178 279,964 Vested and paid (85,492 ) (85,492 ) Forfeited (1,046 ) (1,269 ) (2,862 ) (5,177 ) Outstanding as of December 31, 2016 — 72,979 116,316 189,295 Calculated fair market value as of December 31, 2016 $ 4,992,974 $ 7,355,790 $ 12,348,763 Current liability $ 4,143,373 $ - $ 4,143,373 Long-term liability - 3,565,135 3,565,135 Liability as of December 31, 2016 $ 4,143,373 $ 3,565,135 $ 7,708,508 To be recognized in future periods $ 849,601 $ 3,790,655 $ 4,640,255 Vesting date June 2017 June 2018 The cash settled for the awards under TRC LTIP were $4.8 million, $7.8 million and $14.7 million for 2016, 2015 and 2014. The remaining weighted average recognition period for the unrecognized compensation cost is approximately 1.3 years. 2010 TRC Stock Incentive Plan In December 2010, Targa adopted the Targa Resources Corp. 2010 Stock Incentive Plan (“2010 TRC Plan”) for employees, consultants and non-employee directors of the Company. The 2010 TRC Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as incentive options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock awards (“Phantom Stock Awards”), (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards (collectively referred to a “Awards”). Restricted Stock Awards - Total shares of our common stock authorized under this plan are 5,000,000. Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends, and paid in cash when the award vests. The restricted stock awards will be included in the outstanding shares of our common stock upon issuance. Restricted Stock in Lieu of Salary –During 2016, Targa issued on a quarterly basis, a total of 32,267 shares of restricted stock to two of our executives in lieu of all of their 2016 base salary. These awards vest one year from the date of each grant. The weighted average grant-date fair value of these shares of restricted stock was $41.43. The number of shares of restricted stock awarded was determined by dividing one-fourth of the officer’s annual base salary by the average closing price of the shares of common stock for five trading days before the end of each quarter. Restricted Stock in Lieu of Bonus – During 2016, Targa issued 153,252 shares of restricted stock awards in lieu of cash bonus for its executives at the weighted average grant-date fair value of $26.34. These awards will cliff vest in three years. Director Grants – The committee awarded Targa’s common stock to its outside directors. In 2016, 2015 and 2014, Targa issued 24,234, 6,429 and 5,165 shares of director grants with the weighted average grant-date fair value of $16.45, $86.49 and $87.45. Restricted Stock Units Awards – RSUs are similar to restricted stock, except that shares of common stock are not issued until the RSUs vest. The vesting periods vary from one year to five years. In 2016, 2015 and 2014, Targa issued 1,129,705, 140,477 and 54,357 shares of RSUs with the weighted average grant-date fair value of $27.87, $83.54 and $112.89. The following table summarizes the restricted stock and RSUs under the 2010 TRC Plan in shares and in dollars for the year indicated. Number Weighted Average of shares Grant-Date Fair Value Outstanding at December 31, 2015 313,362 85.70 Granted 1,186,206 28.00 Forfeited (14,989 ) 75.17 Vested (116,329 ) 58.55 Outstanding at December 31, 2016 1,368,250 $ 38.10 Stock compensation expense under Targa’s plans totaled $41.2 million, $22.8 million, and $25.4 million for the years ended December 31, 2016, 2015, and 2014. As of December 31, 2016, Targa has $44.8 million of unrecognized compensation expenses associated with share-based awards and approximate remaining weighted average vesting periods of 2.3 years related to our various compensation plans. The fair values of share-based awards vested in 2016, 2015 and 2014 were $19.8, $31.8 million and $20.1 million. Targa Pursuant to ASU 2016-09, tax benefits of dividends on share-based payment awards should be recognized as income tax benefits or expenses in the income statement. Targa adopted the applicable amendments in the second quarter of 2016 and recognized a $0.5 million tax deficiency as an income tax expense for the year ended 2016. See Note 2 – Basis of Presentation. Subsequent Events On January 14, 2017, 22,017 shares of restricted stock units granted on January 14, 2014 vested and Targa repurchased 6,990 shares at $57.95 per share to satisfy the employee’s minimum statutory tax withholdings on the vested awards. In January 2017, the Committee made following awards under the 2010 TRC Plan. • 13,818 shares of TRC’s common stock to our outside directors. • 114,301 shares of restricted stock units to executive management and employees for the 2017 compensation cycle that will cliff vest three years from the grant date. • 113,901 shares of performance share units to executive management and employees for the 2017 compensation cycle that will vest on December 31, 2019. • 491,000 shares of our restricted stock units to executive management and employees. The awards will vest 30% in January 2021, 30% in January 2020 and 40% in January 2023. The performance share units granted under the 2010 TRC Plan are three-year equity-settled awards linked to the performance of shares of our common stock. The awards also include dividend equivalent rights that are based on the notional dividends accumulated during the vesting period. The vesting of the performance share units is dependent on the satisfaction of a combination of certain service-related conditions and the Company’s total shareholder return (“TSR”) relative to the TSR of the members of a specified comparator group of publicly-traded midstream companies (the “LTIP Peer Group”) measured over designated periods. The TSR performance factor is determined by the Committee at the end of the overall performance period based on relative performance over the designated weighting periods as follows: (i) 25% based on annual relative TSR for the first year; (ii) 25% based on annual relative TSR for the second year; (iii) 25% based on annual relative TSR for the third year; and (iv) the remaining 25% based on cumulative three year relative TSR over the entirety of the performance period. With respect to each weighting period, the Committee determines the “guideline performance percentage,” which could range from 0% to 250%, based upon the Company’s relative TSR performance for the applicable period. The TSR performance factor will be calculated by averaging the guideline performance percentage for each weighting period, and the average percentage may then be decreased or increased by the Committee at its discretion. The grantee will become vested in a number of performance share units equal the target number awarded multiplied by the TSR performance factor, and vested performance share units will be settled by the issuance of Company common stock. The value of dividend equivalent rights will be paid in cash. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Segment Information | Note 23 — Segment Information We operate in two primary segments (previously referred to as divisions): (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided. Concurrent with the completion of the TRC/TRP Merger in the first quarter of 2016, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of aggregation for our reportable segments. The increase in activity within Field Gathering and Processing due to the Atlas mergers in 2015 coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico. Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs. Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington. Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin. and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column. Reportable segment information is shown in the following tables: Year Ended December 31, 2016 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 621.9 $ 4,942.0 $ 62.9 $ — $ 5,626.8 Fees from midstream services 486.6 577.5 — — 1,064.1 1,108.5 5,519.5 62.9 — 6,690.9 Intersegment revenues Sales of commodities 2,124.4 251.5 — (2,375.9 ) — Fees from midstream services 7.8 23.5 — (31.3 ) — 2,132.2 275.0 — (2,407.2 ) — Revenues $ 3,240.7 $ 5,794.5 $ 62.9 $ (2,407.2 ) $ 6,690.9 Operating margin $ 577.1 $ 574.4 $ 62.9 $ — $ 1,214.4 Other financial information: Total assets (1) $ 9,800.6 $ 2,868.7 $ 21.8 $ 53.8 $ 12,744.9 Goodwill $ 210.0 $ — $ — $ — $ 210.0 Capital expenditures $ 402.5 $ 185.3 $ — $ 4.3 $ 592.1 (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Year Ended December 31, 2015 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 1,485.4 $ 3,895.8 $ 84.2 $ — $ 5,465.4 Fees from midstream services 427.1 766.1 — — 1,193.2 1,912.5 4,661.9 84.2 — 6,658.6 Intersegment revenues Sales of commodities 1,126.3 208.9 — (1,335.2 ) — Fees from midstream services 8.7 17.8 — (26.5 ) — 1,135.0 226.7 — (1,361.7 ) — Revenues $ 3,047.5 $ 4,888.6 $ 84.2 $ (1,361.7 ) $ 6,658.6 Operating margin $ 515.1 $ 681.7 $ 84.2 $ — $ 1,281.0 Other financial information: Total assets (1) $ 10,391.9 $ 2,567.1 $ 127.1 $ 40.7 $ 13,126.8 Goodwill $ 417.0 $ — $ — $ — $ 417.0 Capital expenditures $ 496.3 $ 272.0 $ — $ 8.9 $ 777.2 Business acquisition $ 5,024.2 $ — $ — $ — $ 5,024.2 (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Year Ended December 31, 2014 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 552.4 $ 7,050.8 $ (8.0 ) $ — $ 7,595.2 Fees from midstream services 224.7 796.6 — — 1,021.3 777.1 7,847.4 (8.0 ) — 8,616.5 Intersegment revenues Sales of commodities 2,068.8 339.3 — (2,408.1 ) — Fees from midstream services 5.2 28.5 — (33.7 ) — 2,074.0 367.8 — (2,441.8 ) — Revenues $ 2,851.1 $ 8,215.2 $ (8.0 ) $ (2,441.8 ) $ 8,616.5 Operating margin $ 449.9 $ 694.7 $ (8.0 ) $ — $ 1,136.6 Other financial information: Total assets (1) $ 3,776.2 $ 2,476.1 $ 60.2 $ 34.8 $ 6,347.3 Capital expenditures $ 437.1 $ 304.6 $ — $ 6.1 $ 747.8 (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. The following table shows our consolidated revenues by product and service for the periods presented: 2016 2015 2014 Sales of commodities: Natural gas $ 1,584.5 $ 1,578.6 $ 1,414.1 NGL 3,777.3 3,558.3 5,960.1 Condensate 133.9 142.4 134.3 Petroleum products 68.2 101.6 96.3 Derivative activities 62.9 84.5 (9.6 ) 5,626.8 5,465.4 7,595.2 Fees from midstream services: Fractionating and treating 126.2 209.0 208.9 Storage, terminaling, transportation and export 420.0 506.2 548.1 Gathering and processing 445.0 393.7 196.9 Other 72.9 84.3 67.4 1,064.1 1,193.2 1,021.3 Total revenues $ 6,690.9 $ 6,658.6 $ 8,616.5 The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: 2016 2015 2014 Reconciliation of operating margin to net income (loss): Operating margin $ 1,214.4 $ 1,281.0 $ 1,136.6 Depreciation and amortization expenses (757.7 ) (677.1 ) (346.5 ) General and administrative expenses (177.1 ) (153.6 ) (139.8 ) Goodwill impairment (207.0 ) (290.0 ) — Interest expense, net (233.5 ) (207.8 ) (143.8 ) Other, net (68.1 ) (11.2 ) 3.4 Income tax (expense) benefit 0.3 (0.6 ) (4.8 ) Net income (loss) $ (228.7 ) $ (59.3 ) $ 505.1 |
Selected Quarterly Financial Da
Selected Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2016 | |
Selected Quarterly Financial Information [Abstract] | |
Selected Quarterly Financial Data (Unaudited) | Note 24 — Selected Quarterly Financial Data (Unaudited) Our results of operations by quarter for the years ended December 31, 2016 and 2015 were as follows: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2016 Revenues $ 1,442.4 $ 1,583.6 $ 1,652.3 $ 2,012.6 $ 6,690.9 Gross margin 431.4 438.4 429.6 468.6 1,768.0 Income from operations (1)(2) 37.5 68.4 53.7 (93.6 ) 66.0 Net income (loss) 10.6 (4.9 ) (6.1 ) (228.3 ) (228.7 ) Net income (loss) attributable to limited partners (9.9 ) (37.9 ) (42.6 ) (233.7 ) (324.1 ) 2015 Revenues $ 1,679.7 $ 1,699.4 $ 1,632.1 $ 1,647.4 $ 6,658.6 Gross margin 421.1 471.3 468.8 459.8 1,821.0 Income (loss) from operations (3)(4) 140.6 114.8 117.3 (205.3 ) 167.4 Net income (loss) 77.8 53.3 53.3 (243.7 ) (59.3 ) Net income (loss) attributable to limited partners 30.3 1.2 3.6 (232.6 ) (197.5 ) (1) Includes an additional goodwill impairment of $24.0 million in the first quarter of 2016. See Note 7 – Goodwill. (2) Includes a goodwill impairment of $183.0 million in the fourth quarter of 2016. See Note 7 – Goodwill. (3) Includes $32.6 million of impairment losses in the fourth quarter of 2015. See Note 6 – Property, Plant and Equipment and Intangible Assets. (4) Includes a provisional goodwill impairment of $290.0 million in the fourth quarter of 2015. See Note 7 – Goodwill. |
Significant Accounting Polici32
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Consolidation Policy | Consolidation Policy Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests. We follow the equity method of accounting when we do not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing goodwill and long-lived assets for possible impairment, (4) estimating the useful lives of assets, (5) determining amounts to accrue for contingencies, guarantees and indemnifications and (6) estimating redemption value of mandatorily redeemable preferred interests. Actual results, therefore, could differ materially from estimated amounts. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. Checks outstanding at the end of a period are reclassified to accounts payable, as we extinguish liabilities when the creditor receives our payment and we are relieved of our obligation (which generally occurs when our bank honors that check). |
Comprehensive Income | Comprehensive Income Comprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as cash flow hedges. |
Allowance for Doubtful Accounts | Allowance for Doubtful Accounts Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required. |
Inventories | Inventories Our inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of cost or market using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are classified as Property, Plant and Equipment. Inventories also include materials and supplies required for our Badlands expansion activities in North Dakota, which are valued at cost using the specific identification method. |
Product Exchanges | Product Exchanges Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities. |
Gas Processing Imbalances | Gas Processing Imbalances Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs. |
Derivative Instruments | Derivative Instruments We utilize derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which under GAAP, are not accounted for as derivatives. As a result, the revenues and expenses associated with such contracts are recognized during the period when volumes are physically delivered or received. If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense. If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss resulting from the change in fair value on the derivative is recognized currently in earnings as a component of revenues. We formally document all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the gain or loss related to the change in fair value to earnings in the current period. We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately. For balance sheet classification purposes, we analyze the fair values of the derivative instruments on a contract by contract basis and report the related fair values and any related collateral by counterparty on a gross basis. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment are stated at acquisition value less accumulated depreciation. All of our property, plant and equipment purchased from Targa from 2007 to 2010 in drop-down transactions were stated at historical cost in the transactions recorded under common control accounting. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination 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. The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset (asset group) with the asset’s (asset group’s) expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize increased depreciation expense equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of additional depreciation expense due to impairment. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations. |
Goodwill | Goodwill Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Goodwill must be assigned to reporting units for the purpose of impairment testing. A reporting unit is an operating segment or one level below an operating segment (also known as a component). Our annual goodwill impairment test is performed as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not that the fair value of the reporting unit is less than the carrying amount. Prior to us conducting the goodwill impairment test, to the extent triggering events exist, we complete a review of the carrying values of our long-lived assets, including property, plant and equipment and other intangible assets, and if it is determined that the carrying values are not recoverable, we reduce the carrying values of the long-lived assets pursuant to our policy on property, plant and equipment. The annual goodwill impairment test typically entails performing a two-step goodwill impairment test. However, we are permitted to first assess qualitative factors to determine if the two-step goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or otherwise determine that a two-step goodwill impairment test is required, the first step involves comparing the estimated fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of a reporting unit exceeds its fair value, the second step is required and involves comparing the implied fair value of goodwill to the carrying value of goodwill for that reporting unit. The implied fair value of goodwill is determined by assigning the reporting unit’s fair value to its individual assets and liabilities. If the carrying value of goodwill assigned to a reporting unit exceeds the implied fair value of goodwill, the excess of the carrying value over the implied fair value is recognized as a goodwill impairment loss on our Consolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets. |
Intangible Assets | Intangible Assets Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with business acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Amortization expense attributable to these assets is recorded on a straight-line basis or, where more appropriate, in a manner that closely resembles the expected pattern in which we benefit from services provided to customers. |
Asset Retirement Obligations | Asset Retirement Obligations We record the fair value of estimated asset retirement obligations (“AROs”) associated with tangible long-lived assets. Retirement obligations associated with long-lived assets are recognized for those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction. These obligations, which are estimated based on discounted cash flow estimates, are accreted to full value over time as a period cost. In addition, asset retirement costs are capitalized as part of the related asset’s carrying value and are depreciated over the asset’s respective useful life. At least annually, we review the projected timing and amount of asset retirement obligations. Changes resulting from revisions to the timing or the amount of the undiscounted cash flows are recognized as an increase or decrease in the carrying amount of the retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. Upon settlement, any difference between the recorded amount and the actual settlement cost will be recognized at a gain or loss. |
Debt Issue Costs | Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Debt issuance costs related to revolving credit facilities are presented as other long-term assets and debt issuance costs related to other long-term debt are reflected as a deduction from the carrying amount of other long-term debt in the Consolidated Balance Sheets. |
Accounts Receivable Securitization Facility | Accounts Receivable Securitization Facility Proceeds from the sale or contribution of certain receivables under the accounts receivable securitization facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities on our Consolidated Statements of Cash Flows. |
Environmental Liabilities and Other Loss Contingencies | Environmental Liabilities and Other Loss Contingencies Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. |
Income Taxes | Income Taxes We generally are not subject to federal income taxes. For federal income tax purposes, our earnings or losses are included in the tax returns of our separate partners. The taxable income or loss passed through to our partners may vary substantially from the net income or net loss we report in the Consolidated Statements of Operations. As part of the APL merger, we acquired TPL Arkoma, Inc. a corporate subsidiary subject to federal and state income tax. The Partnership’s corporate subsidiary accounts for income taxes under the asset and liability method and provides deferred income taxes for all significant temporary differences. As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes for our taxable corporate subsidiary. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheets. We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we establish a valuation allowance. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies. We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize deferred tax assets, and therefore no valuation allowance has been established. The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are generally not subject to federal and state income taxes at the Partnership level. We are also subject to the Texas margin tax, consisting generally of a 0.75% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas. See Note 19 for discussion of the Partnership’s federal and state income tax expense (benefits) of its taxable subsidiary as well as the Partnership’s net deferred income tax assets (liabilities). |
