Document and Entity Information
Document and Entity Information - shares | 12 Months Ended | |
Dec. 31, 2019 | Feb. 17, 2020 | |
Cover [Abstract] | ||
Entity Registrant Name | TARGA RESOURCES PARTNERS LP | |
Trading Symbol | NGLS | |
Entity Central Index Key | 0001379661 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Preferred Units Outstanding | 5,000,000 | |
Document Fiscal Year Focus | 2019 | |
Document Fiscal Period Focus | FY | |
Document Type | 10-K | |
Amendment Flag | false | |
Document Period End Date | Dec. 31, 2019 | |
Entity Small Business | false | |
Entity Shell Company | false | |
Entity Emerging Growth Company | false | |
Entity Current Reporting Status | Yes | |
Entity Tax Identification Number | 65-1295427 | |
Entity File Number | 001-33303 | |
Entity Address, Address Line One | 811 Louisiana Street | |
Entity Address, Address Line Two | SuiteĀ 2100 | |
Entity Address, City or Town | Houston | |
Entity Address, State or Province | TX | |
Entity Address, Postal Zip Code | 77002 | |
City Area Code | 713 | |
Local Phone Number | 584-1000 | |
Entity Interactive Data Current | Yes | |
Title of 12(b) Security | 9.0% Series A Fixed-to-Floating Rate Cumulative RedeemablePerpetual Preferred Units | |
Security Exchange Name | NYSE | |
Entity Incorporation, State or Country Code | DE | |
Document Annual Report | true | |
Document Transition Report | false | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets: | ||
Cash and cash equivalents | $ 291.1 | $ 203.3 |
Trade receivables, net of allowances of $0.0 and $0.1 million at December 31, 2019 and December 31, 2018 | 855.2 | 864.4 |
Inventories | 161.5 | 164.7 |
Assets from risk management activities | 103.3 | 115.3 |
Other current assets | 54.2 | 32.2 |
Held for sale assets (see Note 4) | 137.7 | |
Total current assets | 1,603 | 1,379.9 |
Property, plant and equipment | 19,870.6 | 17,213.8 |
Accumulated depreciation and amortization | (5,321.6) | (4,285.5) |
Property, plant and equipment, net | 14,549 | 12,928.3 |
Intangible assets, net | 1,735 | 1,983.2 |
Goodwill, net | 45.2 | 46.6 |
Long-term assets from risk management activities | 35.5 | 34.1 |
Investments in unconsolidated affiliates | 738.7 | 490.5 |
Other long-term assets | 38.1 | 27.5 |
Total assets | 18,744.5 | 16,890.1 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 1,283.7 | 1,636.9 |
Accounts payable to Targa Resources Corp. | 193.8 | 187.4 |
Liabilities from risk management activities | 104.1 | 33.6 |
Current debt obligations | 382.2 | 1,027.9 |
Held for sale liabilities (see Note 4) | 6.4 | |
Total current liabilities | 1,970.2 | 2,885.8 |
Long-term debt | 7,005.2 | 5,197.4 |
Long-term liabilities from risk management activities | 40.8 | 3.1 |
Deferred income taxes, net | 23 | 23.9 |
Other long-term liabilities | 260 | 233.8 |
Contingencies (see Note 18) | ||
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, 2019 and December 31, 2018) | 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, 2019 and December 31, 2018) | 5,022.7 | 6,227.2 |
General partner (5,629,136 and 5,629,136 units issued and 5,629,136 and 5,629,136 outstanding as of December 31, 2019 and December 31, 2018) | 778 | 802.6 |
Accumulated other comprehensive income (loss) | 122.5 | 124.9 |
Partners' Capital | 6,043.8 | 7,275.3 |
Noncontrolling interests | 3,401.5 | 1,270.8 |
Total owners' equity | 9,445.3 | 8,546.1 |
Total liabilities and owners' equity | $ 18,744.5 | $ 16,890.1 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets: | ||
Trade receivables, allowances | $ 0 | $ 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 ($) | 12 Months Ended | ||||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |||
Revenues: | |||||
Total revenues | $ 8,671,100,000 | $ 10,484,000,000 | $ 8,814,900,000 | ||
Costs and expenses: | |||||
Product purchases | 6,118,500,000 | 8,238,200,000 | 6,906,100,000 | ||
Operating expenses | 792,800,000 | 722,000,000 | 622,800,000 | ||
Depreciation and amortization expense | 971,700,000 | 815,900,000 | 809,500,000 | ||
General and administrative expense | 267,500,000 | 240,800,000 | 190,500,000 | ||
Impairment of property, plant and equipment | 243,200,000 | 0 | 378,000,000 | ||
Impairment of goodwill | 0 | 210,000,000 | 0 | ||
Other operating (income) expense | 71,300,000 | 3,500,000 | 17,400,000 | ||
Income (loss) from operations | 206,100,000 | [1] | 253,600,000 | [2] | (109,400,000) |
Other income (expense): | |||||
Interest expense, net | (320,800,000) | (170,000,000) | (217,800,000) | ||
Equity earnings (loss) | 39,000,000 | 7,300,000 | (17,000,000) | ||
Gain (loss) from financing activities | (1,400,000) | (1,300,000) | (10,900,000) | ||
Gain (loss) from sale of equity-method investment | 69,300,000 | 0 | 0 | ||
Change in contingent considerations | (8,700,000) | 8,800,000 | 99,600,000 | ||
Other, net | 0 | 100,000 | (2,500,000) | ||
Income (loss) before income taxes | (16,500,000) | 98,500,000 | (258,000,000) | ||
Income tax (expense) benefit | 900,000 | 100,000 | 7,400,000 | ||
Net income (loss) | (15,600,000) | 98,600,000 | (250,600,000) | ||
Less: Net income (loss) attributable to noncontrolling interests | 239,100,000 | 47,600,000 | 38,900,000 | ||
Net income (loss) attributable to Targa Resources Partners LP | (254,700,000) | 51,000,000 | (289,500,000) | ||
Net income attributable to preferred limited partners | 11,300,000 | 11,300,000 | 11,300,000 | ||
Net income (loss) attributable to general partner | (5,300,000) | 800,000 | (6,000,000) | ||
Net income (loss) attributable to common limited partners | (260,700,000) | 38,900,000 | (294,800,000) | ||
Net income (loss) attributable to Targa Resources Partners LP | (254,700,000) | 51,000,000 | (289,500,000) | ||
Sales of Commodities [Member] | |||||
Revenues: | |||||
Total revenues | 7,393,800,000 | 9,278,700,000 | 7,751,100,000 | ||
Fees from Midstream Services [Member] | |||||
Revenues: | |||||
Total revenues | $ 1,277,300,000 | $ 1,205,300,000 | $ 1,063,800,000 | ||
[1] | Includes | ||||
[2] | Includes |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Net income (loss) | $ (15.6) | $ 98.6 | $ (250.6) |
Other comprehensive income (loss): | |||
Other comprehensive income (loss) | (2.4) | 170.9 | 15.8 |
Comprehensive income (loss) | (18) | 269.5 | (234.8) |
Less: Comprehensive income (loss) attributable to noncontrolling interests | 239.1 | 47.6 | 38.9 |
Comprehensive income (loss) attributable to Targa Resources Partners LP | (257.1) | 221.9 | (273.7) |
Commodity Contracts [Member] | |||
Other comprehensive income (loss): | |||
Change in fair value | 135.6 | 132.5 | (28.8) |
Settlements reclassified to revenues | $ (138) | $ 38.4 | $ 44.6 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY - USD ($) shares in Thousands, $ in Millions | Total | Limited Partner Preferred [Member] | Limited Partners Common [Member] | General Partner Units [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Non-controlling Interests [Member] |
Balance at Dec. 31, 2016 | $ 7,150.6 | $ 120.6 | $ 5,939.9 | $ 796.7 | $ (61.8) | $ 355.2 |
Balance (in units) at Dec. 31, 2016 | 5,000 | 275,168 | 5,629 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Contributions from Targa Resources Corp. | 1,720 | $ 0 | $ 1,685.5 | $ 34.5 | 0 | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 0 | |||
Purchase of noncontrolling interests in subsidiaries, net | (12.5) | $ 0 | $ 0 | $ 0 | 0 | (12.5) |
Distributions to noncontrolling interests | (48.1) | 0 | 0 | 0 | 0 | (48.1) |
Contributions from noncontrolling interests | 141.6 | 0 | 0 | 0 | 0 | 141.6 |
Other comprehensive income (loss) | 15.8 | 0 | 0 | 0 | 15.8 | 0 |
Net income (loss) | (250.6) | 11.3 | (294.8) | (6) | 0 | 38.9 |
Distributions | (858.6) | (11.3) | (830.3) | (17) | 0 | 0 |
Balance at Dec. 31, 2017 | 7,858.2 | $ 120.6 | $ 6,500.3 | $ 808.2 | (46) | 475.1 |
Balance (in units) at Dec. 31, 2017 | 5,000 | 275,168 | 5,629 | |||
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 | 1.1 | $ 0 | $ 0 | $ 0 | 0 | 1.1 |
Purchase of noncontrolling interests in subsidiaries, net | (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 | 275,168 | 5,629 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Contributions from Targa Resources Corp. | 200 | $ 0 | $ 196 | $ 4 | 0 | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 0 | |||
Sale of ownership interests in subsidiaries | 1,609 | $ 0 | $ (10.5) | $ (0.2) | 0 | 1,619.7 |
Distributions to noncontrolling interests | (283.4) | 0 | 0 | 0 | 0 | (283.4) |
Contributions from noncontrolling interests | 555.3 | 0 | 0 | 0 | 0 | 555.3 |
Other comprehensive income (loss) | (2.4) | 0 | 0 | 0 | (2.4) | 0 |
Net income (loss) | (15.6) | 11.3 | (260.7) | (5.3) | 0 | 239.1 |
Distributions | (1,163.7) | (11.3) | (1,129.3) | (23.1) | 0 | 0 |
Balance at Dec. 31, 2019 | $ 9,445.3 | $ 120.6 | $ 5,022.7 | $ 778 | $ 122.5 | $ 3,401.5 |
Balance (in units) at Dec. 31, 2019 | 5,000 | 275,168 | 5,629 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash flows from operating activities | |||
Net income (loss) | $ (15,600,000) | $ 98,600,000 | $ (250,600,000) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Amortization in interest expense | 9,200,000 | 9,100,000 | 9,300,000 |
Depreciation and amortization expense | 971,700,000 | 815,900,000 | 809,500,000 |
Impairment of property, plant and equipment | 243,200,000 | 0 | 378,000,000 |
Impairment of goodwill | 0 | 210,000,000 | 0 |
Accretion of asset retirement obligations | 4,700,000 | 3,700,000 | 3,900,000 |
Increase (decrease) in redemption value of mandatorily redeemable preferred interests | 0 | (72,100,000) | 3,300,000 |
Deferred income tax expense (benefit) | (900,000) | (100,000) | (2,900,000) |
Equity (earnings) loss of unconsolidated affiliates | (39,000,000) | (7,300,000) | 17,000,000 |
Distributions of earnings received from unconsolidated affiliates | 49,600,000 | 20,800,000 | 12,500,000 |
Risk management activities | 112,800,000 | 9,800,000 | 10,000,000 |
(Gain) loss on sale or disposition of business and assets | 71,100,000 | (100,000) | 15,900,000 |
(Gain) loss from financing activities | 1,400,000 | 1,300,000 | 10,900,000 |
(Gain) loss from sale of equity-method investment | (69,300,000) | 0 | 0 |
Change in contingent considerations | 8,700,000 | (8,800,000) | (99,600,000) |
Changes in operating assets and liabilities, net of business acquisitions: | |||
Receivables and other assets | (11,900,000) | (9,800,000) | (177,700,000) |
Inventories | (45,000,000) | (13,900,000) | (73,200,000) |
Accounts payable and other liabilities | 72,300,000 | 156,500,000 | 191,300,000 |
Net cash provided by operating activities | 1,363,000,000 | 1,213,600,000 | 857,600,000 |
Cash flows from investing activities | |||
Outlays for property, plant and equipment | (2,877,300,000) | (3,114,000,000) | (1,297,500,000) |
Outlays for business acquisition, net of cash acquired | 0 | 0 | (570,800,000) |
Proceeds from sale of business and assets | 14,800,000 | 256,900,000 | 2,700,000 |
Investments in unconsolidated affiliates | (266,800,000) | (282,000,000) | (9,500,000) |
Proceeds from sale of equity-method investment | 70,300,000 | 0 | 0 |
Return of capital from unconsolidated affiliates | 3,500,000 | 5,500,000 | 200,000 |
Other, net | (15,900,000) | (12,500,000) | (17,800,000) |
Net cash used in investing activities | (3,071,400,000) | (3,146,100,000) | (1,892,700,000) |
Debt obligations: | |||
Proceeds from borrowings under credit facility | 2,650,000,000 | 1,870,000,000 | 1,736,000,000 |
Repayments of credit facility | (3,350,000,000) | (1,190,000,000) | (1,866,000,000) |
Proceeds from borrowings under accounts receivable securitization facility | 944,200,000 | 546,600,000 | 666,600,000 |
Repayments of accounts receivable securitization facility | (854,200,000) | (616,600,000) | (591,600,000) |
Proceeds from issuance of senior notes | 2,500,000,000 | 1,000,000,000 | 750,000,000 |
Redemption of senior notes | (749,400,000) | 0 | (538,100,000) |
Principal payments of finance leases | (11,500,000) | 0 | 0 |
Costs incurred in connection with financing arrangements | (35,400,000) | (16,200,000) | (7,500,000) |
Payment of contingent consideration | (317,100,000) | 0 | 0 |
Purchase of noncontrolling interests in subsidiary | 0 | (100,000) | (12,500,000) |
Sale of ownership interests in subsidiaries | 1,619,700,000 | 0 | 0 |
Contributions from general partner | 4,000,000 | 12,000,000 | 34,500,000 |
Contributions from TRC | 196,000,000 | 588,100,000 | 1,685,500,000 |
Contributions from noncontrolling interests | 555,300,000 | 817,900,000 | 141,600,000 |
Distributions to noncontrolling interests | (191,700,000) | (70,800,000) | (48,100,000) |
Distributions to unitholders | (1,163,700,000) | (929,800,000) | (858,600,000) |
Net cash provided by financing activities | 1,796,200,000 | 2,011,100,000 | 1,091,800,000 |
Net change in cash and cash equivalents | 87,800,000 | 78,600,000 | 56,700,000 |
Cash and cash equivalents, beginning of period | 203,300,000 | 124,700,000 | 68,000,000 |
Cash and cash equivalents, end of period | $ 291,100,000 | $ 203,300,000 | $ 124,700,000 |
Organization and Operations
Organization and Operations | 12 Months Ended |
Dec. 31, 2019 | |
Limited Liability Company Or Limited Partnership Business Organization And Operations [Abstract] | |
Organization and Operations | Note 1 ā Organization and Operations Our Organization Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (āTargaā or āTRCā or the āCompanyā or āParentā). In this Annual Report, unless the context requires otherwise, references to āwe,ā āus,ā āour,ā āTRP,ā or the āPartnershipā are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. Our common units are wholly owned by TRC and no longer publicly traded as a result of TRCās acquisition of our outstanding common units that it and its subsidiaries did not already own in 2016. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the āPreferred Unitsā) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol āNGLS/PA.ā Our Operations We are primarily engaged in the business of: ā¢ gathering, compressing, treating, processing, transporting and selling natural gas; ā¢ transporting, storing, fractionating, treating and selling NGLs and NGL products, including services to LPG exporters; and ā¢ gathering, storing, terminaling and selling crude oil. See Note 25 ā 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 Targaās centralized general and administrative services. |
Basis of Presentation
Basis of Presentation | 12 Months Ended |
Dec. 31, 2019 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Basis of Presentation | Note 2 ā Basis of Presentation These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2019 and 2018, and the results of operations, comprehensive income, cash flows, and changes in ownersā equity for the years ended December 31, 2019, 2018 and 2017. 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, 2019 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | Note 3 ā Significant Accounting Policies Consolidation Policy Our consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain gas gathering and processing facilities in which we own an undivided interest and are responsible for our proportionate share of the costs and expenses of the facilities. Third party ownership interests in our controlled subsidiaries are presented 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. All intercompany balances and transactions have been eliminated in consolidation. We apply the equity method of accounting to investments over which we exercise significant influence over the operating and financial policies of our investee, but do not exercise control. 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 . among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative cost accruals, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets, (5) estimating contingencies, guarantees and indemnifications and (6) estimating redemption value of mandatorily redeemable preferred interests. Cash and Cash Cash and cash equivalents include all cash on hand, demand deposits, and short-term, highly liquid investments that are readily convertible into cash, and have original maturities of three months or less. 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 partyās ability and history of making required payments, economic events and other factors. We assess the need for adjustments to our allowance when the financial condition of any party changes or additional information becomes available. Inventories Our inventories consist primarily of NGL product inventories, which are valued at the lower of cost or net realizable value, using the average cost method. 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. Commodity inventories that are not physically or contractually available for sale under normal operations (ādeadstockā) are included in Property, Plant and Equipment. 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 our cash flows due to fluctuating energy commodity prices. 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. Cash flows from derivative instruments designated as hedges are recognized in the same financial statement line item as the cash flows from the respective item being hedged. 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 instrumentās 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 achieving the offset of changes in cash flows attributable to the hedged risk. We record all derivative instruments at fair value with the exception of those that we apply the normal purchases and normal sales election. The table below summarizes the accounting treatment for our derivative instruments, and the impact on our consolidated financial statements: Recognition and Measurement Derivative Treatment Balance Sheet Income Statement Normal Purchases and Normal Sales Fair value not recorded Earnings recognized when volumes are physically delivered or received Mark-to-Market Recorded at fair value Change in fair value recognized currently in earnings Cash Flow Hedge Recorded at fair value with changes in fair value deferred in Accumulated Other Comprehensive Income ("AOCI") The gain/loss on the derivative instrument is reclassified out of AOCI into earnings when the forecasted transaction occurs We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated, ceases to be highly effective or the forecasted transaction is no longer probable to occur. Property, Plant and Equipment Property, plant and equipment is recorded at acquisition cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including our expected use of the asset and the supply of and demand for hydrocarbons in the markets served, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations. Expenditures for routine maintenance and repairs are expensed as incurred. Expenditures to refurbish an asset that increases its existing service potential or prevents environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. Certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs, are capitalized. Impairment of Long-Lived Assets We evaluate long-lived assets for impairment when events or changes in circumstances indicate our carrying amount of an asset may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. 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 long-lived assets and the recognition of additional impairments. 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 subject to amortization but is tested for impairment at least annually. This test requires us to attribute goodwill to an appropriate reporting unit, which is an operating segment or one level below an operating segment (also known as a component). We evaluate goodwill for impairment on November 30 of each year, or whenever impairment indicators are present. 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. 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. As part of our goodwill impairment test, we may first assess qualitative factors to determine if the quantitative goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or 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). We recognize an impairment loss in our Consolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets for the amount by which the carrying amount exceeds the reporting unitās fair value. The goodwill impairment loss will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, when measuring goodwill, we consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit, if applicable. Intangible Assets Our intangible assets include 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. We amortize the costs of our assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis, where such pattern is not readily determinable, over the periods in which we benefit from services provided to customers. Asset Retirement Obligations Asset retirement obligations (āAROsā) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. We record a liability and increase the basis in the underlying asset for the present value of each expected asset retirement obligation (āAROā) when there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction. Our obligations are estimated based on discounted cash flow estimates. Over time, the ARO liability is accreted to its present value as a period cost and the capitalized amount is depreciated over the assetās respective useful life. At least annually, we review the projected timing and amount of asset retirement obligations and reflect revisions as an increase or decrease in the carrying amount of the liability and the basis in the underlying asset. Upon settlement, we will recognize any difference between the recorded amount and the actual settlement cost as a gain or loss. Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt and any original issue discount or premium are deferred and charged to interest expense over the term of the related debt. Debt issuance costs related to revolving credit facilities are presented as other long-term assets, and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction to the carrying amount of long-term debt on the Consolidated Balance Sheets. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issuance costs. Accounts Receivable Securitization Facility Proceeds from the sale or contribution of certain receivables under the accounts receivable securitization facility (the āSecuritization Facilityā) 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 We accrue a liability for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources, when the loss is probable and reasonably estimable. 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 Partnershipās 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 22 ā Income Tax for discussion of the Partnershipās federal and state income tax expense (benefits) of its taxable subsidiary as well as the Partnershipās net deferred income tax assets (liabilities). 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 (āOCIā), which includes changes in the fair value of derivative instruments that are designated as cash flow hedges. Revenue Recognition Our operating revenues are primarily derived from the following activities: ā¢ sales of natural gas, NGLs, condensate and crude oil; ā¢ services related to compressing, gathering, treating, and processing of natural gas; and ā¢ services related to NGL fractionation, terminaling and storage, transportation and treating. 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 quarterās 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 employeesā tax withholding obligations on vested awards. The withheld shares were recorded as treasury units at cost. Recent Accounting Pronouncements Recently adopted accounting pronouncements Leases In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update (āASUā) 2016-02, Leases (Topic 842). The amendments in this update supersede the leases guidance in Topic 840. We adopted Topic 842 on January 1, 2019 by applying the optional transition method in ASU 2018-11, which permits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The adoption of Topic 842 did not result in a cumulative effect adjustment to retained earnings on January 1, 2019. As part of the adoption of Topic 842, we recognized a net right-of-use asset of $64.2 million (net of $0.4 million of lease incentives/deferred rent) and lease liability of $64.6 million. Other practical expedients we elected include: ā¢ The package for transition relief, which among other things, allows us to carry forward our historical lease classification; ā¢ The land easements transition, which allows us to carry forward our historical accounting treatment for land easements prior to the effective date of the new leases standard, and evaluate only new or modified land easements on or after January 1, 2019 under Topic 842; ā¢ The short-term lease election, which allows us to elect not to record leases with an initial term of twelve months or less, for all asset classes; ā¢ The election to not separate non-lease components from lease components for all the asset classes in our current lease portfolio, where Targa is the lessee; and ā¢ The election to not separate non-lease components from lease components for gathering, processing and storage assets, where Targa is the lessor. Based on our election, we determined the non-lease component in certain of these arrangements is the predominant component and therefore account for the arrangements under ASC 606. We recognize the following for all leases (with the exception of short-term leases) at the commencement date: ā¢ A lease liability, which is a lesseeās obligation to make lease payments arising from a lease. ā¢ A right-of-use asset, which is an asset that represents the lesseeās right to use, or control the use of, a specified asset for the lease term. We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered short-term leases, which are excluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of future lease payments over the lease term. The right-of-use asset also includes any lease prepayments and excludes lease incentives. As most of the Companyās leases do not provide an implicit interest rate, we use our incremental borrowing rate as the discount rate to compute the present value of our lease liability. The discount rate applied is determined based on information available on the date of adoption for all leases existing as of that date, and on the date of lease commencement for all subsequent leases. Our lease arrangements may include variable lease payments based on an index or market rate, or may be based on performance. For variable lease payments based on an index or market rate, we estimate and apply a rate based on information available at the commencement date. Variable lease payments based on performance are excluded from the calculation of the right-of-use asset and lease liability, and are recognized in our Consolidated Statements of Operations when the contingency underlying such variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options are included in the measurement of our right-of-use asset and liability, provided we determine that we are reasonably certain to exercise the option. See Note 12 ā Leases for additional details. |
Joint Ventures, Acquisitions an
Joint Ventures, Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2019 | |
Business Combinations [Abstract] | |
Joint Ventures, Acquisitions and Divestitures | Note 4 ā Joint Ventures, Acquisitions and Divestitures Joint Ventures Grand Prix Joint Venture In May 2017, we announced plans to construct the Grand Prix pipeline (āGrand Prixā) , a new common carrier NGL pipeline Grand Prix transports NGLs from the Permian Basin, North Texas, and Southern Oklahoma to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas . In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the āGrand Prix Joint Ventureā), which owns the portion of Grand Prix extending from the Permian Basin to Mont Belvieu, Texas, Grand Prix Joint Venture is included in our Logistics and Transportation segment. Grand Prix is comprised of three primary segments: ā¢ Permian Basin Segment ā Connects our Gathering and Processing positions (as well as third-party positions) throughout the Delaware and Midland Basins to North Texas. ā¢ Southern Oklahoma Extension ā Connects our SouthOK and North Texas Gathering and Processing positions (as well as third-party positions) to our North Texas to Mont Belvieu Segment. ā¢ North Texas to Mont Belvieu Segment ā The Permian Basin Segment and Southern Oklahoma Extension connect to a 30-inch diameter pipeline segment in North Texas, which connects Permian, North Texas and Oklahoma volumes to Mont Belvieu. Grand Prix volumes flowing on the pipeline from the Permian Basin to Mont Belvieu are included in Grand Prix Joint Venture, while the volumes flowing from North Texas and Oklahoma to Mont Belvieu accrue solely to Targaās benefit. Cayenne In July 2017, we entered into the Cayenne Pipeline, LLC joint venture (āCayenne 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 (āEnterpriseā) pipeline at Toca, Louisiana, for delivery to Enterpriseās Norco Fractionator. We own a 50% interest in Cayenne. See Note 8 ā Investments in Unconsolidated Affiliates for activity related to Cayenne. Gulf Coast Express Joint Venture In December 2017, we entered into definitive joint venture agreements to form Gulf Coast Express Pipeline LLC (āGCXā) with Kinder Morgan Texas Pipeline LLC (āKMTPā) and DCP Midstream Partners, LP (āDCPā) for the purpose of developing the Gulf Coast Express Pipeline (āGCX Pipelineā), a natural gas pipeline from the Waha hub, including direct connections to the tailgate of many of our Midland Basin processing facilities, to Agua Dulce in South Texas. Targa GCX Pipeline LLC (ā GCX DevCo JVā) Infrastructure Partners (āStonepeakā) See Note 8 ā Investments in Unconsolidated Affiliates for activity related to GCX. Little Missouri 4 Joint Venture In January 2018, we formed a 50/50 joint venture in Little Missouri 4 LLC (āLittle Missouri 4ā) with Hess Midstream Partners LP to construct a new 200 natural gas processing plant (āLM4 Plantā) at Targaās existing Little Missouri facility. Little Missouri 4 began operations in the third quarter of 2019. Targa is the operator of the LM4 Plant. See Note 8 ā Investments in Unconsolidated Affiliates for activity related to Little Missouri 4. DevCo Joint Ventures In February 2018, we formed three development joint ventures (āDevCo JVsā) with investment vehicles affiliated with Stonepeak to fund portions of Grand Prix, GCX and an approximately 100 MBbl/d fractionator in Mont Belvieu, Texas (āTrain 6ā). 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 extensions into Southern Oklahoma and Central Oklahoma). Stonepeak owns an 80% interest in both DevCo JV , which owns our 25% interest in GCX, and Targa Train 6 LLC (āTrain 6 DevCo JVā), which owns a 100% interest in the fractionation train. The Train 6 DevCo JV does not include certain fractionation-related infrastructure such as brine and storage, which were funded and are owned 100% by us. We hold the remaining interests in the DevCo JVs as well as control the management 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 date that all three projects commenced commercial operations, we have the option to acquire all or part of Stonepeakās interests in the DevCo JVs. Targa may acquire up to 50% of Stonepeakās invested capital in multiple increments with a minimum of $100 million, and Stonepeakās 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 controls the management of the DevCo JVs unless and until Targa declines to exercise its option to acquire Stonepeak's interests. Train 6 began operations in the second quarter of 2019. Grand Prix began full service in the third quarter of 2019. X Pipeline was placed in service late in the third quarter of 2019. We . We continue to account for the Grand Prix Joint Venture on a consolidated basis in o an equity method investment as disclosed in Note 8 ā Investments in Unconsolidated Affiliates. 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 āCarnero Joint Ventureā). 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. 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 āNew Delawareā) and Outrigger Midland Operating, LLC (āNew Midlandā and together with New Delaware, the āPermian Acquisitionā). 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 āinitial purchase priceā). Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million could have been payable to the sellers of New Delaware and New Midland in potential earn-out payments. The first earn-out payment was due in May 2018 and expired with no required payment. The second earn-out payment was based on a multiple of realized gross margin through February 28,2019 and resulted in a $317.1 million final payment made in May 2019. The cash portion of the acquisition was funded primarily through the January 2017 public offering of 9,200,000 shares of common stock (including the shares sold pursuant to the underwritersā overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. Since March 1, 2017, financial and statistical data of New Delaware and New Midland have been included in Permian Delaware operations. The acquired businesses, which contributed revenues of $127.9 million and a net loss of $19.8 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 year ended December 31, 2017 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 Pro Forma Revenues $ 8,829.0 Net income (loss) (252.2 ) 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: ā¢ Reflect the amortization expense resulting from the fair value of intangible assets recognized as part of the Permian Acquisition. ā¢ Reflect the change in depreciation expense resulting from the difference between the historical balances of the Permian Acquisitionās property, plant and equipment, net, and the fair value of property, plant and equipment acquired. ā¢ 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. The initial fair value of the acquired New Delaware and New Midland assets included $570.8 million cash paid, net of $3.3 million cash acquired, and contingent consideration valued at $416.3 million as of the acquisition date. 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 and Contingent Consideration A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition was recognized at its fair value, which was based on inputs that are not observable in the market and therefore represent level 3 inputs (see Note 15 ā Fair Value Measurements). 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 was recorded within Other long-term liabilities on our Consolidated Balance Sheets. The final earn-out payment of $317.1 million was made in May 2019. As discussed in Note 15 ā Fair Value Measurements, 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 (āBoardwalkā) and all of the equity interests in FCPP Pipeline, LLC from Boardwalk Field Services, LLC (āBFSā) 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 āFlag City Acquisitionā), we acquired a natural gas processing plant with 150 MMcf/d of operating capacity (the āFlag City Plantā) 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, due to the redirection of the gas processing activities under the Flag City Plant contracts Flag City Plant was decommissioned and its assets were later contributed to Centrahoma Processing, LLC (āCentrahomaā), 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 (āMPLXā). In 2018, utilizing the Flag City Plant assets, Centrahoma constructed the Hickory Hills Plant in Hughes County, Oklahoma (the āHickory Hills Plantā). In October 2018, Targa also contributed the 120 MMcf/d cryogenic Tupelo Plant in Coal County, Oklahoma (the āTupelo Plantā) to Centrahoma. In conjunction with Targaās 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. Divestitures Sale of Venice Gathering System, L.L.C. Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (āVESCOā), 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. (āVGSā), 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 (āFERCā), for approximately $0.4 million in cash. Historically, VGS has been reported in our Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice Gas Plant through our ownership in VESCO. As a result of the sale, we recognized a loss of $16.1 million in our Consolidated Statements of Operations for the year ended December 31, 2017 as part of our Other operating (income) expense. 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 resulted in a loss of $57.5 million included within Other operating income (expense) in our Consolidated Statements of Operations. We used the proceeds to repay debt and to fund a portion of our growth capital program. The sale of these businesses is included in our Logistics and Transportation segment and 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. Sale of Interest in Train 7 In February 2019, we announced an extension of the Grand Prix from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with the Williams Companies, Inc. (āWilliamsā) 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 also exercised its option to acquire a 20% equity interest in Train 7 and subsequently executed a joint venture agreement with us in the second quarter of 2019. Certain fractionation-related infrastructure for Train 7, including storage caverns and brine handling, will be funded and owned 100% by Targa. We present Train 7 on a consolidated basis in our consolidated financial statements. Sale of Interest in Targa Badlands LLC On April 3, 2019, we closed on the sale of a 45% interest After the seventh anniversary We continue to be the operator of Targa Badlands and hold majority governance rights. As a result, we continue to present Targa Badlands on a consolidated basis in our consolidated financial Sale of Crude Gathering and Storage Facilities Assets and liabilities held for sale In November 2019, we executed agreements to sell our crude gathering and storage business in Permian Delaware for approximately $134 million. The sale closed on January 22, 2020 and we used the net proceeds to repay debt and to fund a portion of our growth capital program. The adjusted carrying amounts of the assets and liabilities held for sale are as follows: December 31, 2019 Current assets: Trade receivables $ 6.9 Intangible assets, net accumulated amortization and estimated loss on sale 52.1 Goodwill 1.4 Property, plant and equipment, net of accumulated depreciation and estimated loss on sale 77.3 Total assets held for sale $ 137.7 Current liabilities: Accounts payable and accrued liabilities $ 6.2 Other long-term obligations 0.2 Total liabilities held for sale $ 6.4 |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2019 | |
Inventory Disclosure [Abstract] | |
Inventories | Note 5 ā Inventories December 31, 2019 December 31, 2018 Commodities $ 156.5 $ 151.1 Materials and supplies 5.0 13.6 $ 161.5 $ 164.7 |
Property, Plant and Equipment a
Property, Plant and Equipment and Intangible Assets | 12 Months Ended |
Dec. 31, 2019 | |
Property Plant And Equipment And Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | Note 6 ā Property, Plant and Equipment and Intangible Assets Property, Plant and Equipment December 31, 2019 December 31, 2018 Estimated Useful Lives (In Years) Gathering systems $ 8,976.8 $ 7,547.9 5 to 20 Processing and fractionation facilities 5,137.0 4,001.0 5 to 25 Terminaling and storage facilities 1,495.5 1,138.7 5 to 25 Transportation assets 2,292.4 445.1 10 to 50 Other property, plant and equipment 183.9 334.3 3 to 25 Land 159.7 144.3 ā Construction in progress 1,576.5 3,602.5 ā Finance lease right-of-use assets 48.8 ā Property, plant and equipment 19,870.6 17,213.8 Accumulated depreciation and amortization (5,321.6 ) (4,285.5 ) Property, plant and equipment, net $ 14,549.0 $ 12,928.3 Intangible assets $ 2,643.5 $ 2,736.6 10 to 20 Accumulated amortization (908.5 ) (753.4 ) Intangible assets, net $ 1,735.0 $ 1,983.2 During the preparation of the Company's first quarter 2019 consolidated financial statements, the Company identified an error related to depreciation expense on certain assets that should have been placed in-service during 2018. The Company does not believe this error is material to its previously issued historical consolidated financial statements for any of the periods impacted and accordingly, has not adjusted the historical financial statements. The Company recorded the cumulative impact of the adjustment in the period of identification, resulting in a one-time $12.5 million overstatement of depreciation expense. For each of the years ended December 31, 2019, 2018 and 2017 depreciation expense was $800.1 million, $633.3 million and $621.3 million. Asset Impairments We have recorded non-cash pre-tax impairments during the years ended December 31, 2019 and 2017. The impairments were a result of our assessment that forecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net book value of the underlying assets. For each analysis, we measured the impairment of property, plant and equipment using discounted estimated future cash flows (āDCFā) including a terminal value (a Level 3 fair value measurement). The future cash flows were based on our estimates of operating and cash flow results, economic obsolescence, the business climate, contractual, legal, and other factors In the fourth quarter of 2019, we recorded an impairment charge of $225.3 million for the partial impairment of gas processing facilities and gathering systems associated with our North Texas and Coastal operations in our Gathering and Processing segment. Underlying our assessment was the expected continuing decline in natural gas production across the Barnett Shale in North Texas and Gulf of Mexico due to the sustained low commodity price environment. During 2017, we recorded an impairment charge of $378.0 million for the partial impairment of gas processing facilities and gathering systems associated with our North Texas operations in our Gathering and Processing segment. Given the price environment at the time, we projected a continuing decline in natural gas production across the Barnett Shale in North Texas. Write-down of Assets In 2019, we recorded an asset write-down of $17.9 million primarily associated with certain treating units in our Gathering and Processing segment. We wrote down the assets to their recoverable amounts using third party pricing to assess a discounted replacement cost based on the existing condition and location of the units. We consider such input to be a level 2 input in the fair value hierarchy. The write-down of assets is 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 prior business combinations. The fair value of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers. For each of the years ended December 31, 2019, 2018 and 2017 amortization expense for our intangible assets was $171.6 million, $182.6 million and $188.2 million. The estimated annual amortization expense for intangible assets is approximately $159.4 million, $149.5 million, $141.2 million, $136.0 million and $132.2 million for each of the years 2020 through 2024. As of December 31, 2019, the weighted average amortization period for our intangible assets was approximately 14.2 years. The changes in our intangible assets are as follows: December 31, 2019 December 31, 2018 Beginning of period $ 1,983.2 $ 2,165.8 Held for sale assets (76.6 ) ā Amortization (171.6 ) (182.6 ) End of period $ 1,735.0 $ 1,983.2 Asset Sales During the second quarter of 2018, we sold our inland marine barge business, which was included in our Logistics and Transportation 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 15 ā Fair Value Measurements. |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2019 | |
