Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2018 | |
Document And Entity Information [Abstract] | |
Entity Registrant Name | Targa Resources Partners LP |
Trading Symbol | NGLS |
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 | 2,018 |
Document Fiscal Period Focus | FY |
Document Type | 10-K |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2018 |
Entity Shell Company | false |
Entity Small Business | false |
Entity Emerging Growth Company | false |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 203.3 | $ 124.7 |
Trade receivables, net of allowances of $0.1 and $0.1 million at December 31, 2018 and December 31, 2017 | 864.4 | 825.7 |
Inventories | 164.7 | 204.5 |
Assets from risk management activities | 115.3 | 37.9 |
Other current assets | 32.2 | 55.8 |
Total current assets | 1,379.9 | 1,248.6 |
Property, plant and equipment | 17,213.8 | 14,198.6 |
Accumulated depreciation | (4,285.5) | (3,768.7) |
Property, plant and equipment, net | 12,928.3 | 10,429.9 |
Intangible assets, net | 1,983.2 | 2,165.8 |
Goodwill, net | 46.6 | 256.6 |
Long-term assets from risk management activities | 34.1 | 23.2 |
Investments in unconsolidated affiliates | 490.5 | 221.6 |
Other long-term assets | 27.5 | 13.3 |
Total assets | 16,890.1 | 14,359 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 1,636.9 | 1,106.6 |
Accounts payable to Targa Resources Corp. | 187.4 | 76.9 |
Liabilities from risk management activities | 33.6 | 79.7 |
Current debt obligations | 1,027.9 | 350 |
Total current liabilities | 2,885.8 | 1,613.2 |
Long-term debt | 5,197.4 | 4,268 |
Long-term liabilities from risk management activities | 3.1 | 19.6 |
Deferred income taxes, net | 23.9 | 24 |
Other long-term liabilities | 233.8 | 576 |
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, 2017 and December 31, 2016) | 120.6 | 120.6 |
Common limited partners (275,168,410 and 275,168,410 units issued and 275,168,410 and 275,168,410 outstanding as of December 31, 2017 and December 31, 2016) | 6,227.2 | 6,500.3 |
General partner (5,629,136 and 5,629,136 units issued and 5,629,136 and 5,629,136 outstanding as of December 31, 2017 and December 31, 2016) | 802.6 | 808.2 |
Accumulated other comprehensive income (loss) | 124.9 | (46) |
Partners' Capital | 7,275.3 | 7,383.1 |
Noncontrolling interests in subsidiaries | 1,270.8 | 475.1 |
Total owners' equity | 8,546.1 | 7,858.2 |
Total liabilities and owners' equity | $ 16,890.1 | $ 14,359 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Trade receivables, allowances | $ 0.1 | $ 0.1 |
Owners' equity: | ||
Common limited partners units issued (in units) | 275,168,410 | 275,168,410 |
Common limited partners units outstanding (in units) | 275,168,410 | 275,168,410 |
General partner units issued (in units) | 5,629,136 | 5,629,136 |
General partner units outstanding (in units) | 5,629,136 | 5,629,136 |
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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||
Revenues: | |||||
Total revenues | $ 10,484 | $ 8,814.9 | $ 6,690.9 | ||
Costs and expenses: | |||||
Product purchases (see Note 3) | 8,238.2 | 6,906.1 | 4,922.9 | ||
Operating expenses | 722 | 622.8 | 553.6 | ||
Depreciation and amortization expense | 815.9 | 809.5 | 757.7 | ||
General and administrative expense | 240.8 | 190.5 | 177.1 | ||
Impairment of property, plant and equipment | 0 | 378 | 0 | ||
Impairment of goodwill | 210 | 0 | 207 | ||
Other operating (income) expense | 3.5 | 17.4 | 6.6 | ||
Income (loss) from operations | 253.6 | [1] | (109.4) | [2] | 66 |
Other income (expense): | |||||
Interest expense, net | (170) | (217.8) | (233.5) | ||
Equity earnings (loss) | 7.3 | (17) | (14.3) | ||
Gain (loss) from financing activities | (1.3) | (10.9) | (48.2) | ||
Change in contingent considerations | 8.8 | 99.6 | 0.4 | ||
Other, net | 0.1 | (2.5) | 0.6 | ||
Income (loss) before income taxes | 98.5 | (258) | (229) | ||
Income tax (expense) benefit | 0.1 | 7.4 | 0.3 | ||
Net income (loss) | 98.6 | (250.6) | (228.7) | ||
Less: Net income (loss) attributable to noncontrolling interests | 47.6 | 38.9 | 20.7 | ||
Net income (loss) attributable to Targa Resources Partners LP | 51 | (289.5) | (249.4) | ||
Net income attributable to preferred limited partners | 11.3 | 11.3 | 11.3 | ||
Net income (loss) attributable to general partner | 0.8 | (6) | 63.4 | ||
Net income (loss) attributable to common limited partners | 38.9 | (294.8) | (324.1) | ||
Net income (loss) attributable to Targa Resources Partners LP | 51 | (289.5) | (249.4) | ||
Sales of Commodities [Member] | |||||
Revenues: | |||||
Total revenues | 9,278.7 | 7,751.1 | 5,626.8 | ||
Fees from Midstream Services [Member] | |||||
Revenues: | |||||
Total revenues | $ 1,205.3 | $ 1,063.8 | $ 1,064.1 | ||
[1] | Includes a non-cash pre-tax impairment charge of $210.0 million in the fourth quarter of 2018. See Note 7 – Goodwill. | ||||
[2] | Includes a non-cash pre-tax impairment charge of $378.0 million in the third quarter of 2017. See Note 6 – Property, Plant and Equipment and Intangible Assets |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Net income (loss) | $ 98.6 | $ (250.6) | $ (228.7) |
Other comprehensive income (loss): | |||
Other comprehensive income (loss) | 170.9 | 15.8 | (148.6) |
Comprehensive income (loss) | 269.5 | (234.8) | (377.3) |
Less: Comprehensive income (loss) attributable to noncontrolling interests | 47.6 | 38.9 | 20.7 |
Comprehensive income (loss) attributable to Targa Resources Partners LP | 221.9 | (273.7) | (398) |
Commodity Contracts [Member] | |||
Other comprehensive income (loss): | |||
Change in fair value | 132.5 | (28.8) | (103.6) |
Settlements reclassified to revenues | $ 38.4 | $ 44.6 | $ (45) |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY - USD ($) $ in Millions | Total | Limited Partner Preferred [Member] | Limited Partners Common [Member] | General Partner Units [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Treasury Units [Member] | Non-controlling Interests [Member] |
Balance at Dec. 31, 2015 | $ 6,902.9 | $ 120.6 | $ 4,550.4 | $ 1,735.3 | $ 86.8 | $ (10.3) | $ 420.1 |
Balance (in units) at Dec. 31, 2015 | 5,000,000 | 184,871,000 | 3,773,000 | 212,000 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Compensation on equity grants | 2.2 | $ 0 | $ 2.2 | $ 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 |
Issuance of common units under compensation program | 0 | $ 0 | $ 0 | $ 0 | 0 | $ 0 | 0 |
Issuance of common units under compensation program (in units) | 0 | 30,000 | 0 | 0 | |||
Units tendered for tax withholding obligations | (0.1) | $ 0 | $ 0 | $ 0 | 0 | $ (0.1) | 0 |
Units tendered for tax withholding obligations (in units) | 0 | (1,000) | 0 | 1,300 | |||
Cancellation of treasury units | 0 | $ 0 | $ (10.2) | $ (0.2) | 0 | $ 10.4 | 0 |
Cancellation of treasury units (in units) | 0 | 0 | 0 | (213,000) | |||
Contributions from Targa Resources Corp. | 1,381 | $ 0 | $ 1,353.4 | $ 27.6 | 0 | $ 0 | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 58,621,000 | 1,197,000 | 0 | |||
Purchase of noncontrolling interests in subsidiary | (37.2) | $ 0 | $ 63.7 | $ 1 | 0 | $ 0 | (102.2) |
Distributions to noncontrolling interests | (26.7) | 0 | 0 | 0 | 0 | 0 | (26.7) |
Contributions from noncontrolling interests | 43.3 | 0 | 0 | 0 | 0 | 0 | 43.3 |
Other comprehensive income (loss) | (148.6) | 0 | 0 | 0 | (148.6) | 0 | 0 |
Net income (loss) | (228.7) | 11.3 | (324.1) | 63.4 | 0 | 0 | 20.7 |
Distributions | (737.3) | (11.3) | (598.9) | (127.1) | 0 | 0 | 0 |
Exchange of Incentive Distribution Rights and special general partner interest for units | 0 | $ 0 | $ 903.6 | $ (903.6) | 0 | $ 0 | 0 |
Exchange of Incentive Distribution Rights and special general partner interest for units (in units) | 0 | 31,647,000 | 659,000 | 0 | |||
Balance at Dec. 31, 2016 | 7,150.6 | $ 120.6 | $ 5,939.9 | $ 796.7 | (61.8) | $ 0 | 355.2 |
Balance (in units) at Dec. 31, 2016 | 5,000,000 | 275,168,000 | 5,629,000 | 0 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Contributions from Targa Resources Corp. | 1,720 | $ 0 | $ 1,685.5 | $ 34.5 | 0 | $ 0 | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 0 | 0 | |||
Purchase of noncontrolling interests in subsidiary | (12.5) | $ 0 | $ 0 | $ 0 | 0 | $ 0 | (12.5) |
Distributions to noncontrolling interests | (48.1) | 0 | 0 | 0 | 0 | 0 | (48.1) |
Contributions from noncontrolling interests | 141.6 | 0 | 0 | 0 | 0 | 0 | 141.6 |
Other comprehensive income (loss) | 15.8 | 0 | 0 | 0 | 15.8 | 0 | 0 |
Net income (loss) | (250.6) | 11.3 | (294.8) | (6) | 0 | 0 | 38.9 |
Distributions | (858.6) | (11.3) | (830.3) | (17) | 0 | 0 | 0 |
Balance at Dec. 31, 2017 | 7,858.2 | $ 120.6 | $ 6,500.3 | $ 808.2 | (46) | $ 0 | 475.1 |
Balance (in units) at Dec. 31, 2017 | 5,000,000 | 275,168,000 | 5,629,000 | 0 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Contributions from Targa Resources Corp. | 600.1 | $ 0 | $ 588.1 | $ 12 | 0 | 0 | |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 0 | ||||
Acquisition of related party (see Note 15) | 1.1 | $ 0 | $ 0 | $ 0 | 0 | 1.1 | |
Purchase of noncontrolling interests in subsidiary | (0.1) | 0 | 0 | 0 | 0 | (0.1) | |
Distributions to noncontrolling interests | (70.8) | 0 | 0 | 0 | 0 | (70.8) | |
Contributions from noncontrolling interests | 817.9 | 0 | 0 | 0 | 0 | 817.9 | |
Other comprehensive income (loss) | 170.9 | 0 | 0 | 0 | 170.9 | 0 | |
Net income (loss) | 98.6 | 11.3 | 38.9 | 0.8 | 0 | 47.6 | |
Distributions | (929.8) | (11.3) | (900.1) | (18.4) | 0 | 0 | |
Balance at Dec. 31, 2018 | $ 8,546.1 | $ 120.6 | $ 6,227.2 | $ 802.6 | $ 124.9 | $ 1,270.8 | |
Balance (in units) at Dec. 31, 2018 | 5,000,000 | 275,168,000 | 5,629,000 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities | |||
Net income (loss) | $ 98.6 | $ (250.6) | $ (228.7) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Amortization in interest expense | 9.1 | 9.3 | 11.9 |
Compensation on equity grants | 0 | 0 | 2.2 |
Depreciation and amortization expense | 815.9 | 809.5 | 757.7 |
Impairment of property, plant and equipment | 0 | 378 | 0 |
Impairment of goodwill | 210 | 0 | 207 |
Accretion of asset retirement obligations | 3.7 | 3.9 | 4.6 |
Increase (decrease) in redemption value of mandatorily redeemable preferred interests | (72.1) | 3.3 | (15.2) |
Deferred income tax expense (benefit) | (0.1) | (2.9) | (0.3) |
Equity (earnings) loss of unconsolidated affiliates | (7.3) | 17 | 14.3 |
Distributions of earnings received from unconsolidated affiliates | 20.8 | 12.5 | 4.1 |
Risk management activities | 9.8 | 10 | 26 |
(Gain) loss on sale or disposition of business and assets | (0.1) | 15.9 | 6.1 |
(Gain) loss from financing activities | 1.3 | 10.9 | 48.2 |
Change in contingent considerations included in Other expense (income) | (8.8) | (99.6) | (0.4) |
Changes in operating assets and liabilities, net of business acquisitions: | |||
Receivables and other assets | (9.8) | (177.7) | (171.9) |
Inventories | (13.9) | (73.2) | (15.9) |
Accounts payable and other liabilities | 156.5 | 191.3 | 188.7 |
Net cash provided by operating activities | 1,213.6 | 857.6 | 838.4 |
Cash flows from investing activities | |||
Outlays for property, plant and equipment | (3,114) | (1,297.5) | (562.1) |
Outlays for business acquisition, net of cash acquired | 0 | (570.8) | 0 |
Investments in unconsolidated affiliates | (282) | (9.5) | (4.4) |
Return of capital from unconsolidated affiliates | 5.5 | 0.2 | 4.1 |
Other, net | (12.5) | (17.8) | (1) |
Net cash used in investing activities | (3,146.1) | (1,892.7) | (558.6) |
Proceeds from sale of business and assets | 256.9 | 2.7 | 4.8 |
Debt obligations: | |||
Proceeds from borrowings under credit facility | 1,870 | 1,736 | 1,710 |
Repayments of credit facility | (1,190) | (1,866) | (1,840) |
Proceeds from borrowings under accounts receivable securitization facility | 546.6 | 666.6 | 171.4 |
Repayments of accounts receivable securitization facility | (616.6) | (591.6) | (115.7) |
Proceeds from issuance of senior notes | 1,000 | 750 | 1,000 |
Redemption of senior notes | 0 | (538.1) | (1,852.2) |
Redemption of TPL senior notes | 0 | 0 | (13.3) |
Costs incurred in connection with financing arrangements | (16.2) | (7.5) | (30.1) |
Repurchase of common units under compensation plans | 0 | 0 | (0.1) |
Purchase of noncontrolling interests in subsidiary | (0.1) | (12.5) | (37.2) |
Contributions from general partner | 12 | 34.5 | 27.6 |
Contributions from TRC | 588.1 | 1,685.5 | 1,353.4 |
Contributions from noncontrolling interests | 817.9 | 141.6 | 43.3 |
Distributions to noncontrolling interests | (70.8) | (48.1) | (26.7) |
Distributions to unitholders | (929.8) | (858.6) | (737.3) |
Payments of distribution equivalent rights | 0 | 0 | (0.3) |
Net cash provided by (used in) financing activities | 2,011.1 | 1,091.8 | (347.2) |
Net change in cash and cash equivalents | 78.6 | 56.7 | (67.4) |
Cash and cash equivalents, beginning of period | 124.7 | 68 | 135.4 |
Cash and cash equivalents, end of period | $ 203.3 | $ 124.7 | $ 68 |
Organization and Operations
Organization and Operations | 12 Months Ended |
Dec. 31, 2018 | |
Limited Liability Company Or Limited Partnership Business Organization And Operations [Abstract] | |
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,” “TRP,” 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 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 our 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 our 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, transporting and selling natural gas; • storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters; • gathering, storing, terminaling and selling crude oil; and • storing, terminaling and selling refined petroleum products. See Note 24 – 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, 2018 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Basis of Presentation | These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2018 and 2017, and the results of operations, comprehensive income, cash flows, and changes in owners’ equity for the years ended December 31, 2018, 2017 and 2016. 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. |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
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 gathering and 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. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as an impairment loss within equity earnings (loss) in our Consolidated Statements of Operations. 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 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 included in 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). 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 net realizable value using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are included in 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 net realizable value 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. 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. 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 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. 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 or asset group with its 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 an impairment 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 impairments. 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 attributed 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, 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. We are permitted to first assess qualitative factors for a reporting unit to determine if the quantitative goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or otherwise determine that a goodwill impairment test is required, our annual goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount (including attributed goodwill). Prior to our adoption of Accounting Standards Update (“ASU”) 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment Intangible Assets Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with business and asset 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 in a manner that closely resembles the expected benefit pattern of the intangible assets, or where such pattern is not readily determinable, on a straight-line basis, over the periods in which we benefit from services provided to customers. Asset Retirement Obligations We record the fair value of estimated asset retirement obligations (“ARO”) associated with tangible long-lived assets. Retirement obligations associated with long-lived assets are only 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, as are any original issue discount or premium. Debt issuance costs related to revolving credit facilities are presented as other long-term assets and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction from the carrying amount of long-term debt on 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 in 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 operating 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 using 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. If 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 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. 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 21 – Income Tax 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). Dividends Preferred and Common dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital. Mandatorily Redeemable Preferred Interests Mandatorily redeemable preferred interests are included in other long-term liabilities 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 be redeemed in the future. Changes in the redemption value are included in interest expense, net in our Consolidated Statements of Operations. 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. 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 our Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income, noncontrolling interests reflects the attribution of results to third-party investors. 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 • services related We have multiple types of contracts with commercial counterparties and many of these may result in cash inflows to Targa due to the structure of settlement provisions with embedded fees. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606. Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases. Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues. We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis. Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price. Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract. The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation. Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue. We have certain long-term contractual arrangements under which we have received consideration, but for which all conditions for revenue recognition have not been met. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided. Significant Judgments Certain provisions of our service contracts (i.e., tiered price structures) require further assessment to determine if the allocation exception for variable consideration is met. If the allocation exception is not met, we estimate the total consideration that we expect to be entitled to for the applicable term of the contract, based on projections of future activity. In such instance, revenue is recognized using an output method of progress based on the volume of commodities serviced during the reporting period. Our estimate of total consideration is reassessed each reporting period until contract completion. For contracts with minimum volume commitments, we generally expect the customer to meet the commitment. However, such contracts are reassessed throughout the term of the commitment, and if we no longer expect the customer to meet the commitment, the allocation exception for variable consideration would not be met. That is, from that point onwards, an allocation based on the applicable fee applied to the volumes serviced does not depict the amount of consideration which we expect to be entitled to, in exchange for the service. In such instance, revenue will be recognized up to the minimum volume commitment in proportion to the days of service elapsed and the remaining duration of the commitment. Contract Assets We classify our contract assets as receivables because we generally have an unconditional right to payment for the commodities sold or services performed at the end of reporting period. 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 Recently issued accounting pronouncements not yet adopted Leases In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases (Topic 842) In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU 2018-10, Codification Improvements to Topic 842, Leases In July 2018, the FASB also issued ASU 2018-11, Leases (Topic 842): Targeted Improvements We expect to adopt Topic 842 on January 1, 2019 and intend to elect the land easement practical expedient as well as the optional transition method. We also expect to adopt the package of practical expedients permitting us to not reassess under the new standard our prior conclusions regarding lease identification, lease classification and initial direct costs, the practical expedient to not separate lease and non-lease components for all of our existing lessee and lessor arrangements, and to elect an accounting policy to not apply the recognition requirements of Topic 842 to our short-term leases. We do not expect to elect the practical expedient for use of hindsight in determining the lease term and assessing impairment of our right-of-use assets. We established a cross-functional team to implement the new standard and are currently in the process of implementing a leases software solution, evaluating the impact of the new standard on our consolidated financial statements and implementing appropriate changes to our internal processes and controls to support the accounting and disclosure requirements of the new standard. Based on our evaluation to-date and from the perspective as the lessee, our leasing activity primarily consists of office space, vehicles, railcars, and tractors. We expect to recognize upon adoption of ASC 842 at January 1, 2019 an estimated right-of-use asset and a lease liability on our consolidated balance sheet. These amounts would represent less than 2% of our total consolidated asset and liabilities, respectively. At this time, we do not expect a material cumulative effect adjustment to retained earnings on January 1, 2019. 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. Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract In August 2018, the FASB issued ASU 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract Recently adopted accounting pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) • Embedded fees within commodity supply contracts where the counterparty is not deemed to be a customer are now reported as a reduction of “Product purchases.” Historically, such fees were reported as “Fees from midstream services.” • Noncash consideration in the form of commodities received in-kind from a customer is now recognized as service revenue within “Fees from midstream services” when the service is performed. Historically, the noncash consideration was only recognized as revenue upon sale to a third party without corresponding “Product purchases.” • For certain contracts structured as a purchase where we do not control the commodities, but rather are acting as an agent for the supplier, revenue is now recognized for the net amount of consideration we expect to retain in exchange for our service. Historically, the purchase from the supplier and subsequent sale were reported gross. The following tables summarize the effects of adoption on our consolidated financial statements: Year Ended December 31, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 9,611.9 $ (333.2 ) $ 9,278.7 Fees from midstream serv |
Newly-Formed Joint Ventures, Ac
Newly-Formed Joint Ventures, Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Newly-Formed Joint Ventures, Acquisitions and Divestitures | Joint Ventures Grand Prix Joint Venture In May 2017, we announced plans to construct the Grand Prix pipeline (“Grand Prix”), a new common carrier NGL pipeline. Grand Prix will transport volumes from the Permian Basin and our North Texas system to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supported by our volumes and other third-party customer volume commitments, and is expected to be fully in service in the third quarter of 2019. In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”), which owns the portion of Grand Prix extending from the Permian Basin to Mont Belvieu, Texas, Concurrent with the sale of the 25% interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC (“EagleClaw”), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement whereby EagleClaw dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin. In March 2018, we announced an extension of Grand Prix from North Texas into southern Oklahoma. The pipeline expansion is supported by long-term commitments for both transportation and fractionation from our existing processing plants in the Arkoma area in our SouthOK system and from third-party commitments, including a long-term commitment for transportation and fractionation with Valiant Midstream, LLC. The extension of Grand Prix into southern Oklahoma is not part of the Grand Prix Joint Venture and its expected cost of approximately $350 million will be funded exclusively by Targa. The capacity of the 24-inch pipeline segment from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d. The pipeline segment from the Permian Basin will be connected to a 30-inch diameter pipeline segment in North Texas, where Permian, North Texas and Oklahoma volumes will be connected to Mont Belvieu, and will have capacity of approximately 450 MBbl/d, expandable to 950 MBbl/d. The capacity from Oklahoma to North Texas will vary based on telescoping pipe size. In February 2019, we announced an extension of Grand Prix from southern Oklahoma to the STACK region of Central Oklahoma where it will connect with Williams’ new Bluestem Pipeline and link the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. Williams will also have an initial option to purchase a 20% equity interest in one of our recently announced fractionation trains (Train 7 or Train 8) in Mont Belvieu. This Grand Prix extension is expected to be completed in the first quarter of 2021 and is not part of the Grand Prix Joint Venture. Grand Prix volumes flowing on the pipeline from the Permian Basin to Mont Belvieu are included in the Blackstone and Grand Prix Development LLC (“Grand Prix DevCo JV”) joi The total cost for Grand Prix, including the extension into Oklahoma, is expected to be approximately $1.9 billion Cayenne In July 2017, we entered into the Cayenne Pipeline, LLC joint venture (“Cayenne with American Midstream LLC to convert an existing 62-mile gas pipeline to an NGL pipeline connecting the VESCO plant in Venice, Louisiana to the Enterprise Products Operating LLC (“Enterprise”) pipeline at Toca, Louisiana, for delivery to Enterprise’s Norco Fractionator. We acquired a 50% interest in the Cayenne for $5.0 million. The project commenced operations in December 2 017 Gulf Coast Express Joint Venture In December 2017, we entered into definitive joint venture agreements with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP (“DCP”) with respect to the joint development of the Gulf Coast Express Pipeline a natural gas pipeline from the Waha hub to Agua Dulce in South Texas We and DCP each own a 25% interest, and KMTP owns a 35% interest in GCX. In December 2018, Altus Midstream Company exercised their option to purchase the remaining 15% interest, which was originally held by KMTP. KMTP will serve as the construction manager and operator of GCX. We have committed significant volumes to GCX. In addition, Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin system, has committed volumes to the project. See Note 8 – Investments in Unconsolidated Affiliates for activity related to the GCX Joint Venture. Little Missouri 4 Joint Venture In January 2018, we formed a 50/50 joint venture with Hess Midstream Partners LP to construct a new 200 MMcf/d natural gas processing plant (“LM4 Plant”) at Targa’s existing Little Missouri facility (“Little Missouri 4”). The LM4 Plant is anticipated to be completed in the second quarter of 2019. Targa is managing the construction of, and will operate, the LM4 Plant. See Note 8 – Investments in Unconsolidated Affiliates for activity related to the Little Missouri 4 Joint Venture. DevCo Joint Ventures In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix, GCX and an approximately 100 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). Stonepeak owns a 95% interest in the Grand Prix DevCo JV, which owns a 20% interest in the Grand Prix Joint Venture (which does not include the extension into southern Oklahoma). Stonepeak owns an 80% interest in both Targa GCX Pipeline LLC (“ DevCo JV”), which owns our 25% interest in GCX, and Targa Train 6 LLC (“Train 6 DevCo JV”), which owns a 100% interest in certain assets associated with Train 6. The Train 6 DevCo JV does not include certain fractionation-related infrastructure such as brine and storage, which will be funded and owned 100% by us. We hold the remaining interests in the DevCo JVs as well as control the management, construction and operation of Grand Prix and Train 6. The following diagram displays the ownership structure of the DevCo JVs: For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, we have the option to acquire all or part of Stonepeak’s interests in the DevCo JVs. Targa may acquire up to 50% of Stonepeak’s invested capital in multiple increments with a minimum of $100 million, and Stonepeak’s remaining 50% interest in a single final purchase. The purchase price payable for such partial or full interests is based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs. Targa will control the management of the DevCo JVs unless and until Targa declines to exercise its option to acquire Stonepeak's interests. Train 6 is expected to begin operations in the second quarter of 2019 . Grand Prix is expected to be fully in service in the third quarter of 2019. X is expected to be in service in the fourth quarter of 2019, pending regulatory approvals. We . We continue to account for Grand Prix and Train 6 on a consolidated basis in o an equity method investment as disclosed in Note 8 – Investments in Unconsolidated Affiliates. Agua Blanca In April 2018, we joined WhiteWater Midstream, LLC (“WhiteWater Midstream”), WPX Energy, Inc., and Markwest Energy Partners, L.P., as joint venture partners in WhiteWater Midstream’s Delaware Basin Agua Blanca pipeline (“Agua Blanca Joint Venture”). The Agua Blanca pipeline is an approximately 160 mile natural gas residue pipeline with an initial capacity of 1.4 Bcf/d. The pipeline, which commenced operations in April 2018, runs from Orla, Texas to the Waha hub, servicing portions of Culberson, Loving, Pecos, Reeves and Ward counties with multiple direct downstream connections including to the Trans-Pecos Header. We acquired a 10% interest in the Agua Blanca for $3.5 million. See Note 8 – Investments in Unconsolidated Affiliates for activity related to the Agua Blanca Joint Venture. Carnero Joint Venture In May 2018, Sanchez Midstream Partners LP and we merged our respective 50% interests in the Carnero gathering and Carnero processing joint ventures, which own the high-pressure Carnero gathering line and Raptor natural gas processing plant, to form an expanded 50/50 joint venture in South Texas (the “Carnero Joint Venture”). In connection with the joint venture merger transactions, the Carnero Joint Venture acquired our 200 MMcf/d Silver Oak II natural gas processing plant located in Bee County Texas, which increased the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d. Additional enhancements to the prior joint ventures include dedication of over 315,000 additional gross acres in the Western Eagle Ford, operated by Sanchez Energy Corporation, under a new long-term firm gas gathering and processing agreement. Including the approximately 105,000 Catarina acreage, the joint venture now has over 420,000 gross acres dedicated long term. We operate the gas gathering and processing facilities in the joint venture. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. Whistler Pipeline In August 2018, we announced that we were involved in the development of the Whistler Pipeline (“Whistler”), consisting of a proposed pipeline designed to transport natural gas from the Waha area of the Permian Basin to Agua Dulce in South Texas, with an additional segment continuing from Agua Dulce to Wharton County, TX. we do not expect to have any meaningful ownership interest in Whistler but will continue to work to commercialize the project as it provides strategic residue takeaway for us and our customers. Acquisitions Permian Acquisition On March 1, 2017, Targa completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”). We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the “initial purchase price”). Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments. The first earn-out payment due in May 2018 expired with no required payment. The second potential earn-out payment would occur in May 2019 and will be based upon a multiple of realized gross margin through February 28, 2019 from contracts that existed on March 1, 2017. The New Delaware assets include 70 MMcf New Midland’s gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties in Texas. 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. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the New Midland system. Since March 1, 2017, financial and statistical data of New Midland have been included in SAOU operations. New Delaware’s gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and the New Midland’s gas gathering and processing assets were connected to our WestTX system in the fourth quarter of 2017. We believe connecting the acquired assets to our legacy Permian footprint creates operational and capital synergies, and is expected to afford enhanced flexibility in serving our producer customers. On January 26, 2017, Targa completed a public offering of 9,200,000 shares of its common stock (including the shares sold pursuant to the underwriters’ overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. Targa used the net proceeds from this public offering to fund the cash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes. The acquired businesses, which contributed revenues of $127.9 million and a net loss of $31.5 million to us for the period from March 1, 2017 to December 31, 2017, are included in our Gathering and Processing segment. As of December 31, 2017, we had incurred $5.6 million of acquisition-related costs. These expenses are included in Other expense in our Consolidated Statements of Operations for the year ended December 31, 2017. Pro Forma Impact of Permian Acquisition on Consolidated Statements of Operations The following summarized unaudited pro forma Consolidated Statements of Operations information for the years ended December 31, 2017 and December 31, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future. December 31, 2017 December 31, 2016 Pro Forma Pro Forma Revenues $ 8,829.0 $ 6,725.6 Net income (loss) (252.2 ) (284.5 ) The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to the unaudited results of the acquired businesses for the periods indicated: • Reflect the amortization expense resulting from the fair value of intangible assets recognized as part of the Permian Acquisition. • Reflect the change in depreciation expense resulting from the difference between the historical balances of the Permian Acquisition’s property, plant and equipment, net, and the fair value of property, plant and equipment acquired. • Exclude $5.6 million of acquisition-related costs incurred as of December 31, 2017 from pro forma net income for the year ended December 31, 2017. Pro forma net income for the year ended December 31, 2016 was adjusted to include those charges. The following table summarizes the consideration transferred to acquire New Delaware and New Midland: Fair Value of Consideration Transferred: Cash paid, net of $3.3 million cash acquired $ 570.8 Contingent consideration valuation as of the acquisition date 416.3 Total $ 987.1 We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair value of the assets acquired and liabilities assumed at the acquisition date is shown below: Fair value determination (final): March 1, 2017 Trade and other current receivables, net $ 6.7 Other current assets 0.6 Property, plant and equipment 255.8 Intangible assets 692.3 Current liabilities (14.1 ) Other long-term liabilities (0.8 ) Total identifiable net assets 940.5 Goodwill 46.6 Total fair value of assets acquired and liabilities assumed $ 987.1 Under the acquisition method of accounting, the assets acquired and liabilities assumed are recognized at their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill . operational and capital synergies. The fair value of assets acquired included trade receivables of $6.7 million, all of which has been subsequently collected. 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. During the three months ended June 30, 2017, we recorded measurement period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs, including forecasts of future volumes, capital expenditures and operating expenses. The measurement period adjustments were based upon information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the measurement of the amounts recognized at that date. We recognized these measurement period adjustments in the three months ended June 30, 2017, with the effect in our Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at March 1, 2017. During the three months ended June 30, 2017, the acquisition date fair value of contingent consideration liability decreased by $45.3 million, intangible assets increased by $66.7 million, and other assets, net, increased by $0.4 million, which resulted in a decrease in goodwill of $112.4 million. These adjustments resulted in an increase in depreciation and amortization expense of $0.4 million recorded for the three months ended June 30, 2017. During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional measurement period adjustments. Contingent Consideration A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its fair value. We agreed to pay up to an additional $935.0 million in aggregate potential earn-out payments in May 2018 and May 2019. The acquisition date fair value of the potential earn-out payments of $416.3 million was originally recorded within Other long-term liabilities on our Consolidated Balance Sheets. As discussed in Note 11 – Other Long-term Liabilities, changes in the fair value of the liability (that were not accounted for as revisions of the acquisition date fair value) have been included in Other income (expense). Flag City Acquisition and Centrahoma Contributions On May 9, 2017, we purchased all of the equity interests in Flag City Processing Partners, LLC ("FCPP") from Boardwalk Midstream, LLC (“Boardwalk”) and all of the equity interests in FCPP Pipeline, LLC from Boardwalk Field Services, LLC (“BFS”) for a base purchase price of $60.0 million subject to customary closing adjustments. The final adjustment to the base purchase price paid to Boardwalk was an additional $3.6 million. As part of the acquisition (the “Flag City Acquisition”), we acquired a natural gas processing plant with 150 MMcf/d of operating capacity (the “Flag City Plant”) located in Jackson County, Texas; 24 miles of gas gathering pipeline systems and related rights of ways located in Bee and Karnes counties in Texas; 102.1 acres of land surrounding the Flag City Plant; and a limited number of gas supply contracts. In 2017, the gas processing activities under the Flag City Plant contracts were redirected to our Silver Oak Plants, and the Flag City Plant was decommissioned in order to move the plant and its component parts to other Targa locations. In December 2017, Targa contributed the Flag City Plant assets to Centrahoma Processing, LLC (“Centrahoma”), a consolidated subsidiary and joint venture that we operate, in which we have a 60% ownership interest. The remaining 40% ownership interest in Centrahoma is held by MPLX LP (“MPLX”). In 2018, utilizing the Flag City Plant assets, Centrahoma constructed the Hickory Hills Plant in Hughes County, Oklahoma (the “Hickory Hills Plant”). The Hickory Hills Plant processes growing natural gas production from the Arkoma Woodford Basin and began operations in December 2018. In October 2018, Targa also contributed the 120 MMcf/d cryogenic Tupelo Plant in Coal County, Oklahoma (the “Tupelo Plant”) to Centrahoma. In conjunction with Targa’s contribution of both the Flag City Plant assets and the Tupelo Plant, MPLX made cash contributions to Centrahoma in order to maintain its 40% ownership interest. We accounted for the Flag City Acquisition as an asset acquisition and capitalized less than $0.1 million of acquisition related costs as a component of the cost of assets acquired, which resulted in an allocation of $52.3 million of property, plant and equipment, $7.7 million of intangible assets for customer contracts and $3.6 million of current assets and liabilities, net. Purchase of Outstanding Silver Oak II Interest Effective as of June 1, 2017, we repurchased from SN Catarina, LLC (a subsidiary of Sanchez Energy Corp.) its 10% interest in our consolidated Silver Oak II Gas processing facility located in Bee County, Texas for a purchase price of $12.5 million. 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. Purchase of Outstanding 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. Divestitures Sale of Venice Gathering System, L.L.C. Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice Gas Plant and the Venice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations (“ARO”) were assumed by the buyer. Sale of Refined Products and Crude Oil Storage and Terminaling Facilities On September 12, 2018, we executed agreements to sell our Downstream refined products and crude oil storage and terminaling facilities in Tacoma, Washington, and Baltimore, Maryland, to a third party for approximately $165 million. The sale closed on October 31, 2018 and we used the proceeds to repay debt and to fund a portion of our growth capital program. In relation to the sale, we classified our Tacoma and Baltimore refined products and crude oil storage and terminaling facilities assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $57.5 million included within Other operating income (expense) in our Consolidated Statements of Operations in the third quarter of 2018. In the fourth quarter, we recognized an additional $1.6 million loss upon closing of the sale. The sale of these businesses does not qualify for reporting as discontinued operations as it did not represent a strategic shift that would have a major effect on our operations and financial results. Subsequent Event In February 2019, we entered into definitive agreements to sell a 45% interest in Targa Badlands LLC, the entity that holds all of our assets in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities for $1.6 billion. We will continue to be the operator of Targa Badlands LLC and will hold majority governance rights. Future growth capital is expected to be funded on a pro rata basis. Targa Badlands LLC will pay a minimum quarterly distribution to Blackstone and to Targa based on their initial investments, and Blackstone’s capital contributions will have a liquidation preference upon a sale of Targa Badlands LLC. We will continue to present Targa Badlands LLC on a consolidated basis in our consolidated financial statements. We expect to use the net cash proceeds to pay down debt and for general corporate purposes, including funding our growth capital program. The transaction is expected to close in the second quarter of 2019 and is subject to customary regulatory approvals and closing conditions. |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2018 | |
Inventory Disclosure [Abstract] | |
Inventories | December 31, 2018 December 31, 2017 Commodities $ 151.1 $ 191.6 Materials and supplies 13.6 12.9 $ 164.7 $ 204.5 |
Property, Plant and Equipment a
Property, Plant and Equipment and Intangible Assets | 12 Months Ended |
Dec. 31, 2018 | |
Property Plant And Equipment And Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | Property, Plant and Equipment December 31, 2018 December 31, 2017 Estimated Useful Lives (In Years) Gathering systems $ 7,547.9 $ 7,037.2 5 to 20 Processing and fractionation facilities 4,001.0 3,563.0 5 to 25 Terminaling and storage facilities 1,138.7 1,244.1 5 to 25 Transportation assets 445.1 343.6 10 to 25 Other property, plant and equipment 334.3 303.5 3 to 25 Land 144.3 125.7 — Construction in progress 3,602.5 1,581.5 — Property, plant and equipment 17,213.8 14,198.6 Accumulated depreciation (4,285.5 ) (3,768.7 ) Property, plant and equipment, net $ 12,928.3 $ 10,429.9 Intangible assets $ 2,736.6 $ 2,736.6 10 to 20 Accumulated amortization (753.4 ) (570.8 ) Intangible assets, net $ 1,983.2 $ 2,165.8 For each of the years ended December 31, 2018, 2017 and 2016 depreciation expense was $633.3 million, $621.3 million and $601.5 million. 2017 Impairment of North Texas Gathering and Processing Assets We recorded a non-cash pre-tax impairment charge of $378.0 million in the third quarter of 2017 for the partial impairment of gas processing facilities and gathering systems associated with our North Texas operations in our Gathering and Processing segment. The impairment was a result of our assessment that forecasted undiscounted future net cash flows from operations, while positive, would not be sufficient to recover the existing total net book value of the underlying assets. Given the price environment at the time, we projected a continuing decline in natural gas production across the Barnett Shale in North Texas due in part to producers pursuing more attractive opportunities in other basins. We measured the impairment of property, plant and equipment using discounted estimated future cash flow analysis (“DCF”) including a terminal value (a Level 3 fair value measurement). The future cash flows were based on our estimates of future revenues, income from operations and other factors, such as timing of capital expenditures. We took into account current and expected industry and market conditions, including commodity prices and volumetric forecasts. The discount rate used in our DCF analysis was based on a weighted average cost of capital determined from relevant market comparisons. These carrying value adjustments are included in Impairment of property, plant and equipment in our Consolidated Statements of Operations. Intangible Assets Intangible assets consist of customer contracts and customer relationships acquired in the Permian Acquisition and the acquisition of the Flag City Plant assets in SouthTX in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlands 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. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers. The intangible assets acquired in the Permian Acquisition were recorded at a fair value of $692.3 million. We are amortizing these intangible assets over a 15-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. The intangible assets acquired in the Flag City Acquisition were recorded at a fair value of $7.7 million. We are amortizing these intangible assets over a 10-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. The intangible assets acquired in the Atlas mergers were recorded at a fair value of $1,354.9 million. We are amortizing these intangible assets over a 20-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified. The intangible assets acquired in the Badlands acquisition were recorded at a fair value of $679.6 million. Amortization expense attributable to these intangible assets is recorded using a method that closely reflects the cash flow pattern underlying the intangible asset valuation over a 20-year life. For each of the years ended December 31, 2018, 2017 and 2016 amortization expense for our intangible assets was $182.6 million, $188.2 million and $156.1 million. The estimated annual amortization expense for intangible assets is approximately $171.6 million, $159.4 million, $149.5 million, $141.2 million and $136.0 million for each of the years 2019 through 2023. As of December 31, 2018, the weighted average amortization period for our intangible assets was approximately 14.9 years. The changes in our intangible assets are as follows: December 31, 2018 December 31, 2017 Beginning of period $ 2,165.8 $ 1,654.0 Additions from Permian Acquisition — 692.3 Additions from Flag City Acquisition — 7.7 Amortization (182.6 ) (188.2 ) End of period $ 1,983.2 $ 2,165.8 Asset Sales During the second quarter of 2018, we sold our inland marine barge business, which was included in our Logistics and Marketing segment, to a third party for $69.3 million. During the fourth quarter of 2018, we exchanged a portion of our Versado gathering system, located primarily in Yoakum County, Texas, and Lea County, New Mexico, and associated contracts and assets, with a third party for consideration that includes 1) a gathering system located primarily in Lea County, New Mexico, and associated contracts and assets, 2) an initial cash payment and 3) deferred payments due semi-annually beginning on June 30, 2019, through December 31, 2022. The acquired gathering system has been integrated into the Versado gathering system. Due to the significant monetary portion of the consideration received, the exchange of these assets was accounted for as a derecognition of nonfinancial assets, and a gain of $44.4 million was recognized in our Consolidated Statements of Operations for the year ended December 31, 2018 as part of Other operating (income) expense. The gain was calculated as the difference between the fair value of the consideration received, including the fair value of acquired gathering system, less our book basis of the assets transferred. The fair value of the acquired assets was determined using the indirect cost method of valuation, adjusted for any physical and economic obsolescence, and other management estimates. The fair value measurements of assets acquired are based on inputs that are a combination of Level 2 and Level 3 inputs, as defined in Note 14 – Fair Value Measurements. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2018 | |
Goodwill And Intangible Assets Disclosure [Abstract] | |
Goodwill | Goodwill related to the 2015 Atlas mergers was attributable to the WestTX and SouthTX reporting units in our Gathering and Processing segment. We also recognized goodwill of approximately $46.6 million related to the Permian Acquisition on March 1, 2017, which was attributed to the New Midland and New Delaware reporting units in our Gathering and Processing segment. Changes in the net amounts of our goodwill are as follows: WestTX SouthTX New Midland New Delaware Total Balance at December 31, 2015, net $ 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, net 174.7 35.3 — — 210.0 Permian Acquisition, March 1, 2017 — — 23.2 23.4 46.6 Balance at December 31, 2017, net 174.7 35.3 23.2 23.4 256.6 Impairment for 2018 annual assessment (174.7 ) (35.3 ) — — (210.0 ) Balance at December 31, 2018, net $ — $ — $ 23.2 $ 23.4 $ 46.6 The future cash flows and resulting fair values of these reporting units are sensitive to changes in crude oil, natural 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. 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 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. As of December 31, 2015, we had not completed our November 30, 2015 impairment assessment of the goodwill resulting from the February 2015 Atlas mergers. Based on the results of that preliminary evaluation, we recorded a provisional goodwill impairment in our Consolidated Statements of Operations during the fourth quarter of 2015. During the first quarter of 2016, we finalized our 2015 impairment assessment and recorded additional impairment expense of $24.0 million in our Consolidated Statements of Operations. 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 2016 annual evaluation of goodwill for impairment was completed in the fourth quarter of 2016. 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, We did not record any goodwill impairment charges for the year ended December 31, 2017, as the fair values of all reporting units exceeded their accounting carrying values. Our 2018 annual evaluation of goodwill for impairment was completed in the fourth quarter of 2018. Due to the impact of lower forecasted commodity prices and a reduction in forecasted volumes as a result of changes in producers’ drilling activity, we recorded impairment expense of $210.0 million in our Consolidated Statements of Operations, representing the impairment of the remaining goodwill for WestTX and SouthTX. |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 12 Months Ended |
Dec. 31, 2018 | |
Equity Method Investments And Joint Ventures [Abstract] | |
Investments in Unconsolidated Affiliates | Our • a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”); • three • a 50 Joint Venture ; • a 25% non-operated ownership interest in GCX; • a 50 ownership interest in Little Missouri 4; and • a 10% non-operated ownership interest in the Agua Blanca Joint Venture . Investments in GCF, Cayenne Joint Venture, GCX and Agua Blanca Joint Venture are included in the total assets of Logistics and Marketing segment. Investments in T2 Joint Ventures and Little Missouri 4 are included in the total assets of Gathering and Processing segment. See Note 24 — Segment Information for more information regarding our segment assets. 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. The T2 Joint Ventures were formed to provide services for the benefit of their joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companies have capacity lease agreements with their joint interest owners, which cover costs of operations (excluding depreciation and amortization). See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the formation of our GCX Joint Venture and Little Missouri 4 Joint Venture, and our acquisition of interests in the Cayenne Joint Venture and the Agua Blanca Joint Venture. The following table shows the activity related to our investments in unconsolidated affiliates: Balance at December 31, 2015 Equity Earnings (Loss) Cash Distributions (1) Acquisition (Disposition) Contributions Balance at December 31, 2016 GCF $ 49.5 $ 4.1 $ (7.5 ) $ — $ — $ 46.1 T2 LaSalle 63.6 (5.2 ) — — 0.2 58.6 T2 Eagle Ford 123.8 (9.4 ) — — 4.2 118.6 T2 EF Cogen 22.0 (3.8 ) (0.7 ) — — 17.5 Cayenne — — — — — — GCX — — — — — — Little Missouri 4 — — — — — — Agua Blanca — — — — — — Total $ 258.9 $ (14.3 ) $ (8.2 ) $ — $ 4.4 $ 240.8 Balance at December 31, 2016 Equity Earnings (Loss) Cash Distributions (1) Acquisition (Disposition) Contributions Balance at December 31, 2017 GCF $ 46.1 $ 12.4 $ (12.7 ) $ — $ — $ 45.8 T2 LaSalle 58.6 (4.9 ) — — 0.4 54.1 T2 Eagle Ford 118.6 (10.6 ) — — 1.2 109.2 T2 EF Cogen 17.5 (13.9 ) — — 0.3 3.9 Cayenne — — — 5.0 3.6 8.6 GCX — — — — — — Little Missouri 4 — — — — — — Agua Blanca — — — — — — Total $ 240.8 $ (17.0 ) $ (12.7 ) $ 5.0 $ 5.5 $ 221.6 Balance at December 31, 2017 Equity Earnings (Loss) Cash Distributions (1)(2) Acquisition (Disposition) Contributions (3) Balance at December 31, 2018 GCF $ 45.8 $ 16.8 $ (22.3 ) $ — $ — $ 40.3 T2 LaSalle 54.1 (4.9 ) — — 0.1 49.3 T2 Eagle Ford 109.2 (10.2 ) — — — 99.0 T2 EF Cogen 3.9 (1.8 ) — (2.1 ) — — Cayenne 8.6 6.4 (4.0 ) — 5.6 16.6 GCX (4) — 0.8 — — 210.8 211.6 Little Missouri 4 — — (8.0 ) — 75.3 67.3 Agua Blanca — 0.2 — 3.5 2.7 6.4 Total $ 221.6 $ 7.3 $ (34.3 ) $ 1.4 $ 294.5 $ 490.5 (1) Includes $5.5 million, $0.2 million and $4.1 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, 2018, 2017 and 2016. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in our Consolidated Statements of Cash Flows in the period in which they occur. (2) Includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures. (3) Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4. See Note 22 – Supplemental Cash Flow Information. (4) As discussed in Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures, our 25% interest in GCX is owned by GCX DevCo JV, of which we own a 20% interest. GCX DevCo JV is accounted for on a consolidated basis in our consolidated financial statements. Our equity loss for the year ended December 31, 2017 includes the effect of an impairment in the carrying value of our investment in T2 EF Cogen. As a result of the decrease in current and expected future utilization of the underlying cogeneration assets, we determined that factors indicated that a decrease in the value of our investment occurred that was other than temporary. As a result of this evaluation, we recorded an impairment loss of approximately $12.0 million in the first quarter of 2017, which represented our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as our impairment of the unamortized excess fair value resulting from the Atlas mergers. Effective December 31, 2018: (i) we conveyed our 50% ownership interest in T2 EF Cogen to our joint venture partner and received a distribution of certain assets from the joint venture; and, (ii) we were named as operator of T2 LaSalle and T2 Eagle Ford. The carrying values of the T2 Joint Ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of December 31, 2018 of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20-year useful lives of the underlying assets. The following tables summarize the combined financial information of our investments in unconsolidated affiliates (all data presented on a 100% basis): December 31, 2018 December 31, 2017 (In millions) Current assets $ 200.7 $ 29.1 Non-current assets $ 1,329.7 $ 379.8 Current liabilities $ 233.9 $ 11.0 Non-current liabilities $ 179.2 $ — Net assets $ 1,117.3 $ 397.9 Year Ended December 31, 2018 2017 2016 (In millions) Operating revenues $ 130.6 $ 84.3 $ 70.3 Operating expenses $ 96.9 $ 80.5 $ 91.4 Net income (loss) $ 34.7 $ 3.4 $ (21.5 ) |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 12 Months Ended |
Dec. 31, 2018 | |
Payables And Accruals [Abstract] | |
Accounts Payable and Accrued Liabilities | December 31, 2018 December 31, 2017 Commodities $ 721.9 $ 711.9 Other goods and services 474.5 286.9 Interest 79.4 54.1 Permian Acquisition contingent consideration, estimated current portion 308.2 6.8 Income and other taxes 45.4 26.3 Other 7.5 20.6 $ 1,636.9 $ 1,106.6 Accounts payable and accrued liabilities includes $52.2 million and $49.7 million of liabilities to creditors to whom we have issued checks that remain outstanding as of December 31, 2018 and December 31, 2017. The current portion of the Permian Acquisition contingent consideration represents the estimated fair value of the earn-out payments due within twelve months of the respective balance sheet dates. |
Debt Obligations
Debt Obligations | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt Obligations | December 31, 2018 December 31, 2017 Current: Accounts receivable securitization facility, due December 2019 (1) $ 280.0 $ 350.0 Senior unsecured notes, 4⅛% fixed rate, due November 2019 (2) 749.4 — 1,029.4 350.0 Debt issuance costs, net of amortization (1.5 ) — Current debt obligations 1,027.9 350.0 Long-term: Senior secured revolving credit facility, variable rate, due June 2023 (3) 700.0 20.0 Senior unsecured notes: 4⅛% fixed rate, due November 2019 — 749.4 5¼% fixed rate, due May 2023 559.6 559.6 4¼% fixed rate, due November 2023 583.9 583.9 6¾% fixed rate, due March 2024 580.1 580.1 5⅛% fixed rate, due February 2025 500.0 500.0 5⅞% fixed rate, due April 2026 1,000.0 — 5⅜% fixed rate, due February 2027 500.0 500.0 5% fixed rate, due January 2028 750.0 750.0 TPL notes, 4¾% fixed rate, due November 2021 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 48.1 48.1 Unamortized premium 0.3 0.4 5,228.5 4,298.0 Debt issuance costs, net of amortization (31.1 ) (30.0 ) Long-term debt 5,197.4 4,268.0 Total debt obligations $ 6,225.3 $ 4,618.0 Irrevocable standby letters of credit outstanding $ 79.5 $ 27.2 ________________ (1) As of December 31, 2018, we had $340.0 million of qualifying receivables under our $400.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. (2) The 4⅛ (3) As of December 31, 2018, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $1,420.5 million. The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2018, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2019 2020 2021 2022 2023 After 2023 (in millions) TRP Revolver $ 700.0 $ — $ — $ — $ — $ 700.0 $ — Senior unsecured notes (1) 5,277.6 749.4 — 6.5 — 1,191.6 3,330.1 Accounts receivable securitization facility 280.0 280.0 — — — — — Total $ 6,257.6 $ 1,029.4 $ — $ 6.5 $ — $ 1,891.6 $ 3,330.1 ________________________________________________________________________________________ (1) The 4⅛% 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, 2018: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 3.4% - 5.8% 3.8% Accounts receivable securitization facility 2.6% - 3.4% 3.0% Compliance with Debt Covenants As of December 31, 2018, we were in compliance with the covenants contained in our various debt agreements. Debt Obligations Revolving Credit Facility In June 2018, we entered into an agreement to amend and restate the TRP Revolver, which extended the maturity date from October 2020 to June 2023, increased available commitments from $1.6 billion to $2.2 billion and lowered the applicable margin range and commitment fee range used in the calculation of interest. Our ability to request additional commitments of $500.0 million remained unchanged. The TRP Revolver provides for certain changes to occur upon the Partnership receiving an investment grade credit rating from Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Corporation (“S&P”), including the release of the security interests in all collateral at the request of the Partnership. 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 (a) before the collateral release date, ranging from 0.25% to 1.25% dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (b) upon and after the collateral release date, ranging from 0.125% to 0.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The Eurodollar rate is equal to LIBOR rate plus an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. We are required to pay a commitment fee equal to an applicable rate ranging from (a) before the collateral release date, 0.25% to 0.375% (dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA) and (b) upon and after the collateral release date, 0.125% to 0.35% (dependent on our non-credit-enhanced senior unsecured long-term debt ratings) times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The TRP Revolver is collateralized by a pledge of assets and equity from certain of the Partnership’s subsidiaries. Borrowings are guaranteed by our restricted subsidiaries. The TRP Revolver requires us to maintain a total leverage ratio (the ratio of consolidated indebtedness to our consolidated Adjusted EBITDA, in each case as defined in the TRP Revolver), determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, of no more than (a) before the collateral release date, 5.50 to 1.00 and (b) upon and after the collateral release date, 5.25 to 1.00 (or 5.50 to 1.00 during a specified acquisition period). The TRP Revolver generally removes the requirement that we maintain a maximum senior leverage ratio (the ratio of consolidated indebtedness, excluding indebtedness arising in connection with unsecured debt to consolidated Adjusted EBITDA) of no more than 4.00 to 1.00, except that we may not incur second lien indebtedness or consummate an acquisition of, or investment in, any included unrestricted subsidiary that would cause our senior leverage ratio to exceed 4.00 to 1.00 and we may not redeem our preferred units if doing so would cause our senior leverage ratio to exceed 3.50 to 1.00. The TRP Revolver also requires us to maintain an interest coverage ratio of no less than 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination. For any four-fiscal quarter period during which a material acquisition or disposition occurs, the total leverage ratio and interest coverage ratio will be determined on a pro forma basis as though such event had occurred as of the first day of such four-fiscal quarter period. 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. 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, the aggregate principal of which shall not exceed $400,000,000). During the year ended December 31, 2018, we incurred a loss of $1.3 million to partially write-off debt issuance costs associated with the TRP Revolver amendment as a result of a change in syndicate members. The remaining debt issuance costs, along with debt issuance costs incurred with this amendment, will be amortized on a straight-line basis over the TRP Revolver’s new term. Accounts Receivable Securitization Facility On December 7, 2018, we amended and extended the accounts receivable securitization facility to increase the facility size from $350.0 million to $400.0 million with a termination date of December 6, 2019. As of December 31, 2018, total funding under the Securitization Facility was $280.0 million. The Securitization Facility provides up to $400.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 6, 2019. Under the Securitization Facility, certain 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 or contributed 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 or contributing subsidiaries or the Partnership. Any excess receivables are eligible to satisfy the claims. Senior Unsecured Notes All issues of unsecured senior notes are pari passu with existing and future senior indebtedness. 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 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 or 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 5 ⅛% Senior Notes February 1, 2020 105.125% 5 ⅜% Senior Notes February 1, 2020 105.375% 5% Senior Notes January 15, 2021 105.000% 5 ⅞% Senior Notes April 15, 2021 105.875% 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 5 ¼% Senior Notes November 1 2018 101.750 % 2019 100.875 % 2020 and thereafter 100 % 4 ¼% Senior Notes May 15 2018 102.125 % 2019 101.417 % 2020 100.708 % 2021 and thereafter 100 % 6 ¾% Senior Notes September 15 2019 103.375 % 2020 101.688 % 2021 and thereafter 100 % 5 ⅛% Senior Notes February 1 2020 103.844 % 2021 102.563 % 2022 101.281 % 2023 and thereafter 100 % 5 ⅞% Senior Notes April 15 2021 104.406 % 2022 102.938 % 2023 101.469 % 2024 and thereafter 100 % 5 ⅜% Senior Notes February 1 2022 102.688 % 2023 101.792 % 2024 100.896 % 2025 and thereafter 100 % 5% Senior Notes January 15 2023 102.500 % 2024 101.667 % 2025 100.833 % 2026 and thereafter 100 % TPL 4 ¾% Notes May 15 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 Unsecured Notes Issuances In October 2016, the Partnership Issuers issued $500.0 million of 5⅛ 5⅜ In October 2017, we issued $750.0 million aggregate principal amount of 5% senior notes due January 2028 (the “5% Senior Notes due 2028”). We used the net proceeds of $744.1 million after costs from this offering to redeem our 5% Senior Notes, reduce borrowings under our credit facilities, and for general partnership purposes. In April 2018, we issued $1.0 billion aggregate principal amount of 5 ⅞ ⅞ Subsequent Event In January 2019, we issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029, resulting in total net proceeds of $744.4 million and $744.4 million, respectively. The net proceeds from the offerings were used to redeem in full our outstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date and the remainder is expected to be used for general partnership purposes, which may include repaying borrowings under its credit facilities or other indebtedness, funding growth investments and acquisitions and working capital. Debt Repurchases & Extinguishments In June 2017, we redeemed our outstanding 6⅜% Senior Notes due August 2022 (“6⅜% Senior Notes”), totaling $278.7 million in aggregate principal amount, at a price of 103.188% of the principal amount plus accrued interest through the redemption date. The redemption resulted in a $10.7 million loss, which is reflected as Loss from financing activities in our Consolidated Statements of Operations for the year ended December 31, 2017 , consisting of premiums paid of $8.9 million and a non-cash loss to write-off $1.8 million of unamortized debt issuance costs. In October 2017, we redeemed our outstanding 5% Senior Notes due 2018 at par value plus accrued interest through the redemption date. The redemption resulted in a non-cash Loss from financing activities to write-off $0.2 million of unamortized debt issuance costs during the year ended December 31, 2017 . During the year ended December 31, 2016 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 During the years ended December 31, 2018 and 2017, we did not repurchase any of our outstanding senior notes on the open market. 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, 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 2020 ⅞ Debt Repurchases and Extinguishments Summary The following table summarizes the debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2018 2017 2016 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 6⅜% Senior Notes — 8.9 — 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 ) 4¼% Senior Notes — — (7.7 ) 6¾% Senior Notes — — (2.4 ) Write-off of debt issuance costs: TRP Revolver 1.3 — 0.9 5% Senior Notes — 0.2 4.2 4⅛% Senior Notes — — 0.4 6⅞% Senior Notes — — 4.9 6⅜% Senior Notes — 1.8 0.2 5¼% Senior Notes — — 0.2 4¼% Senior Notes — — 0.3 6¾% Senior Notes — — 0.2 Loss (gain) from financing activities $ 1.3 $ 10.9 $ 48.2 |