Noncontrolling Interests | Noncontrolling Interests Third-party ownership in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of our Consolidated Balance Sheets. In the Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income, noncontrolling interests reflects the attribution of results to third-party investors. |
Mandatorily Redeemable Preferred Interests | Mandatorily Redeemable Preferred Interests Mandatorily redeemable preferred interests are included in other long term liabilities (or assets) on our Consolidated Balance Sheets. Mandatorily redeemable preferred interests with multiple or indeterminate redemption dates are reported at their estimated redemption value as of the reporting date. This point-in-time value does not represent the amount that ultimately would become payable (or receivable) in the future when the interests are redeemed. Changes in the redemption value are recorded in interest expense, net on our Consolidated Statements of Operations. |
Revenue Recognition | Revenue Recognition Our operating revenues are primarily derived from the following activities: • sales of natural gas, NGLs, condensate, crude oil and petroleum products; • services related to compressing, gathering, treating, and processing of natural gas; and • services related to NGL fractionation, terminaling and storage, transportation and treating. We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. For natural gas processing activities, we receive either fees and/or a percentage of proceeds from commodity sales as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Typically, our percent-of-proceeds contracts also include a fee-based component. We generally report sales revenues gross in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another are reported as a single transaction on a combined net basis. We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized as revenue during the periods that services will be provided. Deferred revenue is included in Other long-term liabilities on our Consolidated Balance Sheets. |
Unit-Based and Share-Based Compensation | Unit-Based and Share-Based Compensation Prior to the TRC/TRP Merger, we awarded unit-based compensation to employees of Targa and to directors and non-management directors of our General Partner in the form of restricted common units and performance units. We withheld units to satisfy employees’ tax withholding obligations on vested awards. The withheld shares were recorded as treasury units at cost. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Revenue from Contracts with Customers In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Other Assets and Deferred Costs – Contracts with Customers With the issuance in August 2015 of ASU 2015-14 , Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers We expect to adopt this new revenue recognition standard on January 1, 2018, presenting a cumulative effect adjustment in the period the standard is adopted. We also anticipate electing the practical expedient to apply the guidance retrospectively to only those contracts that are not completed contracts at the date of initial application. We are continuing to evaluate the effect of the standard on our , including accounting associated with contracts containing noncash consideration and variable consideration, the effect of ASU 2016-20 on our disclosure requirements, and how the standard would impact our current revenue recognition and disclosure policies upon adoption. Consolidation In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis Presentation of Debt Issuance Costs In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs Leases In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases. Share-Based Compensation In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. Cash Flow Classification In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) Recognition of Intra-Entity Transfers of Assets Other than Inventory In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory Business Combinations In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business Goodwill Impairment In January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment |
Impact of Revisions to Activity
Impact of Revisions to Activity Reported in Consolidated Statements of Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Impact of Revisions to Activity Reported in Consolidated Statements of Comprehensive Income (Loss) | The following table displays the impact of these revisions to activity reported in our Consolidated Statements of Comprehensive Income (Loss) during the year ended December 31, 2015. Year Ended December 31, 2015 December 31, 2015 As Reported As Corrected Commodity hedging contracts: Change in fair value $ 81.2 $ 112.7 Settlements reclassified to revenues (54.8 ) (86.3 ) Other comprehensive income (loss) $ 26.4 $ 26.4 |
Business Acquisitions (Tables)
Business Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Pro Forma Consolidated Results of Operations | Pro Forma Impact of Atlas Mergers on Consolidated Statement of Operations The following summarized unaudited pro forma Consolidated Statement of Operations information for the year ended December 31, 2015 assumes that our acquisition of APL and Targa’s acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed the APL merger as of January 1, 2014, or that the results that will be attained in the future. Amounts presented below are in millions: December 31, 2015 Pro Forma Revenues $ 6,947.3 Net income (62.2 ) |
Consideration Transferred to Acquire ATLS and APL | The following table summarizes the consideration transferred to acquire ATLS and APL, which are viewed together as a single integrated transaction for GAAP reporting purposes: Fair Cash paid, net of cash acquired (1) $ 745.7 Common shares of TRC 1,008.5 Replacement restricted stock units awarded (3) 5.2 Less: value of APL common units owned by ATLS (147.4 ) Total $ 1,612.0 Fair Value of Consideration Transferred by Targa for APL: Cash paid, net of cash acquired (2) $ 828.7 Common units of TRP 2,568.5 Replacement phantom units awarded (3) 15.0 Total $ 3,412.2 Total fair value of consideration transferred $ 5,024.2 (1) Targa acquired $5.5 million of cash. (2) We acquired $35.3 million of cash. (3) The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. |
Fair Value Determination Related to the Atlas Mergers | Our final fair value determination related to the Atlas mergers was as follows: Fair value determination: February Trade and other current receivables, net $ 181.1 Other current assets 24.4 Assets from risk management activities 102.1 Property, plant and equipment 4,616.9 Investments in unconsolidated affiliates 214.5 Intangible assets 1,354.9 Other long-term assets 5.5 Current liabilities (258.8 ) Long-term debt (1,573.3 ) Deferred income tax liabilities, net (13.6 ) Other long-term liabilities (119.1 ) Total identifiable net assets 4,534.6 Noncontrolling interest in subsidiaries (216.9 ) Current liabilities retained by Targa (0.5 ) Goodwill 707.0 Total fair value of consideration transferred $ 5,024.2 |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Inventory Disclosure [Abstract] | |
Components of Inventories | December 31, 2016 December 31, 2015 Commodities $ 126.9 $ 128.3 Materials and supplies 10.8 12.7 $ 137.7 $ 141.0 |
Property, Plant and Equipment36
Property, Plant and Equipment and Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property Plant And Equipment And Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | December 31, 2016 December 31, 2015 Estimated Useful Lives (In Years) Gathering systems $ 6,626.9 $ 6,304.5 5 to 20 Processing and fractionation facilities 3,383.6 2,988.5 5 to 25 Terminaling and storage facilities 1,205.0 1,115.0 5 to 25 Transportation assets 451.4 454.0 10 to 25 Other property, plant and equipment 274.0 220.9 3 to 25 Land 121.2 108.8 — Construction in progress 449.8 736.5 — Property, plant and equipment 12,511.9 11,928.2 Accumulated depreciation (2,821.0 ) (2,225.6 ) Property, plant and equipment, net $ 9,690.9 $ 9,702.6 Intangible assets $ 2,036.6 $ 2,036.6 20 Accumulated amortization (382.6 ) (226.5 ) Intangible assets, net $ 1,654.0 $ 1,810.1 |
Schedule of Changes in Intangible Assets | The fair values of intangible assets acquired in the Atlas mergers were recorded at a fair value of $1,354.9 million and are being amortized over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation over a 20-year life. The changes in our intangible assets are as follows: December 31, 2016 December 31, 2015 Beginning of period $ 1,810.1 $ 591.9 Additions from acquisition — 1,354.9 Amortization (156.1 ) (136.7 ) Intangible assets, net $ 1,654.0 $ 1,810.1 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill And Intangible Assets Disclosure [Abstract] | |
Changes in Gross Amounts of Goodwill and Impairment Loss | Changes in the gross amounts of our goodwill are as follows: WestTX SouthTX SouthOK Total Balance at January 1, 2015 $ — $ — $ — $ — Acquisition, February 27, 2015 364.5 160.3 182.2 707.0 Provisional impairment for 2015 annual assessment (37.6 ) (70.2 ) (182.2 ) (290.0 ) Balance at December 31, 2015 326.9 90.1 — 417.0 Additional impairment for 2015 annual assessment (14.4 ) (9.6 ) — (24.0 ) Impairment for 2016 annual assessment (137.8 ) (45.2 ) — (183.0 ) Balance at December 31, 2016 $ 174.7 $ 35.3 $ — $ 210.0 |
Investments in Unconsolidated38
Investments in Unconsolidated Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Equity Method Investments And Joint Ventures [Abstract] | |
Activity Related to Partnership's Investment in Unconsolidated Affiliate | The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 EF Cogen Total Balance at December 31, 2013 $ 55.9 $ — $ — $ — $ 55.9 Equity earnings (loss) 18.0 — — — 18.0 Cash distributions (1) (23.7 ) — — — (23.7 ) Balance at December 31, 2014 $ 50.2 $ — $ — $ — $ 50.2 Fair value of T2 Joint Ventures acquired — 67.5 126.7 20.3 214.5 Equity earnings (loss) 13.8 (3.9 ) (9.4 ) (3.0 ) (2.5 ) Cash distributions (1) (14.5 ) — — (0.5 ) (15.0 ) Cash calls for expansion projects — — 6.5 5.2 11.7 Balance at December 31, 2015 $ 49.5 $ 63.6 $ 123.8 $ 22.0 $ 258.9 Equity earnings (loss) 4.1 (5.2 ) (9.4 ) (3.8 ) (14.3 ) Cash distributions (1) (7.5 ) — — (0.7 ) (8.2 ) Cash calls for expansion projects — 0.2 4.2 — 4.4 Balance at December 31, 2016 $ 46.1 $ 58.6 $ 118.6 $ 17.5 $ 240.8 (1) Includes $4.1 million and $1.2 million in distributions received from GCF and the T2 Joint Ventures in excess of our share of cumulative earnings for the years ended December 31, 2016 and 2015. Includes $5.7 million in distributions from GCF in excess of our share of cumulative earnings for the year ended December 31, 2014. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows. |
Accounts Payable and Accrued 39
Accounts Payable and Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Payables And Accruals [Abstract] | |
Schedule of Accounts Payable and Accrued Liabilities | December 31, 2016 December 31, 2015 Commodities $ 574.5 $ 378.7 Other goods and services 113.4 141.3 Interest 52.2 80.3 Compensation and benefits — 0.4 Income and other taxes 19.1 10.4 Other 14.7 18.0 $ 773.9 $ 629.1 |
Debt Obligations (Tables)
Debt Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of Outstanding Debt | December 31, 2016 December 31, 2015 Current: Accounts receivable securitization facility, due December 2017 $ 275.0 $ 219.3 Long-term: Senior secured revolving credit facility, variable rate, due October 2020 (1) 150.0 280.0 Senior unsecured notes: 5% fixed rate, due January 2018 250.5 1,100.0 4 ⅛ 749.4 800.0 6 ⅝ — 342.1 Unamortized premium — 5.0 6 ⅞ — 483.6 Unamortized discount — (22.1 ) 6 ⅜ 278.7 300.0 5 ¼ 559.6 583.7 4¼% fixed rate, due November 2023 583.9 623.5 6¾% fixed rate, due March 2024 580.1 600.0 5⅛ % fixed rate, due February 2025 500.0 — 5⅜ % fixed rate, due February 2027 500.0 — TPL notes, 6 ⅝ — 12.9 Unamortized premium — 0.2 TPL notes, 4¾% fixed rate, due November 2021 (2) 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 (2) 48.1 48.1 Unamortized premium 0.5 0.5 4,207.3 5,164.0 Debt issuance costs, net of amortization (30.3 ) (38.3 ) Total long-term debt 4,177.0 5,125.7 Total debt obligations $ 4,452.0 $ 5,345.0 Irrevocable standby letters of credit outstanding $ 13.2 $ 12.9 (1) As of December 31, 2016, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,436.8 million. (2) TPL notes are not guaranteed by us. |
Schedule of Contractual Maturities of Outstanding Debt Obligations | The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2016, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2017 2018 2019 2020 2021 After 2021 (in millions) TRP Revolver $ 150.0 $ — $ — $ — $ 150.0 $ — $ — Senior unsecured notes 4,056.8 — 250.5 749.4 — 6.5 3,050.4 Accounts receivable securitization facility 275.0 275.0 — — — — — Total $ 4,481.8 $ 275.0 $ 250.5 $ 749.4 $ 150.0 $ 6.5 $ 3,050.4 |
Interest Rates Incurred on Variable-Rate Debt Obligations | The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2016: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 2.4% - 5.3% 2.8% Accounts receivable securitization facility 1.2% - 1.8% 1.3% |
Schedule of Redemption Prices for Issued Debt | We may redeem up to 35% of the aggregate principal amount of the notes in the table below at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 180 days of the date of the closing of such equity offering. Note Issue Any Date Prior To Price 4 ⅛% Notes November 15, 2017 104.125% 6 ¾% Notes September 15, 2018 106.750% 5 ⅛% Notes February 1, 2020 105.125% 5 ⅜% Notes February 1, 2022 105.375% We may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed. Note Redemption Date Year Price 4 ⅛% Notes November 15 2016 102.063 % 2017 101.031 % 2018 and thereafter 100 % 6 ⅜% Notes February 1 2017 103.188 % 2018 102.125 % 2019 101.063 % 2020 and thereafter 100 % 5 ¼% Notes November 1 2017 102.625 % 2018 101.750 % 2019 100.875 % 2020 and thereafter 100 % 4 ¼% Notes May 15 2018 102.125 % 2019 101.417 % 2020 100.708 % 2021 and thereafter 100 % 6 ¾% Notes September 15 2019 103.375 % 2020 101.688 % 2021 and thereafter 100 % 5 ⅛% Notes February 1 2020 103.844 % 2021 102.563 % 2022 101.281 % 2023 and thereafter 100 % 5 ⅜% Notes February 1 2022 102.688 % 2023 101.792 % 2024 100.896 % 2025 and thereafter 100 % TPL 4 ¾% Notes May 15 2017 102.375 % 2018 101.188 % 2019 and thereafter 100 % TPL 5 ⅞% Notes February 1 2018 102.938 % 2019 101.958 % 2020 100.979 % 2021 and thereafter 100 % |
Summary of Debt Repurchased on Open Market Portion of Outstanding Senior Notes | In December 2015, we repurchased on the open market a portion of our outstanding Senior Notes as follows: Debt Repurchased Book Value Payment Gain/(Loss) Write-off of Debt Issuance Costs Net Gain/(Loss) 5¼% Senior Notes $ 16.3 $ (13.0 ) $ 3.3 $ (0.1 ) $ 3.2 4¼% Senior Notes 1.5 (1.2 ) 0.3 — 0.3 6⅝% Senior Notes 0.1 (0.1 ) — — — $ 17.9 $ (14.3 ) $ 3.6 $ (0.1 ) $ 3.5 During the year ended December 31, 2016, we repurchased on the open market a portion of our outstanding senior notes as follows: Debt Repurchased Book Value Payment Gain/(Loss) Write-off of Debt Issuance Costs Net Gain/(Loss) 5¼% Senior Notes $ 24.1 $ (20.1 ) $ 4.0 $ (0.2 ) $ 3.8 4¼% Senior Notes 39.5 (31.8 ) 7.7 (0.3 ) 7.4 6⅞% Senior Notes 4.8 (4.3 ) 0.5 (0.1 ) 0.4 6⅝% Senior Notes 32.6 (29.5 ) 3.1 — 3.1 6⅜% Senior Notes 21.3 (18.7 ) 2.6 (0.2 ) 2.4 6¾% Senior Notes 19.9 (17.5 ) 2.4 (0.2 ) 2.2 5% Senior Notes 366.4 (368.2 ) (1.8 ) (2.1 ) (3.9 ) 4⅛% Senior Notes 50.6 (44.2 ) 6.4 (0.4 ) 6.0 $ 559.2 $ (534.3 ) $ 24.9 $ (3.5 ) $ 21.4 Debt Tendered Outstanding Note Balance Prior to Tender Offers Amount Tendered Premium Paid Accrued Interest Paid Total Tender Offer Payments Note Balance After Tender Offers 5% Senior Notes $ 733.6 $ 483.1 $ 16.9 $ 5.4 $ 505.4 $ 250.5 6⅝% Senior Notes 309.9 281.7 10.5 0.3 292.5 28.2 6⅞% Senior Notes 478.6 373.5 14.4 4.6 392.5 105.1 Total $ 1,522.1 $ 1,138.3 $ 41.8 $ 10.3 $ 1,190.4 $ 383.8 The results of the TPL Notes Tender Offers were: Debt Tendered Outstanding Note Balance Prior to Tender Offers Amount Tendered Premium Paid Accrued Interest Paid Total Tender Offer Payments % Tendered Note Balance After Tender Offers 6⅝% Senior Notes $ 500.0 $ 140.1 $ 2.1 $ 3.7 $ 145.9 28.02 % $ 359.9 4¾% Senior Notes 400.0 393.5 5.9 5.3 404.7 98.38 % 6.5 5⅞% Senior Notes 650.0 601.9 8.7 2.6 613.2 92.60 % 48.1 Total $ 1,550.0 $ 1,135.5 $ 16.7 $ 11.6 $ 1,163.8 $ 414.5 The following table summarizes the debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2016 2015 2014 Premium over face value paid upon redemption: 5% Senior Notes $ 16.9 $ — $ — 6⅝% Senior Notes 11.5 — — 6⅞% Senior Notes 18.0 — — 6⅝% TPL Notes 0.4 — — 7⅞% Senior Notes — — 9.9 Recognition of unamortized discount: 6⅞% Senior Notes 19.5 — — Recognition of unamortized premium: 6⅝% Senior Notes (4.3 ) — — 6⅝% TPL Notes (0.2 ) — — Loss (gain) on repurchase of debt: 5% Senior Notes 1.8 — — 4⅛% Senior Notes (6.4 ) — — 6⅝% Senior Notes (2.8 ) — — 6⅞% Senior Notes (0.8 ) — — 6⅜% Senior Notes (2.6 ) — — 5¼% Senior Notes (4.0 ) (3.3 ) — 4¼% Senior Notes (7.7 ) (0.3 ) — 6¾% Senior Notes (2.4 ) — — Loss from financing with Exchange Offer: 6⅝% Senior Notes — 0.7 — Write-off of debt issuance costs: TRP Revolver 0.9 — — 5% Senior Notes 4.2 — — 4⅛% Senior Notes 0.4 — — 6⅞% Senior Notes 4.9 — — 6⅜% Senior Notes 0.2 — — 5¼% Senior Notes 0.2 0.1 — 4¼% Senior Notes 0.3 — — 6¾% Senior Notes 0.2 — — 7⅞% Senior Notes — — 2.5 Loss (gain) from financing activities $ 48.2 $ (2.8 ) $ 12.4 |
Other Long-term Liabilities (Ta
Other Long-term Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Other Liabilities Noncurrent [Abstract] | |
Other Long-term Liabilities | Other long-term liabilities are comprised of the following obligations: December 31, 2016 December 31, 2015 Asset retirement obligations $ 64.1 $ 69.9 Mandatorily redeemable preferred interests 68.5 82.9 Deferred revenue 69.8 27.7 Other liabilities 2.9 4.4 Total long-term liabilities $ 205.3 $ 184.9 |
Changes in Aggregate Asset Retirement Obligations | The changes in our ARO are as follows 2016 2015 Beginning of period $ 69.9 $ 56.8 Fair value of ARO acquired with APL merger — 4.0 Change in cash flow estimate (9.1 ) 3.8 Accretion expense 4.6 5.3 Retirement of ARO (1.3 ) — End of period $ 64.1 $ 69.9 |
Schedule of Changes in Long-term Liability Attributable to Mandatorily Redeemable Preferred Interests | The following table shows the changes attributable to mandatorily redeemable preferred interests: 2016 2015 Beginning of period $ 82.9 $ — Acquired mandatorily redeemable preferred interests — 109.3 Income attributable to mandatorily redeemable preferred interests 0.8 2.8 Change in estimated redemption value included in interest expense (15.2 ) (30.6 ) Other activity, net — 1.4 End of period $ 68.5 $ 82.9 |
Components of Deferred Revenue | The following table shows the components of deferred revenue: December 31, 2016 December 31, 2015 Splitter agreement $ 43.0 $ — Gas contract amendment 19.7 21.1 Other deferred revenue 7.1 6.6 Total deferred revenue $ 69.8 $ 27.7 |
Changes in Deferred Revenue | The following table shows the changes in deferred revenue: 2016 2015 Beginning of period $ 27.7 $ 4.1 Additions 45.2 26.3 Revenue recognized (3.1 ) (2.7 ) End of period $ 69.8 $ 27.7 |
Partnership Units and Related42
Partnership Units and Related Matters (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Partners Capital [Abstract] | |
Schedule of Distributions | The following details the distributions declared or paid by the Partnership during 2016, 2015 and 2014: Three Months Date Paid Total Distributions Targa Ended Or to Be Paid Distributions Corp. 2016 December 31, 2016 February 10, 2017 $ 198.1 $ 195.3 September 30, 2016 November 11, 2016 194.7 191.9 June 30, 2016 August 11, 2016 181.7 178.9 March 31, 2016 May 12, 2016 157.6 154.8 2015 December 31, 2015 February 9, 2016 $ 200.4 $ 61.4 September 30, 2015 November 13, 2015 200.4 61.4 June 30, 2015 August 14, 2015 200.4 61.4 March 31, 2015 May 15, 2015 193.9 59.0 2014 December 31, 2014 February 13, 2015 $ 137.4 $ 51.6 September 30, 2014 November 14, 2014 130.9 48.9 June 30, 2014 August 14, 2014 125.7 46.3 March 31, 2014 May 15, 2014 121.3 44.0 |
Derivative Instruments and He43
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Notional Volume of Commodity Hedges | At December 31, 2016, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2017 2018 2019 Natural Gas Swaps MMBtu/d 133,448 84,800 45,683 Natural Gas Basis Swaps MMBtu/d 72,219 - - Natural Gas Options MMBtu/d 22,900 9,486 - NGL Swaps Bbl/d 9,635 4,688 3,369 NGL Futures Bbl/d 6,118 959 - NGL Options Bbl/d 1,468 1,676 - Condensate Swaps Bbl/d 2,270 1,770 643 Condensate Options Bbl/d 1,380 691 590 |
Fair Values of Derivative Instruments | The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of December 31, 2016 Fair Value as of December 31, 2015 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 16.7 $ 48.6 $ 92.1 $ 2.1 Long-term 5.1 26.1 34.9 2.4 Total derivatives designated as hedging instruments $ 21.8 $ 74.7 $ 127.0 $ 4.5 Derivatives not designated as hedging instruments Commodity contracts Current $ 0.1 $ 0.5 $ 0.1 $ 3.1 Total derivatives not designated as hedging instruments $ 0.1 $ 0.5 $ 0.1 $ 3.1 Total current position $ 16.8 $ 49.1 $ 92.2 $ 5.2 Total long-term position 5.1 26.1 34.9 2.4 Total derivatives $ 21.9 $ 75.2 $ 127.1 $ 7.6 |