Goodwill And Intangible Assets Disclosure [Abstract] | |
Goodwill | Note 7 ā Goodwill Goodwill attributable to the WestTX and SouthTX reporting units in our Gathering and Processing segment was related to our acquisition of Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively the āAtlas mergersā). 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 Delaware Supersystem 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 Delaware Supersystem Total Balance as of December 31, 2017: Goodwill $ 364.5 $ 160.3 $ 23.2 $ 23.4 $ ā $ 571.4 Accumulated impairment losses (189.8 ) (125.0 ) ā ā ā (314.8 ) Net 174.7 35.3 23.2 23.4 ā 256.6 Impairment (174.7 ) (35.3 ) ā ā ā (210.0 ) Balance as of December 31, 2018: Goodwill 364.5 160.3 23.2 23.4 ā 571.4 Accumulated impairment losses (364.5 ) (160.3 ) ā ā ā (524.8 ) Net ā ā 23.2 23.4 ā 46.6 Impairment ā ā ā ā ā ā Reporting unit aggregation (1) ā ā ā (23.4 ) 23.4 ā Balance as of December 31, 2019: Goodwill 364.5 160.3 23.2 ā 23.4 571.4 Goodwill allocated to held for sale assets ā ā ā ā (1.4 ) (1.4 ) Accumulated impairment losses (364.5 ) (160.3 ) ā ā ā (524.8 ) Net ā ā 23.2 ā 22.0 45.2 (1) In 2019, we began aggregating the results of Delaware Supersystem activity, including New Delaware. Discrete financial information for New Delaware is no longer available and management now reviews aggregate Delaware Supersystem operating results. 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 ā 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 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 15 ā Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation. 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 producersā 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. We did not record any goodwill impairment charges for the year ended December 31, 2019, as the fair values of all reporting units exceeded their accounting carrying values. While no impairment is indicated, there is goodwill being allocated to held for sale assets. |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 12 Months Ended |
Dec. 31, 2019 | |
Equity Method Investments And Joint Ventures [Abstract] | |
Investments in Unconsolidated Affiliates | Note 8 ā Investments in Unconsolidated Affiliates Our Gathering and Processing Segment ā¢ two (together the āT2 Joint Venturesā) ; and ā¢ a 50 Logistics and Transportation Segment ā¢ a 25% non-operated ownership interest in GCX ; ā¢ a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (āGCFā); and ā¢ a 50 operated ownership interest in Cayenne . 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. See Note 4 ā Joint Ventures, Acquisitions and Divestitures for discussion of the formation of our GCX and Little Missouri 4 and our acquisition of interests in Cayenne. The following table shows the activity related to our investments in unconsolidated affiliates: Balance at December 31, 2016 Equity Earnings (Loss) Cash Distributions Acquisition Contributions Balance at December 31, 2017 GCX $ ā $ ā $ ā $ ā $ ā $ ā Little Missouri 4 ā ā ā ā ā ā T2 Eagle Ford 118.6 (10.6 ) ā ā 1.2 109.2 T2 LaSalle 58.6 (4.9 ) ā ā 0.4 54.1 GCF 46.1 12.4 (12.7 ) ā ā 45.8 Cayenne ā ā ā 5.0 3.6 8.6 T2 EF Cogen 17.5 (13.9 ) ā ā 0.3 3.9 Agua Blanca ā ā ā ā ā ā Total $ 240.8 $ (17.0 ) $ (12.7 ) $ 5.0 $ 5.5 $ 221.6 Balance at December 31, 2017 Equity Earnings (Loss) Cash Distributions (1) Acquisition (Disposition) Contributions (2) Balance at December 31, 2018 GCX (3) $ ā $ 0.8 $ ā $ ā $ 210.8 $ 211.6 Little Missouri 4 ā ā (8.0 ) ā 75.3 67.3 T2 Eagle Ford 109.2 (10.2 ) ā ā ā 99.0 T2 LaSalle 54.1 (4.9 ) ā ā 0.1 49.3 GCF 45.8 16.8 (22.3 ) ā ā 40.3 Cayenne 8.6 6.4 (4.0 ) ā 5.6 16.6 T2 EF Cogen 3.9 (1.8 ) ā (2.1 ) ā ā Agua Blanca ā 0.2 ā 3.5 2.7 6.4 Total $ 221.6 $ 7.3 $ (34.3 ) $ 1.4 $ 294.5 $ 490.5 Balance at December 31, 2018 Equity Earnings (Loss) Cash Distributions Disposition Contributions Balance at December 31, 2019 GCX (3) $ 211.6 $ 27.7 $ (25.3 ) $ ā $ 233.5 $ 447.5 Little Missouri 4 67.3 3.4 ā ā 33.0 103.7 T2 Eagle Ford (4) 99.0 (9.4 ) ā ā ā 89.6 T2 LaSalle (4) 49.3 (4.5 ) ā ā ā 44.8 GCF 40.3 16.1 (19.2 ) ā ā 37.2 Cayenne 16.6 7.2 (8.2 ) ā 0.3 15.9 Agua Blanca 6.4 (1.5 ) (0.4 ) (4.5 ) ā ā Total $ 490.5 $ 39.0 $ (53.1 ) $ (4.5 ) $ 266.8 $ 738.7 ( 1 ) Includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures. ( 2 ) Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4. ( 3 ) As discussed in Note 4 ā 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. ( 4 ) 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. 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 the T2 Joint Ventures. On April 1, 2019, we assumed the operatorship of the T2 Joint Ventures. During 2019, we closed on the sale of an equity-method investment for $73.8 million, of which $3.5 million contingent consideration was received in January 2020. As a result of the sale, we recognized a gain of $69.3 million reported in Gain (loss) from sale of equity-method investment. The following tables summarize the combined financial information of our investments in unconsolidated affiliates (all data presented on a 100% basis): December 31, 2019 December 31, 2018 (In millions) Current assets $ 136.3 $ 200.7 Non-current assets $ 2,291.6 $ 1,329.7 Current liabilities $ 93.8 $ 233.9 Non-current liabilities $ 3.4 $ 179.2 Net assets $ 2,330.7 $ 1,117.3 Year Ended December 31, 2019 2018 2017 (In millions) Operating revenues $ 265.5 $ 130.6 $ 84.3 Operating expenses $ 144.2 $ 96.9 $ 80.5 Net income (loss) $ 87.7 $ 34.7 $ 3.4 |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 12 Months Ended |
Dec. 31, 2019 | |
Payables And Accruals [Abstract] | |
Accounts Payable and Accrued Liabilities | Note 9 ā Accounts Payable and Accrued Liabilities December 31, 2019 December 31, 2018 Commodities $ 683.6 $ 721.9 Other goods and services 311.5 474.5 Interest 125.4 79.4 Permian Acquisition contingent consideration ā 308.2 Income and other taxes 62.0 45.4 Accrued distributions to noncontrolling interests 91.7 ā Other 9.5 7.5 $ 1,283.7 $ 1,636.9 Accounts payable and accrued liabilities includes $21.6 million and $52.2 million of liabilities to creditors to whom we have issued checks that remain outstanding as of December 31, 2019 and December 31, 2018. Permian Acquisition Contingent Consideration As a result of the Permian Acquisition, we included the fair value of the contingent consideration in accounts payable and accrued liabilities as of December 31, 2018. The contingent consideration earn-out period ended on February 28, 2019 and resulted in a $317.1 million payment in May 2019. |
Debt Obligations
Debt Obligations | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Debt Obligations | Note 10 ā Debt Obligations December 31, 2019 December 31, 2018 Current: Securitization Facility, due December 2020 $ 370.0 $ 280.0 Senior unsecured notes, 4ā November 2019 ā 749.4 370.0 1,029.4 Debt issuance costs, net of amortization ā (1.5 ) Finance lease liabilities 12.2 ā Current debt obligations 382.2 1,027.9 Long-term: Senior secured revolving credit facility, variable rate, due June 2023 ā 700.0 Senior unsecured notes: 5Ā¼ May 2023 559.6 559.6 4Ā¼ November 2023 583.9 583.9 6Ā¾ March 2024 580.1 580.1 5ā February 2025 500.0 500.0 5ā April 2026 1,000.0 1,000.0 5ā February 2027 500.0 500.0 6Ā½ July 2027 750.0 ā 5% fixed rate, due January 2028 750.0 750.0 6ā January 2029 750.0 ā 5Ā½ March 2030 1,000.0 ā TPL notes, 4Ā¾ November 2021 6.5 6.5 TPL notes, 5ā August 2023 48.1 48.1 Unamortized premium 0.3 0.3 7,028.5 5,228.5 Debt issuance costs, net of amortization (49.1 ) (31.1 ) Finance lease liabilities 25.8 ā Long-term debt 7,005.2 5,197.4 Total debt obligations $ 7,387.4 $ 6,225.3 Irrevocable standby letters of credit outstanding (3) $ 88.2 $ 79.5 ________________ (1) As of December 31, 2019, we had $400.0 million of qualifying receivables under our $400.0 million Securitization Facility, resulting in availability of $30.0 million. (2) The 4ā (3) As of December 31, 2019, availability under our $2.2 billion senior secured revolving credit facility (āTRP Revolverā) was $2,111.8 million. (4) āTPLā refers to Targa Pipeline Partners LP. The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2019, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2020 2021 2022 2023 2024 After 2024 (in millions) Senior unsecured notes $ 7,028.2 $ ā $ 6.5 $ ā $ 1,191.6 $ 580.1 $ 5,250.0 Securitization Facility 370.0 370.0 ā ā ā ā ā Total $ 7,398.2 $ 370.0 $ 6.5 $ ā $ 1,191.6 $ 580.1 $ 5,250.0 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, 2019: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 3.5% - 4.7% 4.1% Securitization Facility 2.6% - 3.4% 3.1% Compliance with Debt Covenants As of December 31, 2019, we were in compliance with the covenants contained in our various debt agreements. Debt Obligations Revolving Credit Facility The TRP Revolver, which has a maturity date of June 2023, provides available commitments up to $2.2 billion and allows us to request up to $500.0 million in additional commitments. The TRP Revolver provides for certain changes to occur upon the Partnership receiving an investment grade credit rating from Moodyās Investors Service, Inc. (āMoodyāsā) or Standard & Poorās Corporation (āS&Pā), 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 Americaās 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 Partnershipās 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 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). On June 7, 2019, the Partnership entered into the First Amendment to the TRP Revolver (the āFirst Amendmentā). The First Amendment, among other things, amended the TRP Revolver to (a) increase the maximum percentage of Consolidated EBITDA attributable to Material Project EBITDA. Adjustments from 20% to 30% solely for the fiscal periods from and including the fiscal period ending June 30, 2019 until and including the fiscal period ending June 30, 2020, after which time the maximum percentage of Consolidated EBITDA attributable to Material Project EBITDA. Adjustments shall revert to 20% of Consolidated EBITDA and (b) include in the calculation of Consolidated EBITDA for a period certain cash distributions received by the Partnership (or and of its consolidated restricted subsidiaries) from unrestricted subsidiaries (or entities that are not subsidiaries) after the end of such period but on or prior to the date that TRP calculates Consolidated EBITDA for such period. Accounts Receivable Securitization Facility On December 6, 2019, we renewed and amended the Securitization Facility by changing the termination date from December 6, 2019 to December 4, 2020. As of December 31, 2019, total funding under the Securitization Facility was $370.0 million. The Securitization Facility provides up to $400.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 4, 2020. 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 āTRLLCā), 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 senior unsecured 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 Moodyās or S&P We may redeem the senior unsecured notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount plus an applicable make-whole premium, plus accrued and unpaid interest and liquidation damages, if any, to the redemption date, as specified in the indenture of each series. We may also redeem up to 35% of the aggregate principal amount of each series of notes at the redemption dates and prices set forth in the indentures plus accrued and unpaid interest and liquidation damages, if any, to the redemption date 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. We may also redeem all or part of each of the series of senior unsecured notes on or after the redemption dates as specified in the indenture of each series at the redemption prices as specified in the indenture of each series plus accrued and unpaid interest to the redemption date and liquidation damages, if any, on the notes redeemed. Senior Unsecured Notes Issuances In October 2017, we issued $750.0 million aggregate principal amount of 5% senior notes due January 2028 In April 2018, we issued $1.0 billion aggregate principal amount of 5ā % April 2026 ā In January 2019, we issued $750.0 million of 6Ā½ July 2027 6ā January 2029 4ā In November 2019, the Partnership issued $1.0 billion aggregate principal amount of 5Ā½ March 2030 Debt Repurchases & Extinguishments In June 2017, we redeemed our outstanding 6ā August 2022 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 Gain (loss) from financing activities to write-off $0.2 million of unamortized debt issuance costs during the year ended December 31, 2017 . In February 2019, we redeemed our outstanding 4ā 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. Debt Repurchases and Extinguishments Summary The following table summarizes the impact of debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2019 2018 2017 Premium over face value paid upon redemption: 6ā % Senior Notes ā ā 8.9 Write-off of debt issuance costs: TRP Revolver ā 1.3 ā 4ā % Senior Notes 1.4 ā ā 5% Senior Notes ā ā 0.2 6ā % Senior Notes ā ā 1.8 Loss (gain) from financing activities $ 1.4 $ 1.3 $ 10.9 |
Other Long-term Liabilities
Other Long-term Liabilities | 12 Months Ended |
Dec. 31, 2019 | |
Other Liabilities Noncurrent [Abstract] | |
Other Long-term Liabilities | Note 11 ā Other Long-term Liabilities Other long-term liabilities are comprised of the following obligations: December 31, 2019 December 31, 2018 Asset retirement obligations $ 65.8 $ 55.0 Deferred revenue 172.0 175.5 Operating lease liabilities 18.2 ā Other liabilities 4.0 3.3 Total long-term liabilities $ 260.0 $ 233.8 Asset Retirement Obligations Our ARO primarily relate to certain gas gathering pipelines and processing facilities and NGL pipelines. The changes in our ARO are as follows: 2019 2018 Beginning of period $ 55.0 $ 50.3 Additions (1) 11.8 ā Change in cash flow estimate (5.1 ) 1.8 Accretion expense 4.7 3.7 Retirement of ARO (0.6 ) (0.8 ) End of period $ 65.8 $ 55.0 (1) Amount reflects additions of ARO related to the commencement of operations of Grand Prix. 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 partnerās 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 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 of $72.1 million is primarily attributable to the amendments. Income attributable to mandatorily redeemable preferred interests totaled $4.1 million during the year ended December 31, 2018. The estimated redemption value did not change during the year ended December 31, 2019. Deferred Revenue Deferred revenue as of December 31, 2019 and December 31, 2018, was $172.0 million and $175.5 million, respectively, which includes $129.0 million of payments received from Vitol Americas Corp. (āVitolā) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co. The payments were received in 2016, 2017, and 2018 as part of an agreement (the āSplitter Agreementā) related to the construction and operation of a crude oil and condensate splitter. In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects to terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is dependent upon resolution of the dispute with Vitol. Deferred revenue also includes nonmonetary consideration received in a 2015 amendment (the āgas contract amendmentā) 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, 2019, 2018 and 2017, we recognized approximately $3.9 million, $3.9 million and $3.1 million of revenue for these transactions. The following table shows the components of deferred revenue: December 31, 2019 December 31, 2018 Splitter agreement $ 129.0 $ 129.0 Gas contract amendment 39.8 42.2 Other deferred revenue 3.2 4.3 Total deferred revenue $ 172.0 $ 175.5 The following table shows the changes in deferred revenue: 2019 2018 Balance at December 31, 2018 $ 175.5 $ 136.2 Additions 0.4 43.2 Revenue recognized (3.9 ) (3.9 ) Balance at December 31, 2019 $ 172.0 $ 175.5 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. 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 producersā 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. At December 31, 2018, the fair value of the second potential earn-out payment of $308.2 million was recorded as a component of accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. The contingent consideration earn-out period ended on February 28, 2019 and resulted in a $317.1 million payment in May 2019. The following table shows the changes in the fair value of the contingent consideration related to the Permian Acquisition: Year Ended December 31, 2019 Year Ended December 31, 2018 March 1, 2017 to December 31, 2017 Beginning of period $ 308.2 $ 317.0 $ 416.3 Increase (decrease) in fair value, included in Other income (expense) 8.9 (8.8 ) (99.3 ) Earn-out payment (317.1 ) ā ā End of period ā 308.2 317.0 Less: Current portion ā (308.2 ) (6.8 ) Long-term balance at end of period $ ā $ ā 310.2 See Note 15 ā Fair Value Measurements for additional discussion of the fair value methodology. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Leases | Note 12 ā Leases We have non-cancellable operating leases primarily associated with our office facilities, rail assets, land, and storage and terminal assets. We have finance leases primarily associated with our tractors and vehicles. Our leases have remaining lease terms of 1 to 5 years The balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated Balance Sheets are as follows: Balance Sheet Location December 31, 2019 Right-of-use assets Operating leases, gross Other long-term assets $ 31.6 Finance leases, gross Property, plant and equipment 48.8 Lease liabilities Current: Operating leases Accounts payable and accrued liabilities $ 6.5 Finance leases Current debt obligations 12.2 Non-current: Operating leases Other long-term liabilities $ 18.2 Finance leases Long-term debt 25.8 Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements of Operations, depending on the nature of the leases. Finance lease costs are included in Depreciation and amortization expense and Interest income (expense) in our Consolidated Statements of Operations. The components of lease expense were as follows: Year Ended December 31, 2019 Lease cost Operating lease cost $ 8.2 Short-term lease cost 30.0 Variable lease cost 4.9 Finance lease cost Amortization of right-of-use assets 13.1 Interest expense 1.6 Total lease cost $ 57.8 During t he years ended December 31, 2018 and otal operating leases expense incurred were $51.9 million and $46.2 million, which includes short-term leases for compressors and equipment. Other supplemental information related to our leases are as follows: Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 8.2 Operating cash flows for finance leases 1.6 Financing cash flows for finance leases 11.5 The weighted-average remaining lease terms for operating leases and finance leases are 4 years and 3 years, respectively. The weighted-average discount rates for operating leases and finance leases are 3.9% and 3.9%, respectively. The following table presents the maturities of our lease liabilities under non-cancellable leases as of December 31, 2019: Operating Leases Finance Leases Future Minimum Lease Payments Beginning After December 31, 2019 $ 7.4 $ 13.4 2020 6.8 11.7 2021 5.7 10.2 2022 4.2 4.7 2023 2.3 0.5 Thereafter 0.4 ā Total undiscounted cash flows 26.8 40.5 Less imputed interest (2.1 ) (2.5 ) Total lease liabilities $ 24.7 $ 38.0 The following table presents future minimum payments under non-cancellable leases as of December 31, 2018: Leases 2019 $ 20.5 2020 17.7 2021 14.9 2022 12.6 2023 6.0 Thereafter 1.7 Total payments $ 73.4 |
Partnership Units and Related M
Partnership Units and Related Matters | 12 Months Ended |
Dec. 31, 2019 | |
Partners Capital [Abstract] | |