Other Long-term Liabilities
Other Long-term Liabilities | 12 Months Ended |
Dec. 31, 2018 | |
Other Liabilities Noncurrent [Abstract] | |
Other Long-term Liabilities | Other long-term liabilities are comprised of the following obligations: December 31, 2018 December 31, 2017 Asset retirement obligations $ 55.0 $ 50.3 Mandatorily redeemable preferred interests — 76.2 Deferred revenue 175.5 136.2 Permian Acquisition contingent consideration, noncurrent portion — 310.2 Other liabilities 3.3 3.1 Total long-term liabilities $ 233.8 $ 576.0 Asset Retirement Obligations Our ARO primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows: 2018 2017 Beginning of period $ 50.3 $ 64.1 Additions — 0.8 Reduction due to sale of VGS — (21.6 ) Change in cash flow estimate 1.8 3.1 Accretion expense 3.7 3.9 Retirement of ARO (0.8 ) — End of period $ 55.0 $ 50.3 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 years ended December 31, 2018, 2017 and 2016, interest earned on the notes receivable of $9.7 million, $10.3 million, and $10.5 million, exclusive of the priority return payable to our partner, is reflected within Interest expense, net in 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, 2018. 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. In February 2018, the parties amended the agreements governing each joint venture to: (i) increase the priority return for capital contributions made on or after January 1, 2017; and (ii) add a non-consent feature effective with respect to certain capital projects undertaken on or after January 1, 2017. During the year ended December 31, 2018, the change in estimated redemption value of the mandatorily redeemable preferred interests is primarily attributable to the amendments. The following table shows the changes attributable to mandatorily redeemable preferred interests: 2018 2017 Beginning of period $ 76.2 $ 68.5 Income attributable to mandatorily redeemable preferred interests (4.1 ) 4.4 Change in estimated redemption value included in interest expense, net (72.1 ) 3.3 End of period $ — $ 76.2 Deferred Revenue 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., entered into a long-term, fee-based agreement (“Splitter Agreement”) under which we would build and operate a crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“Channelview Splitter”) and provide approximately 730,000 Bbl of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 Bbl/d of crude oil and condensate into its various components, including naphtha, distillate, gas oil, kerosene/jet fuel, and liquefied petroleum gas and will provide segregated storage for the crude and condensate and each of their components. In January 2018, Vitol US Holding Co. acquired Noble Americas Corp. The first three annual payments of $43.0 million due under the Splitter Agreement were received in 2016, 2017 and 2018 and have been recorded as deferred revenue. The deferred revenue was expected to be recognized over the contractual term of seven years, commencing with start-up of operations. The Channelview Splitter is currently in the process of start-up and commissioning and has an estimated total cost of approximately $160 million. Deferred revenue also includes nonmonetary consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processing agreement. We measured the estimated fair value of the gathering assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. In December 2017, we received monetary consideration to further amend the terms of the gas gathering and processing agreement. 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 is being recognized over the periods that future performance will be provided, which extend through 2023. For the years ended December 31, 2018, 2017 and 2016, we recognized approximately $3.9 million, $3.1 million and $3.1 million of revenue for these transactions. The following table shows the components of deferred revenue: December 31, 2018 December 31, 2017 Splitter agreement $ 129.0 $ 86.0 Gas contract amendment 42.2 44.7 Other deferred revenue 4.3 5.5 Total deferred revenue $ 175.5 $ 136.2 The following table shows the changes in deferred revenue: 2018 2017 Beginning of period $ 136.2 $ 69.8 Additions 43.2 69.5 Revenue recognized (3.9 ) (3.1 ) End of period $ 175.5 $ 136.2 Permian Acquisition Contingent Consideration Upon closing of the Permian Acquisition, a contingent consideration liability arising from potential earn-out provisions was recognized at its preliminary fair value. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures. The first potential earn-out payment would have occurred in May 2018 while the second potential earn-out payment would occur in May 2019. The acquisition date fair value of the contingent consideration of $416.3 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets. For the period from the acquisition date to December 31, 2017, the fair value of the contingent consideration decreased by $99.3 million, primarily related to reductions in forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since the acquisition date, bringing the total Permian Acquisition contingent consideration to $317.0 million at December 31, 2017, of which $6.8 million was a current liability. The portion of the earn-out due in 2018 expired with no required payment. For the period from December 31, 2017 to December 31, 2018, the fair value of the contingent consideration decreased by $8.8 million, primarily attributable to lower actual and forecasted volumes for the remainder of the earn-out period, partially offset by a shorter discount period The following table shows the changes in the fair value of the contingent consideration related to the Permian Acquisition discussed in Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures: Year Ended December 31, 2018 March 1, 2017 to December 31, 2017 Beginning of period $ 317.0 $ 416.3 Decrease in fair value, included in Other income (expense) (8.8 ) (99.3 ) End of period 308.2 317.0 Less: Current portion (308.2 ) (6.8 ) Long-term balance at end of period — 310.2 See Note 14 – Fair Value Measurements for additional discussion of the fair value methodology. |
Partnership Units and Related M
Partnership Units and Related Matters | 12 Months Ended |
Dec. 31, 2018 | |
Partners Capital [Abstract] | |
Partnership Units and Related Matters | 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 common stock. 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 2018, 2017 and 2016: Three Months Ended Date Paid Or to Be Paid Total Distributions Distributions to Targa Resources Corp. 2018 December 31, 2018 February 13, 2019 $ 241.3 $ 238.5 September 30, 2018 November 13, 2018 237.6 234.8 June 30, 2018 August 13, 2018 234.0 231.2 March 31, 2018 May 11, 2018 229.7 226.9 2017 December 31, 2017 February 12, 2018 $ 228.5 $ 225.7 September 30, 2017 November 10, 2017 225.4 222.6 June 30, 2017 August 10, 2017 225.4 222.6 March 31, 2017 May 11, 2017 209.6 206.8 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 The IDR Giveback Amendment in conjunction with the Atlas mergers, 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 our 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 our 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 our 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 Subsequent to the TRC/TRP Merger, 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 our general partner. In December 2016, Targa made a $190.0 million capital contribution to us which was allocated accordingly. For the years ended December 31, 2018, 2017 and 2016, Targa made total capital contributions to us of $600.0 million, $1,720.0 million and $1,381.0 million. 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 Preferred Unitholders will not have the conversion right described above with respect to the Preferred Units called for redemption. The Preferred Unitholders have no voting rights except for certain exceptions set forth in our Partnership Agreement. As of December 31, 2018, we have 5,000,000 Preferred Units outstanding. We paid $11.3 million of distributions each year to the Preferred Unitholders for 2018, 2017 and 2016. In January and February 2019, the board of directors of our general partner declared a cash distribution of $0.1875 per Preferred Unit, resulting in approximately $0.9 million in distributions each month. The distributions declared in January were paid on February 15, 2019 and the distributions declared in February will be paid on March 15, 2019. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
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 entered into derivative instruments to hedge the commodity price risks associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Marketing segment and (iii) natural gas transportation basis risk in our Logistics and Marketing segment 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 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. 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, 2018, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2019 2020 2021 2022 2023 Natural Gas Swaps MMBtu/d 171,102 63,630 35,755 - - Natural Gas Basis Swaps MMBtu/d 113,295 105,417 91,658 75,000 20,000 NGL Swaps Bbl/d 17,929 13,267 3,676 - - NGL Futures Bbl/d 8,975 3,115 - - - NGL Options Bbl/d 410 - - - - Condensate Swaps Bbl/d 3,413 1,980 994 - - Condensate Options Bbl/d 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 on 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, 2018 Fair Value as of December 31, 2017 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 112.5 $ 18.9 $ 37.9 $ 78.6 Long-term 31.6 1.5 23.2 18.7 Total derivatives designated as hedging instruments $ 144.1 $ 20.4 $ 61.1 $ 97.3 Derivatives not designated as hedging instruments Commodity contracts Current $ 2.8 $ 14.7 $ — $ 1.1 Long-term 2.5 1.6 — 0.9 Total derivatives not designated as hedging instruments $ 5.3 $ 16.3 $ — $ 2.0 Total current position $ 115.3 $ 33.6 $ 37.9 $ 79.7 Total long-term position 34.1 3.1 23.2 19.6 Total derivatives $ 149.4 $ 36.7 $ 61.1 $ 99.3 The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro Forma Net Presentation December 31, 2018 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 100.0 $ (33.6 ) $ (14.2 ) $ 70.0 $ (17.8 ) Counterparties without offsetting positions - assets 15.3 - - 15.3 - Counterparties without offsetting positions - liabilities - - - - - 115.3 (33.6 ) (14.2 ) 85.3 (17.8 ) Long Term Position Counterparties with offsetting positions or collateral 8.9 (3.1 ) - 5.9 (0.1 ) Counterparties without offsetting positions - assets 25.2 - - 25.2 - Counterparties without offsetting positions - liabilities - - - - - 34.1 (3.1 ) - 31.1 (0.1 ) Total Derivatives Counterparties with offsetting positions or collateral 108.9 (36.7 ) (14.2 ) 75.9 (17.9 ) Counterparties without offsetting positions - assets 40.5 - - 40.5 - Counterparties without offsetting positions - liabilities - - - - - $ 149.4 $ (36.7 ) $ (14.2 ) $ 116.4 $ (17.9 ) Gross Presentation Pro Forma Net Presentation December 31, 2017 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 37.9 $ (74.7 ) $ 22.9 $ 13.8 $ (27.7 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (5.0 ) - - (5.0 ) 37.9 (79.7 ) 22.9 13.8 (32.7 ) Long Term Position Counterparties with offsetting positions or collateral 23.2 (17.3 ) - 14.8 (8.9 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (2.3 ) - - (2.3 ) 23.2 (19.6 ) - 14.8 (11.2 ) Total Derivatives Counterparties with offsetting positions or collateral 61.1 (92.0 ) 22.9 28.6 (36.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.3 ) - - (7.3 ) $ 61.1 $ (99.3 ) $ 22.9 $ 28.6 $ (43.9 ) 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 asset of $112.7 million as of December 31, 2018. The estimated fair value is net of an adjustment for credit risk based on the default probabilities 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 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 2018 2017 2016 Commodity contracts $ 132.5 $ (28.8 ) $ (103.6 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2018 2017 2016 Revenues (38.4 ) (44.6 ) 45.0 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 2018 2017 2016 Commodity contracts Revenue $ (32.5 ) $ (5.1 ) $ 0.9 Based on valuations as of December 31, 2018, we expect to reclassify commodity hedge related deferred gains of $123.8 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2021, with $92.5 million of gains to be reclassified over the next twelve months. See Note 14 – Fair Value Measurements and Note 24 – Segment Information for additional disclosures related to derivative instruments and hedging activities. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
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 on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on 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, 2018, a net asset position of $112.7 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 asset of $37.3 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 $188.7 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. Contingent consideration liabilities related to business acquisitions are carried at fair value. 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 on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: December 31, 2018 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) $ 144.4 $ 144.4 $ — $ 137.5 $ 6.9 Liabilities from commodity derivative contracts (1) 31.7 31.7 — 31.3 0.4 Permian Acquisition contingent consideration (2) 308.2 308.2 — — 308.2 TPL contingent consideration (3) 2.4 2.4 — — 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 203.3 203.3 — — — TRP Revolver 700.0 700.0 — 700.0 — Senior unsecured notes 5,277.9 5,088.9 — 5,088.9 — Accounts receivable securitization facility 280.0 280.0 — 280.0 — December 31, 2017 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) $ 60.3 $ 60.3 $ — $ 58.8 $ 1.5 Liabilities from commodity derivative contracts (1) 98.5 98.5 — 93.3 5.2 Permian Acquisition contingent consideration (2) 317.0 317.0 — — 317.0 TPL contingent consideration (3) 2.4 2.4 — — 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 124.7 124.7 — — — TRP Revolver 20.0 20.0 — 20.0 — Senior unsecured notes 4,278.0 4,362.4 — 4,362.4 — Accounts receivable securitization facility 350.0 350.0 — 350.0 — ________________ (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) We have a contingent consideration liability related to the Permian Acquisition, which is carried at fair value. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures. (3) 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. Additional Information Regarding Level 3 Fair Value Measurements Included on 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, 2018, we had 13 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 Permian Acquisition contingent consideration was determined using a Monte Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. A significant decrease in expected gross margin during the earn-out period, or significant increase in the discount rate or volatility would result in a lower fair value estimate. The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs for both models are not observable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. Changes in the fair value of these liabilities are included in Other income (expense) in our 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, 2017 $ (3.8 ) $ (319.4 ) Change in fair value of Permian Acquisition contingent consideration (1) - 8.8 New Level 3 derivative instruments (1.4 ) - Settlements included in Revenue 2.8 - Unrealized gain/(loss) included in OCI 8.9 - Balance, December 31, 2018 $ 6.5 $ (310.6 ) ________________ (1) Represents the change in fair value between December 31, 2017 and December 31, 2018 of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the initial fair value. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Transactions with Unconsolidated Affiliates The following table summarizes transactions with unconsolidated affiliates: GCF T2 Joint Ventures Cayenne GCX Total 2018: Revenues $ 0.3 $ 5.2 $ — $ 0.1 $ 5.6 Product purchases (5.1 ) (0.6 ) (7.2 ) (1.2 ) $ (14.1 ) Operating expenses — (3.6 ) — — $ (3.6 ) 2017: Revenues $ 0.3 $ 2.1 $ — $ — $ 2.4 Product purchases (4.4 ) (1.1 ) — — (5.5 ) Operating expenses — (3.8 ) — — (3.8 ) 2016: Revenues $ 0.4 $ 5.2 $ — $ — $ 5.6 Product purchases (3.2 ) (2.6 ) — — (5.8 ) Operating expenses — (4.0 ) — — (4.0 ) 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) until March 2018, 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, 2018 2017 2016 Targa billings of payroll and related costs included in operating expenses $ 236.8 $ 204.4 $ 171.8 Targa allocation of general and administrative expense 221.4 175.2 159.9 Cash distributions to Targa based on general partner and limited partner ownership (1) 918.5 847.3 587.0 Cash contributions from Targa related to limited partner ownership (2) 588.1 1,685.5 1,353.4 Cash contributions from Targa to maintain its 2% general partner ownership 12.0 34.5 27.6 ________________ (1) Prior to the execution of the Third A&R Partnership Agreement, 2016 cash distributions to Targa also included IDRs. (2) The 2016 cash contributions from Targa related to limited partner ownership was contributed for the issuance of common units. The 2018 and 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to the general partner. See Note 12 – Partnership Units and Related Matters. Relationship with Sajet Resources LLC In December 2010, immediately prior to Targa’s initial public offering, Sajet Resources LLC (“Sajet”) was spun-off from Targa. The primary assets of Sajet are real property. Sajet also holds (i) an ownership interest in Floridian Natural Gas Storage Company, LLC through a December 2016 merger with Tesla Resources LLC, (ii) an ownership interest in Allied CNG Ventures LLC and (iii) certain technology rights. Former holders of our pre-IPO common equity, including certain of our current and former executives, managers and directors collectively own an 18% interest in Sajet. We provide general and administrative services to Sajet and were reimbursed for these amounts at our actual cost. Fees for services provided to Sajet totaled less than $0.1 million in January and February of 2018, $0.3 million in the year ended December 31, 2017, and $0.5 million in the year ended December 31, 2016. In March 2018, we acquired the 82% interest in Sajet that was held by Warburg Pincus sponsored funds for $5.0 million in cash (the “Warburg Funds Transaction”) and extinguished Sajet’s third-party debt in exchange for a promissory note from Sajet of $9.9 million. Minority shareholders had the right to join the transaction and sell up to 100% of their membership interests in Sajet to us at substantially the same terms and price as the Warburg Funds Transaction (the “Tag-Along Rights”). Minority shareholders who currently hold, or formerly held, executive positions at Targa, and minority shareholders who are board members of Targa, agreed not to exercise their Tag-Along Rights resulting from the Warburg Funds Transaction. Certain minority shareholders chose to sell interests totaling 1.6% for approximately $0.1 million in April 2018. Since March 2018, Sajet has been accounted for on a consolidated basis in our consolidated financial statements. |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2018 | |
Leases [Abstract] | |
Commitments | Future non-cancelable commitments related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregate thereafter: In Aggregate 2019 2020 2021 2022 2023 Thereafter Operating leases (1) $ 73.4 $ 20.5 $ 17.7 $ 14.9 $ 12.6 $ 6.0 $ 1.7 Land site lease and rights of way (2) 122.3 4.0 3.6 3.7 4.2 4.0 102.8 $ 195.7 $ 24.5 $ 21.3 $ 18.6 $ 16.8 $ 10.0 $ 104.5 ________________ (1) Includes minimum payments on lease obligations for office space, railcars and tractors. (2) Land site lease and rights 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 non-cancelable commitments were: 2018 2017 2016 Operating leases (1) $ 51.9 $ 46.2 $ 45.1 Land site lease and rights of way 6.1 5.2 4.4 $ 58.0 $ 51.4 $ 49.5 ________________ (1) Includes short-term leases for items such as compressors and equipment. |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Loss Contingency [Abstract] | |
Contingencies | Legal Proceedings We are a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We are also a party to various proceedings with governmental environmental agencies in 2018, including but not limited to the Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Health, Environmental Health Section, which assert penalties for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business. On December 28, 2018, Targa Midstream Services LLC and the New Mexico Environment Department entered into a Settlement Agreement and Stipulated Final Compliance Order resolving alleged air emissions violations relating to flaring of acid gas at Targa Midstream Services LLC’s Monument gas processing plant in Lea County, New Mexico. This order imposes a $150,000 penalty and a Supplemental Environmental Project involving the provision of additional compression facilities. Additionally, on February 26, 2019, the U.S. Environmental Protection Agency Region 8 and Targa Badlands LLC entered into a Final Order and Consent Agreement in connection with Targa Badland LLC’s alleged violation of Subpart ZZZZ of the National Emission Standards for Hazardous Air Pollutants at its Junction Compressor Station in McKenzie County, North Dakota. The Consent Agreement imposes a $220,000 civil penalty and certain compliance improvements. |
Significant Risks and Uncertain
Significant Risks and Uncertainties | 12 Months Ended |
Dec. 31, 2018 | |
Risks And Uncertainties [Abstract] | |
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, NGLs and crude oil 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, future commodity purchases and sales, and transportation basis risk. 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 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 limit our use of swaps to hedge the prices of less than our expected equity volumes. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange margin requirements, so we may have to increase our cash deposit due to a rise in natural gas and NGL prices. 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 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 $36.7 million as of December 31, 2018. The range of losses attributable to our individual counterparties would be between $0.3 million and $28.0 million, depending on the counterparty in default. The 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 the counterparties decline, the 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 $0.1 million as of December 31, 2018 and $0.1 million as of December 31, 2017. Significant Commercial Relationship During the year ended December 31, 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 15% of our consolidated revenues. No customer comprised greater than 10% of our consolidated revenues in the years ended December 31, 2017 and 2016. Interest Rate Risk We are exposed to changes in interest rates, primarily as a result of 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. |
Revenue
Revenue | 12 Months Ended |
Dec. 31, 2018 | |
Revenue From Contract With Customer [Abstract] | |
Revenue | Fixed consideration allocated to remaining performance obligations The following table includes the estimated minimum revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments and for which a guaranteed amount of revenue can be calculated . These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements. 2019 2020 2021 and after Fixed consideration to be recognized as of December 31, 2018 $ 496.5 $ 450.8 $ 2,126.9 In accordance with the optional exemptions that we elected to apply, the amounts presented in the table exclude variable consideration for which the allocation exception is met and consideration associated with performance obligations of short-term contracts. In addition, consideration from contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed is also excluded from the table above, with the exception of any fixed consideration attributable to such contracts. The nature of the performance obligations for which the consideration has been excluded is consistent with the performance obligations described within our revenue recognition accounting policy and the estimated remaining duration of such contracts primarily ranges from 1 to 15 years. In addition, variability exists in the consideration excluded due to the unknown quantity and composition of volumes to be serviced or sold as well as fluctuations in the market price of commodities to be received as consideration or sold over the applicable remaining contract terms. Such variability is resolved at the end of each future month or quarter. For additional information on our revenue recognition policy and the adoption of ASU No. 2014-09, see Note 3 – Significant Accounting Policies. For disclosures related to disaggregated revenue, see Note 24 – Segment Information. |
Other Operating (Income) Expens
Other Operating (Income) Expense | 12 Months Ended |
Dec. 31, 2018 | |
Other Income And Expenses [Abstract] | |
Other Operating (Income) Expense | Other Operating (Income) Expense is comprised of the following: Year Ended December 31, 2018 2017 2016 (Gain) loss on sale or disposal of assets $ (0.1 ) $ 15.9 $ 6.1 Miscellaneous business tax 3.2 0.8 0.5 Other 0.4 0.7 — $ 3.5 $ 17.4 $ 6.6 The (Gain) loss on sale or disposal of assets is comprised of the following: Year Ended December 31, 2018 2017 2016 Sale of inland marine barge business $ (48.1 ) $ — $ — Exchange of a portion of Versado gathering system (44.4 ) — — Sale of storage and terminaling facilities 59.1 — — Disposal of benzene treating unit 20.5 — — Sale of Venice gathering system — 16.1 — Other 12.8 (0.2 ) 6.1 $ (0.1 ) $ 15.9 $ 6.1 |
Income Tax
Income Tax | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Tax | Our income tax expense (benefit) is summarized below: 2018 2017 2016 Current expense (benefit) $ — $ (4.5 ) $ — Deferred expense (benefit) (0.1 ) (2.9 ) (0.3 ) Total income tax expense (benefit) $ (0.1 ) $ (7.4 ) $ (0.3 ) On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). The Tax Act makes broad and complex changes to the Internal Revenue Code of 1986, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) eliminating the corporate alternative minimum tax (AMT) and changing how existing AMT credits are realized; (3) creating a new limitation on deductible interest expense; and (4) changing rules related to uses and limitation of net operating loss carryforwards created in tax years beginning after December 31, 2017. The SEC staff issued Staff Accounting Bulletin No. 118 (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Act for which the accounting under ASC 740 is complete. To the extent that a company's accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act. In connection with our initial analysis of the impact of the Tax Act, we recorded a discrete net deferred tax benefit of $1.0 million in the year ended December 31, 2017, for TPL Arkoma, Inc. This net deferred tax benefit consisted of the corporate tax rate reduction. As of December 31, 2017, we were able to make reasonable estimates of certain elements of the Tax Act, which we recorded as provisional adjustments. Our accounting for all applicable elements of the Tax Act is complete: • We reclassified $0.3 million of AMT credits from deferred tax assets to long term assets. We expect to receive this amount as a refund in 2019, 2020 and 2021. • Reduction of U.S. federal corporate tax rate: The Tax Act reduces the corporate tax rate to 21%, effective January 1, 2018. We recorded a provisional deferred tax benefit of $1.0 million for the year ended December 31, 2017. • Cost recovery: In the year ended December 31, 2017, we recorded a provisional tax depreciation expense of $0.7 million, which did not include full expensing of all qualifying capital expenditures. In the year ended December 31, 2018, we completed our analysis of capital expenditures and recorded no additional expenditures. 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. Our deferred income tax assets and liabilities at December 31, 2018 and 2017, consisted of differences related to the timing of recognition of certain types of costs as follows: 2018 2017 Deferred tax assets: Net operating loss carryforwards $ 12.9 $ 13.7 Deferred tax liabilities: Property, plant, and equipment (36.8 ) (37.7 ) Net deferred tax asset (liability) $ (23.9 ) $ (24.0 ) As of December 31, 2018, TPL Arkoma, Inc. had net operating loss carry forwards for federal income tax purposes of approximately $50.3 million, which expire at various dates from 2029 to 2038. 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, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Year Ended December 31, 2018 2017 2016 Cash: Interest paid, net of capitalized interest (1) $ 203.2 $ 198.7 $ 263.8 Income taxes paid, net of refunds 0.2 (4.9 ) 1.3 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 49.0 $ 9.0 $ 17.4 Impact of capital expenditure accruals on property, plant and equipment 216.9 205.4 27.6 Transfers from materials and supplies inventory to property, plant and equipment 12.7 3.6 2.4 Contribution of property, plant and equipment to investments in unconsolidated affiliates 16.0 1.0 Change in ARO liability and property, plant and equipment due to revised cash flow estimate 1.8 3.1 (9.1 ) Property, plant and equipment received in asset exchange 24.1 — — Receivable for asset exchange 15.0 — — Asset received related to conveyance of ownership interest in investment in unconsolidated affiliate 3.0 — — Non-cash financing activities: Cancellation of treasury units — — 10.4 Accrued distributions on unvested equity awards under share compensation arrangements — — 0.2 Exchange of IDRs and Special GP interest for units — — 903.6 Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): Contingent consideration recorded at the acquisition date $ — $ 416.3 $ — Non-cash balance sheet movements related to the purchase of noncontrolling interests in subsidiary (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): Common limited partner units $ — $ — $ 63.7 General partner units — — 1.3 Noncontrolling interests — — (65.0 ) Non-cash balance sheet movements related to acquisition of related party: Noncontrolling interest $ 1.1 $ — $ — ________________ (1) Interest capitalized on major projects was $46.3 million, $14.3 million and $8.3 million for the years ended December 31, 2018, 2017 and 2016. |
Compensation Plans
Compensation Plans | 12 Months Ended |
Dec. 31, 2018 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