Pro Forma Impact of Derivatives Net in Consolidated Balance Sheet | The pro forma impact of reporting derivatives in our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro forma net presentation December 31, 2016 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 16.8 $ (46.1 ) $ 7.0 $ 5.7 $ (28.0 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (3.0 ) - - (3.0 ) 16.8 (49.1 ) 7.0 5.7 (31.0 ) Long Term Position Counterparties with offsetting positions or collateral 5.1 (18.7 ) - - (13.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.4 ) - - (7.4 ) 5.1 (26.1 ) - (21.0 ) Total Derivatives Counterparties with offsetting positions or collateral 21.9 (64.8 ) 7.0 5.7 (41.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (10.4 ) - - (10.4 ) $ 21.9 $ (75.2 ) $ 7.0 $ 5.7 $ (52.0 ) Gross Presentation Pro forma net presentation December 31, 2015 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 86.9 $ (5.2 ) $ - $ 81.7 $ - Counterparties without offsetting positions - assets 5.3 - - 5.3 - Counterparties without offsetting positions - liabilities - - - - - 92.2 (5.2 ) - 87.0 - Long Term Position Counterparties with offsetting positions or collateral 34.2 (2.4 ) - 31.8 - Counterparties without offsetting positions - assets 0.7 - - 0.7 - Counterparties without offsetting positions - liabilities - - - - - 34.9 (2.4 ) 32.5 - Total Derivatives Counterparties with offsetting positions or collateral 121.1 (7.6 ) - 113.5 - Counterparties without offsetting positions - assets 6.0 - - 6.0 - Counterparties without offsetting positions - liabilities - - - - - $ 127.1 $ (7.6 ) $ - $ 119.5 $ - |
Amounts Recorded in OCI and Amounts Reclassified from OCI to Revenue and Expense | The following tables reflect amounts recorded in Other Comprehensive Income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated: Derivatives in Cash Flow Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Hedging Relationships 2016 2015 2014 Commodity contracts $ (103.6 ) $ 112.7 $ 59.7 Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2016 2015 2014 Interest expense, net $ — $ — $ (2.4 ) Revenues 45.0 86.3 (4.2 ) $ 45.0 $ 86.3 $ (6.6 ) |
Gain (Loss) Recognized in Income on Derivatives | The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. Derivatives Not Designated Location of Gain Recognized in Gain (Loss) Recognized in Income on Derivatives as Hedging Instruments Income on Derivatives 2016 2015 2014 Commodity contracts Revenue $ 0.9 $ (5.7 ) $ (5.5 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value of Assets and Liabilities Measured on a Recurring Basis | The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: December 31, 2016 Fair Value Carrying Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 21.0 $ 21.0 $ — $ 19.6 $ 1.4 Liabilities from commodity derivative contracts (1) 74.2 74.2 — 69.3 4.9 TPL contingent consideration (2) 2.6 2.6 — — 2.6 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 68.0 68.0 — — — TRP Revolver 150.0 150.0 — 150.0 — Senior unsecured notes 4,057.3 4,101.6 — 4,101.6 — Accounts receivable securitization facility 275.0 275.0 — 275.0 — December 31, 2015 Fair Value Carrying Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 127.1 $ 127.1 $ — $ 123.1 $ 4.0 Liabilities from commodity derivative contracts (1) 7.6 7.6 — 7.3 0.3 TPL contingent consideration (2) 3.0 3.0 — — 3.0 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 135.4 135.4 — — — TRP Revolver 280.0 280.0 — 280.0 — Senior unsecured notes 4,884.0 4,192.0 — 4,192.0 — Accounts receivable securitization facility 219.3 219.3 — 219.3 — (1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes. (2) See Note 4 – Business Acquisitions. |
Reconciliation of Changes in Fair Value of Financial Instruments Classified as Level 3 | The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts Contingent Asset/(Liability) Liability Balance, December 31, 2015 $ 3.7 $ (3.0 ) Change in fair value of TPL contingent consideration - 0.4 New Level 3 instruments 0.9 - Settlements included in Revenue 0.2 - Unrealized gain/(loss) included in OCI (8.4 ) - Balance, December 31, 2016 $ (3.6 ) $ (2.6 ) |
Related Party Transactions - 45
Related Party Transactions - Targa (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Summary of Transactions with Affiliates | The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable. Year Ended December 31, 2016 2015 2014 Targa billings of payroll and related costs included in operating expense $ 171.8 $ 153.8 $ 124.9 Targa allocation of general and administrative expense 159.9 136.2 129.4 Cash distributions to Targa based on IDR, GP and common unit ownership 587.0 233.4 180.7 Cash contributions from Targa related to limited partner ownership (1) 1,353.4 — — Cash contributions from Targa to maintain its 2% general partner ownership 27.6 60.1 7.7 (1) Of the cash contributions from Targa related to limited partner ownership, $1,167.2 million was contributed for the issuance of common units and $186.2 million was contributed after the Third A&R Partnership Agreement. |
Commitments (Leases) (Tables)
Commitments (Leases) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Leases [Abstract] | |
Future Lease Obligations for Next Five Fiscal Years | Future lease obligations are presented below in aggregate and for each of the next five fiscal years: In Aggregate 2017 2018 2019 2020 2021 Operating leases (1) $ 35.6 $ 14.6 $ 10.1 $ 5.2 $ 3.6 $ 2.1 Land site lease and right-of-way (2) 14.2 3.2 2.8 2.8 2.7 2.7 $ 49.8 $ 17.8 $ 12.9 $ 8.0 $ 6.3 $ 4.8 (1) Includes minimum payments on lease obligations for office space, railcars and tractors. (2) Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual. |
Total Expenses on Lease Obligations, Including Short-Term Leases of Compressors and Equipment | Total expenses incurred under the above lease obligations , including short-term leases of compressors and equipment, 2016 2015 2014 Operating leases (1) $ 45.1 $ 42.4 $ 24.4 Land site lease and right-of-way 4.4 4.2 4.1 $ 49.5 $ 46.6 $ 28.5 (1) Includes short-term leases for items such as compressors and equipment. |
Other Operating (Income) Expe47
Other Operating (Income) Expense (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Other Income And Expenses [Abstract] | |
Other Operating (Income) Expense | Other Operating (Income) Expense is comprised of the following: 2016 2015 2014 (Gain) loss on sale or disposal of assets $ 6.1 $ (8.0 ) $ (4.8 ) Casualty (gain) loss - (0.2 ) 0.1 Miscellaneous business tax 0.5 0.5 0.4 Other - 0.6 1.3 $ 6.6 $ (7.1 ) $ (3.0 ) |
Income Tax (Tables)
Income Tax (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Provision for Income Taxes | 2016 2015 2014 Current expense $ - $ 0.8 $ 3.2 Deferred expense (benefit) (0.3 ) (0.2 ) 1.6 Total income tax expense (benefit) $ (0.3 ) $ 0.6 $ 4.8 |
Deferred Tax Assets and Liabilities | Our deferred income tax assets and liabilities at December 31, 2016 and 2015, consisted of differences related to the timing of recognition of certain types of costs as follows: 2016 2015 Deferred tax assets: Net operating loss carryforwards $ 19.8 $ 19.8 Deferred tax liabilities: Property, plant, and equipment (46.7 ) (47.0 ) Net deferred tax asset (liability) $ (26.9 ) $ (27.2 ) |
Supplemental Cash Flow Inform49
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | 2016 2015 2014 Cash: Interest paid, net of capitalized interest (1) $ 263.8 $ 193.1 $ 131.0 Income taxes paid, net of refunds 1.3 3.4 2.7 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 17.4 $ 1.2 $ 14.8 Impact of capital expenditure accruals on property, plant and equipment 27.6 43.8 19.0 Transfers from materials and supplies inventory to property, plant and equipment 2.4 3.7 4.6 Change in ARO liability and property, plant and equipment due to revised cash flow estimate (9.1 ) 3.8 2.1 Deferred revenue related to property, plant and equipment received under contract amendment — 22.6 — Non-cash financing activities: Debt additions and retirements related to exchange of TRP 6⅝% Notes for 6⅝% TPL Notes $ — $ 342.1 $ — Cancellation of treasury units 10.4 — Accrued distributions on unvested equity awards under share compensation arrangements 0.2 1.6 1.4 Receivables from equity issuances — — 1.0 Change of accrued distributions of preferred units — 0.9 — Exchange of IDRs and Special GP interest for units 903.6 — — Non-cash balance sheet movements related to the purchase of noncontrolling interests in subsidiary (see Note 4 - Business Acquisitions): Common limited partner units 63.7 — — General partner units 1.3 — — Noncontrolling interests (65.0 ) — — Non-cash balance sheet movements related to the Atlas Merger (See Note 4 - Business Acquisitions): Non-cash merger consideration - common units and replacement equity awards $ — $ 2,583.5 $ — Special GP Interest — 1,612.4 — Current liabilities retained by Targa — (0.4 ) — Net non-cash balance sheet movements excluded from consolidated statements of cash flows — 4,195.5 — Net cash merger consideration included in investing activities — 828.7 Total fair value of consideration transferred $ — $ 5,024.2 $ — _____________ (1) Interest capitalized on major projects was $8.3 million, $13.2 million and $16.1 million for 2016, 2015 and 2014. |
Compensation Plans (Tables)
Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Restricted Stock Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of Restricted Stock Units Awards | The following table summarizes the restricted stock units for the year ended 2016 under the Plan: Restricted Stock Units Number Weighted-average of shares Grant-Date Fair Value Outstanding as of December 31, 2015 - $ - Converted 635,467 73.68 Granted 331,282 74.01 Forfeited (20,485 ) 26.38 Vested (245,862 ) 62.23 Outstanding as of December 31, 2016 700,402 51.52 |
Cash Settled Restricted Stock Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of Restricted Stock Units | The following table summarizes the cash-settled restricted stock units for the year ended 2016 under the TRC LTIP (in shares and millions of dollars). Program Year 2013 Awards 2014 Awards 2015 Awards Total Outstanding as of December 31, 2015 139,700 119,900 192,390 451,990 After conversion on February 17, 2016 86,538 74,248 119,178 279,964 Vested and paid (85,492 ) (85,492 ) Forfeited (1,046 ) (1,269 ) (2,862 ) (5,177 ) Outstanding as of December 31, 2016 — 72,979 116,316 189,295 Calculated fair market value as of December 31, 2016 $ 4,992,974 $ 7,355,790 $ 12,348,763 Current liability $ 4,143,373 $ - $ 4,143,373 Long-term liability - 3,565,135 3,565,135 Liability as of December 31, 2016 $ 4,143,373 $ 3,565,135 $ 7,708,508 To be recognized in future periods $ 849,601 $ 3,790,655 $ 4,640,255 Vesting date June 2017 June 2018 |
Restricted Stock And Restricted Stock Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of Restricted Stock Units Awards | The following table summarizes the restricted stock and RSUs under the 2010 TRC Plan in shares and in dollars for the year indicated. Number Weighted Average of shares Grant-Date Fair Value Outstanding at December 31, 2015 313,362 85.70 Granted 1,186,206 28.00 Forfeited (14,989 ) 75.17 Vested (116,329 ) 58.55 Outstanding at December 31, 2016 1,368,250 $ 38.10 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Information by Segment | Reportable segment information is shown in the following tables: Year Ended December 31, 2016 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 621.9 $ 4,942.0 $ 62.9 $ — $ 5,626.8 Fees from midstream services 486.6 577.5 — — 1,064.1 1,108.5 5,519.5 62.9 — 6,690.9 Intersegment revenues Sales of commodities 2,124.4 251.5 — (2,375.9 ) — Fees from midstream services 7.8 23.5 — (31.3 ) — 2,132.2 275.0 — (2,407.2 ) — Revenues $ 3,240.7 $ 5,794.5 $ 62.9 $ (2,407.2 ) $ 6,690.9 Operating margin $ 577.1 $ 574.4 $ 62.9 $ — $ 1,214.4 Other financial information: Total assets (1) $ 9,800.6 $ 2,868.7 $ 21.8 $ 53.8 $ 12,744.9 Goodwill $ 210.0 $ — $ — $ — $ 210.0 Capital expenditures $ 402.5 $ 185.3 $ — $ 4.3 $ 592.1 (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Year Ended December 31, 2015 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 1,485.4 $ 3,895.8 $ 84.2 $ — $ 5,465.4 Fees from midstream services 427.1 766.1 — — 1,193.2 1,912.5 4,661.9 84.2 — 6,658.6 Intersegment revenues Sales of commodities 1,126.3 208.9 — (1,335.2 ) — Fees from midstream services 8.7 17.8 — (26.5 ) — 1,135.0 226.7 — (1,361.7 ) — Revenues $ 3,047.5 $ 4,888.6 $ 84.2 $ (1,361.7 ) $ 6,658.6 Operating margin $ 515.1 $ 681.7 $ 84.2 $ — $ 1,281.0 Other financial information: Total assets (1) $ 10,391.9 $ 2,567.1 $ 127.1 $ 40.7 $ 13,126.8 Goodwill $ 417.0 $ — $ — $ — $ 417.0 Capital expenditures $ 496.3 $ 272.0 $ — $ 8.9 $ 777.2 Business acquisition $ 5,024.2 $ — $ — $ — $ 5,024.2 (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Year Ended December 31, 2014 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 552.4 $ 7,050.8 $ (8.0 ) $ — $ 7,595.2 Fees from midstream services 224.7 796.6 — — 1,021.3 777.1 7,847.4 (8.0 ) — 8,616.5 Intersegment revenues Sales of commodities 2,068.8 339.3 — (2,408.1 ) — Fees from midstream services 5.2 28.5 — (33.7 ) — 2,074.0 367.8 — (2,441.8 ) — Revenues $ 2,851.1 $ 8,215.2 $ (8.0 ) $ (2,441.8 ) $ 8,616.5 Operating margin $ 449.9 $ 694.7 $ (8.0 ) $ — $ 1,136.6 Other financial information: Total assets (1) $ 3,776.2 $ 2,476.1 $ 60.2 $ 34.8 $ 6,347.3 Capital expenditures $ 437.1 $ 304.6 $ — $ 6.1 $ 747.8 (1) Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. |
Revenues by Product and Service | The following table shows our consolidated revenues by product and service for the periods presented: 2016 2015 2014 Sales of commodities: Natural gas $ 1,584.5 $ 1,578.6 $ 1,414.1 NGL 3,777.3 3,558.3 5,960.1 Condensate 133.9 142.4 134.3 Petroleum products 68.2 101.6 96.3 Derivative activities 62.9 84.5 (9.6 ) 5,626.8 5,465.4 7,595.2 Fees from midstream services: Fractionating and treating 126.2 209.0 208.9 Storage, terminaling, transportation and export 420.0 506.2 548.1 Gathering and processing 445.0 393.7 196.9 Other 72.9 84.3 67.4 1,064.1 1,193.2 1,021.3 Total revenues $ 6,690.9 $ 6,658.6 $ 8,616.5 |
Reconciliation of Operating Margin to Net Income (Loss) | The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: 2016 2015 2014 Reconciliation of operating margin to net income (loss): Operating margin $ 1,214.4 $ 1,281.0 $ 1,136.6 Depreciation and amortization expenses (757.7 ) (677.1 ) (346.5 ) General and administrative expenses (177.1 ) (153.6 ) (139.8 ) Goodwill impairment (207.0 ) (290.0 ) — Interest expense, net (233.5 ) (207.8 ) (143.8 ) Other, net (68.1 ) (11.2 ) 3.4 Income tax (expense) benefit 0.3 (0.6 ) (4.8 ) Net income (loss) $ (228.7 ) $ (59.3 ) $ 505.1 |
Selected Quarterly Financial 52
Selected Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Selected Quarterly Financial Information [Abstract] | |
Results of Operations by Quarter | Our results of operations by quarter for the years ended December 31, 2016 and 2015 were as follows: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2016 Revenues $ 1,442.4 $ 1,583.6 $ 1,652.3 $ 2,012.6 $ 6,690.9 Gross margin 431.4 438.4 429.6 468.6 1,768.0 Income from operations (1)(2) 37.5 68.4 53.7 (93.6 ) 66.0 Net income (loss) 10.6 (4.9 ) (6.1 ) (228.3 ) (228.7 ) Net income (loss) attributable to limited partners (9.9 ) (37.9 ) (42.6 ) (233.7 ) (324.1 ) 2015 Revenues $ 1,679.7 $ 1,699.4 $ 1,632.1 $ 1,647.4 $ 6,658.6 Gross margin 421.1 471.3 468.8 459.8 1,821.0 Income (loss) from operations (3)(4) 140.6 114.8 117.3 (205.3 ) 167.4 Net income (loss) 77.8 53.3 53.3 (243.7 ) (59.3 ) Net income (loss) attributable to limited partners 30.3 1.2 3.6 (232.6 ) (197.5 ) (1) Includes an additional goodwill impairment of $24.0 million in the first quarter of 2016. See Note 7 – Goodwill. (2) Includes a goodwill impairment of $183.0 million in the fourth quarter of 2016. See Note 7 – Goodwill. (3) Includes $32.6 million of impairment losses in the fourth quarter of 2015. See Note 6 – Property, Plant and Equipment and Intangible Assets. (4) Includes a provisional goodwill impairment of $290.0 million in the fourth quarter of 2015. See Note 7 – Goodwill. |
Organization and Operations (De
Organization and Operations (Details) | Feb. 17, 2016$ / shares | Dec. 31, 2016shares | Dec. 31, 2015shares |
Subsidiary Of Limited Liability Company Or Limited Partnership [Line Items] | |||
Conversion ratio in stock-for-unit transaction | 0.62 | ||
Common stock, par value (in dollars per share) | $ / shares | $ 0.001 | ||
Series A Cumulative Redeemable Perpetual Preferred Units [Member] | |||
Subsidiary Of Limited Liability Company Or Limited Partnership [Line Items] | |||
Preferred units issued (in units) | shares | 5,000,000 | 5,000,000 | |
Preferred units dividend percentage | 9.00% |
Basis of Presentation (Details)
Basis of Presentation (Details) | Feb. 27, 2015USD ($)Transaction | Dec. 31, 2016USD ($) | Oct. 31, 2016 |
Business Acquisition [Line Items] | |||
Number of legal transactions involved in mergers | Transaction | 2 | ||
Versado Gas Processors L L C | |||
Business Acquisition [Line Items] | |||
Gain or loss on purchase of non controlling interest | $ 0 | ||
Environment Proceeding [Member] | Versado Gas Processors L L C | |||
Business Acquisition [Line Items] | |||
Remaining membership interest to be acquired | 37.00% | ||
Atlas Energy [Member] | |||
Business Acquisition [Line Items] | |||
Total general partner interest acquired | $ 1,600,000,000 |
Impact of Revisions to Activi55
Impact of Revisions to Activity Reported in Consolidated Statements of Comprehensive Income (Loss) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Commodity hedging contracts: | |||
Change in fair value | $ 112.7 | ||
Settlements reclassified to revenues | (86.3) | ||
Other comprehensive income (loss) | $ (148.6) | 26.4 | $ 66.4 |
Scenario, Previously Reported | |||
Commodity hedging contracts: | |||
Change in fair value | 81.2 | ||
Settlements reclassified to revenues | (54.8) | ||
Other comprehensive income (loss) | $ 26.4 |
Significant Accounting Polici56
Significant Accounting Policies (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2016 | |
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | ||
Valuation allowance | $ 0 | |
Margin tax rate | 0.75% | |
Reclassification of unamortized debt issuance costs | $ 38,300,000 | |
Unamortized debt issuance costs | $ 30,300,000 | |
Debt issuance costs | 38,300,000 | 30,300,000 |
Revolving Credit Facility [Member] | ||
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | ||
Debt issuance costs | $ 5,900,000 | $ 15,100,000 |
Business Acquisitions (Details)
Business Acquisitions (Details) | Feb. 27, 2015USD ($)Transaction$ / sharesshares | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2016USD ($)MMcf / dmi | Dec. 31, 2015USD ($) | Dec. 31, 2014 | Feb. 17, 2016$ / shares |
Business Acquisition [Line Items] | |||||||||||
Number of legal transactions involved in mergers | Transaction | 2 | ||||||||||
Percentage of general partner's interest maintained | 2.00% | 2.00% | |||||||||
Common units par value (in dollars per share) | $ / shares | $ 0.001 | ||||||||||
Acquisition-related expenses | $ 19,300,000 | $ 19,300,000 | |||||||||
Revenues from acquired business | $ 1,459,300,000 | ||||||||||
Net loss from acquired business | $ (30,100,000) | ||||||||||
Targa Pipeline Partners LP [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Processing capacity | MMcf / d | 2,053 | ||||||||||
Length of additional pipelines | mi | 12,220 | ||||||||||
Targa Resources Corp [Member] | Common Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Percentage of general partner's interest maintained | 2.00% | ||||||||||
Atlas Energy [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Total general partner interest acquired | $ 1,600,000,000 | ||||||||||
Cash payment related to one-time cash payments and cash settlements of equity awards | 7,300,000 | ||||||||||
Reduction in purchase price | (154,700,000) | ||||||||||
Atlas Energy [Member] | Common Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Common units acquired | 147,400,000 | ||||||||||
Atlas Energy [Member] | Phantom Unit Awards [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash payment related to one-time cash payments and cash settlements of equity awards | $ 4,500,000 | ||||||||||
Atlas Energy [Member] | Targa Pipeline Partners LP [Member] | Common Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Total distribution of common shares (in shares) | shares | 3,363,935 | ||||||||||
Atlas Energy [Member] | Targa Resources Corp [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Percentage of interest in common units | 100.00% | ||||||||||
Total general partner interest acquired | $ 1,600,000,000 | ||||||||||
Distribution of common units/shares for each common unit (in shares) | shares | 0.1809 | ||||||||||
Cash payment (in dollars per common unit) | $ / shares | $ 9.12 | ||||||||||
Cash payments related to acquisition | $ 514,700,000 | ||||||||||
Common units acquired | $ 1,000,000,000 | ||||||||||
Closing market price of common share (in dollars per share) | $ / shares | $ 99.58 | ||||||||||
Common units par value (in dollars per share) | $ / shares | $ 0.001 | ||||||||||
Acquisition-related expenses | $ 11,000,000 | ||||||||||
Atlas Energy [Member] | Targa Resources Corp [Member] | Common Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Total distribution of common shares (in shares) | shares | 10,126,532 | ||||||||||
Common units acquired | $ 147,400,000 | ||||||||||
Atlas Energy [Member] | Targa Resources Corp [Member] | Change Of Control Payments [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash payments related to acquisition | 149,200,000 | ||||||||||
Atlas Energy [Member] | Targa Resources Corp [Member] | Equity Award Settlements [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash payments related to acquisition | $ 88,000,000 | ||||||||||
Atlas Energy [Member] | Targa Resources Corp [Member] | Restricted Stock Units (RSUs) [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Total distribution of common shares (in shares) | shares | 81,740 | ||||||||||