Partnership Units and Related Matters | Note 13 ā Partnership Units and Related Matters Distributions TRC is entitled to receive all available Partnership distributions after payment of preferred unit distributions each quarter. The following details the distributions declared or paid by the Partnership during 2019, 2018 and 2017: Three Months Ended Date Paid Total Distributions Distributions to Targa Resources Corp. 2019 December 31, 2019 February 13, 2020 $ 241.9 $ 239.1 September 30, 2019 November 13, 2019 242.1 239.3 June 30, 2019 August 13, 2019 242.4 239.6 March 31, 2019 April 5, 2019 437.8 435.0 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 Contributions All capital contributions are allocated 98% to the limited partner and 2% to our general partner; however, no units will be issued for those contributions. For the years ended December 31, 2019, 2018 and 2017, Targa made total capital contributions to us of $200.0 million, $600.0 million and $1,720.0 million. Preferred Units Our Preferred Units are listed on the NYSE under the symbol āNGLS/PA.ā 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: ā¢ 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; ā¢ 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; ā¢ 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 ā¢ 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 (āPreferred Unitholdersā) 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, 2019, we have 5,000,000 Preferred Units outstanding. We paid $11.3 million of distributions each year to the Preferred Unitholders for 2019, 2018 and 2017. In January and February 2020, 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 18, 2020 and the distributions declared in February will be paid on March 16, 2020. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Note 14 ā 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 Transportation segment and (iii) natural gas transportation basis risk in our Logistics and Transportation 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 āproxyā 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, 2019, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2020 2021 2022 2023 2024 Natural Gas Swaps MMBtu/d 127,230 123,751 46,100 - - Natural Gas Basis Swaps MMBtu/d 364,275 344,292 210,000 200,000 40,000 NGL Swaps Bbl/d 23,105 11,196 6,036 - - NGL Futures Bbl/d 16,844 - - - - Condensate Swaps Bbl/d 5,471 3,654 1,610 - - 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 value 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, 2019 Fair Value as of December 31, 2018 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 102.1 $ 11.6 $ 112.5 $ 18.9 Long-term 33.7 6.4 31.6 1.5 Total derivatives designated as hedging instruments $ 135.8 $ 18.0 $ 144.1 $ 20.4 Derivatives not designated as hedging instruments Commodity contracts Current $ 1.2 $ 92.5 $ 2.8 $ 14.7 Long-term 1.8 34.4 2.5 1.6 Total derivatives not designated as hedging instruments $ 3.0 $ 126.9 $ 5.3 $ 16.3 Total current position $ 103.3 $ 104.1 $ 115.3 $ 33.6 Total long-term position 35.5 40.8 34.1 3.1 Total derivatives $ 138.8 $ 144.9 $ 149.4 $ 36.7 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, 2019 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 99.8 $ (85.0 ) $ (4.9 ) $ 56.0 $ (46.1 ) Counterparties without offsetting positions - assets 3.5 - - 3.5 - Counterparties without offsetting positions - liabilities - (19.1 ) - - (19.1 ) 103.3 (104.1 ) (4.9 ) 59.5 (65.2 ) Long Term Position Counterparties with offsetting positions or collateral 33.3 (40.5 ) - 18.1 (25.3 ) Counterparties without offsetting positions - assets 2.2 - - 2.2 - Counterparties without offsetting positions - liabilities - (0.3 ) - - (0.3 ) 35.5 (40.8 ) - 20.3 (25.6 ) Total Derivatives Counterparties with offsetting positions or collateral 133.1 (125.5 ) (4.9 ) 74.1 (71.4 ) Counterparties without offsetting positions - assets 5.7 - - 5.7 - Counterparties without offsetting positions - liabilities - (19.4 ) - - (19.4 ) $ 138.8 $ (144.9 ) $ (4.9 ) $ 79.8 $ (90.8 ) 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 ) 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 broker s that clear the hedges through an exchange. We maintain a margin deposit with the broker s 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 value of our derivative instruments. The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of $6.1 million as of December 31, 2019. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterpartiesā 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 for the periods indicated: Derivatives in Cash Flow Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Hedging Relationships 2019 2018 2017 Commodity contracts $ 135.6 $ 132.5 $ (28.8 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2019 2018 2017 Revenues 138.0 (38.4 ) (44.6 ) Based on valuations as of December 31, 2019, we expect to reclassify commodity hedge related deferred gains of $117.7 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2022, with $90.9 million of gains to be reclassified over the next twelve months. 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. For the year ended December 31, 2019, the unrealized mark-to-market losses are primarily attributable to unfavorable movements in natural gas forward basis prices. Derivatives Not Designated Location of Gain Recognized in Gain (Loss) Recognized in Income on Derivatives as Hedging Instruments Income on Derivatives 2019 2018 2017 Commodity contracts Revenue $ (142.1 ) $ (32.5 ) $ (5.1 ) See Note 15 ā Fair Value Measurements and Note 25 ā Segment Information for additional disclosures related to derivative instruments and hedging activities. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 15 ā Fair Value Measurements Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (āfinancial instrumentsā). 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, 2019, a net liability position of $6.1 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $ 114.2 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 $ 102.1 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: ā¢ 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 ā¢ 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 until the end of the related earn-out period. 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: ā¢ Level 1 ā observable inputs such as quoted prices in active markets; ā¢ Level 2 ā 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 ā¢ Level 3 ā 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, 2019 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) $ 136.5 $ 136.5 $ ā $ 136.2 $ 0.3 Liabilities from commodity derivative contracts (1) 142.6 142.6 ā 142.0 0.6 TPL contingent consideration (2) 2.3 2.3 ā ā 2.3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 291.1 291.1 ā ā ā TRP Revolver ā ā ā ā ā Senior unsecured notes 7,028.5 7,376.9 ā 7,376.9 ā Accounts receivable securitization facility 370.0 370.0 ā 370.0 ā 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 $ ā $ 137.5 $ 6.9 Liabilities from commodity derivative contracts (1) 31.7 31.7 ā 31.3 0.4 Permian Acquisition contingent consideration (3) 308.2 308.2 ā ā 308.2 TPL contingent consideration (2) 2.4 2.4 ā ā 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 203.3 203.3 ā ā ā TRP Revolver 700.0 700.0 ā 700.0 ā Senior unsecured notes 5,277.9 5,088.9 ā 5,088.9 ā Accounts receivable securitization facility 280.0 280.0 ā 280.0 ā (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 14 ā 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 for TPLās previous acquisition of a gas gathering system and related assets, which is carried at fair value. (3) We had a contingent consideration liability related to the Permian Acquisition, which was carried at fair value. See Note 4 ā Joint Ventures, Acquisitions and Divestitures . 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 market prices or implied volatilities 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, 2019, we had nine 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 derivativeās 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 have resulted 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. The Permian Acquisition contingent consideration earn-out period ended on February 28, 2019 and resulted in a $317.1 million payment in May 2019. See Note 9 ā Accounts Payable and Accrued Liabilities for additional discussion of the Permian Acquisition contingent consideration. 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) Consideration Balance, December 31, 2018 $ 6.5 $ (310.6 ) Change in fair value of TPL contingent consideration ā 0.1 Completion of Permian Acquisition contingent consideration earn-out period ā 308.2 New Level 3 derivative instruments (0.7 ) ā Transfers out of Level 3 (1) (6.5 ) ā Unrealized gain/(loss) included in OCI 0.4 ā Balance, December 31, 2019 $ (0.3 ) $ (2.3 ) (1) Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 1 6 ā Related Par ty Transactions Transactions with Unconsolidated Affiliates The following table summarizes transactions with unconsolidated affiliates: GCF T2 Joint Ventures Cayenne GCX Little Missouri 4 Agua Blanca Total 2019: Revenues $ 0.3 $ 3.7 $ ā $ 0.8 $ 6.3 $ ā $ 11.0 Product purchases (7.9 ) ā (7.9 ) (24.7 ) ā ā (40.5 ) Operating expenses ā (2.0 ) (0.2 ) ā ā (1.2 ) (3.4 ) General and administrative expenses ā ā ā ā (0.3 ) ā (0.3 ) 2018: Revenues $ 0.3 $ 5.2 $ ā $ 0.1 $ ā $ ā $ 5.6 Product purchases (5.1 ) (0.6 ) (7.2 ) (1.2 ) ā ā (14.1 ) Operating expenses ā (3.6 ) ā ā ā ā (3.6 ) 2017: Revenues $ 0.3 $ 2.1 $ ā $ ā $ ā $ ā $ 2.4 Product purchases (4.4 ) (1.1 ) ā ā ā ā (5.5 ) Operating expenses ā (3.8 ) ā ā ā ā (3.8 ) 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 Targaās 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, 2019 2018 2017 Targa billings of payroll and related costs included in operating expenses $ 248.8 $ 236.8 $ 204.4 Targa allocation of general and administrative expense 237.2 221.4 175.2 Cash distributions to Targa based on general partner and limited partner ownership 1,152.4 918.5 847.3 Cash contributions from Targa related to limited partner ownership (1) 196.0 588.1 1,685.5 Cash contributions from Targa to maintain its 2% general partner ownership 4.0 12.0 34.5 ________________ ( 1 ) The cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to the general partner. See Note 13 ā Partnership Units and Related Matters. Relationship with Sajet Resources LLC In December 2010, immediately prior to Targaās initial public offering, Sajet Resources LLC (āSajetā) was spun-off from Targa. At the time, 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 and (ii) an ownership interest in Allied CNG Ventures LLC. 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 d general and administrative services to Sajet and were reimbursed for these amounts at our actual cost. Fees for s ervices provided to Sajet totaled less than $ 0.1 million in January and February of 2018 and $ 0.3 million in the year ended December 31, 2017 . 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 āWarburg Funds Transactionā) and extinguished Sajetās 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 āTag-Along Rightsā). 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. We hold three outstanding promissory notes from Sajet in the amounts of $9.9 million, $0.5 million and $0.2 million. The interest rate on each of the promissory notes accrues at the prime rate plus six percent |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Commitments | Note 17 ā 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 2020 2021 2022 2023 2024 Thereafter Land sites and rights of way (1) $ 150.4 $ 3.8 $ 4.0 $ 4.4 $ 4.3 $ 4.5 $ 129.4 (1) 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: 2019 2018 2017 Land sites and rights of way $ 6.1 $ 6.1 $ 5.2 |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2019 | |
Loss Contingency [Abstract] | |
Contingencies | Note 18 ā 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, 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 , which assert monetary sanctions 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. |
Significant Risks and Uncertain
Significant Risks and Uncertainties | 12 Months Ended |
Dec. 31, 2019 | |
Risks And Uncertainties [Abstract] | |
Significant Risks and Uncertainties | Note 19 ā 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, transporting, 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 proceeds from the sale of commodities 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, NGL and crude oil prices. Counterparty Risk ā Credit and Concentration Derivative Counterparty Risk Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterpartyās 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 $21.0 million as of December 31, 2019. The range of losses attributable to our individual counterparties would be between $0.2 million and $21.8 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 $0.0 million as of December 31, 2019 and $0.1 million as of December 31, 2018. Significant Commercial Relationship During the years ended December 31, 2019 and 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprised approximately 12% and 15 No customer comprised greater than 10% of our consolidated revenues in the year ended December 31, 2017. Interest Rate Risk We are exposed to changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and the 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 16 ā 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, 2019 | |
Revenue From Contract With Customer [Abstract] | |
Revenue | Note 20 ā 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. 2020 2021 2022 and after Fixed consideration to be recognized as of December 31, 2019 $ 495.1 $ 500.0 $ 3,209.8 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 19 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, see Note 3 ā Significant Accounting Policies. For disclosures related to disaggregated revenue, see Note 25 ā Segment Information. |
Other Operating (Income) Expens
Other Operating (Income) Expense | 12 Months Ended |
Dec. 31, 2019 | |
Other Income And Expenses [Abstract] | |
Other Operating (Income) Expense | Note 21 ā Other Operating (Income) Expense Other Operating (Income) Expense is comprised of the following: Year Ended December 31, 2019 2018 2017 (Gain) loss on sale of disposition of business and assets $ 71.1 $ (0.1 ) $ 15.9 Miscellaneous business tax 0.2 3.2 0.8 Other ā 0.4 0.7 $ 71.3 $ 3.5 $ 17.4 The (Gain) loss on sale or disposal of business and assets is comprised of the following: Year Ended December 31, 2019 2018 2017 Delaware crude gathering - held for sale $ 59.5 $ ā $ ā Sale of inland marine barge business ā (48.1 ) ā Exchange of a portion of Versado gathering system ā (44.4 ) ā Sale of storage and terminaling facilities ā 59.1 ā Disposal of benzene treating unit ā 20.5 ā Sale of Venice gathering system ā ā 16.1 Other 11.6 12.8 (0.2 ) $ 71.1 $ (0.1 ) $ 15.9 |
Income Tax
Income Tax | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Income Tax | Note 22 ā Income Tax Our income tax expense (benefit) is summarized below: 2019 2018 2017 Current expense (benefit) $ ā $ ā $ (4.5 ) Deferred expense (benefit) (0.9 ) (0.1 ) (2.9 ) Total income tax expense (benefit) $ (0.9 ) $ (0.1 ) $ (7.4 ) TPL Arkoma Inc., a corporate subsidiary of the Partnership, is subject to federal and state income tax. The Partnership's corporate subsidiary accounts for income taxes under the asset and liability method and provides deferred income taxes for all significant temporary differences. 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"), which significantly changed United States corporate income tax laws beginning, generally, in 2018. These changes included, among others, (1) a permanent reduction of the United States corporate income tax rate from a top marginal rate of 35 (2) elimination of the corporate alternative minimum tax (āAMTā); (3) immediate deductions for certain new investments instead of deductions for depreciation expense over time, (4) limitation on the tax deduction for interest expense to 30% of adjusted taxable income; (5) limitation of the deduction for net operating losses to 80% of current year taxable income and elimination of net operating loss carrybacks; and (6) elimination of many business deductions and credits, including the domestic production activities deduction, and the deduction for entertainment expenditures The SEC staff issued Staff Accounting Bulletin No. 118 (āSAB 118ā), 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 Tax 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. We completed the accounting for the 2017 provisional items in 2018 as outlined below: Our accounting for all applicable elements of the Tax Act is complete: ā¢ 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 2019-2021. We received $0.2 million of the refund in 2019. ā¢ 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. ā¢ 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, 2019 and 2018, consisted of differences related to the timing of recognition of certain types of costs as follows: 2019 2018 Deferred tax assets: Net operating loss carryforwards $ 13.4 $ 12.9 Deferred tax liabilities: Property, plant, and equipment (36.4 ) (36.8 ) Net deferred tax asset (liability) $ (23.0 ) $ (23.9 ) As of December 31, 2019, TPL Arkoma, Inc. had net operating loss carry forwards for federal income tax purposes of approximately $51.7 million, which expire at various dates from 2029 to 2039. 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, 2019 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | Note 23 ā Supplemental Cash Flow Information Year Ended December 31, 2019 2018 2017 Cash: Interest paid, net of capitalized interest (1) $ 271.5 $ 203.2 $ 198.7 Income taxes paid, net of refunds (1.8 ) 0.2 (4.9 ) Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 21.8 $ 49.0 $ 9.0 Impact of capital expenditure accruals on property, plant and equipment (193.9 ) 216.9 205.4 Transfers from materials and supplies inventory to property, plant and equipment 25.1 12.7 3.6 Contribution of property, plant and equipment to investments in unconsolidated affiliates ā 16.0 1.0 Change in ARO liability and property, plant and equipment due to revised cash flow estimate and additions 6.7 1.8 3.9 Property, plant and equipment received in asset exchange ā 24.1 ā Receivable for asset exchange ā 15.0 ā Asset received related to conveyance of ownership interest in investment in unconsolidated affiliate ā 3.0 ā Non-cash financing activities: Accrued distributions to noncontrolling interests $ 91.7 $ ā $ ā Non-cash balance sheet movements related to assets held for sale (See Note 4 - Joint Ventures, Acquisitions and Divestitures): Trade receivables $ 6.9 $ ā $ ā Intangible assets, net accumulated amortization and estimated loss on sale 52.1 ā ā Goodwill 1.4 ā ā Property, plant and equipment, net of accumulated depreciation and estimated loss on sale 77.3 ā ā Accounts payable and accrued liabilities 6.2 ā ā Other long-term obligations 0.2 ā ā Non-cash balance sheet movements related to the Permian Acquisition - See Note 4 - Joint Ventures, Acquisitions and Divestitures): Contingent consideration recorded at the acquisition date $ ā $ ā $ 416.3 Lease liabilities arising from recognition of right-of-use assets: Operating lease $ 6.9 $ ā $ ā Finance lease 10.1 ā ā (1) Interest capitalized on major projects was $61.8 million, $46.3 million and $14.3 million for the years ended December 31, 2019, 2018 and 2017. |
Compensation Plans
Compensation Plans | 12 Months Ended |