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. Awards Under TRP LTIP 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. The TRP LTIP was administered by the board of directors of our general partner 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 distribution equivalent rights based on the notional distributions accumulated during the vesting period times the vesting percentage. Distribution equivalent rights 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. Distribution equivalent rights 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. 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 distribution equivalent rights of the phantom units were accumulated to be paid in cash at the vesting dates. 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 distribution equivalent rights of the replacement phantom units are paid in cash within 60 days of the payment of distributions. 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 value of the director grants granted in 2016 was $10.11. The fair value related to the units vested was $0.3 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 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 total employees affected by the amendment of the TRP LTIP were 363. 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 addition to the conversion of TRP awards, we issued 331,282 restricted stock units under the Plan in 2016 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 our nonexecutives. The grant-date fair value for the issuances was $74.01. In 2018 and 2017, no restricted stock units were issued under the Plan. The following table summarizes the restricted stock units for the year ended December 31, 2018, under the Plan: Number Weighted-average of shares Grant-Date Fair Value Outstanding as of December 31, 2017 497,947 $ 40.54 Forfeited (4,956 ) 32.86 Vested (191,300 ) 61.94 Outstanding as of December 31, 2018 301,691 27.10 TRC Long Term Incentive Plan The TRC LTIP is administered by the Compensation 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 distribution equivalent rights 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. During 2018, the remaining 112,550 shares of cash-settled awards vested and paid for $6.9 million. The cash settled for the awards under TRC LTIP were $6.9 million, $4.1 million and $4.8 million for 2018, 2017 and 2016. 2010 TRC Stock Incentive Plan In December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan for employees, consultants and non-employee directors of the Company. In May 2017, the 2010 TRC Plan was amended and restated (the “2010 TRC Plan”). Total authorized shares of common stock under the plan is 15,000,000, comprised of 5,000,000 shares originally available and an additional 10,000,000 shares that became available in May. 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 as “Awards”). Unless otherwise specified, the compensation costs for the awards listed below were recognized as expenses over related vesting periods based on the grant-date fair values, reduced by forfeitures incurred. Restricted Stock Awards - 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 vested 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. There was no issuance of this type of awards in 2017 and 2018. Director Grants – The committee awarded Targa’s common stock to its outside directors. In 2018, 2017 and 2016, Targa issued 16,955, 13,818 and 24,234 shares of director grants with the weighted average grant-date fair value of $51.21, $60.48 and $16.45. Starting from January 1, 2018, director grants are restricted stock awards that vest in one year. In prior years, directors were granted shares of common stock with no vesting requirement. Restricted Stock Units Awards – Restricted Stock Units (“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 2018, 2017 and 2016, Targa issued 1,393,812, 1,193,942 and 1,129,705 shares of RSUs with the weighted average grant-date fair value of $51.71, $54.18 and $27.87. The 2018 issuances include 275,076 shares of RSUs for our new retention program. These shares will vest in four years. Restricted Stock in Lieu of Bonus – During 2018, 2017 and 2016, Targa issued 112,438, 84,221 and 153,252 shares of restricted stock awards in lieu of cash bonuses in the form of RSUs for its executives at the weighted average grant-date fair value of $51.09, $55.94 and $26.34. These awards will cliff vest over three years. Dividends on these awards are paid quarterly. 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, 2017 2,428,798 $ 43.78 Granted 1,410,767 51.70 Forfeited (52,449 ) 47.26 Vested (192,981 ) 72.28 Outstanding at December 31, 2018 3,594,135 45.31 Performance Share Units During 2018 and 2017, we issued 182,849 and 113,901 shares of performance share units (“PSUs”) to executive management and employees for the 2018 and 2017 compensation cycle that will vest on December 31, 2020 and December 31, 2019. The PSUs 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 (“DERs”) that are based on the notional dividends accumulated during the vesting period. The vesting of the PSUs 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 PSUs equal to the target number awarded multiplied by the TSR performance factor, and vested PSUs will be settled by the issuance of Company common stock. The value of dividend equivalent rights will be paid in cash. Compensation cost for equity-settled PSUs was recognized as an expense over the performance period based on fair value at the grant date. The compensation cost will be reduced if forfeitures occur. Fair value was calculated using a simulated share price that incorporates peer ranking. DERs associated with equity-settled PSUs 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 with an expected term of three years. The expected volatilities were 55% - 61% for PSUs granted in 2017 and 29% - 53% for PSUs granted in 2018. The following table summarizes the PSUs under the 2010 TRC Plan in shares and in dollars for the years indicated. Number Weighted Average of shares Grant-Date Fair Value Outstanding at December 31, 2017 113,901 $ 99.71 Granted 182,849 81.02 Outstanding at December 31, 2018 296,750 88.19 Cash-settled Awards In October, we issued 69,042 shares of cash-settled awards for our new retention program. These awards vest each quarter for one year. The fair value of the awards is evaluated based on the average of TRC stock prices for the last ten trading days at the end of each quarter. The following table summarizes the cash-settled restricted stock units for the year ended 2018. 2018 Awards Outstanding as of December 31, 2017 — Granted 69,042 Vested and paid (16,872 ) Forfeited (1,942 ) Outstanding as of December 31, 2018 50,228 Calculated fair market value as of December 31, 2018 $ 2,546,445 Current liability $ 1,332,308 Long-term liability — Liability as of December 31, 2018 $ 1,332,308 To be recognized in future periods $ 1,214,137 Stock compensation expense under our plans totaled $59.0 million, $44.2 million, and $41.2 million for the years ended December 31, 2018, 2017, and 2016. As of December 31, 2018, we have $109.4 million of unrecognized compensation expense associated with share-based awards and an approximate remaining weighted average vesting periods of 2.6 years related to our various compensation plans. The fair values of share-based awards vested in 2018, 2017 and 2016 were $18.8 million, $14.4 million and $17.1 million. Cash dividends paid for the vested awards were $3.5 million, $2.5 million and $2.7 million for 2018, 2017 and 2016. Subsequent Events In January 2019, the Compensation Committee of the Targa board of directors made the following awards under the 2010 TRC Plan. • 25,344 shares of restricted stock to our outside directors that will vest in January 2020. • 20,316 shares of RSUs under retention program that will vest on October 1, 2022, together with 3,842 cash-settled RSUs that vest 33% on March 31, 2019, 33% on Jun 30, 2019 and 34% on September 30, 2019. • 269,530 shares of RSUs to executive management for the 2019 compensation cycle that will vest in January 2022 • 261,245 shares of PSUs to executive management for the 2019 compensation cycle that will vest in December 2021. • 95,687 shares of RSUs in lieu of cash bonus to executive management for the 2019 compensation cycle that will vest in January 2022. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Segment Information | We operate in two primary segments: (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. 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 (including the Midland and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK plays) and South Central Kansas; the Williston Basin in North Dakota; and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico. Our Logistics and Marketing segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Marketing segment includes Grand Prix, which is currently under construction. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipeline projects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana. Other contains the results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are 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, 2018 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 1,257.4 $ 8,058.4 $ (37.1 ) $ — $ 9,278.7 Fees from midstream services 715.6 489.7 — — 1,205.3 1,973.0 8,548.1 (37.1 ) — 10,484.0 Intersegment revenues Sales of commodities 3,636.0 317.1 — (3,953.1 ) — Fees from midstream services 7.2 30.8 — (38.0 ) — 3,643.2 347.9 — (3,991.1 ) — Revenues $ 5,616.2 $ 8,896.0 $ (37.1 ) $ (3,991.1 ) $ 10,484.0 Operating margin $ 968.4 $ 592.5 $ (37.1 ) $ — $ 1,523.8 Other financial information: Total assets (1) $ 11,478.8 $ 5,180.6 $ 127.1 $ 103.6 $ 16,890.1 Goodwill $ 46.6 $ — $ — $ — $ 46.6 Capital expenditures $ 1,548.6 $ 1,767.0 $ — $ 12.1 $ 3,327.7 (1) Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Year Ended December 31, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 781.4 $ 6,979.3 $ (9.6 ) $ — $ 7,751.1 Fees from midstream services 566.3 497.5 — — 1,063.8 1,347.7 7,476.8 (9.6 ) — 8,814.9 Intersegment revenues Sales of commodities 3,154.2 321.9 — (3,476.1 ) — Fees from midstream services 6.9 28.0 — (34.9 ) — 3,161.1 349.9 — (3,511.0 ) — Revenues $ 4,508.8 $ 7,826.7 $ (9.6 ) $ (3,511.0 ) $ 8,814.9 Operating margin $ 783.8 $ 511.8 $ (9.6 ) $ — $ 1,286.0 Other financial information: Total assets (1) $ 10,732.3 $ 3,507.4 $ 56.8 $ 62.5 $ 14,359.0 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 1,008.9 $ 470.4 $ — $ 27.2 $ 1,506.5 Business acquisition $ 987.1 $ — $ — $ — $ 987.1 (1) Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. 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) Assets in the Corporate and Eliminations column 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: 2018 2017 2016 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $ 1,810.0 $ 2,005.9 $ 1,591.2 NGL 6,886.9 5,454.2 3,793.4 Condensate 457.9 196.0 133.9 Petroleum products 196.1 144.7 68.2 9,350.9 7,800.8 5,586.7 Non-customer revenue: Derivative activities - Hedge (39.7 ) (44.7 ) 39.1 Derivative activities - Non-hedge (1) (32.5 ) (5.0 ) 1.0 (72.2 ) (49.7 ) 40.1 Total sales of commodities 9,278.7 7,751.1 5,626.8 Fees from midstream services: Revenue recognized from contracts with customers: Fractionating and treating 120.7 132.8 126.2 Storage, terminaling, transportation and export 349.9 342.2 420.0 Gathering and processing 698.1 523.3 445.0 Other 36.6 65.5 72.9 Total fees from midstream services 1,205.3 1,063.8 1,064.1 Total revenues $ 10,484.0 $ 8,814.9 $ 6,690.9 (1) Represents derivative activities that are not designated as hedging instruments under ASC 815. The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: 2018 2017 2016 Reconciliation of reportable segment operating margin to income (loss) before income taxes: Gathering and Processing operating margin $ 968.4 $ 783.8 $ 577.1 Logistics and Marketing operating margin 592.5 511.8 574.4 Other operating margin (37.1 ) (9.6 ) 62.9 Depreciation and amortization expenses (815.9 ) (809.5 ) (757.7 ) General and administrative expenses (240.8 ) (190.5 ) (177.1 ) Impairment of property, plant and equipment — (378.0 ) — Impairment of goodwill (210.0 ) — (207.0 ) Interest expense, net (170.0 ) (217.8 ) (233.5 ) Change in contingent considerations 8.8 99.6 0.4 Other, net 2.6 (47.8 ) (68.5 ) Income (loss) before income taxes $ 98.5 $ (258.0 ) $ (229.0 ) |
Selected Quarterly Financial Da
Selected Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2018 | |
Selected Quarterly Financial Information [Abstract] | |
Selected Quarterly Financial Data (Unaudited) | Our results of operations by quarter for the years ended December 31, 2018 and 2017 were as follows: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018 Revenues $ 2,455.6 $ 2,444.4 $ 2,986.4 $ 2,597.6 $ 10,484.0 Gross margin 514.6 539.1 602.9 589.2 2,245.8 Income (loss) from operations (1) 90.4 159.2 80.6 (76.6 ) 253.6 Net income (loss) 56.0 162.6 (8.7 ) (111.3 ) 98.6 Net income (loss) attributable to common limited partners 39.2 147.6 (20.8 ) (127.1 ) 38.9 2017 Revenues $ 2,112.6 $ 1,867.7 $ 2,131.8 $ 2,702.8 $ 8,814.9 Gross margin 458.4 447.1 468.7 534.6 1,908.8 Income (loss) from operations (2) 53.7 40.7 (320.3 ) 116.5 (109.4 ) Net income (loss) (21.3 ) (29.2 ) (245.0 ) 44.9 (250.6 ) Net income (loss) attributable to common limited partners (29.5 ) (41.4 ) (252.3 ) 28.4 (294.8 ) ________________ (1) Includes ( 2 ) Includes a non-cash pre-tax impairment charge of $378.0 million |
Significant Accounting Polici_2
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
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 gathering and 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. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as an impairment loss within equity earnings (loss) in our Consolidated Statements of Operations. |
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 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 included in 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). |
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 net realizable value using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are included in 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 net realizable value 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. 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. 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 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. 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 or asset group with its 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 an impairment 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 impairments. 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 attributed 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, 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. We are permitted to first assess qualitative factors for a reporting unit to determine if the quantitative goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or otherwise determine that a goodwill impairment test is required, our annual goodwill impairment test is performed by comparing the fair value of a reporting unit with its carrying amount (including attributed goodwill). Prior to our adoption of Accounting Standards Update (“ASU”) 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment |
Intangible Assets | Intangible Assets Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with business and asset 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 in a manner that closely resembles the expected benefit pattern of the intangible assets, or where such pattern is not readily determinable, on a straight-line basis, over the periods 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 (“ARO”) associated with tangible long-lived assets. Retirement obligations associated with long-lived assets are only 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, as are any original issue discount or premium. Debt issuance costs related to revolving credit facilities are presented as other long-term assets and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction from the carrying amount of long-term debt on 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 in 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 operating 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 using 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. If 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 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. 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 21 – Income Tax 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). |
Dividends | Dividends Preferred and Common dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital. |
Mandatorily Redeemable Preferred Interests | Mandatorily Redeemable Preferred Interests Mandatorily redeemable preferred interests are included in other long-term liabilities 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 be redeemed in the future. Changes in the redemption value are included in interest expense, net in our Consolidated Statements of Operations. |
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. |
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 our Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income, noncontrolling interests reflects the attribution of results to third-party investors. |
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 • services related We have multiple types of contracts with commercial counterparties and many of these may result in cash inflows to Targa due to the structure of settlement provisions with embedded fees. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606. Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases. Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues. We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis. Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price. Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract. The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation. Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue. We have certain long-term contractual arrangements under which we have received consideration, but for which all conditions for revenue recognition have not been met. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided. Significant Judgments Certain provisions of our service contracts (i.e., tiered price structures) require further assessment to determine if the allocation exception for variable consideration is met. If the allocation exception is not met, we estimate the total consideration that we expect to be entitled to for the applicable term of the contract, based on projections of future activity. In such instance, revenue is recognized using an output method of progress based on the volume of commodities serviced during the reporting period. Our estimate of total consideration is reassessed each reporting period until contract completion. For contracts with minimum volume commitments, we generally expect the customer to meet the commitment. However, such contracts are reassessed throughout the term of the commitment, and if we no longer expect the customer to meet the commitment, the allocation exception for variable consideration would not be met. That is, from that point onwards, an allocation based on the applicable fee applied to the volumes serviced does not depict the amount of consideration which we expect to be entitled to, in exchange for the service. In such instance, revenue will be recognized up to the minimum volume commitment in proportion to the days of service elapsed and the remaining duration of the commitment. Contract Assets We classify our contract assets as receivables because we generally have an unconditional right to payment for the commodities sold or services performed at the end of reporting period. |
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 Recently issued accounting pronouncements not yet adopted Leases In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases (Topic 842) In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU 2018-10, Codification Improvements to Topic 842, Leases In July 2018, the FASB also issued ASU 2018-11, Leases (Topic 842): Targeted Improvements We expect to adopt Topic 842 on January 1, 2019 and intend to elect the land easement practical expedient as well as the optional transition method. We also expect to adopt the package of practical expedients permitting us to not reassess under the new standard our prior conclusions regarding lease identification, lease classification and initial direct costs, the practical expedient to not separate lease and non-lease components for all of our existing lessee and lessor arrangements, and to elect an accounting policy to not apply the recognition requirements of Topic 842 to our short-term leases. We do not expect to elect the practical expedient for use of hindsight in determining the lease term and assessing impairment of our right-of-use assets. We established a cross-functional team to implement the new standard and are currently in the process of implementing a leases software solution, evaluating the impact of the new standard on our consolidated financial statements and implementing appropriate changes to our internal processes and controls to support the accounting and disclosure requirements of the new standard. Based on our evaluation to-date and from the perspective as the lessee, our leasing activity primarily consists of office space, vehicles, railcars, and tractors. We expect to recognize upon adoption of ASC 842 at January 1, 2019 an estimated right-of-use asset and a lease liability on our consolidated balance sheet. These amounts would represent less than 2% of our total consolidated asset and liabilities, respectively. At this time, we do not expect a material cumulative effect adjustment to retained earnings on January 1, 2019. 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. Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract In August 2018, the FASB issued ASU 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract Recently adopted accounting pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) • Embedded fees within commodity supply contracts where the counterparty is not deemed to be a customer are now reported as a reduction of “Product purchases.” Historically, such fees were reported as “Fees from midstream services.” • Noncash consideration in the form of commodities received in-kind from a customer is now recognized as service revenue within “Fees from midstream services” when the service is performed. Historically, the noncash consideration was only recognized as revenue upon sale to a third party without corresponding “Product purchases.” • For certain contracts structured as a purchase where we do not control the commodities, but rather are acting as an agent for the supplier, revenue is now recognized for the net amount of consideration we expect to retain in exchange for our service. Historically, the purchase from the supplier and subsequent sale were reported gross. The following tables summarize the effects of adoption on our consolidated financial statements: Year Ended December 31, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 9,611.9 $ (333.2 ) $ 9,278.7 Fees from midstream services 1,244.9 (39.6 ) 1,205.3 Total revenues 10,856.8 (372.8 ) 10,484.0 Costs and expenses: Product purchases 8,611.0 (372.8 ) 8,238.2 Income from operations 253.6 — 253.6 Income (loss) before income taxes 98.5 — 98.5 Net income (loss) $ 98.6 $ — $ 98.6 See Note 19 – Revenue for information regarding our performance obligations and Note 24 – Segment Information for further disaggregation of our revenues. 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) Business Combinations In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business Other Income In February Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) Revenue from Contracts with Customers (Topic 606), Targeted Improvements to Accounting for Hedge Activities In August 2017, FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities |
Significant Accounting Polici_3
Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Summary of Effect of Adoption on Consolidated Financial Statements | The following tables summarize the effects of adoption on our consolidated financial statements: Year Ended December 31, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 9,611.9 $ (333.2 ) $ 9,278.7 Fees from midstream services 1,244.9 (39.6 ) 1,205.3 Total revenues 10,856.8 (372.8 ) 10,484.0 Costs and expenses: Product purchases 8,611.0 (372.8 ) 8,238.2 Income from operations 253.6 — 253.6 Income (loss) before income taxes 98.5 — 98.5 Net income (loss) $ 98.6 $ — $ 98.6 |
Newly-Formed Joint Ventures, _2
Newly-Formed Joint Ventures, Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Business Acquisition [Line Items] | |
Pro Forma Consolidated Information of Operations | The following summarized unaudited pro forma Consolidated Statements of Operations information for the years ended December 31, 2017 and December 31, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1, 2016, or that would be attained in the future. December 31, 2017 December 31, 2016 Pro Forma Pro Forma Revenues $ 8,829.0 $ 6,725.6 Net income (loss) (252.2 ) (284.5 ) |
Permian Acquisition [Member] | |
Business Acquisition [Line Items] | |
Consideration Transferred to Acquire Acquirees | The following table summarizes the consideration transferred to acquire New Delaware and New Midland: Fair Value of Consideration Transferred: Cash paid, net of $3.3 million cash acquired $ 570.8 Contingent consideration valuation as of the acquisition date 416.3 Total $ 987.1 |
Fair Value of the Assets and Liabilities Assumed at Acquisition Date | The fair value of the assets acquired and liabilities assumed at the acquisition date is shown below: Fair value determination (final): March 1, 2017 Trade and other current receivables, net $ 6.7 Other current assets 0.6 Property, plant and equipment 255.8 Intangible assets 692.3 Current liabilities (14.1 ) Other long-term liabilities (0.8 ) Total identifiable net assets 940.5 Goodwill 46.6 Total fair value of assets acquired and liabilities assumed $ 987.1 |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Inventory Disclosure [Abstract] | |
Components of Inventories | December 31, 2018 December 31, 2017 Commodities $ 151.1 $ 191.6 Materials and supplies 13.6 12.9 $ 164.7 $ 204.5 |
Property, Plant and Equipment_2
Property, Plant and Equipment and Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property Plant And Equipment And Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | December 31, 2018 December 31, 2017 Estimated Useful Lives (In Years) Gathering systems $ 7,547.9 $ 7,037.2 5 to 20 Processing and fractionation facilities 4,001.0 3,563.0 5 to 25 Terminaling and storage facilities 1,138.7 1,244.1 5 to 25 Transportation assets 445.1 343.6 10 to 25 Other property, plant and equipment 334.3 303.5 3 to 25 Land 144.3 125.7 — Construction in progress 3,602.5 1,581.5 — Property, plant and equipment 17,213.8 14,198.6 Accumulated depreciation (4,285.5 ) (3,768.7 ) Property, plant and equipment, net $ 12,928.3 $ 10,429.9 Intangible assets $ 2,736.6 $ 2,736.6 10 to 20 Accumulated amortization (753.4 ) (570.8 ) Intangible assets, net $ 1,983.2 $ 2,165.8 |
Schedule of Changes in Intangible Assets | The changes in our intangible assets are as follows: December 31, 2018 December 31, 2017 Beginning of period $ 2,165.8 $ 1,654.0 Additions from Permian Acquisition — 692.3 Additions from Flag City Acquisition — 7.7 Amortization (182.6 ) (188.2 ) End of period $ 1,983.2 $ 2,165.8 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Goodwill And Intangible Assets Disclosure [Abstract] | |
Changes in Net Amounts of Goodwill | Changes in the net amounts of our goodwill are as follows: WestTX SouthTX New Midland New Delaware Total Balance at December 31, 2015, net $ 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, net 174.7 35.3 — — 210.0 Permian Acquisition, March 1, 2017 — — 23.2 23.4 46.6 Balance at December 31, 2017, net 174.7 35.3 23.2 23.4 256.6 Impairment for 2018 annual assessment (174.7 ) (35.3 ) — — (210.0 ) Balance at December 31, 2018, net $ — $ — $ 23.2 $ 23.4 $ 46.6 |
Investments in Unconsolidated_2
Investments in Unconsolidated Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Equity Method Investments And Joint Ventures [Abstract] | |
Activity Related to Investment in Unconsolidated Affiliate | The following table shows the activity related to our investments in unconsolidated affiliates: Balance at December 31, 2015 Equity Earnings (Loss) Cash Distributions (1) Acquisition (Disposition) Contributions Balance at December 31, 2016 GCF $ 49.5 $ 4.1 $ (7.5 ) $ — $ — $ 46.1 T2 LaSalle 63.6 (5.2 ) — — 0.2 58.6 T2 Eagle Ford 123.8 (9.4 ) — — 4.2 118.6 T2 EF Cogen 22.0 (3.8 ) (0.7 ) — — 17.5 Cayenne — — — — — — GCX — — — — — — Little Missouri 4 — — — — — — Agua Blanca — — — — — — Total $ 258.9 $ (14.3 ) $ (8.2 ) $ — $ 4.4 $ 240.8 Balance at December 31, 2016 Equity Earnings (Loss) Cash Distributions (1) Acquisition (Disposition) Contributions Balance at December 31, 2017 GCF $ 46.1 $ 12.4 $ (12.7 ) $ — $ — $ 45.8 T2 LaSalle 58.6 (4.9 ) — — 0.4 54.1 T2 Eagle Ford 118.6 (10.6 ) — — 1.2 109.2 T2 EF Cogen 17.5 (13.9 ) — — 0.3 3.9 Cayenne — — — 5.0 3.6 8.6 GCX — — — — — — Little Missouri 4 — — — — — — Agua Blanca — — — — — — Total $ 240.8 $ (17.0 ) $ (12.7 ) $ 5.0 $ 5.5 $ 221.6 Balance at December 31, 2017 Equity Earnings (Loss) Cash Distributions (1)(2) Acquisition (Disposition) Contributions (3) Balance at December 31, 2018 GCF $ 45.8 $ 16.8 $ (22.3 ) $ — $ — $ 40.3 T2 LaSalle 54.1 (4.9 ) — — 0.1 49.3 T2 Eagle Ford 109.2 (10.2 ) — — — 99.0 T2 EF Cogen 3.9 (1.8 ) — (2.1 ) — — Cayenne 8.6 6.4 (4.0 ) — 5.6 16.6 GCX (4) — 0.8 — — 210.8 211.6 Little Missouri 4 — — (8.0 ) — 75.3 67.3 Agua Blanca — 0.2 — 3.5 2.7 6.4 Total $ 221.6 $ 7.3 $ (34.3 ) $ 1.4 $ 294.5 $ 490.5 (1) Includes $5.5 million, $0.2 million and $4.1 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, 2018, 2017 and 2016. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in our Consolidated Statements of Cash Flows in the period in which they occur. (2) Includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures. (3) Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4. See Note 22 – Supplemental Cash Flow Information. (4) As discussed in Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures, our 25% interest in GCX is owned by GCX DevCo JV, of which we own a 20% interest. GCX DevCo JV is accounted for on a consolidated basis in our consolidated financial statements. The following tables summarize the combined financial information of our investments in unconsolidated affiliates (all data presented on a 100% basis): December 31, 2018 December 31, 2017 (In millions) Current assets $ 200.7 $ 29.1 Non-current assets $ 1,329.7 $ 379.8 Current liabilities $ 233.9 $ 11.0 Non-current liabilities $ 179.2 $ — Net assets $ 1,117.3 $ 397.9 Year Ended December 31, 2018 2017 2016 (In millions) Operating revenues $ 130.6 $ 84.3 $ 70.3 Operating expenses $ 96.9 $ 80.5 $ 91.4 Net income (loss) $ 34.7 $ 3.4 $ (21.5 ) |
Accounts Payable and Accrued _2
Accounts Payable and Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Payables And Accruals [Abstract] | |
Schedule of Accounts Payable and Accrued Liabilities | December 31, 2018 December 31, 2017 Commodities $ 721.9 $ 711.9 Other goods and services 474.5 286.9 Interest 79.4 54.1 Permian Acquisition contingent consideration, estimated current portion 308.2 6.8 Income and other taxes 45.4 26.3 Other 7.5 20.6 $ 1,636.9 $ 1,106.6 |
Debt Obligations (Tables)
Debt Obligations (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Outstanding Debt | December 31, 2018 December 31, 2017 Current: Accounts receivable securitization facility, due December 2019 (1) $ 280.0 $ 350.0 Senior unsecured notes, 4⅛% fixed rate, due November 2019 (2) 749.4 — 1,029.4 350.0 Debt issuance costs, net of amortization (1.5 ) — Current debt obligations 1,027.9 350.0 Long-term: Senior secured revolving credit facility, variable rate, due June 2023 (3) 700.0 20.0 Senior unsecured notes: 4⅛% fixed rate, due November 2019 — 749.4 5¼% fixed rate, due May 2023 559.6 559.6 4¼% fixed rate, due November 2023 583.9 583.9 6¾% fixed rate, due March 2024 580.1 580.1 5⅛% fixed rate, due February 2025 500.0 500.0 5⅞% fixed rate, due April 2026 1,000.0 — 5⅜% fixed rate, due February 2027 500.0 500.0 5% fixed rate, due January 2028 750.0 750.0 TPL notes, 4¾% fixed rate, due November 2021 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 48.1 48.1 Unamortized premium 0.3 0.4 5,228.5 4,298.0 Debt issuance costs, net of amortization (31.1 ) (30.0 ) Long-term debt 5,197.4 4,268.0 Total debt obligations $ 6,225.3 $ 4,618.0 Irrevocable standby letters of credit outstanding $ 79.5 $ 27.2 ________________ (1) As of December 31, 2018, we had $340.0 million of qualifying receivables under our $400.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. (2) The 4⅛ (3) As of December 31, 2018, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $1,420.5 million. |
Schedule of Contractual Maturities of Outstanding Debt Obligations | The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2018, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2019 2020 2021 2022 2023 After 2023 (in millions) TRP Revolver $ 700.0 $ — $ — $ — $ — $ 700.0 $ — Senior unsecured notes (1) 5,277.6 749.4 — 6.5 — 1,191.6 3,330.1 Accounts receivable securitization facility 280.0 280.0 — — — — — Total $ 6,257.6 $ 1,029.4 $ — $ 6.5 $ — $ 1,891.6 $ 3,330.1 ________________________________________________________________________________________ (1) The 4⅛% |
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, 2018: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 3.4% - 5.8% 3.8% Accounts receivable securitization facility 2.6% - 3.4% 3.0% |
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 5 ⅛% Senior Notes February 1, 2020 105.125% 5 ⅜% Senior Notes February 1, 2020 105.375% 5% Senior Notes January 15, 2021 105.000% 5 ⅞% Senior Notes April 15, 2021 105.875% 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 5 ¼% Senior Notes November 1 2018 101.750 % 2019 100.875 % 2020 and thereafter 100 % 4 ¼% Senior Notes May 15 2018 102.125 % 2019 101.417 % 2020 100.708 % 2021 and thereafter 100 % 6 ¾% Senior Notes September 15 2019 103.375 % 2020 101.688 % 2021 and thereafter 100 % 5 ⅛% Senior Notes February 1 2020 103.844 % 2021 102.563 % 2022 101.281 % 2023 and thereafter 100 % 5 ⅞% Senior Notes April 15 2021 104.406 % 2022 102.938 % 2023 101.469 % 2024 and thereafter 100 % 5 ⅜% Senior Notes February 1 2022 102.688 % 2023 101.792 % 2024 100.896 % 2025 and thereafter 100 % 5% Senior Notes January 15 2023 102.500 % 2024 101.667 % 2025 100.833 % 2026 and thereafter 100 % TPL 4 ¾% Notes May 15 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 | During the year ended December 31, 2016 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 following table summarizes the debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2018 2017 2016 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 6⅜% Senior Notes — 8.9 — 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 ) 4¼% Senior Notes — — (7.7 ) 6¾% Senior Notes — — (2.4 ) Write-off of debt issuance costs: TRP Revolver 1.3 — 0.9 5% Senior Notes — 0.2 4.2 4⅛% Senior Notes — — 0.4 6⅞% Senior Notes — — 4.9 6⅜% Senior Notes — 1.8 0.2 5¼% Senior Notes — — 0.2 4¼% Senior Notes — — 0.3 6¾% Senior Notes — — 0.2 Loss (gain) from financing activities $ 1.3 $ 10.9 $ 48.2 |
Other Long-term Liabilities (Ta
Other Long-term Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Liabilities Noncurrent [Abstract] | |
Other Long-term Liabilities | Other long-term liabilities are comprised of the following obligations: December 31, 2018 December 31, 2017 Asset retirement obligations $ 55.0 $ 50.3 Mandatorily redeemable preferred interests — 76.2 Deferred revenue 175.5 136.2 Permian Acquisition contingent consideration, noncurrent portion — 310.2 Other liabilities 3.3 3.1 Total long-term liabilities $ 233.8 $ 576.0 |
Changes in Aggregate Asset Retirement Obligations | The changes in our ARO are as follows 2018 2017 Beginning of period $ 50.3 $ 64.1 Additions — 0.8 Reduction due to sale of VGS — (21.6 ) Change in cash flow estimate 1.8 3.1 Accretion expense 3.7 3.9 Retirement of ARO (0.8 ) — End of period $ 55.0 $ 50.3 |
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: 2018 2017 Beginning of period $ 76.2 $ 68.5 Income attributable to mandatorily redeemable preferred interests (4.1 ) 4.4 Change in estimated redemption value included in interest expense, net (72.1 ) 3.3 End of period $ — $ 76.2 |
Components of Deferred Revenue | The following table shows the components of deferred revenue: December 31, 2018 December 31, 2017 Splitter agreement $ 129.0 $ 86.0 Gas contract amendment 42.2 44.7 Other deferred revenue 4.3 5.5 Total deferred revenue $ 175.5 $ 136.2 |
Changes in Deferred Revenue | The following table shows the changes in deferred revenue: 2018 2017 Beginning of period $ 136.2 $ 69.8 Additions 43.2 69.5 Revenue recognized (3.9 ) (3.1 ) End of period $ 175.5 $ 136.2 |
Schedule of Changes in the Fair Value of Permian Acquisition Contingent Consideration | The following table shows the changes in the fair value of the contingent consideration related to the Permian Acquisition discussed in Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures: Year Ended December 31, 2018 March 1, 2017 to December 31, 2017 Beginning of period $ 317.0 $ 416.3 Decrease in fair value, included in Other income (expense) (8.8 ) (99.3 ) End of period 308.2 317.0 Less: Current portion (308.2 ) (6.8 ) Long-term balance at end of period — 310.2 |
Partnership Units and Related_2
Partnership Units and Related Matters (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Partners Capital [Abstract] | |