Atlas Pipeline Partners [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Total general partner interest acquired | $ 5,300,000,000 | ||||||||||
Acquired debt and all other assumed liabilities included purchase consideration | 1,800,000,000 | ||||||||||
Payments for notes tendered and settled upon closing of merger | $ 1,200,000,000 | ||||||||||
Reduction in incentive distribution | $ 9,375,000 | $ 9,375,000 | $ 9,375,000 | $ 9,375,000 | |||||||
Distribution of common units/shares for each common unit (in shares) | shares | 0.5846 | ||||||||||
Cash payment (in dollars per common unit) | $ / shares | $ 1.26 | ||||||||||
Common units acquired | $ 2,600,000,000 | ||||||||||
Closing market price of common share (in dollars per share) | $ / shares | $ 43.82 | ||||||||||
Cash paid in lieu of unit issuances | $ 6,400,000 | ||||||||||
Atlas Pipeline Partners [Member] | Class E Preferred Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Percentage of cumulative redeemable perpetual preferred units | 8.25% | ||||||||||
Atlas Pipeline Partners [Member] | Revolving Credit Facility [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash payments related to acquisition | $ 701,400,000 | $ 701,400,000 | |||||||||
Atlas Pipeline Partners [Member] | Phantom Unit Awards [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash payment representing accelerated vesting of a portion of employees APL phantom awards | $ 600,000 | ||||||||||
Total distribution of common shares (in shares) | shares | 629,231 | ||||||||||
Atlas Pipeline Partners [Member] | Common Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Total distribution of common shares (in shares) | shares | 58,614,157 | ||||||||||
Atlas Pipeline Partners [Member] | Change Of Control Payments [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash payments related to acquisition | $ 28,800,000 | ||||||||||
Atlas Pipeline Partners [Member] | Common Unit Holders [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Cash payments related to acquisition | $ 128,000,000 | ||||||||||
Total distribution of common shares (in shares) | shares | 58,614,157 | ||||||||||
Atlas Pipeline Partners [Member] | Atlas Energy [Member] | Common Units [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Common units owned by parent prior to closing (in units) | shares | 5,754,253 | ||||||||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 1 [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Reduction in incentive distribution | $ 9,375,000 | ||||||||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 2 [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Reduction in incentive distribution | 6,250,000 | ||||||||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 3 [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Reduction in incentive distribution | 2,500,000 | ||||||||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 4 [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Reduction in incentive distribution | $ 1,250,000 | ||||||||||
Atlas Pipeline Partners [Member] | Targa Resources Corp [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Contribution made by Targa to general partner's interest | $ 52,400,000 | ||||||||||
Percentage of general partner's interest maintained | 2.00% |
Business Acquisitions, Pro form
Business Acquisitions, Pro forma Impact of Atlas Mergers on Consolidated Statement of Operations (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Pro forma consolidated results of operations [Abstract] | ||
Revenues | $ 6,947.3 | |
Net income | (62.2) | |
Acquisition-related costs | $ 19.3 | $ 19.3 |
Atlas Resource Partners, LP [Member] | ||
Pro forma consolidated results of operations [Abstract] | ||
Percentage of equity interest sold | 100.00% |
Business Acquisitions, Fair Val
Business Acquisitions, Fair Value of Consideration Transferred (Details) - USD ($) $ in Millions | Feb. 27, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Cash paid, net of cash acquired | $ 0 | $ 828.7 | $ 0 | ||
Total fair value of consideration transferred | $ 5,024.2 | ||||
Atlas Pipeline Partners [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Cash paid, net of cash acquired | [1] | 828.7 | |||
Less: value of APL common units owned by ATLS | (2,600) | ||||
Total fair value of consideration transferred | 3,412.2 | ||||
Cash acquired from acquisition | 35.3 | ||||
Phantom Unit Awards [Member] | Atlas Pipeline Partners [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Common shares of TRC | [2] | 15 | |||
Targa Resources Corp [Member] | Atlas Energy [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Cash paid, net of cash acquired | [3] | 745.7 | |||
Less: value of APL common units owned by ATLS | (1,000) | ||||
Total fair value of consideration transferred | 1,612 | ||||
Cash acquired from acquisition | 5.5 | ||||
Targa Resources Corp [Member] | Replacement Restricted Stock Units RSUs [Member] | Atlas Energy [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Common shares of TRC | [2] | 5.2 | |||
Common Stock [Member] | Targa Resources Corp [Member] | Atlas Energy [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Common shares of TRC | 1,008.5 | ||||
Common Units [Member] | Atlas Energy [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Less: value of APL common units owned by ATLS | (147.4) | ||||
Common Units [Member] | Atlas Pipeline Partners [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Common shares of TRC | 2,568.5 | ||||
Common Units [Member] | Targa Resources Corp [Member] | Atlas Energy [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Less: value of APL common units owned by ATLS | $ (147.4) | ||||
[1] | We acquired $35.3 million of cash. | ||||
[2] | The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. | ||||
[3] | Targa acquired $5.5 million of cash. |
Business Acquisitions, Final Fa
Business Acquisitions, Final Fair Value Determination (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Feb. 27, 2015 | Dec. 31, 2014 | |
Fair value determination [Abstract] | |||||
Trade and other current receivables, net | $ 181.1 | ||||
Other current assets | 24.4 | ||||
Assets from risk management activities | 102.1 | ||||
Property, plant and equipment | 4,616.9 | ||||
Investments in unconsolidated affiliates | 214.5 | ||||
Intangible assets | 1,354.9 | ||||
Other long-term assets | 5.5 | ||||
Current liabilities | (258.8) | ||||
Long-term debt | (1,573.3) | ||||
Deferred income tax liabilities, net | (13.6) | ||||
Other long-term liabilities | (119.1) | ||||
Total identifiable net assets | 4,534.6 | ||||
Noncontrolling interest in subsidiaries | (216.9) | ||||
Current liabilities retained by Targa | (0.5) | ||||
Goodwill | $ 210 | $ 393 | $ 417 | 707 | $ 0 |
Total fair value of consideration transferred | 5,024.2 | ||||
Goodwill amortizable for tax purpose, term | 15 years | ||||
Measurement-period adjustments to preliminary acquisition date fair values [Abstract] | |||||
Trade receivables, fair value | 178.1 | ||||
Trade receivables, gross amount | 178.1 | ||||
Contractual receivables included in current receivables | 3 | ||||
Contractual receivables included in other long term assets | $ 4.5 |
Business Acquisitions, Mandator
Business Acquisitions, Mandatorily Redeemable Preferred Interests (Details) - Mandatorily Redeemable Noncontrolling Interests [Member] $ in Millions | 12 Months Ended | |
Dec. 31, 2016USD ($)JointVenture | Dec. 31, 2015USD ($) | |
Redeemable Noncontrolling Interest [Line Items] | ||
Number of joint ventures | JointVenture | 2 | |
Acquired other long-term liabilities | $ | $ 0 | $ 109.3 |
Business Acquisitions, Continge
Business Acquisitions, Contingent Consideration and Replacement Phantom Units (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Replacement Phantom Units [Member] | |
Business Acquisition [Line Items] | |
Dividend payment period | 60 days |
Replacement Phantom Units [Member] | Vesting Term One [Member] | |
Business Acquisition [Line Items] | |
Vesting percentage original term | 25.00% |
Vesting period of original term | 4 years |
Replacement Phantom Units [Member] | Vesting Term Two [Member] | |
Business Acquisition [Line Items] | |
Vesting percentage original term | 33.00% |
Vesting period of original term | 3 years |
Atlas Pipeline Partners [Member] | |
Business Acquisition [Line Items] | |
Contingent consideration additional amount | $ 6 |
Contingent liability acquisition date fair value | $ 4.2 |
Business Acquisitions, Subseque
Business Acquisitions, Subsequent Event (Details) - Subsequent Event [Member] | Jan. 26, 2017USD ($)$ / sharesshares | Jan. 22, 2017USD ($)aMMcf / dbbl / d |
Business Acquisition [Line Items] | ||
Shares of common stock issued (including underwriters’ overallotment option) | shares | 9,200,000 | |
Shares issued price | $ / shares | $ 57.65 | |
Net proceeds from public offering | $ 524,100,000 | |
Outrigger Delaware [Member] | ||
Business Acquisition [Line Items] | ||
Area of gas gathering and processing and crude gathering systems | a | 145,000 | |
Average weighted contract life | 14 years | |
Processing capacity | MMcf / d | 70 | |
Crude gathering capacity | bbl / d | 40,000 | |
Outrigger Midland [Member] | ||
Business Acquisition [Line Items] | ||
Area of gas gathering and processing and crude gathering systems | a | 105,000 | |
Average weighted contract life | 13 years | |
Processing capacity | MMcf / d | 10 | |
Crude gathering capacity | bbl / d | 40,000 | |
Outrigger Permian Acquisition [Member] | ||
Business Acquisition [Line Items] | ||
Percentage of membership interests acquired | 100.00% | |
Cash payments related to acquisition | $ 475,000,000 | |
Acquired debt and all other assumed liabilities included purchase consideration | 90,000,000 | |
Initial purchase price | $ 565,000,000 | |
Outrigger Permian Acquisition [Member] | Maximum [Member] | ||
Business Acquisition [Line Items] | ||
Additional cash paid in potential earn-out payment | $ 935,000,000 |
Inventories (Details)
Inventories (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Inventory Disclosure [Abstract] | ||
Commodities | $ 126.9 | $ 128.3 |
Materials and supplies | 10.8 | 12.7 |
Total inventory | $ 137.7 | $ 141 |
Property, Plant and Equipment65
Property, Plant and Equipment and Intangible Assets, Property, Plant and Equipment (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment | $ 11,928.2 | $ 12,511.9 | $ 11,928.2 | |
Accumulated depreciation | (2,225.6) | (2,821) | (2,225.6) | |
Property, plant and equipment, net | 9,702.6 | 9,690.9 | 9,702.6 | |
Intangible assets | 2,036.6 | 2,036.6 | 2,036.6 | |
Accumulated amortization | (226.5) | (382.6) | (226.5) | |
Intangible assets, net | 1,810.1 | $ 1,654 | 1,810.1 | $ 591.9 |
Estimated useful life | 20 years | |||
Depreciation expenses for property, plant and equipment | $ 601.5 | 540.5 | 285 | |
Non-cash pre-tax impairment charges | 32.6 | 32.6 | $ 3.2 | |
Additions from acquisition | 1,354.9 | |||
Badlands [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 20 years | |||
Gathering Systems [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment | 6,304.5 | $ 6,626.9 | 6,304.5 | |
Gathering Systems [Member] | Minimum [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 5 years | |||
Gathering Systems [Member] | Maximum [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 20 years | |||
Processing and Fractionation Facilities [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment | 2,988.5 | $ 3,383.6 | 2,988.5 | |
Processing and Fractionation Facilities [Member] | Minimum [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 5 years | |||
Processing and Fractionation Facilities [Member] | Maximum [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 25 years | |||
Terminaling and Storage Facilities [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment | 1,115 | $ 1,205 | 1,115 | |
Terminaling and Storage Facilities [Member] | Minimum [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 5 years | |||
Terminaling and Storage Facilities [Member] | Maximum [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 25 years | |||
Transportation Assets [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment | 454 | $ 451.4 | 454 | |
Transportation Assets [Member] | Minimum [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 10 years | |||
Transportation Assets [Member] | Maximum [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 25 years | |||
Other Property, Plant and Equipment [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment | 220.9 | $ 274 | 220.9 | |
Other Property, Plant and Equipment [Member] | Minimum [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 3 years | |||
Other Property, Plant and Equipment [Member] | Maximum [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Estimated useful life | 25 years | |||
Land [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment | 108.8 | $ 121.2 | 108.8 | |
Construction in Progress [Member] | ||||
Property Plant And Equipment [Line Items] | ||||
Property, plant and equipment | $ 736.5 | $ 449.8 | $ 736.5 |
Property, Plant and Equipment66
Property, Plant and Equipment and Intangible Assets, Schedule of Changes in Intangible Assets(Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Intangible Assets, net [Roll Forward] | |||
Beginning of period | $ 1,810.1 | $ 591.9 | |
Additions from acquisition | 1,354.9 | ||
Amortization | (156.1) | (136.7) | $ (61.5) |
Intangible assets, net | $ 1,654 | $ 1,810.1 | $ 591.9 |
Property, Plant and Equipment67
Property, Plant and Equipment and Intangible Assets, Intangible Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Intangible Assets, net [Roll Forward] | |||
Amortization | $ 156.1 | $ 136.7 | $ 61.5 |
Estimated amortization expense for intangible assets [Abstract] | |||
2,017 | 149.4 | ||
2,018 | 135.7 | ||
2,019 | 124.7 | ||
2,020 | 112.5 | ||
2,021 | $ 102.6 | ||
Weighted average amortization period, intangible assets | 17 years 7 months 6 days |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2017 | Feb. 27, 2015 | |
Goodwill [Line Items] | ||||||||
Goodwill | $ 210 | $ 393 | $ 417 | $ 210 | $ 417 | $ 0 | $ 707 | |
Impairment | (183) | (290) | (207) | (290) | 0 | |||
Additional impairment | $ (24) | |||||||
Goodwill impairment | $ 183 | $ 290 | $ 207 | $ 290 | $ 0 | |||
Scenario Forecast [Member] | ||||||||
Goodwill [Line Items] | ||||||||
Goodwill | $ 210 |
Goodwill - Changes in Gross Amo
Goodwill - Changes in Gross Amounts of Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Goodwill [Roll Forward] | ||||||
Beginning of period | $ 417 | $ 417 | $ 0 | |||
Acquisition | 707 | |||||
Impairment | $ (183) | $ (290) | (207) | (290) | $ 0 | |
Additional impairment | (24) | |||||
Balance | 210 | 393 | 417 | 210 | 417 | 0 |
WestTX [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Beginning of period | 326.9 | 326.9 | 0 | |||
Acquisition | 364.5 | |||||
Impairment | (137.8) | (37.6) | ||||
Additional impairment | (14.4) | |||||
Balance | 174.7 | 326.9 | 174.7 | 326.9 | 0 | |
SouthTX [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Beginning of period | 90.1 | 90.1 | 0 | |||
Acquisition | 160.3 | |||||
Impairment | (45.2) | (70.2) | ||||
Additional impairment | (9.6) | |||||
Balance | 35.3 | 90.1 | 35.3 | 90.1 | 0 | |
SouthOK [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Beginning of period | 0 | 0 | 0 | |||
Acquisition | 182.2 | |||||
Impairment | 0 | (182.2) | ||||
Additional impairment | $ 0 | |||||
Balance | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 |
Investments in Unconsolidated70
Investments in Unconsolidated Affiliates (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016USD ($)JointVenture | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | ||
Schedule Of Equity Method Investments [Line Items] | ||||
Balance at beginning of period | $ 258.9 | $ 50.2 | $ 55.9 | |
Fair value of T2 Joint Ventures acquired | 214.5 | |||
Equity earnings (loss) | (14.3) | (2.5) | 18 | |
Cash distributions | [1] | (8.2) | (15) | (23.7) |
Cash calls for expansion projects | 4.4 | 11.7 | ||
Balance at end of period | 240.8 | 258.9 | 50.2 | |
Return of capital from unconsolidated affiliate | $ 4.1 | 1.2 | 5.7 | |
Gulf Coast Fractionators LP [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Ownership interest | 38.80% | |||
Balance at beginning of period | $ 49.5 | 50.2 | 55.9 | |
Fair value of T2 Joint Ventures acquired | 0 | |||
Equity earnings (loss) | 4.1 | 13.8 | 18 | |
Cash distributions | [1] | (7.5) | (14.5) | (23.7) |
Cash calls for expansion projects | 0 | 0 | ||
Balance at end of period | $ 46.1 | 49.5 | 50.2 | |
T2 Joint Ventures [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Number of non-operated joint ventures acquired in Atlas mergers | JointVenture | 3 | |||
Basis difference on preliminary fair values | $ 36.2 | |||
Preliminary estimated useful lives of the underlying assets | 20 years | |||
T2 La Salle [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Ownership interest | 75.00% | |||
Balance at beginning of period | $ 63.6 | 0 | 0 | |
Fair value of T2 Joint Ventures acquired | 67.5 | |||
Equity earnings (loss) | (5.2) | (3.9) | 0 | |
Cash distributions | [1] | 0 | 0 | 0 |
Cash calls for expansion projects | 0.2 | 0 | ||
Balance at end of period | $ 58.6 | 63.6 | 0 | |
T2 Eagle Ford [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Ownership interest | 50.00% | |||
Balance at beginning of period | $ 123.8 | 0 | 0 | |
Fair value of T2 Joint Ventures acquired | 126.7 | |||
Equity earnings (loss) | (9.4) | (9.4) | 0 | |
Cash distributions | [1] | 0 | 0 | 0 |
Cash calls for expansion projects | 4.2 | 6.5 | ||
Balance at end of period | $ 118.6 | 123.8 | 0 | |
T2 EF Cogen [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Ownership interest | 50.00% | |||
Balance at beginning of period | $ 22 | 0 | 0 | |
Fair value of T2 Joint Ventures acquired | 20.3 | |||
Equity earnings (loss) | (3.8) | (3) | 0 | |
Cash distributions | [1] | (0.7) | (0.5) | 0 |
Cash calls for expansion projects | 0 | 5.2 | ||
Balance at end of period | $ 17.5 | $ 22 | $ 0 | |
[1] | Includes $4.1 million and $1.2 million in distributions received from GCF and the T2 Joint Ventures in excess of our share of cumulative earnings for the years ended December 31, 2016 and 2015. Includes $5.7 million in distributions from GCF in excess of our share of cumulative earnings for the year ended December 31, 2014. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows. |
Accounts Payable and Accrued 71
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Components of accounts payable and accrued liabilities [Abstract] | ||
Commodities | $ 574.5 | $ 378.7 |
Other goods and services | 113.4 | 141.3 |
Interest | 52.2 | 80.3 |
Compensation and benefits | 0.4 | |
Income and other taxes | 19.1 | 10.4 |
Other | 14.7 | 18 |
Accounts payable and accrued liabilities | 773.9 | 629.1 |
Outstanding checks | $ 30.2 | $ 34 |
Debt Obligations (Details)
Debt Obligations (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Current: | |||
Accounts receivable securitization facility, due December 2017 | $ 275 | $ 219.3 | |
Long-term [Abstract] | |||
Long-term debt | 4,177 | 5,125.7 | |
Debt issuance costs, net of amortization | (30.3) | (38.3) | |
Total debt obligations | 4,452 | 5,345 | |
Irrevocable standby letters of credit outstanding | 13.2 | 12.9 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 250.5 | 1,100 | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 749.4 | 800 | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 342.1 | ||
Unamortized premium | 5 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 483.6 | ||
Unamortized discount | (22.1) | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 278.7 | 300 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 559.6 | 583.7 | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 583.9 | 623.5 | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 580.1 | 600 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 2025 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 500 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 2027 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 500 | ||
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [1] | 12.9 | |
Unamortized premium | 0.2 | ||
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [1] | 6.5 | 6.5 |
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [1] | 48.1 | 48.1 |
Unamortized premium | 0.5 | 0.5 | |
Senior Secured and Unsecured Notes [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 4,207.3 | 5,164 | |
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2020 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [2] | 150 | 280 |
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2017 [Member] | |||
Current: | |||
Accounts receivable securitization facility, due December 2017 | $ 275 | $ 219.3 | |
[1] | TPL notes are not guaranteed by us. | ||
[2] | As of December 31, 2016, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,436.8 million. |
Debt Obligations (Parenthetical
Debt Obligations (Parenthetical) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Oct. 31, 2016 | ||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 1,600,000,000 | ||
Accounts Receivable Securitization Facility Due December 2017 [Member] | Accounts Receivable Securitization Facility [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Dec. 31, 2017 | ||
Senior Unsecured 5% Notes due January 2018 [Member] | Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Jan. 15, 2018 | ||
Interest rate on fixed rate debt | 5.00% | ||
Senior Unsecured 4 1/8% Notes due November 2019 [Member] | Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Nov. 15, 2019 | ||