Dec. 31, 2019 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Compensation Plans | Note 24 ā Compensation Plans TRC Equity Compensation Plan In connection with the TRC/TRP Merger, TRC adopted and assumed our Long-term Incentive Plan and outstanding awards thereunder, and amended and restated the plan and renamed it the Targa Resources Corp. Equity Compensation Plan (the āPlanā). TRC continued to maintain the Equity Compensation Plan during 2017. However, since the number of shares reserved under the Equity Compensation Plan had been substantially exhausted as of the end of 2016, TRC no longer made grants under the Plan, which terminated in February 2017. The restricted stock units (āRSUsā) remaining under this Plan are the converted TRP awards and the RSUs made in lieu of cash bonus for our nonexecutives. The following table summarizes the RSUs for the year ended December 31, 2019, under the Plan: Number of shares Weighted Average Grant-Date Fair Value Outstanding as of December 31, 2018 301,691 $ 27.10 Vested (294,237 ) 26.48 Outstanding as of December 31, 2019 7,454 51.49 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 TRPās outstanding cash-settled performance unit obligation to cash-settled restricted stock units. During 2018, the remaining 112,550 shares of cash-settled awards vested and we paid $6.9 million related to those awards. Cash settled for the awards under TRC LTIP were $6.9 million and $4.1 million for 2018 and 2017. 2010 TRC Stock Incentive Plan In December 2010, TRC 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 ā2010 TRC Planā). 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 2017. The 2010 TRC Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (āIncentive Optionsā), (ii) stock options that do not qualify as incentive options (āNon-statutory Options,ā and together with Incentive Options, āOptionsā), (iii) stock appreciation rights (āSARsā) granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards (āRestricted Stock Awardsā), (v) phantom stock awards (āPhantom Stock Awardsā), (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards (collectively referred to as āAwardsā). 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 the common stock upon issuance. Director Grants ā The committee awarded TRC common stock to our outside directors. In 2019, 2018 and 2017, TRC issued 25,344, 16,955 and 13,818 shares of director grants with the weighted average grant-date fair value of $42.83, $51.21 and $60.48. 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 ā Restricted Stock Units (āRSUsā) 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 six years. In 2019, 2018 and 2017, TRC issued 1,042,344, 1,393,812 and 1,193,942 shares of RSUs with the weighted average grant-date fair value of $39.95, $51.71 and $54.18. The 2019 and 2018 issuances include 85,547 and 275,076 shares of RSUs for our new retention program. These shares will vest in October 2022 Restricted Stock in Lieu of Bonus ā In 2019, 2018 and 2017, TRC issued 95,687, 112,438 and 84,221 shares of restricted stock awards in lieu of cash bonuses in the form of RSUs for our executives at the weighted average grant-date fair value of $42.83, $51.09 and $55.94. These awards will cliff vest over three years. Dividends on bonus awards issued after 2017 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 of shares Weighted Average Grant-Date Fair Value Outstanding at December 31, 2018 3,594,135 $ 45.31 Granted 1,067,688 40.02 Forfeited (175,861 ) 51.90 Vested (1,093,901 ) 28.31 Outstanding at December 31, 2019 3,392,061 48.79 Performance Share Units During 2019, 2018 and 2017, TRC issued 261,245, 182,849 and 113,901 shares of performance share units (āPSUsā) to executive management and employees for the 2019, 2018 and 2017 compensation cycle that will vest/have vested in January 2022, January 2021 and January 2020. three-year The vesting of the PSUs is dependent on the satisfaction of a combination of certain service-related conditions and the Companyās total shareholder return (āTSRā) relative to the TSR of the members of a specified comparator group of publicly-traded midstream companies (the āLTIP Peer Groupā) 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 āguideline performance percentage,ā which could range from 0% to 250%, based upon the Companyās 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 when the awards vest. 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 ownersā 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 32% - 37% for PSUs granted in 2019, 29% - 53% for PSUs granted in 2018 and 55% - 61% for PSUs granted in 2017. The following table summarizes the PSUs under the 2010 TRC Plan in shares and in dollars for the years indicated. Number of shares Weighted Average Grant-Date Fair Value Outstanding at December 31, 2018 296,750 $ 88.19 Granted 261,245 64.46 Forfeited (29,276 ) 86.57 Outstanding at December 31, 2019 528,719 76.56 Cash-settled Awards During 2019 and 2018, TRC issued 7,836 and 69,042 shares of cash-settled awards for our retention program. These awards are liability awards and 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. All cash-settled awards vested in 2019. Payments for the cash-settled awards are classified within operating activities in the Consolidated Statements of Cash Flows. The following table summarizes the cash-settled restricted stock units for the year ended 2019. Number of shares Outstanding as of December 31, 2018 50,228 Granted 7,836 Vested and paid (54,313 ) Forfeited (3,672 ) Outstanding as of December 31, 2019 79 We made $2.9 million in payments for the cash-settled restricted units during 2019 and no payments in 2018 Stock compensation expense under the plans totaled $61.8 million, $59.0 million, and $44.2 million for the years ended December 31, 2019, 2018, and 2017. As of December 31, 2019, we have $97.7 million of unrecognized compensation expense associated with share-based awards and an approximate remaining weighted average vesting periods of 2.2 years related to our various compensation plans. The fair values of share-based awards vested in 2019, 2018 and 2017 were $55.4 million, $18.8 million and $14.4 million. Cash dividends paid for the vested awards were $15.0 million, $3.5 million and $2.5 million for 2019, 2018 and 2017. Subsequent Events In January 2020, the Compensation Committee of the Targa board of directors made the following awards under the 2010 TRC Plan. ā¢ 29,472 ā¢ 283,015 ā¢ 283,015 ā¢ 81,336 In January 2020, 25,344 shares of director grants vested with no shares withheld to satisfy tax withholding obligations. In January 2020, 121,239 shares of 2017 PSUs vested with 30,804 shares withheld to satisfy tax withholding obligations. In January 2020, total 111,808 shares of RSUs vested with 29,199 shares withheld to satisfy tax withholding obligations. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2019 | |
Segment Reporting [Abstract] | |
Segment Information | Note 25 ā Segment Information We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (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. In the fourth quarter of 2019, we made the following changes to the presentation of our reportable segments: ā¢ Renamed the Logistics and Marketing segment as Logistics and Transportation. The updated name better describes the business composition and activity of the segment given the recent completion of Grand Prix. The change in naming convention did not impact previously reported results for the segment. This segment is also referred to as the Downstream Business. ā¢ Due to changes in how our executive team evaluates segment performance, results of commodity derivative activities related to our equity volume hedges that are designated as accounting hedges are now reported in the Gathering and Processing segment. These hedge activities were previously reported in Other. Our prior period segment information has been updated to reflect the change. There was no impact to our Consolidated Statements of Operations. 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, Central 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) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico. Our Logistics and Transportation 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 transporting, storing, fractionating, terminaling and marketing of NGLs and NGL products, including services to LPG exporters; and certain natural gas supply and marketing activities in support of our other businesses. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana. Other contains the 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, 2019 Gathering and Processing Logistics and Transportation Other Corporate and Eliminations Total Revenues Sales of commodities $ 1,101.6 $ 6,406.1 $ (113.9 ) $ ā $ 7,393.8 Fees from midstream services 728.0 549.3 ā ā 1,277.3 1,829.6 6,955.4 (113.9 ) ā 8,671.1 Intersegment revenues Sales of commodities 2,628.4 132.2 ā (2,760.6 ) ā Fees from midstream services 7.4 28.7 ā (36.1 ) ā 2,635.8 160.9 ā (2,796.7 ) ā Revenues $ 4,465.4 $ 7,116.3 $ (113.9 ) $ (2,796.7 ) $ 8,671.1 Operating margin $ 1,006.5 $ 867.2 $ (113.9 ) $ ā $ 1,759.8 Other financial information: Total assets (1) $ 11,929.8 $ 6,741.8 $ 1.0 $ 71.9 $ 18,744.5 Goodwill $ 45.2 $ ā $ ā $ ā $ 45.2 Capital expenditures $ 1,273.3 $ 1,412.2 $ ā $ 23.5 $ 2,709.0 (1) Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Year Ended December 31, 2018 Gathering and Processing Logistics and Transportation Other Corporate and Eliminations Total Revenues Sales of commodities $ 1,228.2 $ 8,058.4 $ (7.9 ) $ ā $ 9,278.7 Fees from midstream services 715.6 489.7 ā ā 1,205.3 1,943.8 8,548.1 (7.9 ) ā 10,484.0 Intersegment revenues Sales of commodities 3,636.0 317.1 ā (3,953.1 ) ā Fees from midstream services 7.2 30.8 ā (38.0 ) ā 3,643.2 347.9 ā (3,991.1 ) ā Revenues $ 5,587.0 $ 8,896.0 $ (7.9 ) $ (3,991.1 ) $ 10,484.0 Operating margin $ 939.2 $ 592.5 $ (7.9 ) $ ā $ 1,523.8 Other financial information: Total assets (1) $ 11,602.7 $ 5,180.6 $ 3.2 $ 103.6 $ 16,890.1 Goodwill $ 46.6 $ ā $ ā $ ā $ 46.6 Capital expenditures $ 1,548.6 $ 1,767.0 $ ā $ 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 Transportation Other Corporate and Eliminations Total Revenues Sales of commodities $ 774.0 $ 6,979.3 $ (2.2 ) $ ā $ 7,751.1 Fees from midstream services 566.3 497.5 ā ā 1,063.8 1,340.3 7,476.8 (2.2 ) ā 8,814.9 Intersegment revenues Sales of commodities 3,154.2 321.9 ā (3,476.1 ) ā Fees from midstream services 6.9 28.0 ā (34.9 ) ā 3,161.1 349.9 ā (3,511.0 ) ā Revenues $ 4,501.4 $ 7,826.7 $ (2.2 ) $ (3,511.0 ) $ 8,814.9 Operating margin $ 776.4 $ 511.8 $ (2.2 ) $ ā $ 1,286.0 Other financial information: Total assets (1) $ 10,787.7 $ 3,507.4 $ 1.4 $ 62.5 $ 14,359.0 Goodwill $ 256.6 $ ā $ ā $ ā $ 256.6 Capital expenditures $ 1,008.9 $ 470.4 $ ā $ 27.2 $ 1,506.5 Business acquisitions $ 987.1 $ ā $ ā $ ā $ 987.1 (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: 2019 2018 2017 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $ 1,321.7 $ 1,810.0 $ 2,005.9 NGL 5,233.8 6,886.9 5,454.2 Condensate and crude oil 716.1 457.9 196.0 Petroleum products 126.3 196.1 144.7 7,397.9 9,350.9 7,800.8 Non-customer revenue: Derivative activities - Hedge 138.0 (39.7 ) (44.7 ) Derivative activities - Non-hedge (1) (142.1 ) (32.5 ) (5.0 ) (4.1 ) (72.2 ) (49.7 ) Total sales of commodities 7,393.8 9,278.7 7,751.1 Fees from midstream services: Revenue recognized from contracts with customers: Gathering and processing 722.4 698.1 523.3 NGL transportation, fractionation and services 169.4 154.6 170.7 Storage, terminaling and export 356.4 313.0 300.8 Other 29.1 39.6 69.0 Total fees from midstream services 1,277.3 1,205.3 1,063.8 Total revenues $ 8,671.1 $ 10,484.0 $ 8,814.9 (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: 2019 2018 2017 Reconciliation of reportable segment operating margin to income (loss) before income taxes: Gathering and Processing operating margin $ 1,006.5 $ 939.2 $ 776.4 Logistics and Transportation operating margin 867.2 592.5 511.8 Other operating margin (113.9 ) (7.9 ) (2.2 ) Depreciation and amortization expense (971.7 ) (815.9 ) (809.5 ) General and administrative expense (267.5 ) (240.8 ) (190.5 ) Impairment of property, plant and equipment (243.2 ) ā (378.0 ) Impairment of goodwill ā (210.0 ) ā Interest expense, net (320.8 ) (170.0 ) (217.8 ) Equity earnings (loss) 39.0 7.3 (17.0 ) Gain (loss) on sale or disposition of business and assets (71.1 ) 0.1 (15.9 ) Gain (loss) from sale of equity-method investment 69.3 ā ā Gain (loss) from financing activities (1.4 ) (1.3 ) (10.9 ) Change in contingent considerations (8.7 ) 8.8 99.6 Other, net (0.2 ) (3.5 ) (4.0 ) Income (loss) before income taxes $ (16.5 ) $ 98.5 $ (258.0 ) |
Selected Quarterly Financial Da
Selected Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2019 | |
Selected Quarterly Financial Information [Abstract] | |
Selected Quarterly Financial Data (Unaudited) | Note 26 ā Selected Quarterly Financial Data (Unaudited) Our results of operations by quarter for the years ended December 31, 2019 and 2018 were as follows: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2019 Revenues $ 2,299.4 $ 1,995.3 $ 1,902.5 $ 2,473.9 $ 8,671.1 Gross margin 573.4 633.7 574.4 $ 771.1 $ 2,552.6 Income (loss) from operations (1) 64.7 117.2 45.9 $ (21.7 ) $ 206.1 Net income (loss) (19.0 ) 51.7 37.5 $ (85.8 ) $ (15.6 ) Net income (loss) attributable to common limited partners (32.5 ) (7.3 ) (41.0 ) $ (179.9 ) $ (260.7 ) 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 (2) 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 ________________ (1) Includes ( 2 ) Includes |
Significant Accounting Polici_2
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
Accounting Policies [Abstract] | |
Consolidation Policy | Consolidation Policy Our consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain gas gathering and processing facilities in which we own an undivided interest and are responsible for our proportionate share of the costs and expenses of the facilities. Third party ownership interests in our controlled subsidiaries are presented 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. All intercompany balances and transactions have been eliminated in consolidation. We apply the equity method of accounting to investments over which we exercise significant influence over the operating and financial policies of our investee, but do not exercise control. 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 . among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative cost accruals, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets, (5) estimating contingencies, guarantees and indemnifications and (6) estimating redemption value of mandatorily redeemable preferred interests. |
Cash and Cash Equivalents | Cash and Cash Cash and cash equivalents include all cash on hand, demand deposits, and short-term, highly liquid investments that are readily convertible into cash, and have original maturities of three months or less. |
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 partyās ability and history of making required payments, economic events and other factors. We assess the need for adjustments to our allowance when the financial condition of any party changes or additional information becomes available. |
Inventories | Inventories Our inventories consist primarily of NGL product inventories, which are valued at the lower of cost or net realizable value, using the average cost method. 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. Commodity inventories that are not physically or contractually available for sale under normal operations (ādeadstockā) are included in Property, Plant and Equipment. |
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 our cash flows due to fluctuating energy commodity prices. 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. Cash flows from derivative instruments designated as hedges are recognized in the same financial statement line item as the cash flows from the respective item being hedged. 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 instrumentās 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 achieving the offset of changes in cash flows attributable to the hedged risk. We record all derivative instruments at fair value with the exception of those that we apply the normal purchases and normal sales election. The table below summarizes the accounting treatment for our derivative instruments, and the impact on our consolidated financial statements: Recognition and Measurement Derivative Treatment Balance Sheet Income Statement Normal Purchases and Normal Sales Fair value not recorded Earnings recognized when volumes are physically delivered or received Mark-to-Market Recorded at fair value Change in fair value recognized currently in earnings Cash Flow Hedge Recorded at fair value with changes in fair value deferred in Accumulated Other Comprehensive Income ("AOCI") The gain/loss on the derivative instrument is reclassified out of AOCI into earnings when the forecasted transaction occurs We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated, ceases to be highly effective or the forecasted transaction is no longer probable to occur. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is recorded at acquisition cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including our expected use of the asset and the supply of and demand for hydrocarbons in the markets served, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations. Expenditures for routine maintenance and repairs are expensed as incurred. Expenditures to refurbish an asset that increases its existing service potential or prevents environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. Certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs, are capitalized. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets We evaluate long-lived assets for impairment when events or changes in circumstances indicate our carrying amount of an asset may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. 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 long-lived assets and the recognition of additional impairments. |
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 subject to amortization but is tested for impairment at least annually. This test requires us to attribute goodwill to an appropriate reporting unit, which is an operating segment or one level below an operating segment (also known as a component). We evaluate goodwill for impairment on November 30 of each year, or whenever impairment indicators are present. 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. 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. As part of our goodwill impairment test, we may first assess qualitative factors to determine if the quantitative goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or 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). We recognize an impairment loss in our Consolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets for the amount by which the carrying amount exceeds the reporting unitās fair value. The goodwill impairment loss will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, when measuring goodwill, we consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit, if applicable. |
Intangible Assets | Intangible Assets Our intangible assets include 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. We amortize the costs of our assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis, where such pattern is not readily determinable, over the periods in which we benefit from services provided to customers. |
Asset Retirement Obligations | Asset Retirement Obligations Asset retirement obligations (āAROsā) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. We record a liability and increase the basis in the underlying asset for the present value of each expected asset retirement obligation (āAROā) when there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction. Our obligations are estimated based on discounted cash flow estimates. Over time, the ARO liability is accreted to its present value as a period cost and the capitalized amount is depreciated over the assetās respective useful life. At least annually, we review the projected timing and amount of asset retirement obligations and reflect revisions as an increase or decrease in the carrying amount of the liability and the basis in the underlying asset. Upon settlement, we will recognize any difference between the recorded amount and the actual settlement cost as a gain or loss. |
Debt Issue Costs | Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt and any original issue discount or premium are deferred and charged to interest expense over the term of the related debt. Debt issuance costs related to revolving credit facilities are presented as other long-term assets, and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction to the carrying amount of long-term debt on the Consolidated Balance Sheets. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issuance costs. |
Accounts Receivable Securitization Facility | Accounts Receivable Securitization Facility Proceeds from the sale or contribution of certain receivables under the accounts receivable securitization facility (the āSecuritization Facilityā) 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 We accrue a liability for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources, when the loss is probable and reasonably estimable. |
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 Partnershipās 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 22 ā Income Tax for discussion of the Partnershipās federal and state income tax expense (benefits) of its taxable subsidiary as well as the Partnershipās net deferred income tax assets (liabilities). |
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 (āOCIā), which includes changes in the fair value of derivative instruments that are designated as cash flow hedges. |
Revenue Recognition | Revenue Recognition Our operating revenues are primarily derived from the following activities: ā¢ sales of natural gas, NGLs, condensate and crude oil; ā¢ services related to compressing, gathering, treating, and processing of natural gas; and ā¢ services related to NGL fractionation, terminaling and storage, transportation and treating. 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 quarterās 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 employeesā tax withholding obligations on vested awards. The withheld shares were recorded as treasury units at cost. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Recently adopted accounting pronouncements Leases In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update (āASUā) 2016-02, Leases (Topic 842). The amendments in this update supersede the leases guidance in Topic 840. We adopted Topic 842 on January 1, 2019 by applying the optional transition method in ASU 2018-11, which permits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The adoption of Topic 842 did not result in a cumulative effect adjustment to retained earnings on January 1, 2019. As part of the adoption of Topic 842, we recognized a net right-of-use asset of $64.2 million (net of $0.4 million of lease incentives/deferred rent) and lease liability of $64.6 million. Other practical expedients we elected include: ā¢ The package for transition relief, which among other things, allows us to carry forward our historical lease classification; ā¢ The land easements transition, which allows us to carry forward our historical accounting treatment for land easements prior to the effective date of the new leases standard, and evaluate only new or modified land easements on or after January 1, 2019 under Topic 842; ā¢ The short-term lease election, which allows us to elect not to record leases with an initial term of twelve months or less, for all asset classes; ā¢ The election to not separate non-lease components from lease components for all the asset classes in our current lease portfolio, where Targa is the lessee; and ā¢ The election to not separate non-lease components from lease components for gathering, processing and storage assets, where Targa is the lessor. Based on our election, we determined the non-lease component in certain of these arrangements is the predominant component and therefore account for the arrangements under ASC 606. We recognize the following for all leases (with the exception of short-term leases) at the commencement date: ā¢ A lease liability, which is a lesseeās obligation to make lease payments arising from a lease. ā¢ A right-of-use asset, which is an asset that represents the lesseeās right to use, or control the use of, a specified asset for the lease term. We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered short-term leases, which are excluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of future lease payments over the lease term. The right-of-use asset also includes any lease prepayments and excludes lease incentives. As most of the Companyās leases do not provide an implicit interest rate, we use our incremental borrowing rate as the discount rate to compute the present value of our lease liability. The discount rate applied is determined based on information available on the date of adoption for all leases existing as of that date, and on the date of lease commencement for all subsequent leases. Our lease arrangements may include variable lease payments based on an index or market rate, or may be based on performance. For variable lease payments based on an index or market rate, we estimate and apply a rate based on information available at the commencement date. Variable lease payments based on performance are excluded from the calculation of the right-of-use asset and lease liability, and are recognized in our Consolidated Statements of Operations when the contingency underlying such variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options are included in the measurement of our right-of-use asset and liability, provided we determine that we are reasonably certain to exercise the option. See Note 12 ā Leases for additional details. |