Schedule of Distributions | The following details the distributions declared or paid by the Partnership during 2018, 2017 and 2016: Three Months Ended Date Paid Or to Be Paid Total Distributions Distributions to Targa Resources Corp. 2018 December 31, 2018 February 13, 2019 $ 241.3 $ 238.5 September 30, 2018 November 13, 2018 237.6 234.8 June 30, 2018 August 13, 2018 234.0 231.2 March 31, 2018 May 11, 2018 229.7 226.9 2017 December 31, 2017 February 12, 2018 $ 228.5 $ 225.7 September 30, 2017 November 10, 2017 225.4 222.6 June 30, 2017 August 10, 2017 225.4 222.6 March 31, 2017 May 11, 2017 209.6 206.8 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 |
Derivative Instruments and He_2
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Notional Volume of Commodity Hedges | At December 31, 2018, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2019 2020 2021 2022 2023 Natural Gas Swaps MMBtu/d 171,102 63,630 35,755 - - Natural Gas Basis Swaps MMBtu/d 113,295 105,417 91,658 75,000 20,000 NGL Swaps Bbl/d 17,929 13,267 3,676 - - NGL Futures Bbl/d 8,975 3,115 - - - NGL Options Bbl/d 410 - - - - Condensate Swaps Bbl/d 3,413 1,980 994 - - Condensate Options Bbl/d 590 - - - - |
Fair Values of Derivative Instruments | The following schedules reflect the fair values of our derivative instruments and their location on 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, 2018 Fair Value as of December 31, 2017 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 112.5 $ 18.9 $ 37.9 $ 78.6 Long-term 31.6 1.5 23.2 18.7 Total derivatives designated as hedging instruments $ 144.1 $ 20.4 $ 61.1 $ 97.3 Derivatives not designated as hedging instruments Commodity contracts Current $ 2.8 $ 14.7 $ — $ 1.1 Long-term 2.5 1.6 — 0.9 Total derivatives not designated as hedging instruments $ 5.3 $ 16.3 $ — $ 2.0 Total current position $ 115.3 $ 33.6 $ 37.9 $ 79.7 Total long-term position 34.1 3.1 23.2 19.6 Total derivatives $ 149.4 $ 36.7 $ 61.1 $ 99.3 |
Pro Forma Impact of Derivatives Net in Consolidated Balance Sheet | The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro Forma Net Presentation December 31, 2018 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 100.0 $ (33.6 ) $ (14.2 ) $ 70.0 $ (17.8 ) Counterparties without offsetting positions - assets 15.3 - - 15.3 - Counterparties without offsetting positions - liabilities - - - - - 115.3 (33.6 ) (14.2 ) 85.3 (17.8 ) Long Term Position Counterparties with offsetting positions or collateral 8.9 (3.1 ) - 5.9 (0.1 ) Counterparties without offsetting positions - assets 25.2 - - 25.2 - Counterparties without offsetting positions - liabilities - - - - - 34.1 (3.1 ) - 31.1 (0.1 ) Total Derivatives Counterparties with offsetting positions or collateral 108.9 (36.7 ) (14.2 ) 75.9 (17.9 ) Counterparties without offsetting positions - assets 40.5 - - 40.5 - Counterparties without offsetting positions - liabilities - - - - - $ 149.4 $ (36.7 ) $ (14.2 ) $ 116.4 $ (17.9 ) Gross Presentation Pro Forma Net Presentation December 31, 2017 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 37.9 $ (74.7 ) $ 22.9 $ 13.8 $ (27.7 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (5.0 ) - - (5.0 ) 37.9 (79.7 ) 22.9 13.8 (32.7 ) Long Term Position Counterparties with offsetting positions or collateral 23.2 (17.3 ) - 14.8 (8.9 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (2.3 ) - - (2.3 ) 23.2 (19.6 ) - 14.8 (11.2 ) Total Derivatives Counterparties with offsetting positions or collateral 61.1 (92.0 ) 22.9 28.6 (36.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.3 ) - - (7.3 ) $ 61.1 $ (99.3 ) $ 22.9 $ 28.6 $ (43.9 ) |
Amounts Recorded in Other Comprehensive Income and Amounts Reclassified from OCI to Revenue and Expense | The following tables reflect amounts recorded in Other Comprehensive Income 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 2018 2017 2016 Commodity contracts $ 132.5 $ (28.8 ) $ (103.6 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2018 2017 2016 Revenues (38.4 ) (44.6 ) 45.0 |
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 2018 2017 2016 Commodity contracts Revenue $ (32.5 ) $ (5.1 ) $ 0.9 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Breakdown by Fair Value Hierarchy Category for Financial Instruments Included on Consolidated Balance Sheets | The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: December 31, 2018 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) $ 144.4 $ 144.4 $ — $ 137.5 $ 6.9 Liabilities from commodity derivative contracts (1) 31.7 31.7 — 31.3 0.4 Permian Acquisition contingent consideration (2) 308.2 308.2 — — 308.2 TPL contingent consideration (3) 2.4 2.4 — — 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 203.3 203.3 — — — TRP Revolver 700.0 700.0 — 700.0 — Senior unsecured notes 5,277.9 5,088.9 — 5,088.9 — Accounts receivable securitization facility 280.0 280.0 — 280.0 — December 31, 2017 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) $ 60.3 $ 60.3 $ — $ 58.8 $ 1.5 Liabilities from commodity derivative contracts (1) 98.5 98.5 — 93.3 5.2 Permian Acquisition contingent consideration (2) 317.0 317.0 — — 317.0 TPL contingent consideration (3) 2.4 2.4 — — 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 124.7 124.7 — — — TRP Revolver 20.0 20.0 — 20.0 — Senior unsecured notes 4,278.0 4,362.4 — 4,362.4 — Accounts receivable securitization facility 350.0 350.0 — 350.0 — ________________ (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) We have a contingent consideration liability related to the Permian Acquisition, which is carried at fair value. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures. (3) 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. |
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, 2017 $ (3.8 ) $ (319.4 ) Change in fair value of Permian Acquisition contingent consideration (1) - 8.8 New Level 3 derivative instruments (1.4 ) - Settlements included in Revenue 2.8 - Unrealized gain/(loss) included in OCI 8.9 - Balance, December 31, 2018 $ 6.5 $ (310.6 ) ________________ (1) Represents the change in fair value between December 31, 2017 and December 31, 2018 of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the initial fair value. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 2017 2016 Targa billings of payroll and related costs included in operating expenses $ 236.8 $ 204.4 $ 171.8 Targa allocation of general and administrative expense 221.4 175.2 159.9 Cash distributions to Targa based on general partner and limited partner ownership (1) 918.5 847.3 587.0 Cash contributions from Targa related to limited partner ownership (2) 588.1 1,685.5 1,353.4 Cash contributions from Targa to maintain its 2% general partner ownership 12.0 34.5 27.6 ________________ (1) Prior to the execution of the Third A&R Partnership Agreement, 2016 cash distributions to Targa also included IDRs. (2) The 2016 cash contributions from Targa related to limited partner ownership was contributed for the issuance of common units. The 2018 and 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to the general partner. See Note 12 – Partnership Units and Related Matters. |
Unconsolidated Affiliates [Member] | |
Summary of Transactions with Affiliates | The following table summarizes transactions with unconsolidated affiliates: GCF T2 Joint Ventures Cayenne GCX Total 2018: Revenues $ 0.3 $ 5.2 $ — $ 0.1 $ 5.6 Product purchases (5.1 ) (0.6 ) (7.2 ) (1.2 ) $ (14.1 ) Operating expenses — (3.6 ) — — $ (3.6 ) 2017: Revenues $ 0.3 $ 2.1 $ — $ — $ 2.4 Product purchases (4.4 ) (1.1 ) — — (5.5 ) Operating expenses — (3.8 ) — — (3.8 ) 2016: Revenues $ 0.4 $ 5.2 $ — $ — $ 5.6 Product purchases (3.2 ) (2.6 ) — — (5.8 ) Operating expenses — (4.0 ) — — (4.0 ) |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Leases [Abstract] | |
Future Non-Cancelable Commitments Related to Certain Contractual Obligations for Next Five Fiscal Years and in Aggregate Thereafter | Future non-cancelable commitments related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregate thereafter: In Aggregate 2019 2020 2021 2022 2023 Thereafter Operating leases (1) $ 73.4 $ 20.5 $ 17.7 $ 14.9 $ 12.6 $ 6.0 $ 1.7 Land site lease and rights of way (2) 122.3 4.0 3.6 3.7 4.2 4.0 102.8 $ 195.7 $ 24.5 $ 21.3 $ 18.6 $ 16.8 $ 10.0 $ 104.5 ________________ (1) Includes minimum payments on lease obligations for office space, railcars and tractors. |
Total Expenses on Non-Cancelable Commitments | Total expenses incurred under the above non-cancelable commitments were: 2018 2017 2016 Operating leases (1) $ 51.9 $ 46.2 $ 45.1 Land site lease and rights of way 6.1 5.2 4.4 $ 58.0 $ 51.4 $ 49.5 ________________ (1) Includes short-term leases for items such as compressors and equipment. |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Revenue From Contract With Customer [Abstract] | |
Summary of Estimated Minimum Revenue Expected to be Recognized in Future Related to Unsatisfied Performance Obligations | The following table includes the estimated minimum revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments and for which a guaranteed amount of revenue can be calculated . These contracts are comprised primarily of gathering and processing, fractionation, export, terminaling and storage agreements. 2019 2020 2021 and after Fixed consideration to be recognized as of December 31, 2018 $ 496.5 $ 450.8 $ 2,126.9 |
Other Operating (Income) Expe_2
Other Operating (Income) Expense (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Income And Expenses [Abstract] | |
Other Operating (Income) Expense | Other Operating (Income) Expense is comprised of the following: Year Ended December 31, 2018 2017 2016 (Gain) loss on sale or disposal of assets $ (0.1 ) $ 15.9 $ 6.1 Miscellaneous business tax 3.2 0.8 0.5 Other 0.4 0.7 — $ 3.5 $ 17.4 $ 6.6 |
Summary of (Gain) Loss on Sale or Disposal of Assets | The (Gain) loss on sale or disposal of assets is comprised of the following: Year Ended December 31, 2018 2017 2016 Sale of inland marine barge business $ (48.1 ) $ — $ — Exchange of a portion of Versado gathering system (44.4 ) — — Sale of storage and terminaling facilities 59.1 — — Disposal of benzene treating unit 20.5 — — Sale of Venice gathering system — 16.1 — Other 12.8 (0.2 ) 6.1 $ (0.1 ) $ 15.9 $ 6.1 |
Income Tax (Tables)
Income Tax (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Summary of Income Tax Expense (Benefit) | Our income tax expense (benefit) is summarized below: 2018 2017 2016 Current expense (benefit) $ — $ (4.5 ) $ — Deferred expense (benefit) (0.1 ) (2.9 ) (0.3 ) Total income tax expense (benefit) $ (0.1 ) $ (7.4 ) $ (0.3 ) |
Deferred Tax Assets and Liabilities | Our deferred income tax assets and liabilities at December 31, 2018 and 2017, consisted of differences related to the timing of recognition of certain types of costs as follows: 2018 2017 Deferred tax assets: Net operating loss carryforwards $ 12.9 $ 13.7 Deferred tax liabilities: Property, plant, and equipment (36.8 ) (37.7 ) Net deferred tax asset (liability) $ (23.9 ) $ (24.0 ) |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Year Ended December 31, 2018 2017 2016 Cash: Interest paid, net of capitalized interest (1) $ 203.2 $ 198.7 $ 263.8 Income taxes paid, net of refunds 0.2 (4.9 ) 1.3 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 49.0 $ 9.0 $ 17.4 Impact of capital expenditure accruals on property, plant and equipment 216.9 205.4 27.6 Transfers from materials and supplies inventory to property, plant and equipment 12.7 3.6 2.4 Contribution of property, plant and equipment to investments in unconsolidated affiliates 16.0 1.0 Change in ARO liability and property, plant and equipment due to revised cash flow estimate 1.8 3.1 (9.1 ) Property, plant and equipment received in asset exchange 24.1 — — Receivable for asset exchange 15.0 — — Asset received related to conveyance of ownership interest in investment in unconsolidated affiliate 3.0 — — Non-cash financing activities: Cancellation of treasury units — — 10.4 Accrued distributions on unvested equity awards under share compensation arrangements — — 0.2 Exchange of IDRs and Special GP interest for units — — 903.6 Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): Contingent consideration recorded at the acquisition date $ — $ 416.3 $ — Non-cash balance sheet movements related to the purchase of noncontrolling interests in subsidiary (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): Common limited partner units $ — $ — $ 63.7 General partner units — — 1.3 Noncontrolling interests — — (65.0 ) Non-cash balance sheet movements related to acquisition of related party: Noncontrolling interest $ 1.1 $ — $ — ________________ (1) Interest capitalized on major projects was $46.3 million, $14.3 million and $8.3 million for the years ended December 31, 2018, 2017 and 2016. |
Compensation Plans (Tables)
Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of PSUs | The following table summarizes the PSUs under the 2010 TRC Plan in shares and in dollars for the years indicated. Number Weighted Average of shares Grant-Date Fair Value Outstanding at December 31, 2017 113,901 $ 99.71 Granted 182,849 81.02 Outstanding at December 31, 2018 296,750 88.19 |
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 December 31, 2018, under the Plan: Number Weighted-average of shares Grant-Date Fair Value Outstanding as of December 31, 2017 497,947 $ 40.54 Forfeited (4,956 ) 32.86 Vested (191,300 ) 61.94 Outstanding as of December 31, 2018 301,691 27.10 |
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, 2017 2,428,798 $ 43.78 Granted 1,410,767 51.70 Forfeited (52,449 ) 47.26 Vested (192,981 ) 72.28 Outstanding at December 31, 2018 3,594,135 45.31 |
Cash Settled Restricted Stock Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of Cash-settled Restricted Stock Units | The following table summarizes the cash-settled restricted stock units for the year ended 2018. 2018 Awards Outstanding as of December 31, 2017 — Granted 69,042 Vested and paid (16,872 ) Forfeited (1,942 ) Outstanding as of December 31, 2018 50,228 Calculated fair market value as of December 31, 2018 $ 2,546,445 Current liability $ 1,332,308 Long-term liability — Liability as of December 31, 2018 $ 1,332,308 To be recognized in future periods $ 1,214,137 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Information by Segment | Reportable segment information is shown in the following tables: Year Ended December 31, 2018 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 1,257.4 $ 8,058.4 $ (37.1 ) $ — $ 9,278.7 Fees from midstream services 715.6 489.7 — — 1,205.3 1,973.0 8,548.1 (37.1 ) — 10,484.0 Intersegment revenues Sales of commodities 3,636.0 317.1 — (3,953.1 ) — Fees from midstream services 7.2 30.8 — (38.0 ) — 3,643.2 347.9 — (3,991.1 ) — Revenues $ 5,616.2 $ 8,896.0 $ (37.1 ) $ (3,991.1 ) $ 10,484.0 Operating margin $ 968.4 $ 592.5 $ (37.1 ) $ — $ 1,523.8 Other financial information: Total assets (1) $ 11,478.8 $ 5,180.6 $ 127.1 $ 103.6 $ 16,890.1 Goodwill $ 46.6 $ — $ — $ — $ 46.6 Capital expenditures $ 1,548.6 $ 1,767.0 $ — $ 12.1 $ 3,327.7 (1) Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Year Ended December 31, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 781.4 $ 6,979.3 $ (9.6 ) $ — $ 7,751.1 Fees from midstream services 566.3 497.5 — — 1,063.8 1,347.7 7,476.8 (9.6 ) — 8,814.9 Intersegment revenues Sales of commodities 3,154.2 321.9 — (3,476.1 ) — Fees from midstream services 6.9 28.0 — (34.9 ) — 3,161.1 349.9 — (3,511.0 ) — Revenues $ 4,508.8 $ 7,826.7 $ (9.6 ) $ (3,511.0 ) $ 8,814.9 Operating margin $ 783.8 $ 511.8 $ (9.6 ) $ — $ 1,286.0 Other financial information: Total assets (1) $ 10,732.3 $ 3,507.4 $ 56.8 $ 62.5 $ 14,359.0 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 1,008.9 $ 470.4 $ — $ 27.2 $ 1,506.5 Business acquisition $ 987.1 $ — $ — $ — $ 987.1 (1) Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. 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) Assets in the Corporate and Eliminations column 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: 2018 2017 2016 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $ 1,810.0 $ 2,005.9 $ 1,591.2 NGL 6,886.9 5,454.2 3,793.4 Condensate 457.9 196.0 133.9 Petroleum products 196.1 144.7 68.2 9,350.9 7,800.8 5,586.7 Non-customer revenue: Derivative activities - Hedge (39.7 ) (44.7 ) 39.1 Derivative activities - Non-hedge (1) (32.5 ) (5.0 ) 1.0 (72.2 ) (49.7 ) 40.1 Total sales of commodities 9,278.7 7,751.1 5,626.8 Fees from midstream services: Revenue recognized from contracts with customers: Fractionating and treating 120.7 132.8 126.2 Storage, terminaling, transportation and export 349.9 342.2 420.0 Gathering and processing 698.1 523.3 445.0 Other 36.6 65.5 72.9 Total fees from midstream services 1,205.3 1,063.8 1,064.1 Total revenues $ 10,484.0 $ 8,814.9 $ 6,690.9 (1) Represents derivative activities that are not designated as hedging instruments under ASC 815. |
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: 2018 2017 2016 Reconciliation of reportable segment operating margin to income (loss) before income taxes: Gathering and Processing operating margin $ 968.4 $ 783.8 $ 577.1 Logistics and Marketing operating margin 592.5 511.8 574.4 Other operating margin (37.1 ) (9.6 ) 62.9 Depreciation and amortization expenses (815.9 ) (809.5 ) (757.7 ) General and administrative expenses (240.8 ) (190.5 ) (177.1 ) Impairment of property, plant and equipment — (378.0 ) — Impairment of goodwill (210.0 ) — (207.0 ) Interest expense, net (170.0 ) (217.8 ) (233.5 ) Change in contingent considerations 8.8 99.6 0.4 Other, net 2.6 (47.8 ) (68.5 ) Income (loss) before income taxes $ 98.5 $ (258.0 ) $ (229.0 ) |
Selected Quarterly Financial _2
Selected Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Selected Quarterly Financial Information [Abstract] | |
Results of Operations by Quarter | Our results of operations by quarter for the years ended December 31, 2018 and 2017 were as follows: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018 Revenues $ 2,455.6 $ 2,444.4 $ 2,986.4 $ 2,597.6 $ 10,484.0 Gross margin 514.6 539.1 602.9 589.2 2,245.8 Income (loss) from operations (1) 90.4 159.2 80.6 (76.6 ) 253.6 Net income (loss) 56.0 162.6 (8.7 ) (111.3 ) 98.6 Net income (loss) attributable to common limited partners 39.2 147.6 (20.8 ) (127.1 ) 38.9 2017 Revenues $ 2,112.6 $ 1,867.7 $ 2,131.8 $ 2,702.8 $ 8,814.9 Gross margin 458.4 447.1 468.7 534.6 1,908.8 Income (loss) from operations (2) 53.7 40.7 (320.3 ) 116.5 (109.4 ) Net income (loss) (21.3 ) (29.2 ) (245.0 ) 44.9 (250.6 ) Net income (loss) attributable to common limited partners (29.5 ) (41.4 ) (252.3 ) 28.4 (294.8 ) ________________ (1) Includes ( 2 ) Includes a non-cash pre-tax impairment charge of $378.0 million |
Organization and Operations (De
Organization and Operations (Details) | Feb. 17, 2016$ / shares | Dec. 31, 2018shares | Dec. 31, 2017shares |
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, outstanding | shares | 5,000,000 | 5,000,000 | |
Preferred units dividend percentage | 9.00% |
Significant Accounting Polici_4
Significant Accounting Policies (Details) - USD ($) | Jan. 01, 2018 | Dec. 31, 2018 |
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | ||
Margin tax rate | 0.75% | |
Accounting Standards Update 2017-12 [Member] | ||
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | ||
Effect on retained earnings | $ 0 | |
Derivative hedge accumulated ineffectiveness | $ 0 | |
Minimum [Member] | ||
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | ||
Payment of commodities due period | 10 days | |
Maximum [Member] | ||
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | ||
Payment of commodities due period | 30 days |
Significant Accounting Polici_5
Significant Accounting Policies - Summary of Effect of Adoption on Our Consolidated Financial Statements (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | $ 2,597.6 | $ 2,986.4 | $ 2,444.4 | $ 2,455.6 | $ 2,702.8 | $ 2,131.8 | $ 1,867.7 | $ 2,112.6 | $ 10,484 | $ 8,814.9 | $ 6,690.9 | ||||||||||
Costs and expenses: | |||||||||||||||||||||
Product purchases | 8,238.2 | 6,906.1 | 4,922.9 | ||||||||||||||||||
Income from operations | (76.6) | [1] | 80.6 | [1] | 159.2 | [1] | 90.4 | [1] | 116.5 | [2] | (320.3) | [2] | 40.7 | [2] | 53.7 | [2] | 253.6 | [1] | (109.4) | [2] | 66 |
Income (loss) before income taxes | 98.5 | (258) | (229) | ||||||||||||||||||
Net income (loss) | $ (111.3) | $ (8.7) | $ 162.6 | $ 56 | $ 44.9 | $ (245) | $ (29.2) | $ (21.3) | 98.6 | (250.6) | (228.7) | ||||||||||
Sales of Commodities [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | 9,278.7 | 7,751.1 | 5,626.8 | ||||||||||||||||||
Fees from Midstream Services [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | 1,205.3 | $ 1,063.8 | $ 1,064.1 | ||||||||||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | 10,484 | ||||||||||||||||||||
Costs and expenses: | |||||||||||||||||||||
Product purchases | 8,238.2 | ||||||||||||||||||||
Income from operations | 253.6 | ||||||||||||||||||||
Income (loss) before income taxes | 98.5 | ||||||||||||||||||||
Net income (loss) | 98.6 | ||||||||||||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Sales of Commodities [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | 9,278.7 | ||||||||||||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Fees from Midstream Services [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | 1,205.3 | ||||||||||||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Pre-Adoption [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | 10,856.8 | ||||||||||||||||||||
Costs and expenses: | |||||||||||||||||||||
Product purchases | 8,611 | ||||||||||||||||||||
Income from operations | 253.6 | ||||||||||||||||||||
Income (loss) before income taxes | 98.5 | ||||||||||||||||||||
Net income (loss) | 98.6 | ||||||||||||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Pre-Adoption [Member] | Sales of Commodities [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | 9,611.9 | ||||||||||||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Pre-Adoption [Member] | Fees from Midstream Services [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | 1,244.9 | ||||||||||||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Effect of Adoption [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | (372.8) | ||||||||||||||||||||
Costs and expenses: | |||||||||||||||||||||
Product purchases | (372.8) | ||||||||||||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Effect of Adoption [Member] | Sales of Commodities [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | (333.2) | ||||||||||||||||||||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Effect of Adoption [Member] | Fees from Midstream Services [Member] | |||||||||||||||||||||
Revenues: | |||||||||||||||||||||
Total revenues | $ (39.6) | ||||||||||||||||||||
[1] | Includes a non-cash pre-tax impairment charge of $210.0 million in the fourth quarter of 2018. See Note 7 – Goodwill. | ||||||||||||||||||||
[2] | Includes a non-cash pre-tax impairment charge of $378.0 million in the third quarter of 2017. See Note 6 – Property, Plant and Equipment and Intangible Assets |
Newly-Formed Joint Ventures, _3
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Joint Ventures (Details) $ in Millions | Jan. 01, 2020USD ($) | Feb. 06, 2018MBbls / dJointVenture | Feb. 28, 2019 | May 31, 2018aMMcf / d | Apr. 30, 2018USD ($)MBbls / dmi | Mar. 31, 2018USD ($) | Jan. 31, 2018MMcf / d | Jul. 31, 2017USD ($)mi | Apr. 30, 2018MMcf / dmi | Dec. 31, 2018USD ($)MBbls / dinBcf | Dec. 31, 2017 | Sep. 30, 2017 |
Business Acquisition [Line Items] | ||||||||||||
Fractionation-related infrastructure funded and owned percentage | 100.00% | |||||||||||
Altus Midstream Company [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Percentage of interest aquired through option exercised | 15.00% | |||||||||||
Hess Midstream Partners L P | LM4 Plant [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 50.00% | |||||||||||
Processing capacity | MMcf / d | 200 | |||||||||||
Scenario Forecast [Member] | Stonepeak Infrastructure Partners [Member] | DevCo JVs [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Option to acquire interest, minimum capital increments | $ | $ 100 | |||||||||||
Option to acquire, percentage of single final purchase | 50.00% | |||||||||||
Mont Belvieu, Texas [Member] | Train 6 [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of pipeline | MBbls / d | 100 | |||||||||||
Maximum [Member] | Scenario Forecast [Member] | Stonepeak Infrastructure Partners [Member] | DevCo JVs [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Percentage of option to purchase equity stake | 50.00% | |||||||||||
Stonepeak Infrastructure Partners [Member] | GCX DevCo JV [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Number of development joint ventures | JointVenture | 3 | |||||||||||
Ownership interest | 80.00% | |||||||||||
Stonepeak Infrastructure Partners [Member] | Train 6 DevCo JV [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 80.00% | |||||||||||
Stonepeak Infrastructure Partners [Member] | Grand Prix DevCo JV [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 95.00% | |||||||||||
GCX DevCo JV [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 20.00% | |||||||||||
GCX DevCo JV [Member] | GCX [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 25.00% | 25.00% | ||||||||||
Train 6 DevCo JV [Member] | Mont Belvieu, Texas [Member] | Train 6 [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest in assets | 100.00% | |||||||||||
Grand Prix DevCo JV [Member] | Grand Prix Joint Venture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 20.00% | |||||||||||
Grand Prix Joint Venture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Expected cost of joint venture | $ | $ 1,900 | |||||||||||
Grand Prix Joint Venture [Member] | Permian Basin [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Length of pipeline | in | 24 | |||||||||||
Capacity of pipeline | MBbls / d | 300 | |||||||||||
Grand Prix Joint Venture [Member] | Maximum [Member] | Permian Basin [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of pipeline | MBbls / d | 550 | |||||||||||
Grand Prix Joint Venture [Member] | Southern Oklahoma [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Expected cost of joint venture | $ | $ 350 | |||||||||||
Grand Prix Joint Venture [Member] | North Texas [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of pipeline | MBbls / d | 450 | |||||||||||
Grand Prix Joint Venture [Member] | North Texas [Member] | Permian Basin [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Diameter of pipeline | in | 30 | |||||||||||
Grand Prix Joint Venture [Member] | North Texas [Member] | Maximum [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of pipeline | MBbls / d | 950 | |||||||||||
Grand Prix Joint Venture [Member] | Blackstone Energy Partners [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Percentage of joint venture interest sold | 25.00% | |||||||||||
Williams [Member] | Mont Belvieu, Texas [Member] | Scenario Forecast [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Option to purchase equity interest percentage | 20.00% | |||||||||||
Cayenne Joint Venture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Conversion of existing mile gas pipeline | mi | 62 | |||||||||||
Percentage of ownership interest aquired | 50.00% | |||||||||||
Amount of business aquired | $ | $ 5 | |||||||||||
Project commencement date | 2017-12 | |||||||||||
Ownership interest | 50.00% | |||||||||||
GCX [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 25.00% | |||||||||||
Natural gas transportation cost estimated | $ | $ 1,750 | |||||||||||
GCX [Member] | DCP [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 25.00% | |||||||||||
GCX [Member] | KMTP [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 35.00% | |||||||||||
GCX [Member] | Maximum [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of natural gas transported per day | Bcf | 1.98 | |||||||||||
Agua Blanca Joint Venture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Percentage of ownership interest aquired | 10.00% | 10.00% | ||||||||||
Amount of business aquired | $ | $ 3.5 | |||||||||||
Miles of natural gas residue pipeline | mi | 160 | 160 | ||||||||||
Initial capacity of pipeline | MBbls / d | 1.4 | |||||||||||
Carnero Joint Venture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 50.00% | |||||||||||
Processing capacity | MMcf / d | 460 | 260 | ||||||||||
Area of gas gathering and processing facilities | a | 420,000 | |||||||||||
Carnero Joint Venture [Member] | LM4 Plant [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of gas processing plant acquired | MMcf / d | 200 | |||||||||||
Carnero Joint Venture [Member] | Western Eagle Ford [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Area of gas gathering and processing facilities | a | 315,000 | |||||||||||
Carnero Joint Venture [Member] | Catarina [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Area of gas gathering and processing facilities | a | 105,000 |
Newly-Formed Joint Ventures, _4
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Acquisitions (Details) | May 30, 2017USD ($) | May 09, 2017USD ($)amiMMcf | Mar. 31, 2017USD ($) | Mar. 01, 2017USD ($)aMMcfMBbls | Jan. 26, 2017USD ($)$ / sharesshares | Oct. 31, 2018MMcf | Dec. 31, 2017USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2018USD ($) | Mar. 02, 2017USD ($) |
Business Acquisition [Line Items] | ||||||||||
Shares of common stock issued (including shares sold pursuant to underwriters’ overallotment option) | shares | 9,200,000 | |||||||||
Shares issued price | $ / shares | $ 57.65 | |||||||||
Net proceeds from public offering | $ 524,200,000 | |||||||||
Flag City Acquisition [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Equity method investment ownership percentage | 60.00% | 60.00% | ||||||||
Flag City Acquisition [Member] | Southern Oklahoma [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Capacity of cryogenic plant | MMcf | 120 | |||||||||
Flag City Acquisition [Member] | MPLX, Limited Parteners [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Ownership Percentage | 40.00% | 40.00% | ||||||||
Permian Acquisition [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Cash payments related to acquisition | $ 484,100,000 | |||||||||
Additional cash payments related to purchase consideration | $ 90,000,000 | |||||||||
Additional cash that has been paid based on potential earn-out payment | $ 317,000,000 | $ 317,000,000 | $ 308,200,000 | $ 416,300,000 | ||||||
Revenues from acquired businesses | 127,900,000 | |||||||||
Net loss from acquired businesses | $ (31,500,000) | |||||||||
Acquisition-related expenses | $ 5,600,000 | |||||||||
Allocation of property, plant and equipment | $ 255,800,000 | |||||||||
Allocation of intangible assets for customer contracts | $ 692,300,000 | |||||||||
Permian Acquisition [Member] | Maximum [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Additional cash that has been paid based on potential earn-out payment | $ 935,000,000 | |||||||||
Permian Acquisition [Member] | Targa Resources Corp. [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Percentage of ownership interest aquired | 100.00% | |||||||||
New Delaware [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Average weighted contract life | 14 years | |||||||||
Gas processing capacity | MMcf | 70 | |||||||||
Crude gathering capacity | MBbls | 40 | |||||||||
New Delaware [Member] | Minimum [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Area of gas gathering and processing and crude gathering assets | a | 145,000 | |||||||||
New Midland [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Average weighted contract life | 13 years | |||||||||
Gas processing capacity | MMcf | 10 | |||||||||
Crude gathering capacity | MBbls | 40 | |||||||||
New Midland [Member] | Minimum [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Area of gas gathering and processing and crude gathering assets | a | 105,000 | |||||||||
Flag City Acquisition [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Cash payments related to acquisition | $ 60,000,000 | |||||||||
Area of gas gathering and processing and crude gathering assets | a | 102.1 | |||||||||
Gas processing capacity | MMcf | 150 | |||||||||
Additional final adjustment due on base purchase price paid | $ 3,600,000 | |||||||||
Number of miles of gas gathering pipeline systems | mi | 24 | |||||||||
Allocation of property, plant and equipment | $ 52,300,000 | |||||||||
Allocation of intangible assets for customer contracts | 7,700,000 | |||||||||
Allocation of current assets and liabilities, net | 3,600,000 | |||||||||
Flag City Acquisition [Member] | Maximum [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Acquisition-related expenses | $ 100,000 |
Newly-Formed Joint Ventures, _5
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - Permian Acquisition [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Pro forma consolidated results of operations [Abstract] | ||
Revenues | $ 8,829 | $ 6,725.6 |
Net income (loss) | $ (252.2) | $ (284.5) |
Newly-Formed Joint Ventures, _6
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||
Sep. 30, 2017 | Jun. 30, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Mar. 01, 2017 | Dec. 31, 2015 | |
Fair value determination (final) [Abstract] | |||||||
Goodwill | $ 46,600,000 | $ 256,600,000 | $ 210,000,000 | $ 46,600,000 | $ 417,000,000 | ||
Measurement-period adjustments to preliminary acquisition date fair values [Abstract] | |||||||
Trade receivables, preliminary fair value | 6,700,000 | ||||||
Depreciation and amortization expense | $ 815,900,000 | 809,500,000 | $ 757,700,000 | ||||
Measurement Period Adjustments [Member] | |||||||
Measurement-period adjustments to preliminary acquisition date fair values [Abstract] | |||||||
Measurement period adjustment | $ (45,300,000) | ||||||
Intangible assets | 66,700,000 | ||||||
Other assets, net | 400,000 | ||||||
Goodwill | 112,400,000 | ||||||
Depreciation and amortization expense | $ 400,000 | ||||||
Permian Acquisition [Member] | |||||||
Pro forma consolidated results of operations [Abstract] | |||||||
Acquisition-related expenses | $ 5,600,000 | ||||||
Fair value determination (final) [Abstract] | |||||||
Goodwill | $ 46,600,000 | ||||||
Measurement-period adjustments to preliminary acquisition date fair values [Abstract] | |||||||
Measurement period adjustment | $ 0 |
Newly-Formed Joint Ventures, _7
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Fair Value of Consideration Transferred (Details) - USD ($) $ in Millions | Mar. 01, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Cash paid, net of cash acquired | $ 0 | $ 570.8 | $ 0 | |
Permian Acquisition [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Total fair value of consideration transferred | $ 987.1 | |||