Interest rate on fixed rate debt | 4.125% | ||
Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Oct. 1, 2020 | ||
Interest rate on fixed rate debt | 6.625% | ||
Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | [1] | Oct. 1, 2020 | |
Interest rate on fixed rate debt | 6.625% | ||
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Feb. 1, 2021 | ||
Interest rate on fixed rate debt | 6.875% | ||
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Aug. 1, 2022 | ||
Interest rate on fixed rate debt | 6.375% | ||
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | May 1, 2023 | ||
Interest rate on fixed rate debt | 5.25% | ||
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Nov. 15, 2023 | ||
Interest rate on fixed rate debt | 4.25% | ||
Senior Unsecured 6 3/4% Notes due March 2024 [Member] | Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Mar. 15, 2024 | ||
Interest rate on fixed rate debt | 6.75% | ||
Senior Unsecured 5 1/8% Notes due February 2025 [Member] | Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Feb. 28, 2025 | ||
Interest rate on fixed rate debt | 5.125% | ||
Senior Unsecured 5 3/8% Notes due February 2027 [Member] | Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | Feb. 28, 2027 | ||
Interest rate on fixed rate debt | 5.375% | ||
Senior Unsecured 4 3/4% Notes due November 2021 [Member] | Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | [1] | Nov. 15, 2021 | |
Interest rate on fixed rate debt | [1] | 4.75% | |
Senior Unsecured 5 7/8% Notes due August 2023 [Member] | Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | |||
Debt Instrument [Line Items] | |||
Maturity date | [1] | Aug. 1, 2023 | |
Interest rate on fixed rate debt | [1] | 5.875% | |
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2020 [Member] | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 1,600,000,000 | ||
Remaining borrowing capacity | $ 1,436,800,000 | ||
Maturity date | [2] | Oct. 31, 2020 | |
[1] | TPL notes are not guaranteed by us. | ||
[2] | As of December 31, 2016, availability under our $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,436.8 million. |
Debt Obligations, Schedule of C
Debt Obligations, Schedule of Contractual Maturities of Outstanding Debt Obligations (Details) $ in Millions | Dec. 31, 2016USD ($) |
Contractual Obligation [Line Items] | |
Total | $ 4,481.8 |
2,017 | 275 |
2,018 | 250.5 |
2,019 | 749.4 |
2,020 | 150 |
2,021 | 6.5 |
After 2,021 | 3,050.4 |
Accounts Receivable Securitization Facility [Member] | |
Contractual Obligation [Line Items] | |
Total | 275 |
2,017 | 275 |
2,018 | 0 |
2,019 | 0 |
2,020 | 0 |
2,021 | 0 |
After 2,021 | 0 |
Senior Unsecured Notes [Member] | |
Contractual Obligation [Line Items] | |
Total | 4,056.8 |
2,017 | 0 |
2,018 | 250.5 |
2,019 | 749.4 |
2,020 | 0 |
2,021 | 6.5 |
After 2,021 | 3,050.4 |
Revolving Credit Facility [Member] | |
Contractual Obligation [Line Items] | |
Total | 150 |
2,017 | 0 |
2,018 | 0 |
2,019 | 0 |
2,020 | 150 |
2,021 | 0 |
After 2,021 | $ 0 |
Debt Obligations, Interest Rate
Debt Obligations, Interest Rates on Variable-Rate Debt Obligations (Details) | Dec. 31, 2016 |
Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Weighted average interest rate incurred | 1.30% |
Minimum [Member] | Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred, minimum | 1.20% |
Maximum [Member] | Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred, minimum | 1.80% |
TRP Revolver [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Weighted average interest rate incurred | 2.80% |
TRP Revolver [Member] | Minimum [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred, minimum | 2.40% |
TRP Revolver [Member] | Maximum [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred, minimum | 5.30% |
Debt Obligations, Revolving Cre
Debt Obligations, Revolving Credit Agreement (Details) - USD ($) | Feb. 27, 2015 | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Oct. 31, 2016 | Feb. 28, 2015 |
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 1,600,000,000 | |||||
Additional commitment increase available upon request | $ 500,000,000 | $ 300,000,000 | ||||
Write off debt issuance cost | $ 3,500,000 | $ 100,000 | ||||
Atlas Pipeline Partners, L.P. Acquisition [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Cash payments related to change of control payments | 28,800,000 | |||||
Revolving Credit Facility [Member] | Atlas Pipeline Partners, L.P. Acquisition [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Cash payments related to acquisition | $ 701,400,000 | $ 701,400,000 | ||||
TRP Revolver [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Write off debt issuance cost | $ 900,000 | |||||
Maximum consolidated leverage ratio | 5.50 | |||||
Minimum ratio of consolidated EBITDA to consolidated interest expense | 2.25 | |||||
TRP Revolver [Member] | Federal Funds Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Basis spread on variable rate | 0.50% | |||||
TRP Revolver [Member] | London Interbank Offered Rate (LIBOR) | ||||||
Debt Instrument [Line Items] | ||||||
Basis spread on variable rate | 1.00% | |||||
TRP Revolver [Member] | Minimum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Commitment fee percentage | 0.30% | |||||
TRP Revolver [Member] | Minimum [Member] | Base Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Basis spread on variable rate | 0.75% | |||||
TRP Revolver [Member] | Minimum [Member] | Eurodollar [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Basis spread on variable rate | 1.75% | |||||
TRP Revolver [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Commitment fee percentage | 0.50% | |||||
TRP Revolver [Member] | Maximum [Member] | Base Rate [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Basis spread on variable rate | 1.75% | |||||
TRP Revolver [Member] | Maximum [Member] | Eurodollar [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Basis spread on variable rate | 2.75% | |||||
TRP Revolver [Member] | Letters of Credit [Member] | Minimum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate percentage | 1.75% | 1.75% | ||||
TRP Revolver [Member] | Letters of Credit [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate percentage | 2.75% | 2.75% |
Debt Obligations, Accounts Rece
Debt Obligations, Accounts Receivable Securitization Facility (Details) - USD ($) | Dec. 31, 2016 | Oct. 31, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 1,600,000,000 | ||
Funding under securitization facility | $ 275,000,000 | $ 219,300,000 | |
Accounts Receivable Securitization Facility [Member] | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | 275,000,000 | ||
Funding under securitization facility | $ 275,000,000 |
Debt Obligations, Redemption Da
Debt Obligations, Redemption Dates and Prices (Details) | 1 Months Ended | 12 Months Ended |
Oct. 31, 2016 | Dec. 31, 2016 | |
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 103.438% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% | |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% | |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | ||
Debt Instrument [Line Items] | ||
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% | |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% | |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% | |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% | |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% | |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% | |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member] | ||
Debt Instrument [Line Items] | ||
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% | |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% | |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days | |
Any Date Prior To | Sep. 15, 2018 | |
Price | 106.75% | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% | |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% | |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days | |
Any Date Prior To | Nov. 15, 2017 | |
Price | 104.125% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes Due October 2020 [Member] | ||
Debt Instrument [Line Items] | ||
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% | |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% | |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% | |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% | |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% | |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% | |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 2025 [Member] | ||
Debt Instrument [Line Items] | ||
Any Date Prior To | Feb. 1, 2020 | |
Price | 105.125% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 2027 [Member] | ||
Debt Instrument [Line Items] | ||
Any Date Prior To | Feb. 1, 2022 | |
Price | 105.375% | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 15, 2017 [Member] | 2016 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 102.063% | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 15, 2017 [Member] | 2017 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 101.031% | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 15, 2017 [Member] | 2018 and thereafter [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.00% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due February 1, 2017 [Member] | 2017 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 103.188% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due February 1, 2017 [Member] | 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 102.125% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due February 1, 2017 [Member] | 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 101.063% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due February 1, 2017 [Member] | 2020 and thereafter [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.00% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4 % Notes due November 1,2017 [Member] | 2017 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 102.625% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4 % Notes due November 1,2017 [Member] | 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 101.75% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4 % Notes due November 1,2017 [Member] | 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.875% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4 % Notes due November 1,2017 [Member] | 2020 and thereafter [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.00% | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due May 15, 2018 [Member] | 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 102.125% | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due May 15, 2018 [Member] | 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 101.417% | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due May 15, 2018 [Member] | 2020 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.708% | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due May 15, 2018 [Member] | 2021 and thereafter [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.00% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due September 15,2019 [Member] | 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 103.375% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due September 15,2019 [Member] | 2020 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 101.688% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due September 15,2019 [Member] | 2021 and thereafter [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.00% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 1, 2020 [Member] | 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 102.563% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 1, 2020 [Member] | 2022 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 101.281% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 1, 2020 [Member] | 2023 and thereafter [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.00% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 1, 2020 [Member] | 2020 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 103.844% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 1, 2022 [Member] | 2022 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 102.688% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 1, 2022 [Member] | 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 101.792% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 1, 2022 [Member] | 2024 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.896% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 1, 2022 [Member] | 2025 and thereafter [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.00% | |
Senior Unsecured Notes [Member] | Senior Unsecured TPL 4 3/4% Notes due May 15, 2017 [Member] | 2017 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 102.375% | |
Senior Unsecured Notes [Member] | Senior Unsecured TPL 4 3/4% Notes due May 15, 2017 [Member] | 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 101.188% | |
Senior Unsecured Notes [Member] | Senior Unsecured TPL 4 3/4% Notes due May 15, 2017 [Member] | 2021 and thereafter [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.00% | |
Senior Unsecured Notes [Member] | Senior Unsecured TPL 5 7/8% Notes due February 1, 2018 [Member] | 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 102.938% | |
Senior Unsecured Notes [Member] | Senior Unsecured TPL 5 7/8% Notes due February 1, 2018 [Member] | 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 101.958% | |
Senior Unsecured Notes [Member] | Senior Unsecured TPL 5 7/8% Notes due February 1, 2018 [Member] | 2020 [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.979% | |
Senior Unsecured Notes [Member] | Senior Unsecured TPL 5 7/8% Notes due February 1, 2018 [Member] | 2021 and thereafter [Member] | ||
Debt Instrument [Line Items] | ||
Price | 100.00% |
Debt Obligations, Senior Notes
Debt Obligations, Senior Notes Issuances (Details) - Senior Notes [Member] - Partnership Issuers [Member] - USD ($) $ in Millions | 1 Months Ended | |||
Oct. 31, 2016 | Sep. 30, 2015 | Jan. 31, 2015 | Oct. 31, 2014 | |
4⅛% Senior Notes due November 2019 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior notes issued | $ 800 | |||
Interest rate on fixed rate debt | 4.125% | |||
Maturity year | 2,019 | |||
Net proceeds from senior notes | $ 790.8 | |||
5% Senior Notes due January 2018 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior notes issued | $ 1,100 | |||
Interest rate on fixed rate debt | 5.00% | |||
Maturity year | 2,018 | |||
Net proceeds from senior notes | $ 1,089.8 | |||
6 3/4% Senior Notes due March 2024 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior notes issued | $ 600 | |||
Interest rate on fixed rate debt | 6.75% | |||
Maturity year | 2,024 | |||
Net proceeds from senior notes | $ 595 | |||
5⅛% Senior Notes due February 2025 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior notes issued | $ 500 | |||
Interest rate on fixed rate debt | 5.125% | |||
Net proceeds from senior notes | $ 496.2 | |||
Maturity date | Feb. 28, 2025 | |||
5⅜% Senior notes due February 2027 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior notes issued | $ 500 | |||
Interest rate on fixed rate debt | 5.375% | |||
Net proceeds from senior notes | $ 496.2 | |||
Maturity date | Feb. 28, 2027 |
Debt Obligations, Shelf Registr
Debt Obligations, Shelf Registrations Statement (Details) - USD ($) $ in Millions | Apr. 30, 2015 | Jul. 31, 2013 |
July 2013 Shelf [Member] | ||
Debt Instrument [Line Items] | ||
Aggregate amount of debt or equity securities allowed under shelf agreement | $ 800 | |
April 2015 Shelf [Member] | ||
Debt Instrument [Line Items] | ||
Aggregate amount of debt or equity securities allowed under shelf agreement | $ 1,000 |
Debt Obligations, Debt Repurcha
Debt Obligations, Debt Repurchases & Extinguishments (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Nov. 30, 2014 | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||||
Loss on extinguishment of debt | $ 9.7 | ||||
Write off debt issuance cost | $ 3.5 | $ 0.1 | |||
Gain (loss) from financing activities | $ (48.2) | 2.8 | $ (12.4) | ||
Senior Unsecured Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Write off debt issuance cost | 0.1 | ||||
Gain (loss) from financing activities | $ 3.6 | ||||
Senior Unsecured 7 7/8% Notes due October 2018 [Member] | Senior Unsecured Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price, percentage of face value | 103.938% | ||||
Loss on extinguishment of debt | (12.4) | ||||
Premium Paid | 9.9 | ||||
Write off debt issuance cost | $ 2.5 |
Debt Obligations, Summary of De
Debt Obligations, Summary of Debt Repurchased on Open Market Portion of Outstanding Senior Notes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Nov. 15, 2016 | |
Debt Instrument [Line Items] | |||
Debt Repurchase, Book Value | $ 559.2 | $ 17.9 | $ 146.2 |
Debt Repurchase, Payment | (534.3) | (14.3) | |
Gain/(Loss) on Debt Repurchase | 24.9 | 3.6 | |
Debt Repurchase, Write-off of Debt Issuance Costs | (3.5) | (0.1) | |
Net Gain (Loss) on Debt Repurchase | 21.4 | 3.5 | |
5¼% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt Repurchase, Book Value | 24.1 | 16.3 | |
Debt Repurchase, Payment | (20.1) | (13) | |
Gain/(Loss) on Debt Repurchase | 4 | 3.3 | |
Debt Repurchase, Write-off of Debt Issuance Costs | (0.2) | (0.1) | |
Net Gain (Loss) on Debt Repurchase | 3.8 | 3.2 | |
4¼% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt Repurchase, Book Value | 39.5 | 1.5 | |
Debt Repurchase, Payment | (31.8) | (1.2) | |
Gain/(Loss) on Debt Repurchase | 7.7 | 0.3 | |
Debt Repurchase, Write-off of Debt Issuance Costs | (0.3) | ||
Net Gain (Loss) on Debt Repurchase | 7.4 | 0.3 | |
6⅝% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt Repurchase, Book Value | 32.6 | 0.1 | |
Debt Repurchase, Payment | (29.5) | $ (0.1) | |
Gain/(Loss) on Debt Repurchase | 3.1 | ||
Net Gain (Loss) on Debt Repurchase | 3.1 | ||
6⅞% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt Repurchase, Book Value | 4.8 | ||
Debt Repurchase, Payment | (4.3) | ||
Gain/(Loss) on Debt Repurchase | 0.5 | ||
Debt Repurchase, Write-off of Debt Issuance Costs | (0.1) | ||
Net Gain (Loss) on Debt Repurchase | 0.4 | ||
6⅜% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt Repurchase, Book Value | 21.3 | ||
Debt Repurchase, Payment | (18.7) | ||
Gain/(Loss) on Debt Repurchase | 2.6 | ||
Debt Repurchase, Write-off of Debt Issuance Costs | (0.2) | ||
Net Gain (Loss) on Debt Repurchase | 2.4 | ||
6¾% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt Repurchase, Book Value | 19.9 | ||
Debt Repurchase, Payment | (17.5) | ||
Gain/(Loss) on Debt Repurchase | 2.4 | ||
Debt Repurchase, Write-off of Debt Issuance Costs | (0.2) | ||
Net Gain (Loss) on Debt Repurchase | 2.2 | ||
5% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt Repurchase, Book Value | 366.4 | ||
Debt Repurchase, Payment | (368.2) | ||
Gain/(Loss) on Debt Repurchase | (1.8) | ||
Debt Repurchase, Write-off of Debt Issuance Costs | (2.1) | ||
Net Gain (Loss) on Debt Repurchase | (3.9) | ||
4⅛% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt Repurchase, Book Value | 50.6 | ||
Debt Repurchase, Payment | (44.2) | ||
Gain/(Loss) on Debt Repurchase | 6.4 | ||
Debt Repurchase, Write-off of Debt Issuance Costs | (0.4) | ||
Net Gain (Loss) on Debt Repurchase | $ 6 |
Debt Obligations, Issuance of S
Debt Obligations, Issuance of Senior Notes and Concurrent Senior Notes Tender Offers (Details) - Concurrent Senior Notes with Offers Tender [Member] - USD ($) $ in Millions | 1 Months Ended | |||
Oct. 31, 2016 | Dec. 31, 2016 | Oct. 05, 2016 | Sep. 30, 2016 | |
Debt Instrument [Line Items] | ||||
Tender offers principal amount | $ 383.8 | $ 1,000 | $ 1,522.1 | |
Senior Unsecured 5% Notes due January 2018 [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest rate percentage | 5.00% | |||
Maturity date | Jan. 31, 2018 | |||
Tender offers principal amount | 250.5 | 733.6 | ||
Senior Unsecured 6 5/8% Notes due October 2020 [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest rate percentage | 6.625% | |||
Maturity date | Oct. 31, 2020 | |||
Tender offers principal amount | 28.2 | 309.9 | ||
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest rate percentage | 6.875% | |||
Maturity date | Feb. 28, 2021 | |||
Tender offers principal amount | $ 105.1 | $ 478.6 |
Debt Obligations, Senior Note84
Debt Obligations, Senior Notes Tender Offers (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Debt Instrument [Line Items] | |||||
Accrued Interest Paid | [1] | $ 263.8 | $ 193.1 | $ 131 | |
Concurrent Senior Notes with Offers Tender [Member] | |||||
Debt Instrument [Line Items] | |||||
Outstanding Note Balance Prior to Tender Offers | $ 1,522.1 | ||||
Amount Tendered | 1,138.3 | ||||
Premium Paid | 41.8 | ||||
Accrued Interest Paid | 10.3 | ||||
Total Tender Offer Payments | 1,190.4 | ||||
Note Balance After Tender Offers | 383.8 | 383.8 | |||
Concurrent Senior Notes with Offers Tender [Member] | Senior Unsecured 5% Notes due January 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Outstanding Note Balance Prior to Tender Offers | 733.6 | ||||
Amount Tendered | 483.1 | ||||
Premium Paid | 16.9 | ||||
Accrued Interest Paid | 5.4 | ||||
Total Tender Offer Payments | 505.4 | ||||
Note Balance After Tender Offers | 250.5 | 250.5 | |||
Concurrent Senior Notes with Offers Tender [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Outstanding Note Balance Prior to Tender Offers | 309.9 | ||||
Amount Tendered | 281.7 | ||||
Premium Paid | 10.5 | ||||
Accrued Interest Paid | 0.3 | ||||
Total Tender Offer Payments | 292.5 | ||||
Note Balance After Tender Offers | 28.2 | 28.2 | |||