Joint Ventures, Acquisitions _2
Joint Ventures, Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Business Acquisition [Line Items] | |
Pro Forma Consolidated Information of Operations | The following summarized unaudited pro forma Consolidated Statements of Operations information for the year ended December 31, 2017 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 Pro Forma Revenues $ 8,829.0 Net income (loss) (252.2 ) |
Schedule of Carrying Amounts of Assets and Liabilities Held for Sale | The adjusted carrying amounts of the assets and liabilities held for sale are as follows: December 31, 2019 Current assets: Trade receivables $ 6.9 Intangible assets, net accumulated amortization and estimated loss on sale 52.1 Goodwill 1.4 Property, plant and equipment, net of accumulated depreciation and estimated loss on sale 77.3 Total assets held for sale $ 137.7 Current liabilities: Accounts payable and accrued liabilities $ 6.2 Other long-term obligations 0.2 Total liabilities held for sale $ 6.4 |
Permian Acquisition [Member] | |
Business Acquisition [Line Items] | |
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, 2019 | |
Inventory Disclosure [Abstract] | |
Components of Inventories | December 31, 2019 December 31, 2018 Commodities $ 156.5 $ 151.1 Materials and supplies 5.0 13.6 $ 161.5 $ 164.7 |
Property, Plant and Equipment_2
Property, Plant and Equipment and Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Property Plant And Equipment And Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | December 31, 2019 December 31, 2018 Estimated Useful Lives (In Years) Gathering systems $ 8,976.8 $ 7,547.9 5 to 20 Processing and fractionation facilities 5,137.0 4,001.0 5 to 25 Terminaling and storage facilities 1,495.5 1,138.7 5 to 25 Transportation assets 2,292.4 445.1 10 to 50 Other property, plant and equipment 183.9 334.3 3 to 25 Land 159.7 144.3 ā Construction in progress 1,576.5 3,602.5 ā Finance lease right-of-use assets 48.8 ā Property, plant and equipment 19,870.6 17,213.8 Accumulated depreciation and amortization (5,321.6 ) (4,285.5 ) Property, plant and equipment, net $ 14,549.0 $ 12,928.3 Intangible assets $ 2,643.5 $ 2,736.6 10 to 20 Accumulated amortization (908.5 ) (753.4 ) Intangible assets, net $ 1,735.0 $ 1,983.2 |
Schedule of Changes in Intangible Assets | The changes in our intangible assets are as follows: December 31, 2019 December 31, 2018 Beginning of period $ 1,983.2 $ 2,165.8 Held for sale assets (76.6 ) ā Amortization (171.6 ) (182.6 ) End of period $ 1,735.0 $ 1,983.2 |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
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 Delaware Supersystem Total Balance as of December 31, 2017: Goodwill $ 364.5 $ 160.3 $ 23.2 $ 23.4 $ ā $ 571.4 Accumulated impairment losses (189.8 ) (125.0 ) ā ā ā (314.8 ) Net 174.7 35.3 23.2 23.4 ā 256.6 Impairment (174.7 ) (35.3 ) ā ā ā (210.0 ) Balance as of December 31, 2018: Goodwill 364.5 160.3 23.2 23.4 ā 571.4 Accumulated impairment losses (364.5 ) (160.3 ) ā ā ā (524.8 ) Net ā ā 23.2 23.4 ā 46.6 Impairment ā ā ā ā ā ā Reporting unit aggregation (1) ā ā ā (23.4 ) 23.4 ā Balance as of December 31, 2019: Goodwill 364.5 160.3 23.2 ā 23.4 571.4 Goodwill allocated to held for sale assets ā ā ā ā (1.4 ) (1.4 ) Accumulated impairment losses (364.5 ) (160.3 ) ā ā ā (524.8 ) Net ā ā 23.2 ā 22.0 45.2 (1) In 2019, we began aggregating the results of Delaware Supersystem activity, including New Delaware. Discrete financial information for New Delaware is no longer available and management now reviews aggregate Delaware Supersystem operating results. |
Investments in Unconsolidated_2
Investments in Unconsolidated Affiliates (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
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, 2016 Equity Earnings (Loss) Cash Distributions Acquisition Contributions Balance at December 31, 2017 GCX $ ā $ ā $ ā $ ā $ ā $ ā Little Missouri 4 ā ā ā ā ā ā T2 Eagle Ford 118.6 (10.6 ) ā ā 1.2 109.2 T2 LaSalle 58.6 (4.9 ) ā ā 0.4 54.1 GCF 46.1 12.4 (12.7 ) ā ā 45.8 Cayenne ā ā ā 5.0 3.6 8.6 T2 EF Cogen 17.5 (13.9 ) ā ā 0.3 3.9 Agua Blanca ā ā ā ā ā ā Total $ 240.8 $ (17.0 ) $ (12.7 ) $ 5.0 $ 5.5 $ 221.6 Balance at December 31, 2017 Equity Earnings (Loss) Cash Distributions (1) Acquisition (Disposition) Contributions (2) Balance at December 31, 2018 GCX (3) $ ā $ 0.8 $ ā $ ā $ 210.8 $ 211.6 Little Missouri 4 ā ā (8.0 ) ā 75.3 67.3 T2 Eagle Ford 109.2 (10.2 ) ā ā ā 99.0 T2 LaSalle 54.1 (4.9 ) ā ā 0.1 49.3 GCF 45.8 16.8 (22.3 ) ā ā 40.3 Cayenne 8.6 6.4 (4.0 ) ā 5.6 16.6 T2 EF Cogen 3.9 (1.8 ) ā (2.1 ) ā ā Agua Blanca ā 0.2 ā 3.5 2.7 6.4 Total $ 221.6 $ 7.3 $ (34.3 ) $ 1.4 $ 294.5 $ 490.5 Balance at December 31, 2018 Equity Earnings (Loss) Cash Distributions Disposition Contributions Balance at December 31, 2019 GCX (3) $ 211.6 $ 27.7 $ (25.3 ) $ ā $ 233.5 $ 447.5 Little Missouri 4 67.3 3.4 ā ā 33.0 103.7 T2 Eagle Ford (4) 99.0 (9.4 ) ā ā ā 89.6 T2 LaSalle (4) 49.3 (4.5 ) ā ā ā 44.8 GCF 40.3 16.1 (19.2 ) ā ā 37.2 Cayenne 16.6 7.2 (8.2 ) ā 0.3 15.9 Agua Blanca 6.4 (1.5 ) (0.4 ) (4.5 ) ā ā Total $ 490.5 $ 39.0 $ (53.1 ) $ (4.5 ) $ 266.8 $ 738.7 ( 1 ) Includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures. ( 2 ) Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4. ( 3 ) As discussed in Note 4 ā 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. ( 4 ) 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. The following tables summarize the combined financial information of our investments in unconsolidated affiliates (all data presented on a 100% basis): December 31, 2019 December 31, 2018 (In millions) Current assets $ 136.3 $ 200.7 Non-current assets $ 2,291.6 $ 1,329.7 Current liabilities $ 93.8 $ 233.9 Non-current liabilities $ 3.4 $ 179.2 Net assets $ 2,330.7 $ 1,117.3 Year Ended December 31, 2019 2018 2017 (In millions) Operating revenues $ 265.5 $ 130.6 $ 84.3 Operating expenses $ 144.2 $ 96.9 $ 80.5 Net income (loss) $ 87.7 $ 34.7 $ 3.4 |
Accounts Payable and Accrued _2
Accounts Payable and Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Payables And Accruals [Abstract] | |
Schedule of Accounts Payable and Accrued Liabilities | December 31, 2019 December 31, 2018 Commodities $ 683.6 $ 721.9 Other goods and services 311.5 474.5 Interest 125.4 79.4 Permian Acquisition contingent consideration ā 308.2 Income and other taxes 62.0 45.4 Accrued distributions to noncontrolling interests 91.7 ā Other 9.5 7.5 $ 1,283.7 $ 1,636.9 |
Debt Obligations (Tables)
Debt Obligations (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Debt Disclosure [Abstract] | |
Schedule of Outstanding Debt | December 31, 2019 December 31, 2018 Current: Securitization Facility, due December 2020 $ 370.0 $ 280.0 Senior unsecured notes, 4ā November 2019 ā 749.4 370.0 1,029.4 Debt issuance costs, net of amortization ā (1.5 ) Finance lease liabilities 12.2 ā Current debt obligations 382.2 1,027.9 Long-term: Senior secured revolving credit facility, variable rate, due June 2023 ā 700.0 Senior unsecured notes: 5Ā¼ May 2023 559.6 559.6 4Ā¼ November 2023 583.9 583.9 6Ā¾ March 2024 580.1 580.1 5ā February 2025 500.0 500.0 5ā April 2026 1,000.0 1,000.0 5ā February 2027 500.0 500.0 6Ā½ July 2027 750.0 ā 5% fixed rate, due January 2028 750.0 750.0 6ā January 2029 750.0 ā 5Ā½ March 2030 1,000.0 ā TPL notes, 4Ā¾ November 2021 6.5 6.5 TPL notes, 5ā August 2023 48.1 48.1 Unamortized premium 0.3 0.3 7,028.5 5,228.5 Debt issuance costs, net of amortization (49.1 ) (31.1 ) Finance lease liabilities 25.8 ā Long-term debt 7,005.2 5,197.4 Total debt obligations $ 7,387.4 $ 6,225.3 Irrevocable standby letters of credit outstanding (3) $ 88.2 $ 79.5 ________________ (1) As of December 31, 2019, we had $400.0 million of qualifying receivables under our $400.0 million Securitization Facility, resulting in availability of $30.0 million. (2) The 4ā (3) As of December 31, 2019, availability under our $2.2 billion senior secured revolving credit facility (āTRP Revolverā) was $2,111.8 million. (4) āTPLā refers to Targa Pipeline Partners LP. |
Schedule of Contractual Maturities | The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2019, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2020 2021 2022 2023 2024 After 2024 (in millions) Senior unsecured notes $ 7,028.2 $ ā $ 6.5 $ ā $ 1,191.6 $ 580.1 $ 5,250.0 Securitization Facility 370.0 370.0 ā ā ā ā ā Total $ 7,398.2 $ 370.0 $ 6.5 $ ā $ 1,191.6 $ 580.1 $ 5,250.0 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 2020 2021 2022 2023 2024 Thereafter Land sites and rights of way (1) $ 150.4 $ 3.8 $ 4.0 $ 4.4 $ 4.3 $ 4.5 $ 129.4 (1) 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. |
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, 2019: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 3.5% - 4.7% 4.1% Securitization Facility 2.6% - 3.4% 3.1% |
Summary of Impact of Debt Repurchased on Open Market Portion of Outstanding Senior Notes | The following table summarizes the impact of debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2019 2018 2017 Premium over face value paid upon redemption: 6ā % Senior Notes ā ā 8.9 Write-off of debt issuance costs: TRP Revolver ā 1.3 ā 4ā % Senior Notes 1.4 ā ā 5% Senior Notes ā ā 0.2 6ā % Senior Notes ā ā 1.8 Loss (gain) from financing activities $ 1.4 $ 1.3 $ 10.9 |
Other Long-term Liabilities (Ta
Other Long-term Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Other Liabilities Noncurrent [Abstract] | |
Other Long-term Liabilities | Other long-term liabilities are comprised of the following obligations: December 31, 2019 December 31, 2018 Asset retirement obligations $ 65.8 $ 55.0 Deferred revenue 172.0 175.5 Operating lease liabilities 18.2 ā Other liabilities 4.0 3.3 Total long-term liabilities $ 260.0 $ 233.8 |
Changes in Aggregate Asset Retirement Obligations | The changes in our ARO are as follows 2019 2018 Beginning of period $ 55.0 $ 50.3 Additions (1) 11.8 ā Change in cash flow estimate (5.1 ) 1.8 Accretion expense 4.7 3.7 Retirement of ARO (0.6 ) (0.8 ) End of period $ 65.8 $ 55.0 (1) Amount reflects additions of ARO related to the commencement of operations of Grand Prix. |
Components of Deferred Revenue | The following table shows the components of deferred revenue: December 31, 2019 December 31, 2018 Splitter agreement $ 129.0 $ 129.0 Gas contract amendment 39.8 42.2 Other deferred revenue 3.2 4.3 Total deferred revenue $ 172.0 $ 175.5 |
Changes in Deferred Revenue | The following table shows the changes in deferred revenue: 2019 2018 Balance at December 31, 2018 $ 175.5 $ 136.2 Additions 0.4 43.2 Revenue recognized (3.9 ) (3.9 ) Balance at December 31, 2019 $ 172.0 $ 175.5 |
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: Year Ended December 31, 2019 Year Ended December 31, 2018 March 1, 2017 to December 31, 2017 Beginning of period $ 308.2 $ 317.0 $ 416.3 Increase (decrease) in fair value, included in Other income (expense) 8.9 (8.8 ) (99.3 ) Earn-out payment (317.1 ) ā ā End of period ā 308.2 317.0 Less: Current portion ā (308.2 ) (6.8 ) Long-term balance at end of period $ ā $ ā 310.2 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Summary of Balances of Right-of-Use Assets and Liabilities of Finance and Operating Leases | The balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated Balance Sheets are as follows: Balance Sheet Location December 31, 2019 Right-of-use assets Operating leases, gross Other long-term assets $ 31.6 Finance leases, gross Property, plant and equipment 48.8 Lease liabilities Current: Operating leases Accounts payable and accrued liabilities $ 6.5 Finance leases Current debt obligations 12.2 Non-current: Operating leases Other long-term liabilities $ 18.2 Finance leases Long-term debt 25.8 |
Components of Lease Expense | Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements of Operations, depending on the nature of the leases. Finance lease costs are included in Depreciation and amortization expense and Interest income (expense) in our Consolidated Statements of Operations. The components of lease expense were as follows: Year Ended December 31, 2019 Lease cost Operating lease cost $ 8.2 Short-term lease cost 30.0 Variable lease cost 4.9 Finance lease cost Amortization of right-of-use assets 13.1 Interest expense 1.6 Total lease cost $ 57.8 |
Summary of Other Supplemental Information Related to Leases | Other supplemental information related to our leases are as follows: Year Ended December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows for operating leases $ 8.2 Operating cash flows for finance leases 1.6 Financing cash flows for finance leases 11.5 |
Summary of Maturities of Lease Liabilities under Non-cancellable Leases | The following table presents the maturities of our lease liabilities under non-cancellable leases as of December 31, 2019: Operating Leases Finance Leases Future Minimum Lease Payments Beginning After December 31, 2019 $ 7.4 $ 13.4 2020 6.8 11.7 2021 5.7 10.2 2022 4.2 4.7 2023 2.3 0.5 Thereafter 0.4 ā Total undiscounted cash flows 26.8 40.5 Less imputed interest (2.1 ) (2.5 ) Total lease liabilities $ 24.7 $ 38.0 |
Summary of Future Minimum Payments under Non-cancellable Leases | The following table presents future minimum payments under non-cancellable leases as of December 31, 2018: Leases 2019 $ 20.5 2020 17.7 2021 14.9 2022 12.6 2023 6.0 Thereafter 1.7 Total payments $ 73.4 |
Partnership Units and Related_2
Partnership Units and Related Matters (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Partners Capital [Abstract] | |
Schedule of Distributions | The following details the distributions declared or paid by the Partnership during 2019, 2018 and 2017: Three Months Ended Date Paid Total Distributions Distributions to Targa Resources Corp. 2019 December 31, 2019 February 13, 2020 $ 241.9 $ 239.1 September 30, 2019 November 13, 2019 242.1 239.3 June 30, 2019 August 13, 2019 242.4 239.6 March 31, 2019 April 5, 2019 437.8 435.0 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 |
Derivative Instruments and He_2
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Notional Volume of Commodity Hedges | At December 31, 2019, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2020 2021 2022 2023 2024 Natural Gas Swaps MMBtu/d 127,230 123,751 46,100 - - Natural Gas Basis Swaps MMBtu/d 364,275 344,292 210,000 200,000 40,000 NGL Swaps Bbl/d 23,105 11,196 6,036 - - NGL Futures Bbl/d 16,844 - - - - Condensate Swaps Bbl/d 5,471 3,654 1,610 - - |
Fair Values of Derivative Instruments | The following schedules reflect the fair value 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, 2019 Fair Value as of December 31, 2018 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 102.1 $ 11.6 $ 112.5 $ 18.9 Long-term 33.7 6.4 31.6 1.5 Total derivatives designated as hedging instruments $ 135.8 $ 18.0 $ 144.1 $ 20.4 Derivatives not designated as hedging instruments Commodity contracts Current $ 1.2 $ 92.5 $ 2.8 $ 14.7 Long-term 1.8 34.4 2.5 1.6 Total derivatives not designated as hedging instruments $ 3.0 $ 126.9 $ 5.3 $ 16.3 Total current position $ 103.3 $ 104.1 $ 115.3 $ 33.6 Total long-term position 35.5 40.8 34.1 3.1 Total derivatives $ 138.8 $ 144.9 $ 149.4 $ 36.7 |
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, 2019 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 99.8 $ (85.0 ) $ (4.9 ) $ 56.0 $ (46.1 ) Counterparties without offsetting positions - assets 3.5 - - 3.5 - Counterparties without offsetting positions - liabilities - (19.1 ) - - (19.1 ) 103.3 (104.1 ) (4.9 ) 59.5 (65.2 ) Long Term Position Counterparties with offsetting positions or collateral 33.3 (40.5 ) - 18.1 (25.3 ) Counterparties without offsetting positions - assets 2.2 - - 2.2 - Counterparties without offsetting positions - liabilities - (0.3 ) - - (0.3 ) 35.5 (40.8 ) - 20.3 (25.6 ) Total Derivatives Counterparties with offsetting positions or collateral 133.1 (125.5 ) (4.9 ) 74.1 (71.4 ) Counterparties without offsetting positions - assets 5.7 - - 5.7 - Counterparties without offsetting positions - liabilities - (19.4 ) - - (19.4 ) $ 138.8 $ (144.9 ) $ (4.9 ) $ 79.8 $ (90.8 ) 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 ) |
Amounts Recorded in Other Comprehensive Income and Amounts Reclassified from OCI to Revenue | The following tables reflect amounts recorded in Other Comprehensive Income and amounts reclassified from OCI to revenue for the periods indicated: Derivatives in Cash Flow Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Hedging Relationships 2019 2018 2017 Commodity contracts $ 135.6 $ 132.5 $ (28.8 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2019 2018 2017 Revenues 138.0 (38.4 ) (44.6 ) |
Gain (Loss) Recognized in Income on Derivatives | The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. For the year ended December 31, 2019, the unrealized mark-to-market losses are primarily attributable to unfavorable movements in natural gas forward basis prices. Derivatives Not Designated Location of Gain Recognized in Gain (Loss) Recognized in Income on Derivatives as Hedging Instruments Income on Derivatives 2019 2018 2017 Commodity contracts Revenue $ (142.1 ) $ (32.5 ) $ (5.1 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
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, 2019 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) $ 136.5 $ 136.5 $ ā $ 136.2 $ 0.3 Liabilities from commodity derivative contracts (1) 142.6 142.6 ā 142.0 0.6 TPL contingent consideration (2) 2.3 2.3 ā ā 2.3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 291.1 291.1 ā ā ā TRP Revolver ā ā ā ā ā Senior unsecured notes 7,028.5 7,376.9 ā 7,376.9 ā Accounts receivable securitization facility 370.0 370.0 ā 370.0 ā 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 $ ā $ 137.5 $ 6.9 Liabilities from commodity derivative contracts (1) 31.7 31.7 ā 31.3 0.4 Permian Acquisition contingent consideration (3) 308.2 308.2 ā ā 308.2 TPL contingent consideration (2) 2.4 2.4 ā ā 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 203.3 203.3 ā ā ā TRP Revolver 700.0 700.0 ā 700.0 ā Senior unsecured notes 5,277.9 5,088.9 ā 5,088.9 ā Accounts receivable securitization facility 280.0 280.0 ā 280.0 ā (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 14 ā 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 for TPLās previous acquisition of a gas gathering system and related assets, which is carried at fair value. (3) We had a contingent consideration liability related to the Permian Acquisition, which was carried at fair value. See Note 4 ā Joint Ventures, Acquisitions and Divestitures . |
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) Consideration Balance, December 31, 2018 $ 6.5 $ (310.6 ) Change in fair value of TPL contingent consideration ā 0.1 Completion of Permian Acquisition contingent consideration earn-out period ā 308.2 New Level 3 derivative instruments (0.7 ) ā Transfers out of Level 3 (1) (6.5 ) ā Unrealized gain/(loss) included in OCI 0.4 ā Balance, December 31, 2019 $ (0.3 ) $ (2.3 ) (1) Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term. |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