Targa Resources Corp [Member] | Permian Acquisition [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Cash paid, net of cash acquired | 570.8 | |||
Contingent consideration valuation as of the acquisition date | 416.3 | |||
Total fair value of consideration transferred | $ 987.1 |
Newly-Formed Joint Ventures, _8
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Fair Value of Consideration Transferred (Parenthetical) (Details) $ in Millions | Mar. 01, 2017USD ($) |
Targa Resources Corp [Member] | Permian Acquisition [Member] | |
Fair Value of Consideration Transferred by Targa [Abstract] | |
Cash acquired from acquisition | $ 3.3 |
Newly-Formed Joint Ventures, _9
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Fair Value of the Assets and Liabilities Assumed at Acquisition Date (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 01, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Fair value determination (final) [Abstract] | |||||
Goodwill | $ 46.6 | $ 256.6 | $ 46.6 | $ 210 | $ 417 |
Permian Acquisition [Member] | |||||
Fair value determination (final) [Abstract] | |||||
Trade and other current receivables, net | 6.7 | ||||
Other current assets | 0.6 | ||||
Property, plant and equipment | 255.8 | ||||
Intangible assets | 692.3 | ||||
Current liabilities | (14.1) | ||||
Other long-term liabilities | (0.8) | ||||
Total identifiable net assets | 940.5 | ||||
Goodwill | 46.6 | ||||
Total fair value of assets acquired and liabilities assumed | $ 987.1 |
Newly-Formed Joint Ventures,_10
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Contingent Liability (Details) - Permian Acquisition [Member] - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 02, 2017 |
Business Acquisition [Line Items] | |||
Additional cash that may be paid based on potential earn-out payment | $ 308,200,000 | $ 317,000,000 | $ 416,300,000 |
Potential earn-out payments acquisition date fair value | $ 416,300,000 | ||
Maximum [Member] | |||
Business Acquisition [Line Items] | |||
Additional cash that may be paid based on potential earn-out payment | $ 935,000,000 | ||
Other Long-term Liabilities [Member] | |||
Business Acquisition [Line Items] | |||
Potential earn-out payments acquisition date fair value | $ 416,300,000 |
Newly-Formed Joint Ventures,_11
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Purchase of Outstanding Silver Oak II Interests (Details) - USD ($) | Jun. 01, 2017 | Dec. 31, 2018 |
Business Acquisition [Line Items] | ||
Gain (Loss) on Disposition of Business | $ 48,100,000 | |
SN Catarina, LLC [Member] | ||
Business Acquisition [Line Items] | ||
Business acquisition remaining interests acquired | 10.00% | |
Purchase price of business acquisition | $ 12,500,000 | |
Silver Oak II [Member] | ||
Business Acquisition [Line Items] | ||
Gain (Loss) on Disposition of Business | $ 0 |
Newly-Formed Joint Ventures,_12
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Purchase of Outstanding Versado Membership Interest (Details) - Versado Gas Processors L.L.C [Member] | Oct. 31, 2016USD ($) |
Business Acquisition [Line Items] | |
Gain or loss on purchase of non controlling interest | $ 0 |
Environment Proceeding [Member] | |
Business Acquisition [Line Items] | |
Remaining membership interest to be acquired | 37.00% |
Newly-Formed Joint Ventures,_13
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Divestiture (Details) - USD ($) $ in Millions | Sep. 12, 2018 | Apr. 04, 2017 | Dec. 31, 2018 | Sep. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Business Acquisition [Line Items] | |||||||
Loss on sale or disposal of assets | $ 0.1 | $ (15.9) | $ (6.1) | ||||
Refined Products And Crude Oil Storage And Terminaling Facilities [Member] | Tacoma, Washington, And Baltimore, Maryland [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Selling price of property upon agreement | $ 165 | ||||||
Refined Products And Crude Oil Storage And Terminaling Facilities [Member] | Tacoma, Washington, And Baltimore, Maryland [Member] | Other Income (Expense) [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Loss on sale or disposal of assets | $ (1.6) | $ (57.5) | |||||
Venice Gathering System, L.L.C. [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Gain (loss) from sale of divestiture of businesses | $ (16.1) | ||||||
Venice Gathering System, L.L.C. [Member] | Disposal Group, Not Discontinued Operations [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Subsidiary ownership interest sale percentage | 100.00% | ||||||
Proceeds from divestiture of businesses | $ 0.4 | ||||||
Venice Energy Services Company, L.L.C. [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Ownership interest | 76.80% | 76.80% |
Newly-Formed Joint Ventures,_14
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Subsequent Event (Details) - Subsequent Event [Member] - Targa Badlands LLC [Member] $ in Billions | Feb. 21, 2019USD ($) |
Business Acquisition [Line Items] | |
Subsidiary ownership interest sale percentage | 45.00% |
Consideration received on sale of interest on subsidiary | $ 1.6 |
Inventories (Details)
Inventories (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Inventory Disclosure [Abstract] | ||
Commodities | $ 151.1 | $ 191.6 |
Materials and supplies | 13.6 | 12.9 |
Total inventory | $ 164.7 | $ 204.5 |
Property, Plant and Equipment_3
Property, Plant and Equipment and Intangible Assets - Property, Plant and Equipment (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 17,213.8 | $ 14,198.6 | |
Accumulated depreciation | (4,285.5) | (3,768.7) | |
Property, plant and equipment, net | 12,928.3 | 10,429.9 | |
Intangible assets | 2,736.6 | 2,736.6 | |
Accumulated amortization | (753.4) | (570.8) | |
Intangible assets, net | $ 1,983.2 | $ 2,165.8 | $ 1,654 |
Estimated useful life | 20 years | ||
Minimum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 10 years | ||
Maximum [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 | $ 7,547.9 | $ 7,037.2 | |
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 | 4,001 | $ 3,563 | |
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 | 1,138.7 | $ 1,244.1 | |
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 | 445.1 | $ 343.6 | |
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 | 334.3 | $ 303.5 | |
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 | 144.3 | $ 125.7 | |
Construction in Progress [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 3,602.5 | $ 1,581.5 |
Property, Plant and Equipment_4
Property, Plant and Equipment and Intangible Assets - Additional Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2018 | Jun. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2012 | |
Property Plant And Equipment [Line Items] | ||||||||
Depreciation expense | $ 633.3 | $ 621.3 | $ 601.5 | |||||
Non-cash pre-tax impairment charges | $ 210 | $ 378 | 0 | 378 | 0 | |||
Additions from acquisition | $ 692.3 | 692.3 | $ 1,354.9 | |||||
Estimated useful life | 20 years | |||||||
Gain on sale of inland marine barge business | $ 48.1 | |||||||
Gain recognized in exchange of assets | 0.1 | (15.9) | $ (6.1) | |||||
Versado Gathering System [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Gain recognized in exchange of assets | $ 44.4 | |||||||
Logistics and Marketing [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Proceeds from sale of property | $ 69.3 | |||||||
Permian Acquisition [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Estimated useful life | 15 years | |||||||
Flag City Acquisition [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Additions from acquisition | $ 7.7 | $ 7.7 | ||||||
Estimated useful life | 10 years | |||||||
Badlands [Member] | ||||||||
Property Plant And Equipment [Line Items] | ||||||||
Additions from acquisition | $ 679.6 | |||||||
Estimated useful life | 20 years |
Property, Plant and Equipment_5
Property, Plant and Equipment and Intangible Assets - Intangible Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Intangible Assets, net [Roll Forward] | |||
Amortization | $ 182.6 | $ 188.2 | $ 156.1 |
Estimated amortization expense for intangible assets [Abstract] | |||
2,019 | 171.6 | ||
2,020 | 159.4 | ||
2,021 | 149.5 | ||
2,022 | 141.2 | ||
2,023 | $ 136 | ||
Weighted average amortization period, intangible assets | 14 years 10 months 24 days |
Property, Plant and Equipment_6
Property, Plant and Equipment and Intangible Assets - Schedule of Changes in Intangible Assets (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Intangible Assets, net [Roll Forward] | ||||
Beginning of period | $ 2,165.8 | $ 1,654 | ||
Additions from Acquisition | 692.3 | 692.3 | $ 1,354.9 | |
Amortization | (182.6) | (188.2) | $ (156.1) | |
End of period | 1,983.2 | 2,165.8 | $ 1,654 | |
Flag City Acquisition [Member] | ||||
Intangible Assets, net [Roll Forward] | ||||
Additions from Acquisition | $ 7.7 | $ 7.7 |
Goodwill (Details)
Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2018 | Dec. 31, 2016 | Mar. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Mar. 01, 2017 | Dec. 31, 2015 | |
Goodwill [Line Items] | ||||||||
Goodwill | $ 46.6 | $ 210 | $ 46.6 | $ 256.6 | $ 210 | $ 46.6 | $ 417 | |
Goodwill impairment | 210 | $ 183 | $ 24 | $ 210 | $ 0 | $ 207 | ||
Permian Acquisition [Member] | ||||||||
Goodwill [Line Items] | ||||||||
Goodwill | $ 46.6 | |||||||
WestTX And SouthTX [Member] | ||||||||
Goodwill [Line Items] | ||||||||
Goodwill impairment | $ 210 |
Goodwill - Changes in Net Amoun
Goodwill - Changes in Net Amounts of Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2018 | Dec. 31, 2016 | Mar. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Goodwill [Roll Forward] | ||||||
Beginning balance | $ 417 | $ 256.6 | $ 210 | $ 417 | ||
Additional impairment | (24) | |||||
Acquisition | 46.6 | |||||
Impairment | $ (210) | $ (183) | (24) | (210) | 0 | (207) |
Ending balance | 46.6 | 210 | 46.6 | 256.6 | 210 | |
WestTX [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Beginning balance | 326.9 | 174.7 | 174.7 | 326.9 | ||
Additional impairment | (14.4) | |||||
Impairment | (174.7) | (137.8) | ||||
Ending balance | 174.7 | 174.7 | 174.7 | |||
SouthTX [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Beginning balance | 90.1 | 35.3 | 35.3 | 90.1 | ||
Additional impairment | $ (9.6) | |||||
Impairment | (35.3) | (45.2) | ||||
Ending balance | $ 35.3 | 35.3 | $ 35.3 | |||
New Midland [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Beginning balance | 23.2 | |||||
Acquisition | 23.2 | |||||
Ending balance | 23.2 | 23.2 | 23.2 | |||
New Delaware [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Beginning balance | 23.4 | |||||
Acquisition | 23.4 | |||||
Ending balance | $ 23.4 | $ 23.4 | $ 23.4 |
Investments in Unconsolidated_3
Investments in Unconsolidated Affiliates - Additional Information (Details) $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($)JointVenture | |
Gulf Coast Fractionators LP [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Ownership interest | 38.80% | |
T2 Joint Ventures [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Number of non-operated joint ventures acquired in Atlas mergers | JointVenture | 3 | |
T2 La Salle [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Ownership interest | 75.00% | |
T2 Eagle Ford [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Ownership interest | 50.00% | |
T2 EF Cogen [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Ownership interest | 50.00% | 50.00% |
Impairment loss | $ 12 | |
Cayenne Joint Venture [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Ownership interest | 50.00% | |
GCX [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Ownership interest | 25.00% | |
Little Missouri [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Ownership interest | 50.00% | |
Agua Blanca [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Ownership interest | 10.00% | |
T2 LaSalle and T2 Eagle Ford [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Unamortized excess fair value | $ 24.6 | |
Preliminary estimated useful lives of the underlying assets | 20 years |
Investments in Unconsolidated_4
Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | $ 221.6 | $ 240.8 | $ 258.9 | |||
Equity earnings (loss) | 7.3 | (17) | (14.3) | |||
Cash Distributions | [1] | (34.3) | [2] | (12.7) | (8.2) | |
Acquisition (Disposition) | 1.4 | 5 | 0 | |||
Contributions | 294.5 | [3] | 5.5 | 4.4 | ||
Balance at end of period | 490.5 | 221.6 | 240.8 | |||
Gulf Coast Fractionators LP [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 45.8 | 46.1 | 49.5 | |||
Equity earnings (loss) | 16.8 | 12.4 | 4.1 | |||
Cash Distributions | [1] | (22.3) | [2] | (12.7) | (7.5) | |
Acquisition (Disposition) | 0 | 0 | 0 | |||
Contributions | 0 | [3] | 0 | 0 | ||
Balance at end of period | 40.3 | 45.8 | 46.1 | |||
T2 La Salle [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 54.1 | 58.6 | 63.6 | |||
Equity earnings (loss) | (4.9) | (4.9) | (5.2) | |||
Cash Distributions | [1] | 0 | [2] | 0 | 0 | |
Acquisition (Disposition) | 0 | 0 | 0 | |||
Contributions | 0.1 | [3] | 0.4 | 0.2 | ||
Balance at end of period | 49.3 | 54.1 | 58.6 | |||
T2 Eagle Ford [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 109.2 | 118.6 | 123.8 | |||
Equity earnings (loss) | (10.2) | (10.6) | (9.4) | |||
Cash Distributions | [1] | 0 | [2] | 0 | 0 | |
Acquisition (Disposition) | 0 | 0 | 0 | |||
Contributions | 0 | [3] | 1.2 | 4.2 | ||
Balance at end of period | 99 | 109.2 | 118.6 | |||
T2 EF Cogen [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 3.9 | 17.5 | 22 | |||
Equity earnings (loss) | (1.8) | (13.9) | (3.8) | |||
Cash Distributions | [1] | 0 | [2] | 0 | (0.7) | |
Acquisition (Disposition) | (2.1) | 0 | 0 | |||
Contributions | 0 | [3] | 0.3 | 0 | ||
Balance at end of period | 0 | 3.9 | 17.5 | |||
Cayenne Joint Venture [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 8.6 | 0 | 0 | |||
Equity earnings (loss) | 6.4 | 0 | 0 | |||
Cash Distributions | [1] | (4) | [2] | 0 | 0 | |
Acquisition (Disposition) | 0 | 5 | 0 | |||
Contributions | 5.6 | [3] | 3.6 | 0 | ||
Balance at end of period | 16.6 | 8.6 | 0 | |||
GCX [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 0 | [4] | 0 | 0 | ||
Equity earnings (loss) | 0.8 | [4] | 0 | 0 | ||
Cash Distributions | [1] | 0 | [2],[4] | 0 | 0 | |
Acquisition (Disposition) | 0 | [4] | 0 | 0 | ||
Contributions | 210.8 | [3],[4] | 0 | 0 | ||
Balance at end of period | 211.6 | [4] | 0 | [4] | 0 | |
Little Missouri [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 0 | 0 | 0 | |||
Equity earnings (loss) | 0 | 0 | 0 | |||
Cash Distributions | [1] | (8) | [2] | 0 | 0 | |
Acquisition (Disposition) | 0 | 0 | 0 | |||
Contributions | 75.3 | [3] | 0 | 0 | ||
Balance at end of period | 67.3 | 0 | 0 | |||
Agua Blanca [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 0 | 0 | 0 | |||
Equity earnings (loss) | 0.2 | 0 | 0 | |||
Cash Distributions | [1] | 0 | [2] | 0 | 0 | |
Acquisition (Disposition) | 3.5 | 0 | 0 | |||
Contributions | 2.7 | [3] | 0 | 0 | ||
Balance at end of period | $ 6.4 | $ 0 | $ 0 | |||
[1] | Includes $5.5 million, $0.2 million and $4.1 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, 2018, 2017 and 2016. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in our Consolidated Statements of Cash Flows in the period in which they occur. | |||||
[2] | Includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures. | |||||
[3] | Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4. See Note 22 – Supplemental Cash Flow Information. | |||||
[4] | As discussed in Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures, our 25% interest in GCX is owned by GCX DevCo JV, of which we own a 20% interest. GCX DevCo JV is accounted for on a consolidated basis in our consolidated financial statements. |
Investments in Unconsolidated_5
Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Parenthetical) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Feb. 06, 2018 | |
Schedule Of Equity Method Investments [Line Items] | ||||
Return of capital from unconsolidated affiliate | $ 5.5 | $ 0.2 | $ 4.1 | |
Contribution of property, plant and equipment to investment in unconsolidated affiliates | $ 16 | 1 | ||
GCX DevCo JV [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Ownership interest | 20.00% | |||
GCX DevCo JV [Member] | GCX [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Ownership interest | 25.00% | 25.00% | ||
Gulf Coast Fractionators LP [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Return of capital from unconsolidated affiliate | $ 5.5 | $ 0.2 | $ 4.1 | |
Ownership interest | 38.80% | |||
Little Missouri [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Return of capital from unconsolidated affiliate | $ 8 | |||
Ownership interest | 50.00% |
Investments in Unconsolidated_6
Investments in Unconsolidated Affiliates - Summary of Combined Financial Information of Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Equity Method Investment Summarized Financial Information [Abstract] | |||
Current assets | $ 200.7 | $ 29.1 | |
Non-current assets | 1,329.7 | 379.8 | |
Current liabilities | 233.9 | 11 | |
Non-current liabilities | 179.2 | ||
Net assets | 1,117.3 | 397.9 | |
Operating revenues | 130.6 | 84.3 | $ 70.3 |
Operating expenses | 96.9 | 80.5 | 91.4 |
Net income (loss) | $ 34.7 | $ 3.4 | $ (21.5) |
Accounts Payable and Accrued _3
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Components of accounts payable and accrued liabilities [Abstract] | ||
Commodities | $ 721.9 | $ 711.9 |
Other goods and services | 474.5 | 286.9 |
Interest | 79.4 | 54.1 |
Income and other taxes | 45.4 | 26.3 |
Other | 7.5 | 20.6 |
Accounts payable and accrued liabilities | 1,636.9 | 1,106.6 |
Permian Acquisition [Member] | ||
Components of accounts payable and accrued liabilities [Abstract] | ||
Permian Acquisition contingent consideration, estimated current portion | $ 308.2 | $ 6.8 |
Accounts Payable and Accrued _4
Accounts Payable and Accrued Liabilities - Additional Information (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Payables And Accruals [Abstract] | ||
Outstanding checks | $ 52.2 | $ 49.7 |
Debt Obligations (Details)
Debt Obligations (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | |
Current: | |||
Accounts receivable securitization facility, due December 2019 | [1] | $ 280 | $ 350 |
Current debt | 1,029.4 | 350 | |
Debt issuance costs, net of amortization | (1.5) | ||
Current debt obligations | 1,027.9 | 350 | |
Long-term [Abstract] | |||
Long-term debt | 5,197.4 | 4,268 | |
Long-term debt including unamortized premium (discount) | 5,228.5 | 4,298 | |
Debt issuance costs, net of amortization | (31.1) | (30) | |
Total debt obligations | 6,225.3 | 4,618 | |
Irrevocable standby letters of credit outstanding | 79.5 | 27.2 | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | |||
Current: | |||
Long-term debt, current | [2] | 749.4 | |
Long-term [Abstract] | |||
Long-term debt | 749.4 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 559.6 | 559.6 | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 583.9 | 583.9 | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 580.1 | 580.1 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 2025 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 500 | 500 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5⅞% Notes due April 2026 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 1,000 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 2027 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 500 | 500 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2028 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 750 | 750 | |
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 | 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 | 48.1 | 48.1 | |
Unamortized premium | 0.3 | 0.4 | |
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due June 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [3] | $ 700 | $ 20 |
[1] | As of December 31, 2018, we had $340.0 million of qualifying receivables under our $400.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. | ||
[2] | The 4⅛% Senior Notes due 2019 were redeemed in full on February 11, 2019. | ||
[3] | As of December 31, 2018, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $1,420.5 million. |
Debt Obligations (Parenthetical
Debt Obligations (Parenthetical) (Details) - USD ($) $ in Millions | Feb. 11, 2019 | Apr. 30, 2018 | Oct. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Jan. 31, 2019 | |
Debt Instrument [Line Items] | ||||||||
Proceeds from borrowings under accounts receivable securitization facility | $ 546.6 | $ 666.6 | $ 171.4 | |||||
Accounts receivable securitization facility | [1] | $ 280 | $ 350 | |||||
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due June 2023 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | [2] | Jun. 30, 2023 | ||||||
Maximum borrowing capacity | $ 2,200 | |||||||
Remaining borrowing capacity | 1,420.5 | |||||||
Accounts Receivable Securitization Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Proceeds from borrowings under accounts receivable securitization facility | 340 | |||||||
Accounts receivable securitization facility | 400 | |||||||
Availability amount under accounts receivable securitization | $ 60 | |||||||
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2019 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | [1] | Dec. 31, 2019 | ||||||
Senior Unsecured Notes [Member] | Subsequent Event [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Interest rate on fixed rate debt | 4.125% | |||||||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | Nov. 30, 2019 | |||||||
Interest rate on fixed rate debt | 4.125% | |||||||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | Subsequent Event [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | Nov. 30, 2019 | |||||||
Interest rate on fixed rate debt | 4.125% | |||||||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | May 31, 2023 | |||||||
Interest rate on fixed rate debt | 5.25% | |||||||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | Nov. 30, 2023 | |||||||
Interest rate on fixed rate debt | 4.25% | |||||||
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | Mar. 31, 2024 | |||||||
Interest rate on fixed rate debt | 6.75% | |||||||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 2025 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | Feb. 28, 2025 | |||||||
Interest rate on fixed rate debt | 5.125% | |||||||
Senior Unsecured Notes [Member] | Senior Unsecured 5⅞% Notes due April 2026 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | Apr. 30, 2026 | Apr. 30, 2026 | ||||||
Interest rate on fixed rate debt | 5.875% | 5.875% | ||||||
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 2027 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | Feb. 28, 2027 | |||||||
Interest rate on fixed rate debt | 5.375% | |||||||
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2028 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | Jan. 31, 2028 | Jan. 31, 2028 | ||||||
Interest rate on fixed rate debt | 5.00% | 5.00% | ||||||
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | Aug. 31, 2023 | |||||||
Interest rate on fixed rate debt | 5.875% | |||||||
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maturity date | Nov. 30, 2021 | |||||||
Interest rate on fixed rate debt | 4.75% | |||||||
[1] | As of December 31, 2018, we had $340.0 million of qualifying receivables under our $400.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. | |||||||
[2] | As of December 31, 2018, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $1,420.5 million. |
Debt Obligations - Schedule of
Debt Obligations - Schedule of Contractual Maturities of Outstanding Debt Obligations (Details) $ in Millions | Dec. 31, 2018USD ($) | |
Contractual Obligation [Line Items] | ||
Total | $ 6,257.6 | |
2,019 | 1,029.4 | |
2,020 | 0 | |
2,021 | 6.5 | |
2,022 | 0 | |
2,023 | 1,891.6 | |
After 2,023 | 3,330.1 | |
Accounts Receivable Securitization Facility [Member] | ||
Contractual Obligation [Line Items] | ||
Total | 280 | |
2,019 | 280 | |
2,020 | 0 | |
2,021 | 0 | |
2,022 | 0 | |
2,023 | 0 | |
After 2,023 | 0 | |
Senior Unsecured Notes [Member] | ||
Contractual Obligation [Line Items] | ||
Total | 5,277.6 | [1] |
2,019 | 749.4 | [1] |
2,020 | 0 | [1] |
2,021 | 6.5 | [1] |
2,022 | 0 | [1] |
2,023 | 1,191.6 | [1] |
After 2,023 | 3,330.1 | [1] |
Revolving Credit Facility [Member] | ||
Contractual Obligation [Line Items] | ||
Total | 700 | |
2,019 | 0 | |
2,020 | 0 | |
2,021 | 0 | |
2,022 | 0 | |
2,023 | 700 | |
After 2,023 | $ 0 | |
[1] | The 4⅛% Senior Notes due 2019 were redeemed in full on February 11, 2019. |
Debt Obligations - Schedule o_2
Debt Obligations - Schedule of Contractual Maturities of Outstanding Debt Obligations (Parenthetical) (Details) - Senior Unsecured Notes [Member] | Feb. 11, 2019 | Dec. 31, 2018 | Jan. 31, 2019 |
Subsequent Event [Member] | |||
Contractual Obligation [Line Items] | |||
Interest rate on fixed rate debt | 4.125% | ||
Senior Unsecured 4 1/8% Notes due November 2019 [Member] | |||
Contractual Obligation [Line Items] | |||
Interest rate on fixed rate debt | 4.125% | ||
Maturity date | Nov. 30, 2019 | ||
Senior Unsecured 4 1/8% Notes due November 2019 [Member] | Subsequent Event [Member] | |||
Contractual Obligation [Line Items] | |||
Interest rate on fixed rate debt | 4.125% | ||
Maturity date | Nov. 30, 2019 |
Debt Obligations - Interest Rat
Debt Obligations - Interest Rates on Variable-Rate Debt Obligations (Details) | Dec. 31, 2018 |
Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Weighted average interest rate incurred | 3.00% |
Minimum [Member] | Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred | 2.60% |
Maximum [Member] | Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred | 3.40% |
TRP Revolver [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Weighted average interest rate incurred | 3.80% |
TRP Revolver [Member] | Minimum [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred | 3.40% |
TRP Revolver [Member] | Maximum [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred | 5.80% |
Debt Obligations - Revolving Cr
Debt Obligations - Revolving Credit Agreement (Details) | Feb. 17, 2016 | Dec. 31, 2018USD ($) | Dec. 31, 2016USD ($) | Jun. 30, 2018USD ($) | May 31, 2018USD ($) |
Debt Instrument [Line Items] | |||||
Write off debt issuance cost | $ 3,500,000 | ||||
TRP Revolver [Member] | |||||
Debt Instrument [Line Items] | |||||
Maximum borrowing capacity | $ 2,200,000,000 | $ 1,600,000,000 | |||
Additional commitment increase available upon request | $ 500,000,000 | ||||
Write off debt issuance cost | $ 1,300,000 | ||||
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 | 0.25% | ||||
Leverage ratio before the collateral release date | 1 | ||||
Leverage ratio upon and after collateral release date | 1 | ||||
Leverage ratio | 1 | ||||
Maximum senior leverage ratio | 1 | ||||
Interest coverage ratio | 1 | ||||
TRP Revolver [Member] | Minimum [Member] | Unrestricted Subsidiary [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior leverage ratio | 1 | ||||
TRP Revolver [Member] | Minimum [Member] | Redeemable Preferred Units [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior leverage ratio | 1 | ||||
TRP Revolver [Member] | Minimum [Member] | Letters of Credit [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on fixed rate debt | 1.25% | ||||
TRP Revolver [Member] | Minimum [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | |||||
Debt Instrument [Line Items] | |||||
Commitment fee percentage | 0.125% | ||||
TRP Revolver [Member] | Minimum [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | Letters of Credit [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on fixed rate debt | 1.125% | ||||
TRP Revolver [Member] | Minimum [Member] | Base Rate [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 0.25% | ||||
TRP Revolver [Member] | Minimum [Member] | Base Rate [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 0.125% | ||||
TRP Revolver [Member] | Minimum [Member] | Eurodollar [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 1.25% | ||||
TRP Revolver [Member] | Minimum [Member] | Eurodollar [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 1.125% | ||||
TRP Revolver [Member] | Maximum [Member] | |||||
Debt Instrument [Line Items] | |||||
Commitment fee percentage | 0.375% | ||||
Leverage ratio before the collateral release date | 5.50 | ||||
Leverage ratio upon and after collateral release date | 5.25 | ||||
Leverage ratio | 5.50 | ||||
Maximum senior leverage ratio | 4 | ||||
Interest coverage ratio | 2.25 | ||||
Aggregate principal amount | $ 400,000,000 | ||||
TRP Revolver [Member] | Maximum [Member] | Unrestricted Subsidiary [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior leverage ratio | 4 | ||||
TRP Revolver [Member] | Maximum [Member] | Redeemable Preferred Units [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior leverage ratio | 3.50 | ||||
TRP Revolver [Member] | Maximum [Member] | Letters of Credit [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on fixed rate debt | 2.25% | ||||
TRP Revolver [Member] | Maximum [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | |||||
Debt Instrument [Line Items] | |||||
Commitment fee percentage | 0.35% | ||||
TRP Revolver [Member] | Maximum [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | Letters of Credit [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on fixed rate debt | 1.75% | ||||
TRP Revolver [Member] | Maximum [Member] | Base Rate [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 1.25% | ||||
TRP Revolver [Member] | Maximum [Member] | Base Rate [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 0.75% | ||||
TRP Revolver [Member] | Maximum [Member] | Eurodollar [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 2.25% | ||||
TRP Revolver [Member] | Maximum [Member] | Eurodollar [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 1.75% |
Debt Obligations - Accounts Rec
Debt Obligations - Accounts Receivable Securitization Facility (Details) - USD ($) | Dec. 07, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | |
Debt Instrument [Line Items] | ||||
Funding under securitization facility | [1] | $ 280,000,000 | $ 350,000,000 | |
Accounts Receivable Securitization Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Maximum borrowing capacity | $ 400,000,000 | 400,000,000 | $ 350,000,000 | |
Securitization facility termination date | Dec. 6, 2019 | |||
Funding under securitization facility | $ 280,000,000 | |||
[1] | As of December 31, 2018, we had $340.0 million of qualifying receivables under our $400.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. |
Debt Obligations - Senior Unsec
Debt Obligations - Senior Unsecured Notes (Details) - Senior Unsecured Notes [Member] | 12 Months Ended |
Dec. 31, 2018 | |
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 |
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 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 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 |
Senior Unsecured 5⅞% Notes due April 2026 [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 5 1/8% Notes due February 2025 [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 5 3/8% Notes due February 2027 [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 5% Notes due January 2028 [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 |
Debt Obligations- Redemption Da
Debt Obligations- Redemption Dates and Prices (Details) - Senior Unsecured Notes [Member] | 12 Months Ended |
Dec. 31, 2018 | |
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 5 3/8% Notes due February 2027 [Member] | |
Debt Instrument [Line Items] | |
Any Date Prior To | Feb. 1, 2020 |
Price | 105.375% |
Senior Unsecured 5% Notes due January 2028 [Member] | |
Debt Instrument [Line Items] | |
Any Date Prior To | Jan. 15, 2021 |
Price | 105.00% |
Senior Unsecured 5 7/8% Notes due August 2023 [Member] | |
Debt Instrument [Line Items] | |
Any Date Prior To | Apr. 15, 2021 |
Price | 105.875% |
Senior Unsecured 5 1/4 % Notes due November 1,2018 [Member] | 2018 [Member] | |
Debt Instrument [Line Items] | |
Price | 101.75% |
Senior Unsecured 5 1/4 % Notes due November 1,2018 [Member] | 2019 [Member] | |
Debt Instrument [Line Items] | |
Price | 100.875% |
Senior Unsecured 5 1/4 % Notes due November 1,2018 [Member] | 2020 and thereafter [Member] | |
Debt Instrument [Line Items] | |
Price | 100.00% |
Senior Unsecured 4 1/4 % Notes due May 15, 2018 [Member] | 2018 [Member] | |
Debt Instrument [Line Items] | |
Price | 102.125% |
Senior Unsecured 4 1/4 % Notes due May 15, 2018 [Member] | 2019 [Member] | |
Debt Instrument [Line Items] | |
Price | 101.417% |
Senior Unsecured 4 1/4 % Notes due May 15, 2018 [Member] | 2020 [Member] | |
Debt Instrument [Line Items] | |
Price | 100.708% |
Senior Unsecured 4 1/4 % Notes due May 15, 2018 [Member] | 2021 and thereafter [Member] | |
Debt Instrument [Line Items] | |
Price | 100.00% |
Senior Unsecured 6 3/4% Notes due September 15, 2019 [Member] | 2019 [Member] | |
Debt Instrument [Line Items] | |
Price | 103.375% |
Senior Unsecured 6 3/4% Notes due September 15, 2019 [Member] | 2020 [Member] | |
Debt Instrument [Line Items] | |
Price | 101.688% |
Senior Unsecured 6 3/4% Notes due September 15, 2019 [Member] | 2021 and thereafter [Member] | |
Debt Instrument [Line Items] | |
Price | 100.00% |
Senior Unsecured 5 1/8% Notes due Frbruary 1, 2020 [Member] | 2020 [Member] | |
Debt Instrument [Line Items] | |
Price | 103.844% |
Senior Unsecured 5 1/8% Notes due Frbruary 1, 2020 [Member] | 2021 [Member] | |
Debt Instrument [Line Items] | |
Price | 102.563% |
Senior Unsecured 5 1/8% Notes due Frbruary 1, 2020 [Member] | 2022 [Member] | |
Debt Instrument [Line Items] | |
Price | 101.281% |
Senior Unsecured 5 1/8% Notes due Frbruary 1, 2020 [Member] | 2023 and thereafter [Member] | |
Debt Instrument [Line Items] | |
Price | 100.00% |
Senior Unsecured 5 7/8% Notes due April 15,, 2021 [Member] | 2021 [Member] | |
Debt Instrument [Line Items] | |
Price | 104.406% |
Senior Unsecured 5 7/8% Notes due April 15,, 2021 [Member] | 2022 [Member] | |
Debt Instrument [Line Items] | |
Price | 102.938% |
Senior Unsecured 5 7/8% Notes due April 15,, 2021 [Member] | 2023 [Member] | |
Debt Instrument [Line Items] | |
Price | 101.469% |
Senior Unsecured 5 7/8% Notes due April 15,, 2021 [Member] | 2024 and thereafter [Member] | |
Debt Instrument [Line Items] | |
Price | 100.00% |
Senior Unsecured 5 3/8% Notes due February 1, 2022 [Member] | 2022 [Member] | |
Debt Instrument [Line Items] | |
Price | 102.688% |
Senior Unsecured 5 3/8% Notes due February 1, 2022 [Member] | 2023 [Member] | |
Debt Instrument [Line Items] | |
Price | 101.792% |
Senior Unsecured 5 3/8% Notes due February 1, 2022 [Member] | 2024 [Member] | |