Concurrent Senior Notes with Offers Tender [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Outstanding Note Balance Prior to Tender Offers | 478.6 | ||||
Amount Tendered | 373.5 | ||||
Premium Paid | 14.4 | ||||
Accrued Interest Paid | 4.6 | ||||
Total Tender Offer Payments | 392.5 | ||||
Note Balance After Tender Offers | $ 105.1 | $ 105.1 | |||
[1] | Interest capitalized on major projects was $8.3 million, $13.2 million and $16.1 million for 2016, 2015 and 2014. |
Debt Obligations, Note Redempti
Debt Obligations, Note Redemptions (Details) - USD ($) $ in Millions | Nov. 15, 2016 | Oct. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | |||||
Face amount of notes redeemed | $ 146.2 | $ 559.2 | $ 559.2 | $ 17.9 | |
Debt instrument redemption payment | $ 151.1 | ||||
Loss on extinguishment of debt | 9.7 | ||||
Write off debt issuance cost | $ 3.5 | $ 0.1 | |||
Write off of debt premiums | 0.5 | ||||
Write off debt discounts | 4.2 | ||||
Targa Pipeline Partners LP [Member] | |||||
Debt Instrument [Line Items] | |||||
Write off debt issuance cost | $ 1.1 | ||||
Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price, percentage of face value | 103.313% | ||||
Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Targa Pipeline Partners LP [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price, percentage of face value | 103.313% | ||||
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Redemption price, percentage of face value | 103.438% |
Debt Obligations, APL Senior No
Debt Obligations, APL Senior Notes Tender Offers (Details) - USD ($) $ in Millions | Apr. 27, 2015 | Feb. 27, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||||||
Accrued Interest Paid | [1] | $ 263.8 | $ 193.1 | $ 131 | |||
Repayment of debt | 13.3 | 1,168.8 | 0 | ||||
Senior Unsecured 6 5/8% Notes due 2020 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Maturity year | 2,020 | ||||||
Senior Unsecured 6 5/8% Notes due 2020 [Member] | Targa Pipeline Partners LP [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Tendered percentage | 96.30% | ||||||
Concurrent Senior Notes with Offers Tender [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding Note Balance Prior to Tender Offers | 414.5 | 1,550 | |||||
Amount Tendered | 1,135.5 | ||||||
Premium Paid | 16.7 | ||||||
Accrued Interest Paid | 11.6 | ||||||
Total Tender Offer Payments | 1,163.8 | ||||||
Note Balance After Tender Offers | 414.5 | 1,550 | |||||
Payments for notes tendered and settled upon closing of merger | 1,135.5 | ||||||
Concurrent Senior Notes with Offers Tender [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding Note Balance Prior to Tender Offers | 48.1 | 650 | |||||
Amount Tendered | 601.9 | ||||||
Premium Paid | 8.7 | ||||||
Accrued Interest Paid | 2.6 | ||||||
Total Tender Offer Payments | $ 613.2 | ||||||
Tendered percentage | 92.60% | ||||||
Note Balance After Tender Offers | $ 48.1 | 650 | |||||
Interest rate on fixed rate debt | 5.875% | ||||||
Maturity year | 2,023 | ||||||
Payments for notes tendered and settled upon closing of merger | 601.9 | ||||||
Concurrent Senior Notes with Offers Tender [Member] | Senior Unsecured 4 3/4% Notes due 2021 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding Note Balance Prior to Tender Offers | 6.5 | 400 | |||||
Amount Tendered | 393.5 | ||||||
Premium Paid | 5.9 | ||||||
Accrued Interest Paid | 5.3 | ||||||
Total Tender Offer Payments | $ 404.7 | ||||||
Tendered percentage | 98.38% | ||||||
Note Balance After Tender Offers | $ 6.5 | 400 | |||||
Interest rate on fixed rate debt | 4.75% | ||||||
Maturity year | 2,021 | ||||||
Payments for notes tendered and settled upon closing of merger | 393.5 | ||||||
Concurrent Senior Notes with Offers Tender [Member] | Senior Unsecured 6 5/8% Notes due 2020 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Outstanding Note Balance Prior to Tender Offers | $ 359.9 | 500 | |||||
Amount Tendered | 140.1 | ||||||
Premium Paid | 2.1 | ||||||
Accrued Interest Paid | 3.7 | ||||||
Total Tender Offer Payments | $ 145.9 | ||||||
Tendered percentage | 28.02% | ||||||
Note Balance After Tender Offers | $ 359.9 | $ 500 | |||||
Payments for notes tendered and settled upon closing of merger | $ 140.1 | ||||||
Concurrent Senior Notes with Offers Tender [Member] | Senior Unsecured 6 5/8% Notes due 2020 [Member] | Targa Pipeline Partners LP [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Amount Tendered | $ 4.8 | ||||||
Total Tender Offer Payments | 5 | ||||||
Payments for notes tendered and settled upon closing of merger | $ 4.8 | ||||||
[1] | Interest capitalized on major projects was $8.3 million, $13.2 million and $16.1 million for 2016, 2015 and 2014. |
Debt Obligations, Exchange Offe
Debt Obligations, Exchange Offer and Consent Solicitation (Details) - Senior Unsecured 6 5/8% Notes due October 2020 [Member] - Targa Pipeline Partners LP [Member] - USD ($) $ in Millions | Apr. 27, 2015 | Dec. 31, 2015 | May 31, 2015 |
Debt Instrument [Line Items] | |||
Tendered percentage | 96.30% | ||
Costs associated with exchange offer | $ 0.7 | ||
Partnership Issuers [Member] | |||
Debt Instrument [Line Items] | |||
Outstanding Note Balance | $ 342.1 | ||
Unamortized premium | $ 5.6 |
Debt Obligations, Debt Repurc88
Debt Obligations, Debt Repurchases Summary (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||
Loss (gain) on repurchase of debt | $ (48.2) | $ 2.8 | $ (12.4) |
Senior Unsecured Notes [Member] | |||
Debt Instrument [Line Items] | |||
Loss (gain) on repurchase of debt | 3.6 | ||
Write-off of debt issuance costs | 0.9 | ||
Loss (gain) from financing activities | 48.2 | (2.8) | 12.4 |
Senior Unsecured Notes [Member] | 5% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Premium over face value paid upon redemption | 16.9 | ||
Loss (gain) on repurchase of debt | 1.8 | ||
Write-off of debt issuance costs | 4.2 | ||
Senior Unsecured Notes [Member] | 6⅝% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Premium over face value paid upon redemption | 11.5 | ||
Recognition of unamortized premium | (4.3) | ||
Loss (gain) on repurchase of debt | (2.8) | ||
Loss from financing with exchange offer | 0.7 | ||
Senior Unsecured Notes [Member] | 6⅞% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Premium over face value paid upon redemption | 18 | ||
Recognition of unamortized discount | 19.5 | ||
Loss (gain) on repurchase of debt | (0.8) | ||
Write-off of debt issuance costs | 4.9 | ||
Senior Unsecured Notes [Member] | 6⅝% TPL Notes | Targa Pipeline Partners LP [Member] | |||
Debt Instrument [Line Items] | |||
Premium over face value paid upon redemption | 0.4 | ||
Recognition of unamortized premium | (0.2) | ||
Senior Unsecured Notes [Member] | 7⅞% Senior Notes | |||
Debt Instrument [Line Items] | |||
Premium over face value paid upon redemption | 9.9 | ||
Write-off of debt issuance costs | $ 2.5 | ||
Senior Unsecured Notes [Member] | 4⅛% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Loss (gain) on repurchase of debt | (6.4) | ||
Write-off of debt issuance costs | 0.4 | ||
Senior Unsecured Notes [Member] | 6⅜% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Loss (gain) on repurchase of debt | (2.6) | ||
Write-off of debt issuance costs | 0.2 | ||
Senior Unsecured Notes [Member] | 5¼% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Loss (gain) on repurchase of debt | (4) | (3.3) | |
Write-off of debt issuance costs | 0.2 | 0.1 | |
Senior Unsecured Notes [Member] | 4¼% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Loss (gain) on repurchase of debt | (7.7) | $ (0.3) | |
Write-off of debt issuance costs | 0.3 | ||
Senior Unsecured Notes [Member] | 6¾% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Loss (gain) on repurchase of debt | (2.4) | ||
Write-off of debt issuance costs | $ 0.2 |
Other Long-term Liabilities (De
Other Long-term Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Other Liabilities Noncurrent [Abstract] | |||
Asset retirement obligations | $ 64.1 | $ 69.9 | $ 56.8 |
Mandatorily redeemable preferred interests | 68.5 | 82.9 | |
Deferred revenue | 69.8 | 27.7 | $ 4.1 |
Other liabilities | 2.9 | 4.4 | |
Total long-term liabilities | $ 205.3 | $ 184.9 |
Other Long-term Liabilities, As
Other Long-term Liabilities, Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning of period | $ 69.9 | $ 56.8 | |
Fair value of ARO acquired with APL merger | 0 | 4 | |
Change in cash flow estimate | (9.1) | 3.8 | $ 2.1 |
Accretion expense | 4.6 | 5.3 | 4.4 |
Retirement of ARO | (1.3) | 0 | |
End of period | $ 64.1 | $ 69.9 | $ 56.8 |
Other Long-term Liabilities, Ma
Other Long-term Liabilities, Mandatorily Redeemable Preferred Interests (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)JointVenture | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Beginning of period | $ 82.9 | ||
Income attributable to mandatorily redeemable preferred interests | (20.7) | $ 31.9 | $ (37.4) |
Increase (decrease) in redemption value of mandatorily redeemable preferred interests | (15.2) | (30.6) | 0 |
End of period | $ 68.5 | 82.9 | |
Mandatorily Redeemable Preferred Interests [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Number of joint ventures | JointVenture | 2 | ||
Interest earned on notes receivable, net | $ 10.5 | 8.9 | |
Beginning of period | 82.9 | 0 | |
Acquired mandatorily redeemable preferred interests | 0 | 109.3 | |
Income attributable to mandatorily redeemable preferred interests | 0.8 | 2.8 | |
Increase (decrease) in redemption value of mandatorily redeemable preferred interests | (15.2) | (30.6) | |
Other activity, net | 0 | 1.4 | |
End of period | $ 68.5 | $ 82.9 | $ 0 |
Mandatorily Redeemable Preferred Interests [Member] | Joint Ventures [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Number of joint ventures | JointVenture | 2 | ||
Notes receivable, face amount | $ 1,900 | ||
Notes receivable, due date | Jul. 31, 2042 | ||
Mandatorily Redeemable Preferred Interests [Member] | WestOK [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Ownership interest | 100.00% | ||
Mandatorily Redeemable Preferred Interests [Member] | WestTX [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Ownership interest | 72.80% |
Other Long-term Liabilities, De
Other Long-term Liabilities, Deferred Revenue (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 27, 2015bbl | |
Deferred Revenue [Abstract] | ||||
Revenue recognized | $ | $ 3.1 | $ 2.7 | $ 0.1 | |
Channelview Splitter | ||||
Deferred Revenue [Abstract] | ||||
Crude oil and Condensate split operation per day | bbl | 35,000 | |||
Storage capacity of Channelview Terminal | bbl | 730,000 | |||
Channelview Splitter capability to split crude oil and condensate barrel per day | bbl | 35,000 | |||
Channelview Splitter project expected completion period | 2,018 | |||
Channelview Splitter project estimated total cost | $ | $ 140 | |||
Annual differed revenue payments receivable through 2022 | $ | $ 43 | |||
Deferred revenue recognition period over Splitter Agreement start-up period | 2,018 | |||
Deferred revenue recognition period over Splitter Agreement end period | 2,025 |
Other Long-term Liabilities, Co
Other Long-term Liabilities, Components Of Deferred Revenue (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | $ 69.8 | $ 27.7 | $ 4.1 |
Other Deferred Revenue | |||
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | 7.1 | 6.6 | |
Gas Contract Amendment | |||
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | 19.7 | $ 21.1 | |
Channelview Splitter | |||
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | $ 43 |
Other Long-term Liabilities, Ch
Other Long-term Liabilities, Changes In Deferred Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Other Liabilities Noncurrent [Abstract] | |||
Beginning of period | $ 27.7 | $ 4.1 | |
Additions | 45.2 | 26.3 | |
Revenue recognized | (3.1) | (2.7) | $ (0.1) |
End of period | $ 69.8 | $ 27.7 | $ 4.1 |
Partnership Units and Related95
Partnership Units and Related Matters (Details) $ / shares in Units, $ in Millions | Feb. 17, 2016shares | Feb. 27, 2015USD ($)shares | Dec. 31, 2016USD ($)$ / sharesshares | Oct. 31, 2015USD ($)$ / sharesshares | May 31, 2015USD ($) | Mar. 31, 2015 | May 31, 2014USD ($) | Dec. 31, 2016USD ($)$ / sharesshares | Dec. 31, 2015USD ($)shares | Dec. 31, 2014USD ($)shares | Jan. 31, 2016shares |
Limited Partners Capital Account [Line Items] | |||||||||||
Common limited partners units issued (in units) | 275,168,410 | 275,168,410 | 185,083,420 | 0 | |||||||
Net proceeds from sale of common units | $ | $ 316.1 | ||||||||||
General partner contributed to maintain general partner ownership percentage | $ | $ 6.5 | $ 8.4 | |||||||||
Percentage of general partner's interest maintained | 2.00% | 2.00% | |||||||||
Conversion ratio in stock-for-unit transaction | 0.62 | ||||||||||
Number of shares issued in exchange of common units for common shares to the third party (in shares) | 104,525,775 | ||||||||||
Series A preferred limited partners units outstanding (in units) | 5,000,000 | 5,000,000 | |||||||||
Contributions from Targa Resources Corp. | $ | $ 1,381 | $ 60.1 | $ 7.7 | ||||||||
General partner units issued (in units) | 5,629,136 | 5,629,136 | 3,772,871 | ||||||||
Distribution to holders of preferred units | $ | $ 11.3 | $ 1.5 | |||||||||
Series A Preferred Units due November 1, 2020 [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Preferred units dividend percentage | 9.00% | ||||||||||
Preferred unit, redemption price (in dollars per share) | $ / shares | $ 25 | $ 25 | |||||||||
Series A Preferred Units due November 1, 2020 [Member] | London Interbank Offered Rate (LIBOR) | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Percentage of variable interest rate for distribution on preferred units upon maturity | 7.71% | ||||||||||
Series A Preferred Limited Partner Units [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Series A preferred limited partners units outstanding (in units) | 5,000,000 | 5,000,000 | 5,000,000 | ||||||||
Series A preferred limited partners units issued (in units) | 5,000,000 | 5,000,000 | 5,000,000 | ||||||||
Preferred units dividend percentage | 9.00% | ||||||||||
Targa Resources Partners Lp | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Number of shares exchanged in exchange of common units for common shares to the third party (in shares) | 168,590,009 | ||||||||||
Common Units [Member] | Targa Resources Corp [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
General partner contributed to maintain general partner ownership percentage | $ | $ 52.4 | ||||||||||
Percentage of general partner's interest maintained | 2.00% | ||||||||||
Atlas Pipeline Partners [Member] | Targa Resources Corp [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Percentage of general partner's interest maintained | 2.00% | ||||||||||
Atlas Pipeline Partners [Member] | Common Units [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Number of common units included in public offering (in shares) | 58,614,157 | ||||||||||
Atlas Energy [Member] | Common Units [Member] | Targa Pipeline Partners LP [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Number of common units included in public offering (in shares) | 3,363,935 | ||||||||||
Atlas Energy [Member] | Common Units [Member] | Targa Resources Corp [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Number of common units included in public offering (in shares) | 10,126,532 | ||||||||||
TRC/TRP Merger | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Common limited partners units issued (in units) | 58,621,036 | 58,621,036 | |||||||||
Percentage of general partner's interest maintained | 2.00% | ||||||||||
Contributions from Targa Resources Corp. | $ | $ 1,191 | ||||||||||
General partner units issued (in units) | 1,196,346 | 1,196,346 | |||||||||
Percentage of capital contribution towards partner's interest maintained | 98.00% | ||||||||||
TRC/TRP Merger | Targa Resources Corp [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Contributions from Targa Resources Corp. | $ | $ 190 | $ 1,381 | |||||||||
May 2014 EDA [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Dollar amount of common units able to sell from Equity Distribution Agreement | $ | $ 400 | ||||||||||
Capacity remaining available under shelf agreement | $ | $ 4.2 | ||||||||||
August 2013 And May 2014 EDA [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Common limited partners units issued (in units) | 7,175,096 | ||||||||||
Net proceeds from sale of common units | $ | $ 408.4 | ||||||||||
Commissions to sales agents, maximum | 1.00% | ||||||||||
May 2015 EDA [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Dollar amount of common units able to sell from Equity Distribution Agreement | $ | $ 1,000 | ||||||||||
Common limited partners units issued (in units) | 7,377,380 | ||||||||||
Capacity remaining available under shelf agreement | $ | $ 835.6 | ||||||||||
April 2013 Shelf [Member] | Series A Preferred Units [Member] | |||||||||||
Limited Partners Capital Account [Line Items] | |||||||||||
Series A preferred limited partners units issued (in units) | 4,400,000 | ||||||||||
Preferred stock, par value (in dollar per share) | $ / shares | $ 25 | ||||||||||
Number of additional preferred units sold in public offering (in shares) | 600,000 | ||||||||||
Net proceeds received after costs | $ | $ 121.1 |
Partnership Units and Related96
Partnership Units and Related Matters, Distributions (Details) $ / shares in Units, $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||||||||
Feb. 28, 2017USD ($)$ / shares | Jan. 31, 2017USD ($)$ / shares | Dec. 31, 2016USD ($)shares | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($)shares | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($)Distributionshares | Dec. 31, 2014USD ($) | Dec. 01, 2016shares | Jan. 31, 2016shares | |
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Date paid | Feb. 10, 2017 | Nov. 11, 2016 | Aug. 11, 2016 | May 12, 2016 | Feb. 9, 2016 | Nov. 13, 2015 | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 | Nov. 14, 2014 | Aug. 14, 2014 | May 15, 2014 | |||||||
Total Distributions | $ 737,300 | $ 733,600 | $ 493,800 | ||||||||||||||||
Limited Partner unit in exchange for the elimination of the IDRs and Special GP Interest | shares | 275,168,410 | 185,083,420 | 275,168,410 | 185,083,420 | 0 | ||||||||||||||
General Partner unit in exchange for the elimination of the IDRs and Special GP Interest | shares | 5,629,136 | 3,772,871 | 5,629,136 | 3,772,871 | |||||||||||||||
Scenario Forecast [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Distributions to Targa Resources Corp. | $ 900 | ||||||||||||||||||
Cash distribution to be paid | Mar. 15, 2017 | ||||||||||||||||||
Preferred Unit [Member] | Scenario Forecast [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Date of declaration for cash distribution | 2017-02 | ||||||||||||||||||
Cash distribution declared per unit (in dollars per share) | $ / shares | $ 0.1875 | ||||||||||||||||||
Subsequent Event [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Distributions to Targa Resources Corp. | $ 900 | ||||||||||||||||||
Cash distribution to be paid | Feb. 15, 2017 | ||||||||||||||||||
Subsequent Event [Member] | Preferred Unit [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Date of declaration for cash distribution | 2017-01 | ||||||||||||||||||
Cash distribution declared per unit (in dollars per share) | $ / shares | $ 0.1875 | ||||||||||||||||||
IDRs [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Limited Partner unit in exchange for the elimination of the IDRs and Special GP Interest | shares | 20,380,286 | ||||||||||||||||||
General Partner unit in exchange for the elimination of the IDRs and Special GP Interest | shares | 424,590 | ||||||||||||||||||
Special GP Interest [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Limited Partner unit in exchange for the elimination of the IDRs and Special GP Interest | shares | 11,267,485 | ||||||||||||||||||
General Partner unit in exchange for the elimination of the IDRs and Special GP Interest | shares | 234,739 | ||||||||||||||||||
Atlas Pipeline Partners [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Reduction in incentive distribution | $ 9,375 | $ 9,375 | $ 9,375 | $ 9,375 | |||||||||||||||
Number of quarterly distributions that will be reduced | Distribution | 16 | ||||||||||||||||||
Distribution Rights First Quarter for 2016 [Member] | Atlas Pipeline Partners [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Reduction in incentive distribution | $ 6,250 | $ 6,250 | $ 6,250 | ||||||||||||||||
Distributions Paid [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Total Distributions | $ 198,100 | 194,700 | 181,700 | 157,600 | 200,400 | 200,400 | 200,400 | 193,900 | $ 137,400 | $ 130,900 | $ 125,700 | $ 121,300 | |||||||
Distributions to Targa Resources Corp. | $ 195,300 | $ 191,900 | $ 178,900 | $ 154,800 | $ 61,400 | $ 61,400 | $ 61,400 | $ 59,000 | $ 51,600 | $ 48,900 | $ 46,300 | $ 44,000 |
Derivative Instruments and He97
Derivative Instruments and Hedging Activities (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)MMBTUbbl | Dec. 31, 2015USD ($) | Feb. 27, 2015USD ($) | |
Derivative [Line Items] | |||
Fair value of derivative assets | $ | $ 102.1 | ||
Estimated fair value of derivative instruments, net liability | $ | $ 53.3 | ||
Amount expected to reclassify commodity hedge related deferred losses to earnings before income taxes | $ | 60.7 | ||
Amount of deferred losses to be reclassified into earnings before income taxes over next twelve months | $ | $ 39.7 | ||
Year 2017 [Member] | Swaps [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 2,270 | ||
Year 2017 [Member] | Swaps [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 133,448 | ||
Year 2017 [Member] | Swaps [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 9,635 | ||