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, 2019 2018 2017 Targa billings of payroll and related costs included in operating expenses $ 248.8 $ 236.8 $ 204.4 Targa allocation of general and administrative expense 237.2 221.4 175.2 Cash distributions to Targa based on general partner and limited partner ownership 1,152.4 918.5 847.3 Cash contributions from Targa related to limited partner ownership (1) 196.0 588.1 1,685.5 Cash contributions from Targa to maintain its 2% general partner ownership 4.0 12.0 34.5 ________________ ( 1 ) The cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to the general partner. See Note 13 ā 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 Little Missouri 4 Agua Blanca Total 2019: Revenues $ 0.3 $ 3.7 $ ā $ 0.8 $ 6.3 $ ā $ 11.0 Product purchases (7.9 ) ā (7.9 ) (24.7 ) ā ā (40.5 ) Operating expenses ā (2.0 ) (0.2 ) ā ā (1.2 ) (3.4 ) General and administrative expenses ā ā ā ā (0.3 ) ā (0.3 ) 2018: Revenues $ 0.3 $ 5.2 $ ā $ 0.1 $ ā $ ā $ 5.6 Product purchases (5.1 ) (0.6 ) (7.2 ) (1.2 ) ā ā (14.1 ) Operating expenses ā (3.6 ) ā ā ā ā (3.6 ) 2017: Revenues $ 0.3 $ 2.1 $ ā $ ā $ ā $ ā $ 2.4 Product purchases (4.4 ) (1.1 ) ā ā ā ā (5.5 ) Operating expenses ā (3.8 ) ā ā ā ā (3.8 ) |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Leases [Abstract] | |
Schedule of Contractual Maturities | The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2019, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2020 2021 2022 2023 2024 After 2024 (in millions) Senior unsecured notes $ 7,028.2 $ ā $ 6.5 $ ā $ 1,191.6 $ 580.1 $ 5,250.0 Securitization Facility 370.0 370.0 ā ā ā ā ā Total $ 7,398.2 $ 370.0 $ 6.5 $ ā $ 1,191.6 $ 580.1 $ 5,250.0 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 2020 2021 2022 2023 2024 Thereafter Land sites and rights of way (1) $ 150.4 $ 3.8 $ 4.0 $ 4.4 $ 4.3 $ 4.5 $ 129.4 (1) 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 on Non-Cancelable Commitments | Total expenses incurred under the above non-cancelable commitments were: 2019 2018 2017 Land sites and rights of way $ 6.1 $ 6.1 $ 5.2 |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
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. 2020 2021 2022 and after Fixed consideration to be recognized as of December 31, 2019 $ 495.1 $ 500.0 $ 3,209.8 |
Other Operating (Income) Expe_2
Other Operating (Income) Expense (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Other Income And Expenses [Abstract] | |
Other Operating (Income) Expense | Other Operating (Income) Expense is comprised of the following: Year Ended December 31, 2019 2018 2017 (Gain) loss on sale of disposition of business and assets $ 71.1 $ (0.1 ) $ 15.9 Miscellaneous business tax 0.2 3.2 0.8 Other ā 0.4 0.7 $ 71.3 $ 3.5 $ 17.4 |
Summary of (Gain) Loss on Sale or Disposal of Business and Assets | The (Gain) loss on sale or disposal of business and assets is comprised of the following: Year Ended December 31, 2019 2018 2017 Delaware crude gathering - held for sale $ 59.5 $ ā $ ā Sale of inland marine barge business ā (48.1 ) ā Exchange of a portion of Versado gathering system ā (44.4 ) ā Sale of storage and terminaling facilities ā 59.1 ā Disposal of benzene treating unit ā 20.5 ā Sale of Venice gathering system ā ā 16.1 Other 11.6 12.8 (0.2 ) $ 71.1 $ (0.1 ) $ 15.9 |
Income Tax (Tables)
Income Tax (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Summary of Income Tax Expense (Benefit) | Our income tax expense (benefit) is summarized below: 2019 2018 2017 Current expense (benefit) $ ā $ ā $ (4.5 ) Deferred expense (benefit) (0.9 ) (0.1 ) (2.9 ) Total income tax expense (benefit) $ (0.9 ) $ (0.1 ) $ (7.4 ) |
Deferred Tax Assets and Liabilities | Our deferred income tax assets and liabilities at December 31, 2019 and 2018, consisted of differences related to the timing of recognition of certain types of costs as follows: 2019 2018 Deferred tax assets: Net operating loss carryforwards $ 13.4 $ 12.9 Deferred tax liabilities: Property, plant, and equipment (36.4 ) (36.8 ) Net deferred tax asset (liability) $ (23.0 ) $ (23.9 ) |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | Year Ended December 31, 2019 2018 2017 Cash: Interest paid, net of capitalized interest (1) $ 271.5 $ 203.2 $ 198.7 Income taxes paid, net of refunds (1.8 ) 0.2 (4.9 ) Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 21.8 $ 49.0 $ 9.0 Impact of capital expenditure accruals on property, plant and equipment (193.9 ) 216.9 205.4 Transfers from materials and supplies inventory to property, plant and equipment 25.1 12.7 3.6 Contribution of property, plant and equipment to investments in unconsolidated affiliates ā 16.0 1.0 Change in ARO liability and property, plant and equipment due to revised cash flow estimate and additions 6.7 1.8 3.9 Property, plant and equipment received in asset exchange ā 24.1 ā Receivable for asset exchange ā 15.0 ā Asset received related to conveyance of ownership interest in investment in unconsolidated affiliate ā 3.0 ā Non-cash financing activities: Accrued distributions to noncontrolling interests $ 91.7 $ ā $ ā Non-cash balance sheet movements related to assets held for sale (See Note 4 - Joint Ventures, Acquisitions and Divestitures): Trade receivables $ 6.9 $ ā $ ā Intangible assets, net accumulated amortization and estimated loss on sale 52.1 ā ā Goodwill 1.4 ā ā Property, plant and equipment, net of accumulated depreciation and estimated loss on sale 77.3 ā ā Accounts payable and accrued liabilities 6.2 ā ā Other long-term obligations 0.2 ā ā Non-cash balance sheet movements related to the Permian Acquisition - See Note 4 - Joint Ventures, Acquisitions and Divestitures): Contingent consideration recorded at the acquisition date $ ā $ ā $ 416.3 Lease liabilities arising from recognition of right-of-use assets: Operating lease $ 6.9 $ ā $ ā Finance lease 10.1 ā ā (1) Interest capitalized on major projects was $61.8 million, $46.3 million and $14.3 million for the years ended December 31, 2019, 2018 and 2017. |
Compensation Plans (Tables)
Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
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 of shares Weighted Average Grant-Date Fair Value Outstanding at December 31, 2018 296,750 $ 88.19 Granted 261,245 64.46 Forfeited (29,276 ) 86.57 Outstanding at December 31, 2019 528,719 76.56 |
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 RSUs for the year ended December 31, 2019, under the Plan: Number of shares Weighted Average Grant-Date Fair Value Outstanding as of December 31, 2018 301,691 $ 27.10 Vested (294,237 ) 26.48 Outstanding as of December 31, 2019 7,454 51.49 |
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 of shares Weighted Average Grant-Date Fair Value Outstanding at December 31, 2018 3,594,135 $ 45.31 Granted 1,067,688 40.02 Forfeited (175,861 ) 51.90 Vested (1,093,901 ) 28.31 Outstanding at December 31, 2019 3,392,061 48.79 |
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 2019. Number of shares Outstanding as of December 31, 2018 50,228 Granted 7,836 Vested and paid (54,313 ) Forfeited (3,672 ) Outstanding as of December 31, 2019 79 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Segment Reporting [Abstract] | |
Information by Segment | Reportable segment information is shown in the following tables: Year Ended December 31, 2019 Gathering and Processing Logistics and Transportation Other Corporate and Eliminations Total Revenues Sales of commodities $ 1,101.6 $ 6,406.1 $ (113.9 ) $ ā $ 7,393.8 Fees from midstream services 728.0 549.3 ā ā 1,277.3 1,829.6 6,955.4 (113.9 ) ā 8,671.1 Intersegment revenues Sales of commodities 2,628.4 132.2 ā (2,760.6 ) ā Fees from midstream services 7.4 28.7 ā (36.1 ) ā 2,635.8 160.9 ā (2,796.7 ) ā Revenues $ 4,465.4 $ 7,116.3 $ (113.9 ) $ (2,796.7 ) $ 8,671.1 Operating margin $ 1,006.5 $ 867.2 $ (113.9 ) $ ā $ 1,759.8 Other financial information: Total assets (1) $ 11,929.8 $ 6,741.8 $ 1.0 $ 71.9 $ 18,744.5 Goodwill $ 45.2 $ ā $ ā $ ā $ 45.2 Capital expenditures $ 1,273.3 $ 1,412.2 $ ā $ 23.5 $ 2,709.0 (1) Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Year Ended December 31, 2018 Gathering and Processing Logistics and Transportation Other Corporate and Eliminations Total Revenues Sales of commodities $ 1,228.2 $ 8,058.4 $ (7.9 ) $ ā $ 9,278.7 Fees from midstream services 715.6 489.7 ā ā 1,205.3 1,943.8 8,548.1 (7.9 ) ā 10,484.0 Intersegment revenues Sales of commodities 3,636.0 317.1 ā (3,953.1 ) ā Fees from midstream services 7.2 30.8 ā (38.0 ) ā 3,643.2 347.9 ā (3,991.1 ) ā Revenues $ 5,587.0 $ 8,896.0 $ (7.9 ) $ (3,991.1 ) $ 10,484.0 Operating margin $ 939.2 $ 592.5 $ (7.9 ) $ ā $ 1,523.8 Other financial information: Total assets (1) $ 11,602.7 $ 5,180.6 $ 3.2 $ 103.6 $ 16,890.1 Goodwill $ 46.6 $ ā $ ā $ ā $ 46.6 Capital expenditures $ 1,548.6 $ 1,767.0 $ ā $ 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 Transportation Other Corporate and Eliminations Total Revenues Sales of commodities $ 774.0 $ 6,979.3 $ (2.2 ) $ ā $ 7,751.1 Fees from midstream services 566.3 497.5 ā ā 1,063.8 1,340.3 7,476.8 (2.2 ) ā 8,814.9 Intersegment revenues Sales of commodities 3,154.2 321.9 ā (3,476.1 ) ā Fees from midstream services 6.9 28.0 ā (34.9 ) ā 3,161.1 349.9 ā (3,511.0 ) ā Revenues $ 4,501.4 $ 7,826.7 $ (2.2 ) $ (3,511.0 ) $ 8,814.9 Operating margin $ 776.4 $ 511.8 $ (2.2 ) $ ā $ 1,286.0 Other financial information: Total assets (1) $ 10,787.7 $ 3,507.4 $ 1.4 $ 62.5 $ 14,359.0 Goodwill $ 256.6 $ ā $ ā $ ā $ 256.6 Capital expenditures $ 1,008.9 $ 470.4 $ ā $ 27.2 $ 1,506.5 Business acquisitions $ 987.1 $ ā $ ā $ ā $ 987.1 (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: 2019 2018 2017 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $ 1,321.7 $ 1,810.0 $ 2,005.9 NGL 5,233.8 6,886.9 5,454.2 Condensate and crude oil 716.1 457.9 196.0 Petroleum products 126.3 196.1 144.7 7,397.9 9,350.9 7,800.8 Non-customer revenue: Derivative activities - Hedge 138.0 (39.7 ) (44.7 ) Derivative activities - Non-hedge (1) (142.1 ) (32.5 ) (5.0 ) (4.1 ) (72.2 ) (49.7 ) Total sales of commodities 7,393.8 9,278.7 7,751.1 Fees from midstream services: Revenue recognized from contracts with customers: Gathering and processing 722.4 698.1 523.3 NGL transportation, fractionation and services 169.4 154.6 170.7 Storage, terminaling and export 356.4 313.0 300.8 Other 29.1 39.6 69.0 Total fees from midstream services 1,277.3 1,205.3 1,063.8 Total revenues $ 8,671.1 $ 10,484.0 $ 8,814.9 (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: 2019 2018 2017 Reconciliation of reportable segment operating margin to income (loss) before income taxes: Gathering and Processing operating margin $ 1,006.5 $ 939.2 $ 776.4 Logistics and Transportation operating margin 867.2 592.5 511.8 Other operating margin (113.9 ) (7.9 ) (2.2 ) Depreciation and amortization expense (971.7 ) (815.9 ) (809.5 ) General and administrative expense (267.5 ) (240.8 ) (190.5 ) Impairment of property, plant and equipment (243.2 ) ā (378.0 ) Impairment of goodwill ā (210.0 ) ā Interest expense, net (320.8 ) (170.0 ) (217.8 ) Equity earnings (loss) 39.0 7.3 (17.0 ) Gain (loss) on sale or disposition of business and assets (71.1 ) 0.1 (15.9 ) Gain (loss) from sale of equity-method investment 69.3 ā ā Gain (loss) from financing activities (1.4 ) (1.3 ) (10.9 ) Change in contingent considerations (8.7 ) 8.8 99.6 Other, net (0.2 ) (3.5 ) (4.0 ) Income (loss) before income taxes $ (16.5 ) $ 98.5 $ (258.0 ) |
Selected Quarterly Financial _2
Selected Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Selected Quarterly Financial Information [Abstract] | |
Results of Operations by Quarter | Our results of operations by quarter for the years ended December 31, 2019 and 2018 were as follows: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2019 Revenues $ 2,299.4 $ 1,995.3 $ 1,902.5 $ 2,473.9 $ 8,671.1 Gross margin 573.4 633.7 574.4 $ 771.1 $ 2,552.6 Income (loss) from operations (1) 64.7 117.2 45.9 $ (21.7 ) $ 206.1 Net income (loss) (19.0 ) 51.7 37.5 $ (85.8 ) $ (15.6 ) Net income (loss) attributable to common limited partners (32.5 ) (7.3 ) (41.0 ) $ (179.9 ) $ (260.7 ) 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 (2) 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 ________________ (1) Includes ( 2 ) Includes |
Organization and Operations (De
Organization and Operations (Details) - Series A Cumulative Redeemable Perpetual Preferred Units [Member] - shares | 1 Months Ended | 12 Months Ended | |
Oct. 31, 2015 | Dec. 31, 2019 | Dec. 31, 2018 | |
Subsidiary Of Limited Liability Company Or Limited Partnership [Line Items] | |||
Preferred units, outstanding | 5,000,000 | 5,000,000 | |
Preferred units dividend percentage | 9.00% | 9.00% |
Significant Accounting Polici_3
Significant Accounting Policies (Details) - USD ($) | 1 Months Ended | 12 Months Ended |
Jan. 31, 2019 | Dec. 31, 2019 | |
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | ||
Margin tax rate | 0.75% | |
Accounting Standards Update 2016-02 [Member] | ||
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | ||
Effect on retained earnings | $ 0 | |
Right-of-use asset, net of lease incentives and deferred rent | 64,200,000 | |
Lease incentives and deferred rent | 400,000 | |
Lease liability | $ 64,600,000 | |
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 |
Joint Ventures, Acquisitions _3
Joint Ventures, Acquisitions and Divestitures - Additional Information Joint Ventures (Details) $ in Millions | Feb. 06, 2018MBbls / dJointVenture | Jan. 31, 2018MMcf / d | Jul. 31, 2017mi | Dec. 31, 2019USD ($)Bcf | Dec. 31, 2018 | May 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 |
Business Acquisition [Line Items] | ||||||||
Fractionation-related infrastructure funded and owned percentage | 100.00% | |||||||
Train 6 [Member] | Mont Belvieu, Texas [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Capacity of pipeline | MBbls / d | 100 | |||||||
Altus Midstream Company [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Percentage of interest aquired through option exercised | 16.00% | |||||||
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% | |||||||
Hess Midstream Partners L P | LM4 Plant [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership interest | 50.00% | |||||||
Processing capacity | MMcf / d | 200 | |||||||
Maximum [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% | 20.00% | ||||||
GCX DevCo JV [Member] | GCX [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership interest | 25.00% | 25.00% | 25.00% | |||||
Train 6 DevCo JV [Member] | Train 6 [Member] | Mont Belvieu, Texas [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership interest | 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] | Blackstone Energy Partners [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Percentage of joint venture interest sold | 25.00% | |||||||
Cayenne Joint Venture [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Conversion of existing mile gas pipeline | mi | 62 | |||||||
Percentage of ownership interest acquired | 50.00% | |||||||
Project commencement date | 2017-07 | |||||||
GCX [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership interest | 25.00% | |||||||
GCX [Member] | DCP [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership interest | 25.00% | |||||||
GCX [Member] | KMTP [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership interest | 34.00% | |||||||
GCX [Member] | Maximum [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Capacity of natural gas transported per day | Bcf | 1.98 | |||||||
Carnero Joint Venture [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership interest | 50.00% |
Joint Ventures, Acquisitions _4
Joint Ventures, Acquisitions and Divestitures - Additional Information Acquisitions (Details) | May 30, 2017USD ($) | May 09, 2017USD ($)amiMMcf | Mar. 31, 2017USD ($) | Jan. 26, 2017USD ($)$ / sharesshares | Oct. 31, 2018MMcf | Dec. 31, 2017USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | May 31, 2019USD ($) | Mar. 02, 2017USD ($) | Mar. 01, 2017USD ($) |
Business Acquisition [Line Items] | ||||||||||||
Shares of common stock issued (including shares sold pursuant to underwritersā overallotment option) | shares | 9,200,000 | |||||||||||
Shares issued price | $ / shares | $ 57.65 | |||||||||||
Net proceeds from public offering | $ 524,200,000 | |||||||||||
Cash paid, net of cash acquired | $ 0 | $ 0 | $ 570,800,000 | |||||||||
Flag City Acquisition [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Equity method investment ownership percentage | 60.00% | 60.00% | ||||||||||
Flag City Acquisition [Member] | 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 | $ 308,200,000 | $ 317,000,000 | $ 416,300,000 | ||||||||
Fair value of earn-out payment | 317,100,000 | $ 317,100,000 | ||||||||||
Revenues from acquired businesses | 127,900,000 | |||||||||||
Net loss from acquired businesses | $ (19,800,000) | |||||||||||
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] | Targa Resources Corp [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Cash paid, net of cash acquired | 570,800,000 | |||||||||||
Cash acquired from acquisition | 3,300,000 | |||||||||||
Contingent consideration valuation as of the acquisition date | $ 416,300,000 | |||||||||||
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 acquired | 100.00% | |||||||||||
Flag City Acquisition [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Cash payments related to acquisition | $ 60,000,000 | |||||||||||
Additional final adjustment due on base purchase price paid | $ 3,600,000 | |||||||||||
Gas processing capacity | MMcf | 150 | |||||||||||
Number of miles of gas gathering pipeline systems | mi | 24 | |||||||||||
Area of gas gathering and processing and crude gathering assets | a | 102.1 | |||||||||||
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 |
Joint Ventures, Acquisitions _5
Joint Ventures, Acquisitions and Divestitures - Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - Permian Acquisition [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Pro forma consolidated results of operations [Abstract] | |
Revenues | $ 8,829 |
Net income (loss) | $ (252.2) |
Joint Ventures, Acquisitions _6
Joint Ventures, Acquisitions and Divestitures - Additional Information Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Mar. 01, 2017 | |
Fair value determination (final) [Abstract] | ||||
Goodwill | $ 256.6 | $ 45.2 | $ 46.6 | $ 46.6 |
Permian Acquisition [Member] | ||||
Pro forma consolidated results of operations [Abstract] | ||||
Acquisition-related expenses | $ 5.6 | |||
Fair value determination (final) [Abstract] | ||||
Goodwill | $ 46.6 |
Joint Ventures, Acquisitions _7
Joint Ventures, Acquisitions and Divestitures - Fair Value of the Assets and Liabilities Assumed at Acquisition Date (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 01, 2017 |
Fair value determination (final) [Abstract] | ||||
Goodwill | $ 45.2 | $ 46.6 | $ 256.6 | $ 46.6 |
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 |
Joint Ventures, Acquisitions _8
Joint Ventures, Acquisitions and Divestitures - Additional Information Contingent Liability (Details) - Permian Acquisition [Member] - USD ($) | Dec. 31, 2019 | May 31, 2019 | 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 | ||
Fair value of earn-out payment | $ 317,100,000 | $ 317,100,000 | |||
Maximum [Member] | |||||
Business Acquisition [Line Items] | |||||
Additional cash that may be paid based on potential earn-out payment | $ 935,000,000 |
Joint Ventures, Acquisitions _9
Joint Ventures, Acquisitions and Divestitures - Additional Information Divestiture (Details) - USD ($) $ in Millions | Apr. 03, 2019 | Sep. 12, 2018 | Apr. 04, 2017 | Feb. 28, 2019 | Sep. 30, 2018 | Dec. 31, 2019 | Dec. 31, 2017 | Nov. 30, 2019 | Dec. 31, 2018 | Feb. 06, 2018 |
Business Acquisition [Line Items] | ||||||||||
Fractionation-related infrastructure funded and owned percentage | 100.00% | |||||||||
Sale price of crude gathering and storage business | $ 134 | |||||||||
Other Income (Expense) [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Loss on sale or disposal of assets | $ (59.5) | |||||||||
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 | $ (57.5) | |||||||||
Train 7 [Member] | Williams [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Fractionation-related infrastructure funded and owned percentage | 100.00% | |||||||||
Train 7 [Member] | Mont Belvieu, Texas [Member] | Williams [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Percentage of exercised options to acquire equity interest | 20.00% | |||||||||
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 | |||||||||
Targa Badlands LLC [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Subsidiary ownership interest sale percentage | 45.00% | |||||||||
Cash consideration received on sale of interest on subsidiary | $ 1,600 | |||||||||
Option to purchase equity interest percentage | 7.50% | |||||||||
Venice Energy Services Company, L.L.C. [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Ownership interest | 76.80% |
Joint Ventures, Acquisitions_10
Joint Ventures, Acquisitions and Divestitures - Schedule of Carrying Amounts of Assets and Liabilities Held for Sale (Details) $ in Millions | Dec. 31, 2019USD ($) |
Current assets: | |
Trade receivables | $ 6.9 |
Intangible assets, net accumulated amortization and estimated loss on sale | 52.1 |
Goodwill | 1.4 |
Property, plant and equipment, net of accumulated depreciation and estimated loss on sale | 77.3 |
Total assets held for sale | 137.7 |
Current liabilities: | |
Accounts payable and accrued liabilities | 6.2 |
Other long-term obligations | 0.2 |
Total liabilities held for sale | $ 6.4 |
Inventories (Details)