Debt Instrument [Line Items] | |
Price | 100.896% |
Senior Unsecured 5 3/8% Notes due February 1, 2022 [Member] | 2025 and thereafter [Member] | |
Debt Instrument [Line Items] | |
Price | 100.00% |
Senior Unsecured 5% Notes due January 15, 2023 [Member] | 2023 [Member] | |
Debt Instrument [Line Items] | |
Price | 102.50% |
Senior Unsecured 5% Notes due January 15, 2023 [Member] | 2024 [Member] | |
Debt Instrument [Line Items] | |
Price | 101.667% |
Senior Unsecured 5% Notes due January 15, 2023 [Member] | 2025 [Member] | |
Debt Instrument [Line Items] | |
Price | 100.833% |
Senior Unsecured 5% Notes due January 15, 2023 [Member] | 2026 and thereafter [Member] | |
Debt Instrument [Line Items] | |
Price | 100.00% |
Senior Unsecured TPL 4 3/4% Notes due May 15, 2017 [Member] | 2018 [Member] | |
Debt Instrument [Line Items] | |
Price | 101.188% |
Senior Unsecured TPL 4 3/4% Notes due May 15, 2017 [Member] | 2019 and thereafter [Member] | |
Debt Instrument [Line Items] | |
Price | 100.00% |
Senior Unsecured TPL 5 7/8% Notes due February 1, 2018 [Member] | 2018 [Member] | |
Debt Instrument [Line Items] | |
Price | 102.938% |
Senior Unsecured TPL 5 7/8% Notes due February 1, 2018 [Member] | 2019 [Member] | |
Debt Instrument [Line Items] | |
Price | 101.958% |
Senior Unsecured TPL 5 7/8% Notes due February 1, 2018 [Member] | 2020 [Member] | |
Debt Instrument [Line Items] | |
Price | 100.979% |
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 Uns_2
Debt Obligations - Senior Unsecured Notes Issuances (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Jan. 31, 2019 | Apr. 30, 2018 | Oct. 31, 2017 | Oct. 31, 2016 | Dec. 31, 2018 | |
Senior Notes [Member] | 5 1/8% Senior Notes due February 2025 [Member] | Partnership Issuers | |||||
Debt Instrument [Line Items] | |||||
Senior notes issued | $ 500 | ||||
Interest rate on fixed rate debt | 5.125% | ||||
Maturity date | Feb. 28, 2025 | ||||
Net proceeds from senior notes | $ 496.2 | ||||
Senior Notes [Member] | 5 3/8% Senior notes due February 2027 [Member] | Partnership Issuers | |||||
Debt Instrument [Line Items] | |||||
Senior notes issued | $ 500 | ||||
Interest rate on fixed rate debt | 5.375% | ||||
Maturity date | Feb. 28, 2027 | ||||
Net proceeds from senior notes | $ 496.2 | ||||
Senior Unsecured Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on fixed rate debt | 4.125% | ||||
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2028 [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior notes issued | $ 750 | ||||
Interest rate on fixed rate debt | 5.00% | 5.00% | |||
Maturity date | Jan. 31, 2028 | Jan. 31, 2028 | |||
Net proceeds from senior notes | $ 744.1 | ||||
Senior Unsecured Notes [Member] | Senior Unsecured 5⅞% Notes due April 2026 [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior notes issued | $ 1,000 | ||||
Interest rate on fixed rate debt | 5.875% | 5.875% | |||
Maturity date | Apr. 30, 2026 | Apr. 30, 2026 | |||
Net proceeds from senior notes | $ 991.9 | ||||
Senior Unsecured Notes [Member] | 6 1/2% Senior Notes due July 2027 [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior notes issued | $ 750 | ||||
Interest rate on fixed rate debt | 6.50% | ||||
Maturity date | Jul. 31, 2027 | ||||
Net proceeds from senior notes | $ 744.4 | ||||
Senior Unsecured Notes [Member] | 6 7/8% Senior Notes due January 2029 [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Senior notes issued | $ 750 | ||||
Interest rate on fixed rate debt | 6.875% | ||||
Maturity date | Jan. 31, 2029 | ||||
Net proceeds from senior notes | $ 744.4 |
Debt Obligations - Debt Repurch
Debt Obligations - Debt Repurchases and Extinguishments (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Jun. 30, 2017 | Dec. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Oct. 31, 2017 | Nov. 15, 2016 | |
Debt Instrument [Line Items] | |||||||
Face amount of notes redeemed | $ 559.2 | $ 559.2 | $ 146.2 | ||||
Gain (loss) from financing activities | $ (1.3) | $ (10.9) | (48.2) | ||||
Premium Paid | $ 4.9 | ||||||
Write off debt issuance cost | $ 3.5 | ||||||
Senior Unsecured 5% Notes due January 2018 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate on fixed rate debt | 5.00% | ||||||
Write off debt issuance cost | $ 0.2 | ||||||
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate on fixed rate debt | 6.375% | ||||||
Maturity date | Aug. 31, 2022 | ||||||
Face amount of notes redeemed | $ 278.7 | ||||||
Redemption price, percentage of face value | 103.188% | ||||||
Gain (loss) from financing activities | $ (10.7) | ||||||
Premium Paid | 8.9 | ||||||
Write off debt issuance cost | $ 1.8 |
Debt Obligations - Summary of D
Debt Obligations - Summary of Debt Repurchased on Open Market Portion of Outstanding Senior Notes (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Nov. 15, 2016 | |
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | $ 559.2 | $ 146.2 |
Debt Repurchase, Payment | (534.3) | |
Gain/(Loss) on Debt Repurchase | 24.9 | |
Debt Repurchase, Write-off of Debt Issuance Costs | (3.5) | |
Net Gain (Loss) on Debt Repurchase | 21.4 | |
5¼% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 24.1 | |
Debt Repurchase, Payment | (20.1) | |
Gain/(Loss) on Debt Repurchase | 4 | |
Debt Repurchase, Write-off of Debt Issuance Costs | (0.2) | |
Net Gain (Loss) on Debt Repurchase | 3.8 | |
4¼% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 39.5 | |
Debt Repurchase, Payment | (31.8) | |
Gain/(Loss) on Debt Repurchase | 7.7 | |
Debt Repurchase, Write-off of Debt Issuance Costs | (0.3) | |
Net Gain (Loss) on Debt Repurchase | 7.4 | |
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 | |
6⅝% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 32.6 | |
Debt Repurchase, Payment | (29.5) | |
Gain/(Loss) on Debt Repurchase | 3.1 | |
Net Gain (Loss) on Debt Repurchase | 3.1 | |
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
Debt Obligations - Issuance of Senior Notes and Concurrent Senior Notes Tender Offers (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Oct. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Oct. 31, 2017 | Oct. 05, 2016 | Sep. 30, 2016 | |
Debt Instrument [Line Items] | |||||||
Loss on extinguishment of debt | $ 9.7 | ||||||
Premium Paid | 4.9 | ||||||
Write off debt issuance cost | $ 3.5 | ||||||
Write off debt discounts | 4.2 | ||||||
Write off of debt premiums | 0.5 | ||||||
Senior Unsecured 5% Notes due January 2018 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate on fixed rate debt | 5.00% | ||||||
Write off debt issuance cost | $ 0.2 | ||||||
Concurrent Senior Notes with Offers Tender [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Tender offers principal amount | 383.8 | 383.8 | $ 1,000 | $ 1,522.1 | |||
Loss on extinguishment of debt | 59.2 | ||||||
Premium Paid | 41.8 | ||||||
Write off debt issuance cost | 5.8 | ||||||
Write off debt discounts | 15.1 | ||||||
Write off of debt premiums | 3.5 | ||||||
Concurrent Senior Notes with Offers Tender [Member] | Senior Unsecured 5% Notes due January 2018 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate on fixed rate debt | 5.00% | ||||||
Tender offers principal amount | 250.5 | 250.5 | 733.6 | ||||
Premium Paid | 16.9 | ||||||
Concurrent Senior Notes with Offers Tender [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate on fixed rate debt | 6.625% | ||||||
Maturity date | Oct. 31, 2020 | ||||||
Tender offers principal amount | 28.2 | 28.2 | 309.9 | ||||
Premium Paid | 10.5 | ||||||
Concurrent Senior Notes with Offers Tender [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate on fixed rate debt | 6.875% | ||||||
Maturity date | Feb. 28, 2021 | ||||||
Tender offers principal amount | 105.1 | $ 105.1 | $ 478.6 | ||||
Premium Paid | $ 14.4 |
Debt Obligations - Senior Notes
Debt Obligations - Senior Notes Tender Offers (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Debt Instrument [Line Items] | |||||
Premium Paid | $ 4.9 | ||||
Accrued Interest Paid | [1] | $ 203.2 | $ 198.7 | $ 263.8 | |
Concurrent Senior Notes with Offers Tender [Member] | |||||
Debt Instrument [Line Items] | |||||
Outstanding Note Balance Prior to Tender Offers | 1,522.1 | 383.8 | |||
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 6 7/8% Notes due February 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Outstanding Note Balance Prior to Tender Offers | 478.6 | 105.1 | |||
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 | |||
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 | 250.5 | |||
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 | $ 28.2 | |||
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 | |||
[1] | Interest capitalized on major projects was $46.3 million, $14.3 million and $8.3 million for the years ended December 31, 2018, 2017 and 2016. |
Debt Obligations - Note Redempt
Debt Obligations - Note Redemptions (Details) - USD ($) $ in Millions | Nov. 15, 2016 | Oct. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||||
Face amount of notes redeemed | $ 146.2 | $ 559.2 | $ 559.2 | |
Debt instrument redemption payment | $ 151.1 | |||
Loss on extinguishment of debt | 9.7 | |||
Write off debt issuance cost | $ 3.5 | |||
Premium Paid | 4.9 | |||
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 - Debt Repur_2
Debt Obligations - Debt Repurchases and Extinguishments Summary (Details) - USD ($) $ in Millions | 1 Months Ended | 10 Months Ended | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Debt Instrument [Line Items] | |||||
Loss (gain) on repurchase of debt | $ (1.3) | $ (10.9) | $ (48.2) | ||
Senior Unsecured Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Write-off of debt issuance costs | $ 0.9 | 1.3 | |||
Loss (gain) from financing activities | 48.2 | $ 10.9 | $ 1.3 | ||
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 | 0.2 | |||
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) | ||||
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] | 6⅜% Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Premium over face value paid upon redemption | 8.9 | ||||
Loss (gain) on repurchase of debt | (2.6) | ||||
Write-off of debt issuance costs | 0.2 | $ 1.8 | |||
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] | 5¼% Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Loss (gain) on repurchase of debt | (4) | ||||
Write-off of debt issuance costs | 0.2 | ||||
Senior Unsecured Notes [Member] | 4¼% Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Loss (gain) on repurchase of debt | (7.7) | ||||
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 - S
Other Long-term Liabilities - Schedule of Other Long-term Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Other Liabilities Noncurrent [Line Items] | |||
Asset retirement obligations | $ 55 | $ 50.3 | $ 64.1 |
Mandatorily redeemable preferred interests | 76.2 | ||
Deferred revenue | 175.5 | 136.2 | $ 69.8 |
Other liabilities | 3.3 | 3.1 | |
Total long-term liabilities | $ 233.8 | 576 | |
Permian Acquisition [Member] | |||
Other Liabilities Noncurrent [Line Items] | |||
Permian Acquisition contingent consideration, noncurrent portion | $ 310.2 |
Other Long-term Liabilities - C
Other Long-term Liabilities - Changes in Aggregate Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning of period | $ 50.3 | $ 64.1 | |
Additions | 0.8 | ||
Reduction due to sale of VGS | (21.6) | ||
Change in cash flow estimate | 1.8 | 3.1 | $ (9.1) |
Accretion expense | 3.7 | 3.9 | 4.6 |
Retirement of ARO | (0.8) | ||
End of period | $ 55 | $ 50.3 | $ 64.1 |
Other Long-term Liabilities - M
Other Long-term Liabilities - Mandatorily Redeemable Preferred Interests (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($)JointVenture | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Interest expense, net | $ (170) | $ (217.8) | $ (233.5) |
Beginning of period | 76.2 | ||
Increase (decrease) in redemption value of mandatorily redeemable preferred interests | (72.1) | 3.3 | (15.2) |
End of period | 76.2 | ||
Mandatorily Redeemable Preferred Interests [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Interest expense, net | 9.7 | 10.3 | 10.5 |
Beginning of period | 76.2 | 68.5 | |
Income attributable to mandatorily redeemable preferred interests | (4.1) | 4.4 | |
Increase (decrease) in redemption value of mandatorily redeemable preferred interests | (72.1) | 3.3 | |
End of period | $ 0 | $ 76.2 | $ 68.5 |
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 - A
Other Long-term Liabilities - Additional Information (Details) | 10 Months Ended | 12 Months Ended | ||||
Dec. 31, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Mar. 02, 2017USD ($) | Dec. 27, 2015bbl | |
Deferred Revenue [Abstract] | ||||||
Deferred revenue | $ 136,200,000 | $ 175,500,000 | $ 136,200,000 | $ 69,800,000 | ||
Channelview Splitter estimated total cost | 8,238,200,000 | 6,906,100,000 | 4,922,900,000 | |||
Revenue recognized | 3,900,000 | 3,100,000 | 3,100,000 | |||
Increase (decrease) in fair value of contingent consideration liability | (8,800,000) | (99,600,000) | (400,000) | |||
Permian Acquisition [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Preliminary acquisition date fair value of the contingent consideration | 416,300,000 | 416,300,000 | ||||
Increase (decrease) in fair value of contingent consideration liability | (99,300,000) | (8,800,000) | ||||
Additional cash that may be paid based on potential earn-out payment | 317,000,000 | 308,200,000 | 317,000,000 | $ 416,300,000 | ||
Contingent consideration current liability | 6,800,000 | 308,200,000 | 6,800,000 | |||
Permian Acquisition [Member] | Other Long-term Liabilities [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Preliminary acquisition date fair value of the contingent consideration | 416,300,000 | |||||
Permian Acquisition [Member] | Accounts Payable and Accrued Liabilities [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Increase (decrease) in fair value of contingent consideration liability | 8,800,000 | |||||
Fair value of first potential earn-out payment | 0 | |||||
Fair value of second potential earn-out payment | 308,200,000 | |||||
Channelview Splitter [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Storage capacity of Channelview Terminal | bbl | 730,000 | |||||
Channelview Splitter capability to split crude oil and condensate barrel per day | bbl | 35,000 | |||||
Deferred revenue | 86,000,000 | 129,000,000 | 86,000,000 | |||
Channelview Splitter estimated total cost | 160,000,000 | |||||
Channelview Splitter [Member] | First Annual Payment [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Deferred revenue | $ 43,000,000 | |||||
Channelview Splitter [Member] | Second Annual Payment [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Deferred revenue | $ 43,000,000 | $ 43,000,000 | ||||
Channelview Splitter [Member] | Third Annual Payment [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Deferred revenue | $ 43,000,000 |
Other Long-term Liabilities -_2
Other Long-term Liabilities - Components Of Deferred Revenue (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | $ 175.5 | $ 136.2 | $ 69.8 |
Other Deferred Revenue [Member] | |||
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | 4.3 | 5.5 | |
Gas Contract Amendment [Member] | |||
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | 42.2 | 44.7 | |
Channelview Splitter [Member] | |||
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | $ 129 | $ 86 |
Other Long-term Liabilities -_3
Other Long-term Liabilities - Changes In Deferred Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Other Liabilities Noncurrent [Abstract] | |||
Beginning of period | $ 136.2 | $ 69.8 | |
Additions | 43.2 | 69.5 | |
Revenue recognized | (3.9) | (3.1) | $ (3.1) |
End of period | $ 175.5 | $ 136.2 | $ 69.8 |
Other Long-term Liabilities -_4
Other Long-term Liabilities - Schedule of Changes in the Fair Value of Permian Acquisition Contingent Consideration (Details) - USD ($) $ in Millions | 10 Months Ended | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Business Acquisition Contingent Consideration [Line Items] | ||||
Decrease in fair value, included in Other income (expense) | $ (8.8) | $ (99.6) | $ (0.4) | |
Permian Acquisition [Member] | ||||
Business Acquisition Contingent Consideration [Line Items] | ||||
Beginning of period | $ 416.3 | 317 | ||
Decrease in fair value, included in Other income (expense) | (99.3) | (8.8) | ||
End of period | 317 | 308.2 | 317 | |
Less: Current portion | (6.8) | $ (308.2) | (6.8) | |
Long-term balance at end of period | $ 310.2 | $ 310.2 |
Partnership Units and Related_3
Partnership Units and Related Matters (Details) $ / shares in Units, $ in Millions | Feb. 17, 2016shares | Feb. 28, 2019USD ($)$ / shares | Jan. 31, 2019USD ($)$ / shares | Dec. 31, 2016USD ($) | Oct. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2018USD ($)$ / sharesshares | Dec. 31, 2017USD ($)shares | Dec. 31, 2016USD ($) |
Limited Partners Capital Account [Line Items] | ||||||||
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 | |||||||
Common limited partners units issued (in units) | 275,168,410 | 275,168,410 | ||||||
General partner units issued (in units) | 5,629,136 | 5,629,136 | ||||||
Contributions from Targa Resources Corp. | $ | $ 600.1 | $ 1,720 | $ 1,381 | |||||
Distribution to holders of preferred units | $ | $ 11.3 | $ 11.3 | 11.3 | |||||
Scenario Forecast [Member] | ||||||||
Distributions declared and/or paid by the Partnership [Abstract] | ||||||||
Distributions to Targa Resources Corp. | $ | $ 0.9 | |||||||
Cash distribution to be paid | Mar. 15, 2019 | |||||||
Subsequent Event [Member] | ||||||||
Distributions declared and/or paid by the Partnership [Abstract] | ||||||||
Distributions to Targa Resources Corp. | $ | $ 0.9 | |||||||
Cash distribution to be paid | Feb. 15, 2019 | |||||||
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 | ||||||
Series A preferred limited partners units issued (in units) | 5,000,000 | 5,000,000 | ||||||
Preferred units dividend percentage | 9.00% | |||||||
Series A Preferred Units [Member] | April 2013 Shelf [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 | |||||||
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 | |||||||
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% | |||||||
Targa Resources Parrtners LP [Member] | ||||||||
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 | |||||||
Preferred Unit [Member] | Scenario Forecast [Member] | ||||||||
Distributions declared and/or paid by the Partnership [Abstract] | ||||||||
Date of declaration for cash distribution | 2019-02 | |||||||
Cash distribution declared per unit (in dollars per share) | $ / shares | $ 0.1875 | |||||||
Preferred Unit [Member] | Subsequent Event [Member] | ||||||||
Distributions declared and/or paid by the Partnership [Abstract] | ||||||||
Date of declaration for cash distribution | 2019-01 | |||||||
Cash distribution declared per unit (in dollars per share) | $ / shares | $ 0.1875 | |||||||
TRC/TRP Merger | ||||||||
Limited Partners Capital Account [Line Items] | ||||||||
Common limited partners units issued (in units) | 58,621,036 | |||||||
General partner units issued (in units) | 1,196,346 | |||||||
Contributions from Targa Resources Corp. | $ | $ 1,191 | |||||||
TRC/TRP Merger | Limited Partners [Member] | ||||||||
Limited Partners Capital Account [Line Items] | ||||||||
Percentage of capital contribution towards partner's interest maintained | 98.00% | |||||||
TRC/TRP Merger | Targa Resources GP LLC [Member] | ||||||||
Limited Partners Capital Account [Line Items] | ||||||||
Percentage of general partner's interest maintained | 2.00% | |||||||
TRC/TRP Merger | Targa Resources Corp [Member] | ||||||||
Limited Partners Capital Account [Line Items] | ||||||||
Contributions from Targa Resources Corp. | $ | $ 190 | $ 600 | $ 1,720 | $ 1,381 |
Partnership Units and Related_4
Partnership Units and Related Matters - Distributions (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||
Dec. 31, 2018USD ($)shares | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($)shares | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2018USD ($)shares | Dec. 31, 2017USD ($)shares | Dec. 31, 2016USD ($) | Dec. 31, 2015Distribution | Dec. 01, 2016shares | |
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||
Date Paid Or to Be Paid | Feb. 13, 2019 | Nov. 13, 2018 | Aug. 13, 2018 | May 11, 2018 | Feb. 12, 2018 | Nov. 10, 2017 | Aug. 10, 2017 | May 11, 2017 | Feb. 10, 2017 | Nov. 11, 2016 | Aug. 11, 2016 | May 12, 2016 | |||||
Total Distributions | $ | $ 929,800 | $ 858,600 | $ 737,300 | ||||||||||||||
Limited Partner unit in exchange for the elimination of the IDRs and Special GP Interest | 275,168,410 | 275,168,410 | 275,168,410 | 275,168,410 | |||||||||||||
General Partner unit in exchange for the elimination of the IDRs and Special GP Interest | 5,629,136 | 5,629,136 | 5,629,136 | 5,629,136 | |||||||||||||
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 | 20,380,286 | ||||||||||||||||
General Partner unit in exchange for the elimination of the IDRs and Special GP Interest | 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 | 11,267,485 | ||||||||||||||||
General Partner unit in exchange for the elimination of the IDRs and Special GP Interest | 234,739 | ||||||||||||||||
Atlas Pipeline Partners [Member] | |||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||
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 | $ | $ 241,300 | $ 237,600 | $ 234,000 | $ 229,700 | $ 228,500 | $ 225,400 | $ 225,400 | $ 209,600 | $ 198,100 | 194,700 | 181,700 | 157,600 | |||||
Distributions to Targa Resources Corp. | $ | $ 238,500 | $ 234,800 | $ 231,200 | $ 226,900 | $ 225,700 | $ 222,600 | $ 222,600 | $ 206,800 | $ 195,300 | $ 191,900 | $ 178,900 | $ 154,800 |
Derivative Instruments and He_3
Derivative Instruments and Hedging Activities - Notional Volumes Of The Partnership's Commodity Derivative Contracts (Details) | 12 Months Ended |
Dec. 31, 2018MMBTUbbl | |
Year 2020 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 1,980 |
Year 2020 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 63,630 |
Year 2020 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 13,267 |
Year 2020 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 105,417 |
Year 2020 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 3,115 |
Year 2020 [Member] | Options [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2020 [Member] | Options [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2021 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 994 |
Year 2021 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 35,755 |
Year 2021 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 3,676 |
Year 2021 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 91,658 |
Year 2021 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2021 [Member] | Options [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2021 [Member] | Options [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2022 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2022 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 |
Year 2022 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2022 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 75,000 |
Year 2022 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2022 [Member] | Options [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2022 [Member] | Options [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2023 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2023 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 |
Year 2023 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2023 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 20,000 |
Year 2023 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2023 [Member] | Options [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2023 [Member] | Options [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2019 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 3,413 |
Year 2019 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 171,102 |
Year 2019 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 17,929 |
Year 2019 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 113,295 |
Year 2019 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 8,975 |
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] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 410 |
Derivative Instruments and He_4
Derivative Instruments and Hedging Activities - Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets | $ 149.4 | $ 61.1 |
Derivative assets | 115.3 | 37.9 |
Derivative assets | 34.1 | 23.2 |
Derivative liabilities | 36.7 | 99.3 |
Derivative liabilities | 33.6 | 79.7 |
Derivative liabilities | 3.1 | 19.6 |
Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 144.1 | 61.1 |
Derivative liabilities | 20.4 | 97.3 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 112.5 | 37.9 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 31.6 | 23.2 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 18.9 | 78.6 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Position [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 1.5 | 18.7 |
Not Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 5.3 | 0 |
Derivative liabilities | 16.3 | 2 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 2.8 | 0 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 2.5 | 0 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 14.7 | 1.1 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Position [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | $ 1.6 | $ 0.9 |
Derivative Instruments and He_5
Derivative Instruments and Hedging Activities - Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative Asset [Abstract] | ||
Gross asset | $ 149.4 | $ 61.1 |
Pro forma net presentation, asset, total | 116.4 | 28.6 |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 108.9 | 61.1 |
Pro forma net presentation, asset | 75.9 | 28.6 |
Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 40.5 | |
Pro forma net presentation, asset | 40.5 | |
Current Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 115.3 | 37.9 |
Pro forma net presentation, asset, current | 85.3 | 13.8 |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 100 | 37.9 |
Pro forma net presentation, asset | 70 | 13.8 |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 15.3 | |
Pro forma net presentation, asset | 15.3 | |
Long-term Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 34.1 | 23.2 |
Pro forma net presentation, asset, noncurrent | 31.1 | 14.8 |
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 8.9 | 23.2 |
Pro forma net presentation, asset | 5.9 | $ 14.8 |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 25.2 | |
Pro forma net presentation, asset | $ 25.2 |
Derivative Instruments and He_6
Derivative Instruments and Hedging Activities - Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative Liability [Abstract] | ||
Gross liability | $ (36.7) | $ (99.3) |
Pro forma net presentation, liability, total | (17.9) | (43.9) |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (36.7) | (92) |
Pro forma net presentation, liability, total | (17.9) | (36.6) |
Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (7.3) | |
Pro forma net presentation, liability, total | (7.3) | |
Current Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (33.6) | (79.7) |
Pro forma net presentation, liability, current | (17.8) | (32.7) |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (33.6) | (74.7) |
Pro forma net presentation, liability, current | (17.8) | (27.7) |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (5) | |
Pro forma net presentation, liability, current | (5) | |
Long-term Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (3.1) | (19.6) |
Pro forma net presentation, liability, noncurrent | (0.1) | (11.2) |
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (3.1) | (17.3) |
Pro forma net presentation, liability, noncurrent | $ (0.1) | (8.9) |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (2.3) | |
Pro forma net presentation, liability, noncurrent | $ (2.3) |
Derivative Instruments and He_7
Derivative Instruments and Hedging Activities - Pro Forma Impact - Offsetting Collateral (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative Asset [Abstract] | ||
Gross collateral | $ (14.2) | $ 22.9 |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross collateral | (14.2) | 22.9 |
Current Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross collateral | (14.2) | 22.9 |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross collateral | $ (14.2) | $ 22.9 |
Derivative Instruments and He_8
Derivative Instruments and Hedging Activities - Additional Information (Details) $ in Millions | Dec. 31, 2018USD ($) |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Estimated fair value of derivative instruments, net asset | $ 112.7 |
Amount expected to reclassify commodity hedge related deferred gains to earnings before income taxes | 123.8 |
Amount of deferred gains to be reclassified into earnings before income taxes over next twelve months | $ 92.5 |
Derivative Instruments and He_9
Derivative Instruments and Hedging Activities - Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (Loss) Reclassified from OCI into Income (Effective Portion) | $ (38.4) | $ (44.6) | $ 45 |
Commodity Contracts [Member] | Revenues [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) recognized in income on derivatives | (32.5) | (5.1) | 0.9 |
Cash Flow Hedging [Member] | Commodity Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) | $ 132.5 | $ (28.8) | $ (103.6) |
Fair Value Measurements - Addit
Fair Value Measurements - Additional Information (Details) $ in Millions | Dec. 31, 2018USD ($)Swap |
Fair Value Disclosures [Abstract] | |
Derivatives financial instruments, fair value, net | $ 112.7 |
Derivative fair value of net asset if commodity price increases by 10 percent | 37.3 |
Derivative fair value of net asset if commodity price decreases by 10 percent | $ 188.7 |
Number of natural gas basis swaps categorized as Level 3 | Swap | 13 |
Fair Value Measurements - Break
Fair Value Measurements - Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 02, 2017 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Assets from commodity derivative contracts | $ 116.4 | $ 28.6 | ||
Liabilities from commodity derivative contracts | 17.9 | 43.9 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Accounts receivable securitization facility | [1] | 280 | 350 | |
Permian Acquisition [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Additional cash that may be paid based on potential earn-out payment | 308.2 | 317 | $ 416.3 | |
Carrying Value [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Assets from commodity derivative contracts | [2] | 144.4 | 60.3 | |
Liabilities from commodity derivative contracts | [2] | 31.7 | 98.5 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Cash and cash equivalents | 203.3 | 124.7 | ||
Accounts receivable securitization facility | 280 | 350 | ||
Carrying Value [Member] | Permian Acquisition [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Additional cash that may be paid based on potential earn-out payment | [3] | 308.2 | 317 | |
Carrying Value [Member] | TRP Revolver [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 700 | 20 | ||
Carrying Value [Member] | Targa Pipeline Partners LP [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Additional cash that may be paid based on potential earn-out payment | [4] | 2.4 | 2.4 | |
Carrying Value [Member] | Senior Unsecured Notes [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 5,277.9 | 4,278 | ||
Fair Value [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Assets from commodity derivative contracts | [2] | 144.4 | 60.3 | |
Liabilities from commodity derivative contracts | [2] | 31.7 | 98.5 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Cash and cash equivalents | 203.3 | 124.7 | ||
Accounts receivable securitization facility | 280 | 350 | ||
Fair Value [Member] | Permian Acquisition [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Additional cash that may be paid based on potential earn-out payment | [3] | 308.2 | 317 | |
Fair Value [Member] | TRP Revolver [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 700 | 20 | ||
Fair Value [Member] | Targa Pipeline Partners LP [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Additional cash that may be paid based on potential earn-out payment | [4] | 2.4 | 2.4 | |
Fair Value [Member] | Senior Unsecured Notes [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 5,088.9 | 4,362.4 | ||
Fair Value [Member] | Level 2 [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Assets from commodity derivative contracts | [2] | 137.5 | 58.8 | |
Liabilities from commodity derivative contracts | [2] | 31.3 | 93.3 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Accounts receivable securitization facility | 280 | 350 | ||
Fair Value [Member] | Level 2 [Member] | TRP Revolver [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 700 | 20 | ||
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 | 5,088.9 | 4,362.4 | ||
Fair Value [Member] | Level 3 [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Assets from commodity derivative contracts | [2] | 6.9 | 1.5 | |
Liabilities from commodity derivative contracts | [2] | 0.4 | 5.2 | |
Fair Value [Member] | Level 3 [Member] | Permian Acquisition [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Additional cash that may be paid based on potential earn-out payment | [3] | 308.2 | 317 | |
Fair Value [Member] | Level 3 [Member] | Targa Pipeline Partners LP [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Additional cash that may be paid based on potential earn-out payment | [4] | $ 2.4 | $ 2.4 | |
[1] | As of December 31, 2018, we had $340.0 million of qualifying receivables under our $400.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. | |||
[2] | 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. | |||
[3] | We have a contingent consideration liability related to the Permian Acquisition, which is carried at fair value. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures. | |||
[4] | 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. |
Fair Value Measurements - Chang
Fair Value Measurements - Changes in Fair Value of Financial Instruments Classified as Level 3 (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Contingent Liability [Member] | |
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |
Balance, beginning of period | $ (319.4) |
New Level 3 derivative instruments | 0 |
Settlements included in Revenue | 0 |
Unrealized gain/(loss) included in OCI | 0 |
Balance, end of period | (310.6) |
Permian Acquisition [Member] | Contingent Liability [Member] | |
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |
Change in fair value of contingent consideration | 8.8 |
Commodity Derivative Contracts Asset/(Liability) [Member] | |
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |
Balance, beginning of period | (3.8) |
New Level 3 derivative instruments | (1.4) |
Settlements included in Revenue | 2.8 |
Unrealized gain/(loss) included in OCI | 8.9 |
Balance, end of period | $ 6.5 |
Related Party Transactions - Su
Related Party Transactions - Summary of Transactions with Unconsolidated Affiliates (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Related Party Transaction [Line Items] | |||
Revenues | $ 5.6 | $ 2.4 | $ 5.6 |
Product purchases | (14.1) | (5.5) | (5.8) |
Operating expenses | (3.6) | (3.8) | (4) |
Gulf Coast Fractionators LP [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues | 0.3 | 0.3 | 0.4 |
Product purchases | (5.1) | (4.4) | (3.2) |
T2 Joint Ventures [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues | 5.2 | 2.1 | 5.2 |
Product purchases | (0.6) | (1.1) | (2.6) |
Operating expenses | (3.6) | $ (3.8) | $ (4) |
Cayenne [Member] | |||
Related Party Transaction [Line Items] | |||
Product purchases | (7.2) | ||
GCX [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues | 0.1 | ||
Product purchases | $ (1.2) |
Related Party Transactions - _2
Related Party Transactions - Summary of Transactions with Affiliates (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Summary of transactions with Targa [Abstract] | ||||
Cash distributions to Targa based on general partner and limited partner ownership | $ 929.8 | $ 858.6 | $ 737.3 | |
Cash contributions from Targa related to limited partner ownership | 588.1 | 1,685.5 | 1,353.4 | |
Targa Resources Corp. [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Targa billings of payroll and related costs included in operating expenses | 236.8 | 204.4 | 171.8 | |
Targa allocation of general and administrative expense | 221.4 | 175.2 | 159.9 | |
Cash distributions to Targa based on general partner and limited partner ownership | [1] | 918.5 | 847.3 | 587 |
Cash contributions from Targa related to limited partner ownership | [2] | 588.1 | 1,685.5 | 1,353.4 |
Contributions from Targa Resources Corp | $ 12 | $ 34.5 | $ 27.6 | |
Percentage of general partner's interest maintained | 2.00% | |||
[1] | Prior to the execution of the Third A&R Partnership Agreement, 2016 cash distributions to Targa also included IDRs. | |||
[2] | The 2016 cash contributions from Targa related to limited partner ownership was contributed for the issuance of common units. The 2018 and 2017 cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to the general partner. See Note 12 – Partnership Units and Related Matters. |
Related Party Transactions - _3
Related Party Transactions - Summary of Transactions with Affiliates (Parenthetical) (Details) - Targa Resources Corp. [Member] | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Related Party Transaction [Line Items] | ||
Percentage of general partner's interest maintained | 2.00% | |
Limited Partners [Member] | ||
Related Party Transaction [Line Items] | ||
Percentage of capital contribution towards partner's interest maintained | 98.00% | 98.00% |
Targa Resources GP LLC [Member] | ||
Related Party Transaction [Line Items] | ||
Percentage of general partner's interest maintained | 2.00% | 2.00% |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Details) - USD ($) $ in Millions | 1 Months Ended | ||||||
Mar. 31, 2018 | Apr. 30, 2018 | Feb. 28, 2018 | Jan. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2010 | |
Warburg Funds Transaction [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Percentage of ownership interest aquired | 82.00% | ||||||
Cash payments related to acquisition | $ 5 | ||||||
SAJET Resources LLC [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Amount charged to related parties for service | $ 0.3 | $ 0.5 | |||||
Extinguishment of debt in exchange for promissory note | $ 9.9 | ||||||
Minority shareholders interest sold | 1.60% | ||||||
Minority shareholders interest amount | $ 0.1 | ||||||
SAJET Resources LLC [Member] | Maximum [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Amount charged to related parties for service | $ 0.1 | $ 0.1 | |||||
Ownership interest | 100.00% | ||||||
SAJET Resources LLC [Member] | Current and Former Executives, Managers and Directors [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Collective own interest rate | 18.00% |
Commitments (Details)
Commitments (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Future non-cancelable commitments for each of the next five fiscal years and in Aggregate Thereafter [Abstract] | ||||
In Aggregate | $ 195.7 | |||
2,019 | 24.5 | |||
2,020 | 21.3 | |||
2,021 | 18.6 | |||
2,022 | 16.8 | |||
2,023 | 10 | |||
Thereafter | 104.5 | |||
Total expenses on non-cancelable commitments | 58 | $ 51.4 | $ 49.5 | |
Operating Leases [Member] | ||||
Future non-cancelable commitments for each of the next five fiscal years and in Aggregate Thereafter [Abstract] | ||||
In Aggregate | [1] | 73.4 | ||
2,019 | [1] | 20.5 | ||
2,020 | [1] | 17.7 | ||
2,021 | [1] | 14.9 | ||
2,022 | [1] | 12.6 | ||
2,023 | [1] | 6 | ||
Thereafter | [1] | 1.7 | ||
Total expenses on non-cancelable commitments | [2] | 51.9 | 46.2 | 45.1 |
Land Site Lease and Rights of-Way [Member] | ||||
Future non-cancelable commitments for each of the next five fiscal years and in Aggregate Thereafter [Abstract] | ||||
In Aggregate | [3] | 122.3 | ||
2,019 | [3] | 4 | ||
2,020 | [3] | 3.6 | ||
2,021 | [3] | 3.7 | ||
2,022 | [3] | 4.2 | ||
2,023 | [3] | 4 | ||
Thereafter | [3] | 102.8 | ||
Total expenses on non-cancelable commitments | $ 6.1 | $ 5.2 | $ 4.4 | |
[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 rights 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 - Additional Info
Contingencies - Additional Information (Details) - Environment Proceeding [Member] - USD ($) | Feb. 26, 2019 | Dec. 28, 2018 |
Supplemental Environmental Projects [Member] | ||
Loss Contingencies [Line Items] | ||
Contingencies penalty amount | $ 150,000 | |
Compliance Improvements [Member] | Subsequent Event [Member] | ||
Loss Contingencies [Line Items] | ||
Contingencies penalty amount | $ 220,000 |
Significant Risks and Uncerta_2
Significant Risks and Uncertainties (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Concentration Risk [Line Items] | |||
Reduction of maximum loss due to counterparty credit risk by master netting provision | $ 36,700,000 | ||
Allowance for doubtful accounts | $ 100,000 | $ 100,000 | |
Sales Revenue, Net [Member] | Petredec (Europe) Limited [Member] | Customer Concentration Risk [Member] | |||
Concentration Risk [Line Items] | |||
Percentage of consolidated revenues | 15.00% | ||
Concentration risk, percentage | 10.00% | 10.00% | |
Minimum [Member] | |||
Concentration Risk [Line Items] | |||
Potential loss attributable to individual counterparties | $ 300,000 | ||
Maximum [Member] | |||
Concentration Risk [Line Items] | |||
Potential loss attributable to individual counterparties | $ 28,000,000 |
Revenue - Estimated Minimum Rev
Revenue - Estimated Minimum Revenue Expected to be Recognized in Future Related to Unsatisfied Performance Obligations (Details) - Fixed Price Contract [Member] $ in Millions | Dec. 31, 2018USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-01-01 | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Fixed consideration to be recognized | $ 496.5 |
Estimated remaining duration of contracts | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01 | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Fixed consideration to be recognized | $ 450.8 |
Estimated remaining duration of contracts | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2021-01-01 | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Fixed consideration to be recognized | $ 2,126.9 |
Estimated remaining duration of contracts |
Revenue - Additional Informatio
Revenue - Additional Information (Details) - Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-01-01 | Dec. 31, 2018 |
Minimum [Member] | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Estimated remaining duration of contracts | 1 year |
Maximum [Member] | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Estimated remaining duration of contracts | 15 years |
Other Operating (Income) Expe_3
Other Operating (Income) Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Other Income And Expenses [Abstract] | |||
(Gain) loss on sale or disposal of assets | $ (0.1) | $ 15.9 | $ 6.1 |
Miscellaneous business tax | 3.2 | 0.8 | 0.5 |
Other | 0.4 | 0.7 | |
Total other operating (income) expense | $ 3.5 | $ 17.4 | $ 6.6 |
Other Operating (Income) Expe_4
Other Operating (Income) Expense - Summary of (Gain) Loss on Sale or Disposal of Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Other Operating Income Expense [Line Items] | |||
Total (gain) loss on sale or disposal of assets | $ (0.1) | $ 15.9 | $ 6.1 |
Inland Marine Barge Business [Member] | |||
Other Operating Income Expense [Line Items] | |||
Total (gain) loss on sale or disposal of assets | (48.1) | ||
Versado Gathering System [Member] | |||
Other Operating Income Expense [Line Items] | |||
Total (gain) loss on sale or disposal of assets | (44.4) | ||
Storage and Terminaling Facilities [Member] | |||
Other Operating Income Expense [Line Items] | |||
Total (gain) loss on sale or disposal of assets | 59.1 | ||
Benzene Treating Unit [Member] | |||
Other Operating Income Expense [Line Items] | |||
Total (gain) loss on sale or disposal of assets | 20.5 | ||
Venice Gathering System, L.L.C. [Member] | |||
Other Operating Income Expense [Line Items] | |||
Total (gain) loss on sale or disposal of assets | 16.1 | ||
Other [Member] | |||
Other Operating Income Expense [Line Items] | |||
Total (gain) loss on sale or disposal of assets | $ 12.8 | $ (0.2) | $ 6.1 |
Income Tax - Summary of Income
Income Tax - Summary of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income tax (expense) benefit: | |||
Current expense (benefit) | $ 0 | $ (4.5) | $ 0 |
Deferred expense (benefit) | (0.1) | (2.9) | (0.3) |
Total income tax expense (benefit) | $ (0.1) | $ (7.4) | $ (0.3) |
Income Tax - Additional Informa
Income Tax - Additional Information (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Operating Loss Carryforwards [Line Items] | ||
Federal statutory income tax rate, percent | 21.00% | 35.00% |
Reclassification of alternative minimum tax credits from deferred tax assets to long term assets | $ 300,000 | |
Provisional deferred tax benefit | $ 1,000,000 | |
Provisional tax depreciation expense | 700,000 | |
Additional capital expenditure | $ 0 | |
Texas margin tax rate | 0.75% | |
TPL Arkoma, Inc. [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Tax cuts and jobs act of 2017 change in tax rate income tax expense (benefit) | $ (1,000,000) | |
Net operating loss carryforwards | $ 50,300,000 | |
Maximum [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Tax effects measurement period under tax act | 1 year | |
Maximum [Member] | TPL Arkoma, Inc. [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Operating loss carryforwards expiry date | Dec. 31, 2038 | |
Minimum [Member] | TPL Arkoma, Inc. [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Operating loss carryforwards expiry date | Dec. 31, 2029 |
Income Tax - Deferred Tax Asset
Income Tax - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred tax assets [Abstract] | ||
Net operating loss carryforwards | $ 12.9 | $ 13.7 |
Deferred tax liabilities [Abstract] | ||
Property, plant, and equipment | (36.8) | (37.7) |
Net deferred tax asset (liability) | $ (23.9) | $ (24) |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Cash [Abstract] | ||||
Interest paid, net of capitalized interest | [1] | $ 203.2 | $ 198.7 | $ 263.8 |
Income taxes paid, net of refunds | 0.2 | (4.9) | 1.3 | |
Non-cash investing activities [Abstract] | ||||
Deadstock commodity inventory transferred to property, plant and equipment | 49 | 9 | 17.4 | |
Impact of capital expenditure accruals on property, plant and equipment | 216.9 | 205.4 | 27.6 | |
Transfers from materials and supplies inventory to property, plant and equipment | 12.7 | 3.6 | 2.4 | |
Contribution of property, plant and equipment to investments in unconsolidated affiliates | 16 | 1 | ||
Change in ARO liability and property, plant and equipment due to revised cash flow estimate | 1.8 | 3.1 | (9.1) | |
Property, plant and equipment received in asset exchange | 24.1 | |||
Receivable for asset exchange | 15 | |||
Asset received related to conveyance of ownership interest in investment in unconsolidated affiliate | 3 | |||
Non-cash financing activities [Abstract] | ||||
Cancellation of treasury units | 10.4 | |||
Accrued distributions on unvested equity awards under share compensation arrangements | 0.2 | |||
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 - Acquisitions and Divestitures) [Abstract] | ||||
Common limited partner units | 0 | 63.7 | ||
General partner units | 1.3 | |||
Noncontrolling interests | 0 | $ (65) | ||
Non-cash balance sheet movements related to acquisition of related party: | ||||
Noncontrolling interest | $ 1.1 | |||
Permian Acquisition [Member] | ||||
Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): | ||||
Contingent consideration recorded at the acquisition date | $ 416.3 | |||
[1] | Interest capitalized on major projects was $46.3 million, $14.3 million and $8.3 million for the years ended December 31, 2018, 2017 and 2016. |
Supplemental Cash Flow Inform_4
Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |||
Interest capitalized on major projects | $ 46.3 | $ 14.3 | $ 8.3 |
Compensation Plans - TRC Equity
Compensation Plans - TRC Equity Compensation Plan (Details) - shares | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2016 | |
Replacement Phantom Units [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Dividend payment period | 60 days | |
Replacement Phantom Units [Member] | Vesting Term One [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting period of awards | 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 awards | 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] | 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] | Minimum [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting period of awards | 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 awards | 5 years |
Compensation Plans - Partnershi
Compensation Plans - Partnership Director Grants (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Fair value of units vested | $ 18.8 | $ 14.4 | $ 17.1 |
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 | ||
Fair value of units vested | $ 0.3 |
Compensation Plans - Impact of
Compensation Plans - Impact of TRC/TRP Merger (Details) $ / shares in Units, $ in Millions | Feb. 17, 2016USD ($)Employeeshares | Dec. 31, 2018shares | Dec. 31, 2017shares | Dec. 31, 2016$ / sharesshares |
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 | |||
Partnership Long-term Incentive Plan [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Number of employee affected by amendment | Employee | 363 | |||
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) | 0 | 0 | 331,282 | |
Vesting period of awards | 3 years | |||
Weighted average grant date fair value, Granted (in dollars per share) | $ / shares | $ 74.01 | |||
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, 2018$ / sharesshares | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | shares | 497,947 |
Forfeited (in shares) | shares | (4,956) |
Vested (in shares) | shares | (191,300) |
Outstanding, end of period (in shares) | shares | 301,691 |
Weighted-average grant-date fair value [Roll Forward] | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 40.54 |
Forfeited (in dollars per share) | $ / shares | 32.86 |
Vested (in dollars per share) | $ / shares | 61.94 |
Outstanding, end of period (in dollars per share) | $ / shares | $ 27.10 |
Compensation Plans - TRC Long T
Compensation Plans - TRC Long Term Incentive Plan (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Feb. 17, 2016 | |
Cash-Settled Performance Units [Member] | |||||
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award [Table] | |||||
Compensation costs | $ 4.8 | ||||
Cash-settled awards vested | 112,550 | ||||
Cash settled for awards | $ 6.9 | ||||
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 | $ 6.9 | $ 4.1 | $ 4.8 | ||
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 - 2010 TRC S
Compensation Plans - 2010 TRC Stock Incentive Plan (Details) - USD ($) $ / shares in Units, $ in Millions | Jan. 01, 2018 | Jan. 31, 2019 | Oct. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2019 | May 31, 2017 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Stock compensation expense | $ 59 | $ 44.2 | $ 41.2 | |||||
Unrecognized compensation expense | $ 109.4 | |||||||
Weighted average recognition period for unrecognized compensation cost | 2 years 7 months 6 days | |||||||
Fair value of units vested | $ 18.8 | 14.4 | 17.1 | |||||
Cash dividends paid for vested awards | $ 3.5 | $ 2.5 | $ 2.7 | |||||
Performance Units [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Expected volatility, minimum | 29.00% | 55.00% | ||||||
Expected volatility, maximum | 53.00% | 61.00% | ||||||
2010 TRC Stock Incentive Plan [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Total units authorized (in shares) | 15,000,000 | |||||||
Total units available (in shares) | 5,000,000 | |||||||
Total additional units available (in shares) | 10,000,000 | |||||||
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) | 25,344 | |||||||
Vesting date of awards | 2020-01 | |||||||
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) | 0 | 0 | 32,267 | |||||
Granted (in dollars per shares) | $ 41.43 | |||||||
2010 TRC Stock Incentive Plan [Member] | Director Grants [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Vesting period of awards | 1 year | |||||||
Granted (in shares) | 16,955 | 13,818 | 24,234 | |||||
Granted (in dollars per shares) | $ 51.21 | $ 60.48 | $ 16.45 | |||||
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) | 1,393,812 | 1,193,942 | 1,129,705 | |||||
Granted (in dollars per shares) | $ 51.71 | $ 54.18 | $ 27.87 | |||||
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] | Restricted Stock Units (RSUs) [Member] | Executive Management [Member] | 2019 [Member] | Stock Awards Vesting, Tranche Three [Member] | Subsequent Event [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Granted (in shares) | 269,530 | |||||||
Vesting date of awards | 2022-01 | |||||||
2010 TRC Stock Incentive Plan [Member] | RSUs Under New Retention Program [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Vesting period of awards | 4 years | |||||||
Granted (in shares) | 275,076 | |||||||
2010 TRC Stock Incentive Plan [Member] | RSUs Under New Retention Program [Member] | Subsequent Event [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Granted (in shares) | 20,316 | |||||||
Vesting date of awards | 2022-10 | |||||||
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) | 112,438 | 84,221 | 153,252 | |||||
Granted (in dollars per shares) | $ 51.09 | $ 55.94 | $ 26.34 | |||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock in Lieu of Bonus [Member] | Executive Management [Member] | 2019 [Member] | Subsequent Event [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Granted (in shares) | 95,687 | |||||||
Vesting date of awards | 2022-01 | |||||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Granted (in shares) | 182,849 | |||||||
Granted (in dollars per shares) | $ 81.02 | |||||||
Expected term of grant date fair value | 3 years | |||||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [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] | 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] | 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] | 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] | 2017 [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Granted (in shares) | 182,849 | 113,901 | ||||||
Vesting date of awards | Dec. 31, 2020 | Dec. 31, 2019 | ||||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | Minimum [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] | ||||||||
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] | Performance Units [Member] | Executive Management [Member] | 2019 [Member] | Subsequent Event [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Granted (in shares) | 261,245 | |||||||
Vesting date of awards | 2021-12 | |||||||
2010 TRC Stock Incentive Plan [Member] | Equity-Settled Performance Units [Member] | 2017 [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Vesting period of awards | 3 years | |||||||
2010 TRC Stock Incentive Plan [Member] | Cash Settled Restricted Stock Units [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Vesting period of awards | 1 year | |||||||
Granted (in shares) | 69,042 | 69,042 | ||||||
Unrecognized compensation expense | $ 1,214,137 | |||||||
2010 TRC Stock Incentive Plan [Member] | Cash Settled Restricted Stock Units [Member] | Subsequent Event [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Granted (in shares) | 3,842 | |||||||
2010 TRC Stock Incentive Plan [Member] | Cash Settled Restricted Stock Units [Member] | Scenario Forecast [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Vested awards settlement amount | $ 0.6 | |||||||
2010 TRC Stock Incentive Plan [Member] | Cash Settled Restricted Stock Units [Member] | Stock Awards Vesting, Tranche One [Member] | Subsequent Event [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Award vesting percentage | 33.00% | |||||||
Vesting date of awards | 2019-03 | |||||||
2010 TRC Stock Incentive Plan [Member] | Cash Settled Restricted Stock Units [Member] | Stock Awards Vesting, Tranche Two [Member] | Subsequent Event [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Award vesting percentage | 33.00% | |||||||
Vesting date of awards | 2019-06 | |||||||
2010 TRC Stock Incentive Plan [Member] | Cash Settled Restricted Stock Units [Member] | Stock Awards Vesting, Tranche Three [Member] | Subsequent Event [Member] | ||||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||||
Award vesting percentage | 34.00% | |||||||
Vesting date of awards | 2019-09 |
Compensation Plans - Restrict_2
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, 2018$ / sharesshares | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | shares | 2,428,798 |
Granted (in shares) | shares | 1,410,767 |
Forfeited (in shares) | shares | (52,449) |
Vested (in shares) | shares | (192,981) |
Outstanding, end of period (in shares) | shares | 3,594,135 |
Weighted-average grant-date fair value [Roll Forward] | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 43.78 |
Granted (in dollars per shares) | $ / shares | 51.70 |
Forfeited (in dollars per share) | $ / shares | 47.26 |
Vested (in dollars per share) | $ / shares | 72.28 |
Outstanding, end of period (in dollars per share) | $ / shares | $ 45.31 |
Compensation Plans - PSUs under
Compensation Plans - PSUs under 2010 TRC Plan (Details) - 2010 TRC Stock Incentive Plan [Member] - Performance Units [Member] | 12 Months Ended |
Dec. 31, 2018$ / sharesshares | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | shares | 113,901 |
Granted (in shares) | shares | 182,849 |
Outstanding, end of period (in shares) | shares | 296,750 |
Weighted-average grant-date fair value [Roll Forward] | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 99.71 |
Granted (in dollars per shares) | $ / shares | 81.02 |
Outstanding, end of period (in dollars per share) | $ / shares | $ 88.19 |
Compensation Plans - 2010 TRC C
Compensation Plans - 2010 TRC Cash-Settled Restricted Stock Units (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended |
Oct. 31, 2018 | Dec. 31, 2018 | |
Nonvested, number of shares [Roll Forward] | ||
To be recognized in future periods | $ 109.4 | |
Cash Settled Restricted Stock Units [Member] | 2010 TRC Stock Incentive Plan [Member] | ||
Nonvested, number of shares [Roll Forward] | ||
Outstanding, beginning of period (in shares) | ||
Granted (in shares) | 69,042 | 69,042 |
Vested and paid (in shares) | (16,872) | |
Forfeited (in shares) | (1,942) | |
Outstanding, end of period (in shares) | 50,228 | |
Calculated fair market value as of period end | $ 2,546,445 | |
Current liability | 1,332,308 | |
Liability as of year end | 1,332,308 | |
To be recognized in future periods | $ 1,214,137 |
Segment Information - Additiona
Segment Information - Additional Information (Details) | 12 Months Ended |
Dec. 31, 2018Segment | |
Segment Reporting [Abstract] | |
Number of reportable segments | 2 |
Segment Information - Revenues
Segment Information - Revenues and Operating Margin (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues [Abstract] | |||||||||||
Revenues | $ 2,597.6 | $ 2,986.4 | $ 2,444.4 | $ 2,455.6 | $ 2,702.8 | $ 2,131.8 | $ 1,867.7 | $ 2,112.6 | $ 10,484 | $ 8,814.9 | $ 6,690.9 |
Operating margin | 1,523.8 | 1,286 | 1,214.4 | ||||||||
Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 9,278.7 | 7,751.1 | 5,626.8 | ||||||||
Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 1,205.3 | 1,063.8 | 1,064.1 | ||||||||
Gathering and Processing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 5,616.2 | 4,508.8 | 3,240.7 | ||||||||
Operating margin | 968.4 | 783.8 | 577.1 | ||||||||
Logistics and Marketing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 8,896 | 7,826.7 | 5,794.5 | ||||||||
Operating margin | 592.5 | 511.8 | 574.4 | ||||||||
Other [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (37.1) | (9.6) | 62.9 | ||||||||
Operating margin | (37.1) | (9.6) | 62.9 | ||||||||
Corporate and Elimination [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (3,991.1) | (3,511) | (2,407.2) | ||||||||
Operating Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 10,484 | 8,814.9 | 6,690.9 | ||||||||
Operating Segments [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 9,278.7 | 7,751.1 | 5,626.8 | ||||||||
Operating Segments [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 1,205.3 | 1,063.8 | 1,064.1 | ||||||||
Operating Segments [Member] | Gathering and Processing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 1,973 | 1,347.7 | 1,108.5 | ||||||||
Operating Segments [Member] | Gathering and Processing [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 1,257.4 | 781.4 | 621.9 | ||||||||
Operating Segments [Member] | Gathering and Processing [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 715.6 | 566.3 | 486.6 | ||||||||
Operating Segments [Member] | Logistics and Marketing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 8,548.1 | 7,476.8 | 5,519.5 | ||||||||
Operating Segments [Member] | Logistics and Marketing [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 8,058.4 | 6,979.3 | 4,942 | ||||||||
Operating Segments [Member] | Logistics and Marketing [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 489.7 | 497.5 | 577.5 | ||||||||
Operating Segments [Member] | Other [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (37.1) | (9.6) | 62.9 | ||||||||
Operating Segments [Member] | Other [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (37.1) | (9.6) | 62.9 | ||||||||
Intersegment Eliminations [Member] | Gathering and Processing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 3,643.2 | 3,161.1 | 2,132.2 | ||||||||
Intersegment Eliminations [Member] | Gathering and Processing [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 3,636 | 3,154.2 | 2,124.4 | ||||||||
Intersegment Eliminations [Member] | Gathering and Processing [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 7.2 | 6.9 | 7.8 | ||||||||
Intersegment Eliminations [Member] | Logistics and Marketing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 347.9 | 349.9 | 275 | ||||||||
Intersegment Eliminations [Member] | Logistics and Marketing [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 317.1 | 321.9 | 251.5 | ||||||||
Intersegment Eliminations [Member] | Logistics and Marketing [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 30.8 | 28 | 23.5 | ||||||||
Intersegment Eliminations [Member] | Corporate and Elimination [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (3,991.1) | (3,511) | (2,407.2) | ||||||||
Intersegment Eliminations [Member] | Corporate and Elimination [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (3,953.1) | (3,476.1) | (2,375.9) | ||||||||
Intersegment Eliminations [Member] | Corporate and Elimination [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | $ (38) | $ (34.9) | $ (31.3) |
Segment Information - Other Fin
Segment Information - Other Financial Information (Details) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Mar. 01, 2017 | Dec. 31, 2015 | ||
Other financial information [Abstract] | ||||||
Total assets | $ 16,890.1 | $ 14,359 | ||||
Goodwill | 46.6 | 256.6 | $ 210 | $ 46.6 | $ 417 | |
Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 16,890.1 | 14,359 | 12,744.9 | ||
Goodwill | 46.6 | 256.6 | 210 | |||
Capital expenditures | 3,327.7 | 1,506.5 | 592.1 | |||
Business acquisition | 987.1 | |||||
Gathering and Processing [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 11,478.8 | 10,732.3 | 9,800.6 | ||
Goodwill | 46.6 | 256.6 | 210 | |||
Capital expenditures | 1,548.6 | 1,008.9 | 402.5 | |||
Business acquisition | 987.1 | |||||
Logistics and Marketing [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 5,180.6 | 3,507.4 | 2,868.7 | ||
Capital expenditures | 1,767 | 470.4 | 185.3 | |||
Other [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 127.1 | 56.8 | 21.8 | ||
Corporate and Elimination [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 103.6 | 62.5 | 53.8 | ||
Capital expenditures | $ 12.1 | $ 27.2 | $ 4.3 | |||
[1] | Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. |
Segment Information - Revenue_2
Segment Information - Revenues by Product and Service (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | ||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | $ 9,350.9 | $ 7,800.8 | $ 5,586.7 | |||||||||
Non-customer revenue | (72.2) | (49.7) | 40.1 | |||||||||
Total revenues | $ 2,597.6 | $ 2,986.4 | $ 2,444.4 | $ 2,455.6 | $ 2,702.8 | $ 2,131.8 | $ 1,867.7 | $ 2,112.6 | 10,484 | 8,814.9 | 6,690.9 | |
Designated as Hedging Instrument [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Non-customer revenue | (39.7) | (44.7) | 39.1 | |||||||||
Not Designated as Hedging Instrument [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Non-customer revenue | [1] | (32.5) | (5) | 1 | ||||||||
Natural Gas [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 1,810 | 2,005.9 | 1,591.2 | |||||||||
NGL [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 6,886.9 | 5,454.2 | 3,793.4 | |||||||||
Condensate [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 457.9 | 196 | 133.9 | |||||||||
Petroleum Products [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 196.1 | 144.7 | 68.2 | |||||||||
Sales of Commodities [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Total revenues | 9,278.7 | 7,751.1 | 5,626.8 | |||||||||
Fractionating and Treating [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Total revenues | 120.7 | 132.8 | 126.2 | |||||||||
Storage, Terminaling, Transportation and Export [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Total revenues | 349.9 | 342.2 | 420 | |||||||||
Gathering and Processing [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Total revenues | 698.1 | 523.3 | 445 | |||||||||
Other [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Total revenues | 36.6 | 65.5 | 72.9 | |||||||||
Fees from Midstream Services [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Total revenues | $ 1,205.3 | $ 1,063.8 | $ 1,064.1 | |||||||||
[1] | Represents derivative activities that are not designated as hedging instruments under ASC 815. |
Segment Information - Reconcili
Segment Information - Reconciliation of Operating Margin to Net Income (Loss) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2018 | Sep. 30, 2017 | Dec. 31, 2016 | Mar. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | |||||||
Operating margin | $ 1,523.8 | $ 1,286 | $ 1,214.4 | ||||
Depreciation and amortization expenses | (815.9) | (809.5) | (757.7) | ||||
General and administrative expenses | (240.8) | (190.5) | (177.1) | ||||
Impairment of property, plant and equipment | $ (210) | $ (378) | 0 | (378) | 0 | ||
Impairment of goodwill | $ (210) | $ (183) | $ (24) | (210) | 0 | (207) | |
Interest expense, net | (170) | (217.8) | (233.5) | ||||
Change in contingent considerations | 8.8 | 99.6 | 0.4 | ||||
Other, net | 2.6 | (47.8) | (68.5) | ||||
Income (loss) before income taxes | 98.5 | (258) | (229) | ||||
Gathering and Processing [Member] | |||||||
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | |||||||
Operating margin | 968.4 | 783.8 | 577.1 | ||||
Logistics and Marketing [Member] | |||||||
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | |||||||
Operating margin | 592.5 | 511.8 | 574.4 | ||||
Other [Member] | |||||||
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | |||||||
Operating margin | $ (37.1) | $ (9.6) | $ 62.9 |
Selected Quarterly Financial _3
Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |||||||||||
Selected Quarterly Financial Information [Abstract] | |||||||||||||||||||||
Revenues | $ 2,597.6 | $ 2,986.4 | $ 2,444.4 | $ 2,455.6 | $ 2,702.8 | $ 2,131.8 | $ 1,867.7 | $ 2,112.6 | $ 10,484 | $ 8,814.9 | $ 6,690.9 | ||||||||||
Gross margin | 589.2 | 602.9 | 539.1 | 514.6 | 534.6 | 468.7 | 447.1 | 458.4 | 2,245.8 | 1,908.8 | |||||||||||
Income (loss) from operations | (76.6) | [1] | 80.6 | [1] | 159.2 | [1] | 90.4 | [1] | 116.5 | [2] | (320.3) | [2] | 40.7 | [2] | 53.7 | [2] | 253.6 | [1] | (109.4) | [2] | 66 |
Net income (loss) | (111.3) | (8.7) | 162.6 | 56 | 44.9 | (245) | (29.2) | (21.3) | 98.6 | (250.6) | (228.7) | ||||||||||
Net income (loss) attributable to common limited partners | $ (127.1) | $ (20.8) | $ 147.6 | $ 39.2 | $ 28.4 | $ (252.3) | $ (41.4) | $ (29.5) | $ 38.9 | $ (294.8) | $ (324.1) | ||||||||||
[1] | Includes a non-cash pre-tax impairment charge of $210.0 million in the fourth quarter of 2018. See Note 7 – Goodwill. | ||||||||||||||||||||
[2] | Includes a non-cash pre-tax impairment charge of $378.0 million in the third quarter of 2017. See Note 6 – Property, Plant and Equipment and Intangible Assets |
Selected Quarterly Financial _4
Selected Quarterly Financial Data (Unaudited) (Parenthetical) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2018 | Sep. 30, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Selected Quarterly Financial Information [Abstract] | |||||
Non-cash pre-tax impairment charges | $ 210 | $ 378 | $ 0 | $ 378 | $ 0 |