Year 2017 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 72,219 | ||
Year 2017 [Member] | Options [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 1,380 | ||
Year 2017 [Member] | Options [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 22,900 | ||
Year 2017 [Member] | Options [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 1,468 | ||
Year 2017 [Member] | Future | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 6,118 | ||
Year 2018 [Member] | Swaps [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 1,770 | ||
Year 2018 [Member] | Swaps [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 84,800 | ||
Year 2018 [Member] | Swaps [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 4,688 | ||
Year 2018 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 | ||
Year 2018 [Member] | Options [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 691 | ||
Year 2018 [Member] | Options [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 9,486 | ||
Year 2018 [Member] | Options [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 1,676 | ||
Year 2018 [Member] | Future | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 959 | ||
Year 2019 [Member] | Swaps [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 643 | ||
Year 2019 [Member] | Swaps [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 45,683 | ||
Year 2019 [Member] | Swaps [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 3,369 | ||
Year 2019 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 | ||
Year 2019 [Member] | Options [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 590 | ||
Year 2019 [Member] | Options [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 | ||
Year 2019 [Member] | Options [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 0 | ||
Year 2019 [Member] | Future | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 0 | ||
Atlas Pipeline Partners [Member] | |||
Derivative [Line Items] | |||
Fair value of derivative assets | $ | $ 102.1 | ||
Fair value of derivative contracts received as component of derivative contract settlement | $ | $ 26.6 | $ 67.9 | |
Ineffectiveness losses | $ | $ 0 | $ 0.9 |
Derivative Instruments and He98
Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets | $ 21.9 | $ 127.1 |
Derivative liabilities | 75.2 | 7.6 |
Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 16.8 | 92.2 |
Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 5.1 | 34.9 |
Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 49.1 | 5.2 |
Long-term Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 26.1 | 2.4 |
Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 21.8 | 127 |
Derivative liabilities | 74.7 | 4.5 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 16.7 | 92.1 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 5.1 | 34.9 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 48.6 | 2.1 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 26.1 | 2.4 |
Not Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 0.1 | 0.1 |
Derivative liabilities | 0.5 | 3.1 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 0.1 | 0.1 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | $ 0.5 | $ 3.1 |
Derivative Instruments and He99
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative Asset [Abstract] | ||
Derivative assets | $ 21.9 | $ 127.1 |
Pro forma net presentation, asset, total | 5.7 | 119.5 |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 21.9 | 121.1 |
Pro forma net presentation, asset | 5.7 | 113.5 |
Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 6 | |
Pro forma net presentation, asset | 6 | |
Current Position [Member] | ||
Derivative Asset [Abstract] | ||
Derivative assets | 16.8 | 92.2 |
Pro forma net presentation, asset, current | 5.7 | 87 |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 16.8 | 86.9 |
Pro forma net presentation, asset | 5.7 | 81.7 |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 5.3 | |
Pro forma net presentation, asset | 5.3 | |
Long-term Position [Member] | ||
Derivative Asset [Abstract] | ||
Derivative assets | 5.1 | 34.9 |
Pro forma net presentation, asset, noncurrent | 32.5 | |
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | $ 5.1 | 34.2 |
Pro forma net presentation, asset | 31.8 | |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 0.7 | |
Pro forma net presentation, asset | $ 0.7 |
Derivative Instruments and H100
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative Liability [Abstract] | ||
Gross liability | $ (75.2) | $ (7.6) |
Pro forma net presentation, liability, total | (52) | |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (64.8) | (7.6) |
Pro forma net presentation, liability, total | (41.6) | |
Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (10.4) | |
Pro forma net presentation, liability, total | (10.4) | |
Current Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (49.1) | (5.2) |
Pro forma net presentation, liability, current | (31) | |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (46.1) | (5.2) |
Pro forma net presentation, liability, current | (28) | |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (3) | |
Pro forma net presentation, liability, current | (3) | |
Long-term Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (26.1) | (2.4) |
Pro forma net presentation, liability, noncurrent | (21) | |
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (18.7) | $ (2.4) |
Pro forma net presentation, liability, noncurrent | (13.6) | |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (7.4) | |
Pro forma net presentation, liability, noncurrent | $ (7.4) |
Derivative Instruments and H101
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Collateral (Details) $ in Millions | Dec. 31, 2016USD ($) |
Derivative Asset [Abstract] | |
Gross collateral | $ 7 |
Counterparties with Offsetting Position or Collateral [Member] | |
Derivative Asset [Abstract] | |
Gross collateral | 7 |
Current Position [Member] | |
Derivative Asset [Abstract] | |
Gross collateral | 7 |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | |
Derivative Asset [Abstract] | |
Gross collateral | $ 7 |
Derivative Instruments and H102
Derivative Instruments and Hedging Activities, Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (Loss) Reclassified from OCI into Income (Effective Portion) | $ 45 | $ 86.3 | $ (6.6) |
Interest Expense, Net [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (Loss) Reclassified from OCI into Income (Effective Portion) | (2.4) | ||
Revenues [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (Loss) Reclassified from OCI into Income (Effective Portion) | 45 | 86.3 | (4.2) |
Commodity Contracts [Member] | Revenues [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) recognized in income on derivatives | 0.9 | (5.7) | (5.5) |
Cash Flow Hedging [Member] | Commodity Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) | $ (103.6) | $ 112.7 | $ 59.7 |
Fair Value Measurements, Breakd
Fair Value Measurements, Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Derivatives financial instruments, fair value, net | $ 53.3 | ||
Derivative fair value of net liability if commodity price increases by 10 percent | 107.4 | ||
Derivative fair value of net asset if commodity price decreases by 10 percent | 14.9 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | 5.7 | $ 119.5 | |
Liabilities from commodity derivative contracts | 52 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Accounts receivable securitization facility | 275 | 219.3 | |
Carrying Value [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 21 | 127.1 |
Liabilities from commodity derivative contracts | [1] | 74.2 | 7.6 |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 68 | 135.4 | |
Accounts receivable securitization facility | 275 | 219.3 | |
Carrying Value [Member] | TRP Revolver [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 150 | 280 | |
Carrying Value [Member] | Targa Pipeline Partners LP [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Contingent consideration | [2] | 2.6 | 3 |
Carrying Value [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 4,057.3 | 4,884 | |
Fair Value [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 21 | 127.1 |
Liabilities from commodity derivative contracts | [1] | 74.2 | 7.6 |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 68 | 135.4 | |
Accounts receivable securitization facility | 275 | 219.3 | |
Fair Value [Member] | TRP Revolver [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 150 | 280 | |
Fair Value [Member] | Targa Pipeline Partners LP [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Contingent consideration | [2] | 2.6 | 3 |
Fair Value [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 4,101.6 | 4,192 | |
Fair Value [Member] | Level 2 [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 19.6 | 123.1 |
Liabilities from commodity derivative contracts | [1] | 69.3 | 7.3 |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Accounts receivable securitization facility | 275 | 219.3 | |
Fair Value [Member] | Level 2 [Member] | TRP Revolver [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 150 | 280 | |
Fair Value [Member] | Level 2 [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 4,101.6 | 4,192 | |
Fair Value [Member] | Level 3 [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 1.4 | 4 |
Liabilities from commodity derivative contracts | [1] | 4.9 | 0.3 |
Fair Value [Member] | Level 3 [Member] | Targa Pipeline Partners LP [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Contingent consideration | [2] | $ 2.6 | $ 3 |
[1] | The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 – Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes. | ||
[2] | See Note 4 – Business Acquisitions. |
Fair Value Measurements, Change
Fair Value Measurements, Changes in Fair Value of Financial Instruments Classified as Level 3 (Details) | 12 Months Ended |
Dec. 31, 2016USD ($)Swap | |
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items] | |
Number of natural gas basis swaps categorized as Level 3 | Swap | 17 |
Transfers out of Level 3 | $ 0 |
Contingent Liability [Member] | |
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items] | |
Balance, beginning of period | (3,000,000) |
Change in fair value of TPL contingent consideration | 400,000 |
Balance, end of period | (2,600,000) |
Commodity Contracts [Member] | |
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items] | |
Balance, beginning of period | 3,700,000 |
New Level 3 instruments | 900,000 |
Settlements included in Revenue | 200,000 |
Unrealized gain/(loss) included in OCI | (8,400,000) |
Balance, end of period | $ (3,600,000) |
Related Party Transactions -105
Related Party Transactions - Targa (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Summary of transactions with Targa [Abstract] | ||||
Cash contributions from Targa related to limited partner ownership | $ 1,353.4 | $ 0 | $ 0 | |
Percentage of general partner's interest maintained | 2.00% | 2.00% | ||
GCF [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Revenues from transactions with related party | 0.4 | $ 0.5 | $ 0.8 | |
Costs and expenses from transactions with related party | 3.2 | 5.8 | 7.6 | |
T2 Eagle Ford [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Revenues from transactions with related party | 4.6 | 4.4 | ||
Costs and expenses from transactions with related party | 3.2 | 3 | ||
Cost of sales attributable to related party | 2.6 | 4 | ||
Receivable balance with related party | 0.2 | 0.4 | ||
T2 EF Cogen [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Revenues from transactions with related party | 0.6 | 1.4 | ||
Receivable balance with related party | 0.1 | |||
T2 La Salle [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Costs and expenses from transactions with related party | 0.8 | 1.3 | ||
Targa Resources Corp. [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Targa billings of payroll and related costs included in operating expense | 171.8 | 153.8 | 124.9 | |
Targa allocation of general and administrative expense | 159.9 | 136.2 | 129.4 | |
Cash distributions to Targa based on IDR, GP and common unit ownership | 587 | 233.4 | 180.7 | |
Cash contributions from Targa related to limited partner ownership | [1] | 1,353.4 | ||
Contributions from Targa Resources Corp | $ 27.6 | $ 60.1 | $ 7.7 | |
Percentage of general partner's interest maintained | 2.00% | |||
Targa Resources Corp. [Member] | Third A&R Partnership Agreement [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Cash contributions from Targa related to limited partner ownership | $ 186.2 | |||
Targa Resources Corp. [Member] | Issuance of Common Units [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Cash contributions from Targa related to limited partner ownership | $ 1,167.2 | |||
[1] | Of the cash contributions from Targa related to limited partner ownership, $1,167.2 million was contributed for the issuance of common units and $186.2 million was contributed after the Third A&R Partnership Agreement. |
Commitments (Leases) (Details)
Commitments (Leases) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Future lease obligations in aggregate and for each of the next five fiscal years [Abstract] | ||||
In Aggregate | $ 49.8 | |||
2,017 | 17.8 | |||
2,018 | 12.9 | |||
2,019 | 8 | |||
2,020 | 6.3 | |||
2,021 | 4.8 | |||
Total expenses on lease obligations, including short-term leases of compressors and equipment | 49.5 | $ 46.6 | $ 28.5 | |
Operating Leases [Member] | ||||
Future lease obligations in aggregate and for each of the next five fiscal years [Abstract] | ||||
In Aggregate | [1] | 35.6 | ||
2,017 | [1] | 14.6 | ||
2,018 | [1] | 10.1 | ||
2,019 | [1] | 5.2 | ||
2,020 | [1] | 3.6 | ||
2,021 | [1] | 2.1 | ||
Total expenses on lease obligations, including short-term leases of compressors and equipment | [2] | 45.1 | 42.4 | 24.4 |
Land Site Lease and Right-of-Way [Member] | ||||
Future lease obligations in aggregate and for each of the next five fiscal years [Abstract] | ||||
In Aggregate | [3] | 14.2 | ||
2,017 | [3] | 3.2 | ||
2,018 | [3] | 2.8 | ||
2,019 | [3] | 2.8 | ||
2,020 | [3] | 2.7 | ||
2,021 | [3] | 2.7 | ||
Total expenses on lease obligations, including short-term leases of compressors and equipment | $ 4.4 | $ 4.2 | $ 4.1 | |
[1] | Includes minimum payments on lease obligations for office space, railcars and tractors. | |||
[2] | Includes short-term leases for items such as compressors and equipment. | |||
[3] | Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual. |
Contingencies (Details)
Contingencies (Details) | Dec. 16, 2015Plaintiff | Jun. 18, 2015USD ($) | Oct. 31, 2016 |
State Court Lawsuit [Member] | |||
Loss Contingencies [Line Items] | |||
Number of plaintiffs | Plaintiff | 2 | ||
Environment Proceeding [Member] | Versado Gas Processors L L C | |||
Loss Contingencies [Line Items] | |||
Ownership interest in joint venture | 63.00% | ||
Additional interest ownership percentage to be acquired | 37.00% | ||
Environment Proceeding [Member] | New Mexico Environment Department [Member] | |||
Loss Contingencies [Line Items] | |||
Litigation settlement amount offered | $ | $ 29,223 |
Significant Risks and Uncert108
Significant Risks and Uncertainties (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Concentration Risk [Line Items] | |||
Reduction of maximum loss due to counterparty credit risk by master netting provision | $ 21.9 | ||
Allowance for doubtful accounts | $ 0.9 | $ 0.1 | |
Supplier Concentration Risk [Member] | Consolidated Purchases [Member] | ONEOK Hydrocarbon LP [Member] | |||
Summary of activity affecting allowance for bad debts [Roll Forward] | |||
Concentration risk percentage | 11.00% | 12.00% | |
Supplier Concentration Risk [Member] | Consolidated Purchases [Member] | DCP NGL Services LLC [Member] | |||
Summary of activity affecting allowance for bad debts [Roll Forward] | |||
Concentration risk percentage | 11.00% | ||
Minimum [Member] | |||
Concentration Risk [Line Items] | |||
Potential loss attributable to individual counterparties | $ 1.3 | ||
Maximum [Member] | |||
Concentration Risk [Line Items] | |||
Potential loss attributable to individual counterparties | $ 3.8 | ||
Maximum [Member] | Supplier Concentration Risk [Member] | Consolidated Purchases [Member] | |||
Summary of activity affecting allowance for bad debts [Roll Forward] | |||
Concentration risk percentage | 10.00% |
Other Operating (Income) Exp109
Other Operating (Income) Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Other Income And Expenses [Abstract] | |||
(Gain) loss on sale or disposal of assets | $ 6.1 | $ (8) | $ (4.8) |
Casualty (gain) loss | (0.2) | 0.1 | |
Miscellaneous business tax | 0.5 | 0.5 | 0.4 |
Other | 0.6 | 1.3 | |
Total other operating (income) expense | $ 6.6 | $ (7.1) | $ (3) |
Income Tax (Details)
Income Tax (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income tax (expense) benefit: | |||
Current expense | $ 0 | $ 0.8 | $ 3.2 |
Deferred expense (benefit) | (0.3) | (0.2) | 1.6 |
Total income tax expense (benefit) | $ (0.3) | 0.6 | $ 4.8 |
Texas margin tax rate | 0.75% | ||
Deferred tax assets [Abstract] | |||
Net operating loss carryforwards | $ 19.8 | 19.8 | |
Deferred tax liabilities [Abstract] | |||
Property, plant, and equipment | (46.7) | (47) | |
Net deferred tax asset (liability) | (26.9) | $ (27.2) | |
TPL Arkoma, Inc. [Member] | |||
Deferred tax liabilities [Abstract] | |||
Net operating loss carryforwards | $ 51.3 | ||
TPL Arkoma, Inc. [Member] | Minimum [Member] | |||
Deferred tax liabilities [Abstract] | |||
Operating loss carryforwards expiry date | Dec. 31, 2029 | ||
TPL Arkoma, Inc. [Member] | Maximum [Member] | |||
Deferred tax liabilities [Abstract] | |||
Operating loss carryforwards expiry date | Dec. 31, 2036 |
Supplemental Cash Flow Infor111
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Cash [Abstract] | ||||
Interest paid, net of capitalized interest | [1] | $ 263.8 | $ 193.1 | $ 131 |
Income taxes paid, net of refunds | 1.3 | 3.4 | 2.7 | |
Non-cash investing activities [Abstract] | ||||
Deadstock commodity inventory transferred to property, plant and equipment | 17.4 | 1.2 | 14.8 | |
Impact of capital expenditure accruals on property, plant and equipment | 27.6 | 43.8 | 19 | |
Transfers from materials and supplies inventory to property, plant and equipment | 2.4 | 3.7 | 4.6 | |
Change in ARO liability and property, plant and equipment due to revised cash flow estimate | (9.1) | 3.8 | 2.1 | |
Deferred revenue related to property, plant and equipment received under contract amendment | 0 | 22.6 | 0 | |
Non-cash financing activities [Abstract] | ||||
Debt additions and retirements related to exchange of TRP 6⅝% Notes for 6⅝% TPL Notes | 0 | 342.1 | 0 | |
Accrued distributions on unvested equity awards under share compensation arrangements | 0.2 | 1.6 | 1.4 | |
Receivables from equity issuances | 0 | 0 | 1 | |
Change of accrued distributions of preferred units | 0.9 | 0 | ||
Exchange of IDRs and Special GP interest for units | 903.6 | 0 | 0 | |
Non-cash balance sheet movements related to the purchase of noncontrolling interests in subsidiary (see Note 4 - Business Acquisitions) [Abstract] | ||||
Common limited partner units | 63.7 | 0 | 0 | |
General partner units | 1.3 | 0 | 0 | |
Noncontrolling interests | (65) | 0 | 0 | |
Non-cash balance sheet movements related to the Atlas Merger: (See Note 4 - Business Acquisitions) [Abstract] | ||||
Non-cash merger consideration - common units and replacement equity awards | 0 | 2,583.5 | 0 | |
Special GP Interest | 0 | 1,612.4 | 0 | |
Current liabilities retained by Targa | 0 | (0.4) | 0 | |
Net non-cash balance sheet movements excluded from consolidated statements of cash flows | 0 | 4,195.5 | 0 | |
Net cash merger consideration included in investing activities | 0 | 828.7 | 0 | |
Total fair value of consideration transferred | 0 | 5,024.2 | 0 | |
Interest capitalized on major projects | $ 8.3 | 13.2 | $ 16.1 | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | ||||
Non-cash balance sheet movements related to the Atlas Merger: (See Note 4 - Business Acquisitions) [Abstract] | ||||
Interest rate of partnership indebtedness percentage | 6.625% | |||
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | ||||
Non-cash balance sheet movements related to the Atlas Merger: (See Note 4 - Business Acquisitions) [Abstract] | ||||
Interest rate of partnership indebtedness percentage | 6.625% | |||
Treasury Units [Member] | ||||
Non-cash financing activities [Abstract] | ||||
Cancellation of treasury units | $ 10.4 | $ 0 | ||
[1] | Interest capitalized on major projects was $8.3 million, $13.2 million and $16.1 million for 2016, 2015 and 2014. |
Compensation Plans, TRC Equity
Compensation Plans, TRC Equity Compensation Plan (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Replacement Phantom Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant date fair value, Granted (in dollars per share) | $ 43.82 | ||
Dividend payment period | 60 days | ||
Granted (in shares) | 629,231 | ||
Replacement Phantom Units [Member] | Vesting Term One [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period of original term | 4 years | ||
Vesting percentage original term | 25.00% | ||
Replacement Phantom Units [Member] | Vesting Term Two [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period of original term | 3 years | ||
Vesting percentage original term | 33.00% | ||
Targa Resources Corp Equity Compensation Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Termination date | Feb. 7, 2017 | ||
Partnership Long-term Incentive Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total number of units authorized (in shares) | 1,680,000 | ||
Partnership Long-term Incentive Plan [Member] | Performance Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant date fair value, Granted (in dollars per share) | $ 34.48 | $ 57.19 | |
Partnership Long-term Incentive Plan [Member] | Performance Units [Member] | Award Granted in December 2013 [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance period | 3 years | ||
Partnership Long-term Incentive Plan [Member] | Performance Units [Member] | Award Granted in December 2013 [Member] | Vesting Term One [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance period | 2 years | ||
Partnership Long-term Incentive Plan [Member] | Performance Units [Member] | Award Granted in December 2013 [Member] | Vesting Term Two [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance period | 3 years | ||
Partnership Long-term Incentive Plan [Member] | Performance Units [Member] | Award Granted in December 2013 [Member] | Vesting Term Three [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance period | 4 years | ||
Partnership Long-term Incentive Plan [Member] | Phantom Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant date fair value, Granted (in dollars per share) | $ 36.87 | ||
Units issued | 25,162 | ||
Partnership Long-term Incentive Plan [Member] | Phantom Units [Member] | Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period of original term | 1 year | ||
Partnership Long-term Incentive Plan [Member] | Phantom Units [Member] | Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period of original term | 5 years |
Compensation Plans, Partnership
Compensation Plans, Partnership Director Grants (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Fair value of units vested | $ 19.8 | $ 31.8 | $ 20.1 |
Director Grants [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant date fair value, Granted (in dollars per share) | $ 10.11 | $ 44.67 | $ 50.29 |
Fair value of units vested | $ 0.3 | $ 0.5 | $ 0.4 |
Compensation Plans, Impact of T
Compensation Plans, Impact of TRC/TRP Merger (Details) $ in Millions | Feb. 17, 2016USD ($)shares | Dec. 31, 2016shares | Dec. 31, 2015shares |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Conversion ratio in stock-for-unit transaction | 0.62 | ||
Equity-Settled Performance Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Compensation costs | $ | $ 3.9 | ||
Phantom Unit Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding units before conversion | 349,541 | ||
Converted outstanding shares | 216,561 | ||
Granted (in shares) | 629,231 | ||
Partnership Long-term Incentive Plan [Member] | Equity-Settled Performance Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Outstanding units before conversion | 675,745 | ||
Converted outstanding shares | 418,906 | ||
Partnership Long-term Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted (in shares) | 331,282 | ||
Vesting period of original term | 3 years | ||
Partnership Long-term Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Non Executives [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted (in shares) | 310,809 |
Compensation Plans, Restricted
Compensation Plans, Restricted Stock Units (Details) - Restricted Stock Units (RSUs) [Member] - Targa Resources Corp Equity Compensation Plan | 12 Months Ended |
Dec. 31, 2016$ / sharesshares | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | shares | 0 |
Converted (in shares) | shares | 635,467 |
Granted (in shares) | shares | 331,282 |
Forfeited (in shares) | shares | (20,485) |
Vested (in shares) | shares | (245,862) |
Outstanding, end of period (in shares) | shares | 700,402 |
Weighted-average grant-date fair value [Roll Forward] | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 0 |
Converted (in dollars per share) | $ / shares | 73.68 |
Granted (in dollars per shares) | $ / shares | 74.01 |
Forfeited (in dollars per share) | $ / shares | 26.38 |
Vested (in dollars per share) | $ / shares | 62.23 |
Outstanding, end of period (in dollars per share) | $ / shares | $ 51.52 |
Compensation Plans, TRC Long Te
Compensation Plans, TRC Long Term Incentive Plan (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Feb. 17, 2016 | |
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award [Table] | |||||
Weighted average recognition period for unrecognized compensation cost | 2 years 3 months 18 days | ||||
Cash-Settled Performance Units [Member] | |||||
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award [Table] | |||||
Compensation costs | $ 4.8 | ||||
Partnership Long-term Incentive Plan [Member] | Cash-Settled Performance Units [Member] | |||||
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award [Table] | |||||
Liability award | 451,990 | ||||
Cash settled for awards | $ 4.8 | $ 7.8 | $ 14.7 | ||
Weighted average recognition period for unrecognized compensation cost | 1 year 3 months 18 days | ||||
Partnership Long-term Incentive Plan [Member] | Cash-Settled Restricted Stock Units [Member] | |||||
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award [Table] | |||||
Converted outstanding shares | 279,964 |
Compensation Plans, TRC LTIP Ca
Compensation Plans, TRC LTIP Cash-Settled Restricted Stock Units (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($)shares | |
Nonvested, number of shares [Roll Forward] | |
To be recognized in future periods | $ | $ 44.8 |
Cash Settled Restricted Stock Units [Member] | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | 451,990 |
After conversion on February 17, 2016 (in shares) | 279,964 |
Vested and paid (in shares) | (85,492) |
Forfeited (in shares) | (5,177) |
Outstanding, end of period (in shares) | 189,295 |
Calculated fair market value as of period end | $ | $ 12,348,763 |
Current liability | $ | 4,143,373 |
Long-term liability | $ | 3,565,135 |
Liability as of year end | $ | 7,708,508 |
To be recognized in future periods | $ | $ 4,640,255 |
Cash Settled Restricted Stock Units [Member] | 2013 Long Term Incentive Plan [Member] | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | 139,700 |
After conversion on February 17, 2016 (in shares) | 86,538 |
Vested and paid (in shares) | (85,492) |
Forfeited (in shares) | (1,046) |
Cash Settled Restricted Stock Units [Member] | 2014 Long Term Incentive Plan [Member] | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | 119,900 |
After conversion on February 17, 2016 (in shares) | 74,248 |
Forfeited (in shares) | (1,269) |
Outstanding, end of period (in shares) | 72,979 |
Calculated fair market value as of period end | $ | $ 4,992,974 |
Current liability | $ | 4,143,373 |
Long-term liability | $ | 0 |
Liability as of year end | $ | 4,143,373 |
To be recognized in future periods | $ | $ 849,601 |
Vesting date | Jun. 30, 2017 |
Cash Settled Restricted Stock Units [Member] | 2015 Long Term Incentive Plan [Member] | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | 192,390 |
After conversion on February 17, 2016 (in shares) | 119,178 |
Forfeited (in shares) | (2,862) |
Outstanding, end of period (in shares) | 116,316 |
Calculated fair market value as of period end | $ | $ 7,355,790 |
Current liability | $ | 0 |
Long-term liability | $ | 3,565,135 |
Liability as of year end | $ | 3,565,135 |
To be recognized in future periods | $ | $ 3,790,655 |
Vesting date | Jun. 30, 2018 |
Compensation Plans, 2010 TRC St
Compensation Plans, 2010 TRC Stock Incentive Plan (Details) - USD ($) $ / shares in Units, $ in Millions | Jan. 14, 2017 | Jan. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Stock compensation expense | $ 41.2 | $ 22.8 | $ 25.4 | ||
Unrecognized compensation expenses | $ 44.8 | ||||
Weighted average recognition period for unrecognized compensation cost | 2 years 3 months 18 days | ||||
Fair value of units vested | $ 19.8 | 31.8 | 20.1 | ||
Recognized tax benefits | $ 1.1 | $ 1 | |||
ASU 2016-09 [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Income tax deficiency | $ 0.5 | ||||
2010 TRC Stock Incentive Plan [Member] | Director Grants [Member] | Subsequent Event [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Granted (in shares) | 13,818 | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Total units authorized (in shares) | 5,000,000 | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock [Member] | Executives [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of awards | 1 year | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock in Lieu of Salary [Member] | Executives [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Percentage of annual base salary used to determine restricted shares awarded | 25.00% | ||||
Number of trading days | 5 days | ||||
Granted (in shares) | 32,267 | ||||
Granted (in dollars per shares) | $ 41.43 | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock in Lieu of Bonus [Member] | Executives [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of awards | 3 years | ||||
Granted (in shares) | 153,252 | ||||
Granted (in dollars per shares) | $ 26.34 | ||||
2010 TRC Stock Incentive Plan [Member] | Director Grants [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Granted (in shares) | 24,234 | 6,429 | 5,165 | ||
Granted (in dollars per shares) | $ 16.45 | $ 86.49 | $ 87.45 | ||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Granted (in shares) | 1,129,705 | 140,477 | 54,357 | ||
Granted (in dollars per shares) | $ 27.87 | $ 83.54 | $ 112.89 | ||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Granted (in shares) | 491,000 | ||||
Vested (in shares) | (22,017) | ||||
Stock repurchased from employees (in shares) | 6,990 | ||||
Stock repurchase price (in dollars per share) | $ 57.95 | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member] | Stock Awards Vesting, Tranche One [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting date of awards | 2021-01 | ||||
Award vesting percentage | 30.00% | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member] | Stock Awards Vesting, Tranche Two [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting date of awards | 2020-01 | ||||
Award vesting percentage | 30.00% | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member] | Stock Awards Vesting, Tranche Three [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting date of awards | 2023-01 | ||||
Award vesting percentage | 40.00% | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member] | 2017 [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of awards | 3 years | ||||
Granted (in shares) | 114,301 | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Minimum [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of awards | 1 year | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Maximum [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of awards | 5 years | ||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | Subsequent Event [Member] | Stock Awards Vesting, Tranche One [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Award vesting percentage | 25.00% | ||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | Subsequent Event [Member] | Stock Awards Vesting, Tranche Two [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Award vesting percentage | 25.00% | ||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | Subsequent Event [Member] | Stock Awards Vesting, Tranche Three [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Award vesting percentage | 25.00% | ||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | Subsequent Event [Member] | Stock Awards Vesting, Tranche Four [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Award vesting percentage | 25.00% | ||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | Subsequent Event [Member] | 2017 [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Granted (in shares) | 113,901 | ||||
Vesting date of awards | Dec. 31, 2019 | ||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | Minimum [Member] | Subsequent Event [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Guideline performance percentage based on total shareholder return | 0.00% | ||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | Maximum [Member] | Subsequent Event [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Guideline performance percentage based on total shareholder return | 250.00% | ||||
2010 TRC Stock Incentive Plan [Member] | Equity-Settled Performance Units [Member] | Subsequent Event [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of awards | 3 years |
Compensation Plans, Restrict119
Compensation Plans, Restricted Stock And RSUs Under 2010 TRC Plan (Details) - 2010 TRC Stock Incentive Plan [Member] - Restricted Stock And Restricted Stock Units [Member] | 12 Months Ended |
Dec. 31, 2016$ / sharesshares | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | shares | 313,362 |
Granted (in shares) | shares | 1,186,206 |
Forfeited (in shares) | shares | (14,989) |
Vested (in shares) | shares | (116,329) |
Outstanding, end of period (in shares) | shares | 1,368,250 |
Weighted-average grant-date fair value [Roll Forward] | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 85.70 |
Granted (in dollars per shares) | $ / shares | 28 |
Forfeited (in dollars per share) | $ / shares | 75.17 |
Vested (in dollars per share) | $ / shares | 58.55 |
Outstanding, end of period (in dollars per share) | $ / shares | $ 38.10 |
Segment Information, Revenues a
Segment Information, Revenues and Operating Margin (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2016USD ($)Segment | Dec. 31, 2015USD ($)Segment | Dec. 31, 2014USD ($) | |
Segment Reporting Information [Line Items] | |||||||||||
Number of segments | Segment | 2 | ||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | $ 5,626.8 | $ 5,465.4 | $ 7,595.2 | ||||||||
Fees from midstream services | 1,064.1 | 1,193.2 | 1,021.3 | ||||||||
Revenues | $ 2,012.6 | $ 1,652.3 | $ 1,583.6 | $ 1,442.4 | $ 1,647.4 | $ 1,632.1 | $ 1,699.4 | $ 1,679.7 | 6,690.9 | 6,658.6 | 8,616.5 |
Operating margin | 1,214.4 | 1,281 | 1,136.6 | ||||||||
Operating Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 5,626.8 | 5,465.4 | 7,595.2 | ||||||||
Fees from midstream services | 1,064.1 | 1,193.2 | 1,021.3 | ||||||||
Revenues | 6,690.9 | 6,658.6 | 8,616.5 | ||||||||
Gathering and Processing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 3,240.7 | 3,047.5 | 2,851.1 | ||||||||
Operating margin | 577.1 | 515.1 | 449.9 | ||||||||
Gathering and Processing [Member] | Operating Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 621.9 | 1,485.4 | 552.4 | ||||||||
Fees from midstream services | 486.6 | 427.1 | 224.7 | ||||||||
Revenues | 1,108.5 | 1,912.5 | 777.1 | ||||||||
Gathering and Processing [Member] | Intersegment Eliminations [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 2,124.4 | 1,126.3 | 2,068.8 | ||||||||
Fees from midstream services | 7.8 | 8.7 | 5.2 | ||||||||
Revenues | 2,132.2 | 1,135 | 2,074 | ||||||||
Logistics and Marketing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 5,794.5 | 4,888.6 | 8,215.2 | ||||||||
Operating margin | 574.4 | 681.7 | 694.7 | ||||||||
Logistics and Marketing [Member] | Operating Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 4,942 | 3,895.8 | 7,050.8 | ||||||||
Fees from midstream services | 577.5 | 766.1 | 796.6 | ||||||||
Revenues | 5,519.5 | 4,661.9 | 7,847.4 | ||||||||
Logistics and Marketing [Member] | Intersegment Eliminations [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 251.5 | 208.9 | 339.3 | ||||||||
Fees from midstream services | 23.5 | 17.8 | 28.5 | ||||||||
Revenues | 275 | 226.7 | 367.8 | ||||||||
Other [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 62.9 | 84.2 | (8) | ||||||||
Operating margin | 62.9 | 84.2 | (8) | ||||||||
Other [Member] | Operating Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 62.9 | 84.2 | (8) | ||||||||
Revenues | 62.9 | 84.2 | (8) | ||||||||
Corporate and Elimination [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (2,407.2) | (1,361.7) | (2,441.8) | ||||||||
Corporate and Elimination [Member] | Intersegment Eliminations [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | (2,375.9) | (1,335.2) | (2,408.1) | ||||||||
Fees from midstream services | (31.3) | (26.5) | (33.7) | ||||||||
Revenues | $ (2,407.2) | $ (1,361.7) | $ (2,441.8) | ||||||||
Scenario, Previously Reported | Gathering and Processing [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Number of reportable segments | Segment | 2 | ||||||||||
Scenario, Previously Reported | Logistics and Marketing [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Number of reportable segments | Segment | 2 |
Segment Information, Other Fina
Segment Information, Other Financial Information (Details) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2016 | Feb. 27, 2015 | ||
Other financial information [Abstract] | ||||||
Total assets | $ 12,744.9 | $ 13,126.8 | ||||
Goodwill | 210 | 417 | $ 0 | $ 393 | $ 707 | |
Business acquisition | $ 5,024.2 | |||||
Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 12,744.9 | 13,126.8 | 6,347.3 | ||
Goodwill | 210 | 417 | ||||
Capital expenditures | 592.1 | 777.2 | 747.8 | |||
Business acquisition | 5,024.2 | |||||
Gathering and Processing [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 9,800.6 | 10,391.9 | 3,776.2 | ||
Goodwill | 210 | 417 | ||||
Capital expenditures | 402.5 | 496.3 | 437.1 | |||
Business acquisition | 5,024.2 | |||||
Logistics and Marketing [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 2,868.7 | 2,567.1 | 2,476.1 | ||
Capital expenditures | 185.3 | 272 | 304.6 | |||
Other [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 21.8 | 127.1 | 60.2 | ||
Corporate and Elimination [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 53.8 | 40.7 | 34.8 | ||
Capital expenditures | $ 4.3 | $ 8.9 | $ 6.1 | |||
[1] | Corporate assets at the segment level primarily include cash, prepaids and debt issuance costs for our TRP Revolver. |
Segment Information, Revenues b
Segment Information, Revenues by Product and Service (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | $ 5,626.8 | $ 5,465.4 | $ 7,595.2 | ||||||||
Fees from midstream services | 1,064.1 | 1,193.2 | 1,021.3 | ||||||||
Total revenues | $ 2,012.6 | $ 1,652.3 | $ 1,583.6 | $ 1,442.4 | $ 1,647.4 | $ 1,632.1 | $ 1,699.4 | $ 1,679.7 | 6,690.9 | 6,658.6 | 8,616.5 |
Natural Gas [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | 1,584.5 | 1,578.6 | 1,414.1 | ||||||||
NGL [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | 3,777.3 | 3,558.3 | 5,960.1 | ||||||||
Condensate [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | 133.9 | 142.4 | 134.3 | ||||||||
Petroleum Products [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | 68.2 | 101.6 | 96.3 | ||||||||
Derivative Activities [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | 62.9 | 84.5 | (9.6) | ||||||||
Fractionating and Treating [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Fees from midstream services | 126.2 | 209 | 208.9 | ||||||||
Storage, Terminaling, Transportation and Export [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Fees from midstream services | 420 | 506.2 | 548.1 | ||||||||
Gathering and Processing [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Fees from midstream services | 445 | 393.7 | 196.9 | ||||||||
Other [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Fees from midstream services | $ 72.9 | $ 84.3 | $ 67.4 |
Segment Information, Reconcilia
Segment Information, Reconciliation of Operating Margin to Net Income (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reconciliation of operating margin to net income (loss) [Abstract] | |||||||||||
Operating margin | $ 1,214.4 | $ 1,281 | $ 1,136.6 | ||||||||
Depreciation and amortization expenses | (757.7) | (677.1) | (346.5) | ||||||||
General and administrative expenses | (177.1) | (153.6) | (139.8) | ||||||||
Goodwill impairment | $ (183) | $ (290) | (207) | (290) | 0 | ||||||
Interest expense, net | (233.5) | (207.8) | (143.8) | ||||||||
Other, net | (68.1) | (11.2) | 3.4 | ||||||||
Income tax (expense) benefit | 0.3 | (0.6) | (4.8) | ||||||||
Net income (loss) | $ (228.3) | $ (6.1) | $ (4.9) | $ 10.6 | $ (243.7) | $ 53.3 | $ 53.3 | $ 77.8 | $ (228.7) | $ (59.3) | $ 505.1 |
Selected Quarterly Financial124
Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||||||||||
Selected Quarterly Financial Information [Abstract] | |||||||||||||||||||||
Revenues | $ 2,012.6 | $ 1,652.3 | $ 1,583.6 | $ 1,442.4 | $ 1,647.4 | $ 1,632.1 | $ 1,699.4 | $ 1,679.7 | $ 6,690.9 | $ 6,658.6 | $ 8,616.5 | ||||||||||
Gross margin | 468.6 | 429.6 | 438.4 | 431.4 | 459.8 | 468.8 | 471.3 | 421.1 | 1,768 | 1,821 | |||||||||||
Income (loss) from operations | (93.6) | [1],[2] | 53.7 | [1],[2] | 68.4 | [1],[2] | 37.5 | [1],[2] | (205.3) | [3],[4] | 117.3 | [3],[4] | 114.8 | [3],[4] | 140.6 | [3],[4] | 66 | [1],[2] | 167.4 | [3],[4] | 653.3 |
Net income (loss) | (228.3) | (6.1) | (4.9) | 10.6 | (243.7) | 53.3 | 53.3 | 77.8 | (228.7) | (59.3) | 505.1 | ||||||||||
Net income (loss) attributable to common limited partners | (233.7) | $ (42.6) | $ (37.9) | (9.9) | (232.6) | $ 3.6 | $ 1.2 | $ 30.3 | (324.1) | (197.5) | 319 | ||||||||||
Additional goodwill Impairment | $ 24 | ||||||||||||||||||||
Goodwill impairment | $ 183 | 290 | $ 207 | 290 | 0 | ||||||||||||||||
Impairment loss | $ 32.6 | $ 32.6 | $ 3.2 | ||||||||||||||||||
[1] | Includes a goodwill impairment of $183.0 million in the fourth quarter of 2016. See Note 7 – Goodwill | ||||||||||||||||||||
[2] | Includes an additional goodwill impairment of $24.0 million in the first quarter of 2016. See Note 7 – Goodwill. | ||||||||||||||||||||
[3] | Includes $32.6 million of impairment losses in the fourth quarter of 2015. See Note 6 – Property, Plant and Equipment and Intangible Assets. | ||||||||||||||||||||
[4] | Includes a provisional goodwill impairment of $290.0 million in the fourth quarter of 2015. See Note 7 – Goodwill. |