Inventories (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Inventory Disclosure [Abstract] | ||
Commodities | $ 156.5 | $ 151.1 |
Materials and supplies | 5 | 13.6 |
Total inventory | $ 161.5 | $ 164.7 |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 19,870.6 | $ 17,213.8 | |
Accumulated depreciation and amortization | (5,321.6) | (4,285.5) | |
Property, plant and equipment, net | 14,549 | 12,928.3 | |
Intangible assets | 2,643.5 | 2,736.6 | |
Accumulated amortization | (908.5) | (753.4) | |
Intangible assets, net | $ 1,735 | 1,983.2 | $ 2,165.8 |
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 | $ 8,976.8 | 7,547.9 | |
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 | $ 5,137 | 4,001 | |
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 | $ 1,495.5 | 1,138.7 | |
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 | $ 2,292.4 | 445.1 | |
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 | 50 years | ||
Other Property, Plant and Equipment [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 183.9 | 334.3 | |
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 | $ 159.7 | 144.3 | |
Construction in Progress [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | 1,576.5 | $ 3,602.5 | |
Finance Lease Right-of-Use Assets [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 48.8 |
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, 2019 | Jun. 30, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Property Plant And Equipment [Line Items] | |||||
Depreciation expense | $ 800.1 | $ 633.3 | $ 621.3 | ||
Write-down/impairment charge of assets | $ 229 | 243.2 | 0 | 378 | |
Gain on sale of inland marine barge business | 48.1 | ||||
Gain recognized in exchange of assets | (71.1) | 0.1 | $ (15.9) | ||
Versado Gathering System [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Gain recognized in exchange of assets | $ 44.4 | ||||
Logistics and Transportation [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Proceeds from sale of property | $ 69.3 | ||||
Gas Processing Facilities [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Write-down/impairment charge of assets | $ 225.3 | ||||
Gathering and Processing Segment [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Write-down/impairment charge of assets | 17.9 | ||||
Cumulative Impact of Adjustment [Member] | |||||
Property Plant And Equipment [Line Items] | |||||
Depreciation expense | $ 12.5 |
Property, Plant and Equipment_5
Property, Plant and Equipment and Intangible Assets - Intangible Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Intangible Assets, net [Roll Forward] | |||
Amortization | $ 171.6 | $ 182.6 | $ 188.2 |
Estimated amortization expense for intangible assets [Abstract] | |||
2020 | 159.4 | ||
2021 | 149.5 | ||
2022 | 141.2 | ||
2023 | 136 | ||
2024 | $ 132.2 | ||
Weighted average amortization period, intangible assets | 14 years 2 months 12 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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Intangible Assets, net [Roll Forward] | |||
Beginning of period | $ 1,983.2 | $ 2,165.8 | |
Held for sale assets | (76.6) | ||
Amortization | (171.6) | (182.6) | $ (188.2) |
End of period | $ 1,735 | $ 1,983.2 | $ 2,165.8 |
Goodwill (Details)
Goodwill (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 01, 2017 | |
Goodwill [Line Items] | |||||
Goodwill | $ 46,600,000 | $ 45,200,000 | $ 46,600,000 | $ 256,600,000 | $ 46,600,000 |
Goodwill impairment | 210,000,000 | $ 0 | $ 210,000,000 | $ 0 | |
Permian Acquisition [Member] | |||||
Goodwill [Line Items] | |||||
Goodwill | $ 46,600,000 | ||||
WestTX And SouthTX [Member] | |||||
Goodwill [Line Items] | |||||
Goodwill impairment | $ 210,000,000 |
Goodwill - Changes in Net Amoun
Goodwill - Changes in Net Amounts of Goodwill (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 01, 2017 | ||
Goodwill [Roll Forward] | ||||||
Goodwill | $ 571,400,000 | $ 571,400,000 | $ 571,400,000 | $ 571,400,000 | ||
Goodwill allocated to held for sale assets | (1,400,000) | |||||
Accumulated impairment losses | (524,800,000) | (524,800,000) | (524,800,000) | (314,800,000) | ||
Net | 46,600,000 | 45,200,000 | 46,600,000 | 256,600,000 | $ 46,600,000 | |
Impairment | (210,000,000) | 0 | (210,000,000) | 0 | ||
WestTX [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Goodwill | 364,500,000 | 364,500,000 | 364,500,000 | 364,500,000 | ||
Accumulated impairment losses | (364,500,000) | (364,500,000) | (364,500,000) | (189,800,000) | ||
Net | 174,700,000 | |||||
Impairment | (174,700,000) | |||||
SouthTX [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Goodwill | 160,300,000 | 160,300,000 | 160,300,000 | 160,300,000 | ||
Accumulated impairment losses | (160,300,000) | (160,300,000) | (160,300,000) | (125,000,000) | ||
Net | 35,300,000 | |||||
Impairment | (35,300,000) | |||||
New Midland [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Goodwill | 23,200,000 | 23,200,000 | 23,200,000 | 23,200,000 | ||
Net | 23,200,000 | 23,200,000 | 23,200,000 | 23,200,000 | ||
New Delaware [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Goodwill | 23,400,000 | 23,400,000 | 23,400,000 | |||
Net | $ 23,400,000 | $ 23,400,000 | $ 23,400,000 | |||
Reporting unit aggregation | [1] | (23,400,000) | ||||
Delaware Supersystem [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Goodwill | 23,400,000 | |||||
Goodwill allocated to held for sale assets | (1,400,000) | |||||
Net | 22,000,000 | |||||
Reporting unit aggregation | [1] | $ 23,400,000 | ||||
[1] | In 2019, we began aggregating the results of Delaware Supersystem activity, including New Delaware. Discrete financial information for New Delaware is no longer available and management now reviews aggregate Delaware Supersystem operating results. |
Investments in Unconsolidated_3
Investments in Unconsolidated Affiliates - Additional Information (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2017USD ($) | Dec. 31, 2019USD ($)JointVenture | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Jan. 31, 2020USD ($) | |
Schedule Of Equity Method Investments [Line Items] | |||||
Proceeds from sale of equity-method investments, net of contingent consideration received | $ 73.8 | ||||
Gain (loss) from sale of equity-method investment | $ 69.3 | $ 0 | $ 0 | ||
Subsequent Event [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Equity-method investment contingent consideration received | $ 3.5 | ||||
T2 Joint Ventures [Member] | Gathering and Processing [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Number of operated joint ventures acquired in Atlas mergers | JointVenture | 2 | ||||
T2 La Salle [Member] | Gathering and Processing [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Ownership interest | 75.00% | ||||
T2 Eagle Ford [Member] | Gathering and Processing [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Ownership interest | 50.00% | ||||
Little Missouri 4 [Member] | Gathering and Processing [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Ownership interest | 50.00% | ||||
GCX [Member] | Logistics and Transportation [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Ownership interest | 25.00% | ||||
Gulf Coast Fractionators LP [Member] | Logistics and Transportation [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Ownership interest | 38.80% | ||||
Cayenne [Member] | Logistics and Transportation [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 |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | $ 490.5 | $ 221.6 | $ 240.8 | |||
Equity earnings (loss) | 39 | 7.3 | (17) | |||
Cash Distributions | (53.1) | (34.3) | [1] | (12.7) | ||
Acquisition (Disposition) | (4.5) | 1.4 | 5 | |||
Contributions | 266.8 | 294.5 | [2] | 5.5 | ||
Balance at end of period | 738.7 | 490.5 | 221.6 | |||
GCX [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | [3] | 211.6 | ||||
Equity earnings (loss) | [3] | 27.7 | 0.8 | |||
Cash Distributions | [3] | (25.3) | ||||
Contributions | [3] | 233.5 | 210.8 | [2] | ||
Balance at end of period | [3] | 447.5 | 211.6 | |||
T2 Eagle Ford [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 99 | [4] | 109.2 | 118.6 | ||
Equity earnings (loss) | (9.4) | [4] | (10.2) | (10.6) | ||
Contributions | 1.2 | |||||
Balance at end of period | 89.6 | [4] | 99 | [4] | 109.2 | |
Little Missouri 4 [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 67.3 | |||||
Equity earnings (loss) | 3.4 | |||||
Cash Distributions | [1] | (8) | ||||
Contributions | 33 | 75.3 | [2] | |||
Balance at end of period | 103.7 | 67.3 | ||||
T2 La Salle [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 49.3 | [4] | 54.1 | 58.6 | ||
Equity earnings (loss) | (4.5) | [4] | (4.9) | (4.9) | ||
Contributions | 0.1 | [2] | 0.4 | |||
Balance at end of period | 44.8 | [4] | 49.3 | [4] | 54.1 | |
Gulf Coast Fractionators LP [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 40.3 | 45.8 | 46.1 | |||
Equity earnings (loss) | 16.1 | 16.8 | 12.4 | |||
Cash Distributions | (19.2) | (22.3) | [1] | (12.7) | ||
Balance at end of period | 37.2 | 40.3 | 45.8 | |||
Cayenne Joint Venture [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 16.6 | 8.6 | ||||
Equity earnings (loss) | 7.2 | 6.4 | ||||
Cash Distributions | (8.2) | (4) | [1] | |||
Acquisition (Disposition) | 5 | |||||
Contributions | 0.3 | 5.6 | [2] | 3.6 | ||
Balance at end of period | 15.9 | 16.6 | 8.6 | |||
T2 EF Cogen [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 3.9 | 17.5 | ||||
Equity earnings (loss) | (1.8) | (13.9) | ||||
Acquisition (Disposition) | (2.1) | |||||
Contributions | 0.3 | |||||
Balance at end of period | $ 3.9 | |||||
Agua Blanca [Member] | ||||||
Schedule Of Equity Method Investments [Line Items] | ||||||
Balance at beginning of period | 6.4 | |||||
Equity earnings (loss) | (1.5) | 0.2 | ||||
Cash Distributions | (0.4) | |||||
Acquisition (Disposition) | $ (4.5) | 3.5 | ||||
Contributions | [2] | 2.7 | ||||
Balance at end of period | $ 6.4 | |||||
[1] | Includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures. | |||||
[2] | Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4. | |||||
[3] | As discussed in Note 4 ā Joint Ventures, Acquisitions and Divestitures, our 25% interest in GCX is owned by GCX DevCo JV, of which we own a 20% interest. GCX DevCo JV is accounted for on a consolidated basis in our consolidated financial statements. | |||||
[4] | The carrying values of the T2 Joint Ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. |
Investments in Unconsolidated_5
Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Parenthetical) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Feb. 06, 2018 | |
Schedule Of Equity Method Investments [Line Items] | ||||
Return of capital from unconsolidated affiliate | $ 3.5 | $ 5.5 | $ 0.2 | |
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% | 20.00% | ||
GCX DevCo JV [Member] | GCX [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Ownership interest | 25.00% | 25.00% | 25.00% | |
Little Missouri 4 [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Return of capital from unconsolidated affiliate | $ 8 | |||
T2 LaSalle and T2 Eagle Ford [Member] | ||||
Schedule Of Equity Method Investments [Line Items] | ||||
Unamortized excess fair value | $ 23.1 | |||
Preliminary estimated useful lives of the underlying assets | 20 years |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Equity Method Investment Summarized Financial Information [Abstract] | |||
Current assets | $ 136.3 | $ 200.7 | |
Non-current assets | 2,291.6 | 1,329.7 | |
Current liabilities | 93.8 | 233.9 | |
Non-current liabilities | 3.4 | 179.2 | |
Net assets | 2,330.7 | 1,117.3 | |
Operating revenues | 265.5 | 130.6 | $ 84.3 |
Operating expenses | 144.2 | 96.9 | 80.5 |
Net income (loss) | $ 87.7 | $ 34.7 | $ 3.4 |
Accounts Payable and Accrued _3
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Components of accounts payable and accrued liabilities [Abstract] | |||
Commodities | $ 683.6 | $ 721.9 | |
Other goods and services | 311.5 | 474.5 | |
Interest | 125.4 | 79.4 | |
Income and other taxes | 62 | 45.4 | |
Accrued distributions to noncontrolling interests | 91.7 | ||
Other | 9.5 | 7.5 | |
Accounts payable and accrued liabilities | $ 1,283.7 | 1,636.9 | |
Permian Acquisition [Member] | |||
Components of accounts payable and accrued liabilities [Abstract] | |||
Permian Acquisition contingent consideration | $ 308.2 | $ 6.8 |
Accounts Payable and Accrued _4
Accounts Payable and Accrued Liabilities - Additional Information (Details) - USD ($) $ in Millions | Dec. 31, 2019 | May 31, 2019 | Dec. 31, 2018 |
Payables And Accruals [Line Items] | |||
Outstanding checks | $ 21.6 | $ 52.2 | |
Permian Acquisition [Member] | |||
Payables And Accruals [Line Items] | |||
Fair value of earn-out payment | $ 317.1 | $ 317.1 |
Debt Obligations (Details)
Debt Obligations (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | |
Current: | |||
Securitization Facility, due December 2020 | [1] | $ 370 | $ 280 |
Current debt | 370 | 1,029.4 | |
Debt issuance costs, net of amortization | (1.5) | ||
Finance lease liabilities | 12.2 | ||
Current debt obligations | 382.2 | 1,027.9 | |
Long-term [Abstract] | |||
Long-term debt including unamortized premium (discount) | 7,028.5 | 5,228.5 | |
Debt issuance costs, net of amortization | (49.1) | (31.1) | |
Finance lease liabilities | 25.8 | ||
Long-term debt | 7,005.2 | 5,197.4 | |
Total debt obligations | 7,387.4 | 6,225.3 | |
Irrevocable standby letters of credit outstanding | [2] | 88.2 | 79.5 |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | |||
Current: | |||
Long-term debt, current | [3] | 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 5ā % Notes due April 2026 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 1,000 | 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 6 1/2% Notes due July 2027 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 750 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2028 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 750 | 750 | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 7/8% Notes due January 2029 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 750 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/2 % Notes due March 2030 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 1,000 | ||
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 | [4] | 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 | [4] | 48.1 | 48.1 |
Unamortized premium | $ 0.3 | 0.3 | |
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due June 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [2] | $ 700 | |
[1] | As of DecemberĀ 31, 2019, we had $400.0 million of qualifying receivables under our $400.0 million Securitization Facility, resulting in availability of $30.0 million. | ||
[2] | As of December 31, 2019, availability under our $2.2 billion senior secured revolving credit facility (āTRP Revolverā) was $2,111.8 million. | ||
[3] | The 4ā | ||
[4] | āTPLā refers to Targa Pipeline Partners LP. |
Debt Obligations (Parenthetical
Debt Obligations (Parenthetical) (Details) - USD ($) $ in Millions | Feb. 11, 2019 | Nov. 30, 2019 | Apr. 30, 2018 | Oct. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Jan. 31, 2019 | ||
Debt Instrument [Line Items] | ||||||||||
Proceeds from borrowings under accounts receivable securitization facility | $ 944.2 | $ 546.6 | $ 666.6 | |||||||
Accounts receivable securitization facility | [1] | $ 370 | $ 280 | |||||||
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 | 2,111.8 | |||||||||
Securitization Facility [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Proceeds from borrowings under accounts receivable securitization facility | 400 | |||||||||
Accounts receivable securitization facility | 400 | |||||||||
Availability amount under accounts receivable securitization | $ 30 | |||||||||
Securitization Facility [Member] | Securitization Facility Due December 2020 [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maturity date | [1] | Dec. 31, 2020 | ||||||||
Senior Unsecured Notes [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 | Nov. 30, 2019 | [3] | |||||||
Interest rate on fixed rate debt | 4.125% | 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 | 4.125% | |||||||||
Senior Unsecured Notes [Member] | Senior Unsecured 5ā % 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 6 1/2% Notes due July 2027 [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maturity date | Jul. 31, 2027 | |||||||||
Interest rate on fixed rate debt | 6.50% | |||||||||
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] | Senior Unsecured 6 7/8% Notes due January 2029 [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maturity date | Jan. 31, 2029 | |||||||||
Interest rate on fixed rate debt | 6.875% | |||||||||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/2 % Notes due March 2030 [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maturity date | Mar. 31, 2030 | Mar. 31, 2030 | ||||||||
Interest rate on fixed rate debt | 5.50% | 5.50% | ||||||||
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 | [4] | 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 | [4] | Nov. 30, 2021 | ||||||||
Interest rate on fixed rate debt | 4.75% | |||||||||
[1] | As of DecemberĀ 31, 2019, we had $400.0 million of qualifying receivables under our $400.0 million Securitization Facility, resulting in availability of $30.0 million. | |||||||||
[2] | As of December 31, 2019, availability under our $2.2 billion senior secured revolving credit facility (āTRP Revolverā) was $2,111.8 million. | |||||||||
[3] | The 4ā | |||||||||
[4] | āTPLā refers to Targa Pipeline Partners LP. |
Debt Obligations - Schedule of
Debt Obligations - Schedule of Contractual Maturities of Outstanding Debt Obligations (Details) $ in Millions | Dec. 31, 2019USD ($) |
Contractual Obligation [Line Items] | |
Total | $ 7,398.2 |
2020 | 370 |
2021 | 6.5 |
2022 | 0 |
2023 | 1,191.6 |
2024 | 580.1 |
After 2024 | 5,250 |
Securitization Facility [Member] | |
Contractual Obligation [Line Items] | |
Total | 370 |
2020 | 370 |
2021 | 0 |
2022 | 0 |
2023 | 0 |
2024 | 0 |
After 2024 | 0 |
Senior Unsecured Notes [Member] | |
Contractual Obligation [Line Items] | |
Total | 7,028.2 |
2020 | 0 |
2021 | 6.5 |
2022 | 0 |
2023 | 1,191.6 |
2024 | 580.1 |
After 2024 | $ 5,250 |
Debt Obligations - Interest Rat
Debt Obligations - Interest Rates on Variable-Rate Debt Obligations (Details) | Dec. 31, 2019 |
Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Weighted average interest rate incurred | 3.10% |
Minimum [Member] | Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred | 2.60% |
Maximum [Member] | 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 | 4.10% |
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 | 4.70% |
Debt Obligations - Revolving Cr
Debt Obligations - Revolving Credit Agreement (Details) - TRP Revolver [Member] | Jul. 01, 2020 | Jun. 29, 2019 | Feb. 17, 2016 | Jun. 30, 2020 | Dec. 31, 2019USD ($) |
Debt Instrument [Line Items] | |||||
Maximum borrowing capacity | $ 2,200,000,000 | ||||
Additional commitment increase available upon request | $ 500,000,000 | ||||
First Amendment [Member] | |||||
Debt Instrument [Line Items] | |||||
Maximum percentage of consolidated EBITDA | 20.00% | ||||
Scenario Forecast [Member] | First Amendment [Member] | |||||
Debt Instrument [Line Items] | |||||
Maximum percentage of consolidated EBITDA | 20.00% | 30.00% | |||
Federal Funds Rate [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 0.50% | ||||
London Interbank Offered Rate (LIBOR) | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 1.00% | ||||
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 | ||||
Interest coverage ratio | 1 | ||||
Minimum [Member] | Letters of Credit [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on fixed rate debt | 1.25% | ||||
Minimum [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | |||||
Debt Instrument [Line Items] | |||||
Commitment fee percentage | 0.125% | ||||
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% | ||||
Minimum [Member] | Base Rate [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 0.25% | ||||
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% | ||||
Minimum [Member] | Eurodollar [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 1.25% | ||||
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% | ||||
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 | ||||
Interest coverage ratio | 2.25 | ||||
Aggregate principal amount | $ 400,000,000 | ||||
Maximum [Member] | Letters of Credit [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on fixed rate debt | 2.25% | ||||
Maximum [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | |||||
Debt Instrument [Line Items] | |||||
Commitment fee percentage | 0.35% | ||||
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% | ||||
Maximum [Member] | Base Rate [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 1.25% | ||||
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% | ||||
Maximum [Member] | Eurodollar [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 2.25% | ||||
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. 06, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | |
Debt Instrument [Line Items] | ||||
Funding under securitization facility | [1] | $ 370,000,000 | $ 280,000,000 | |
Accounts Receivable Securitization Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Securitization facility termination date | Dec. 6, 2019 | |||
Maximum borrowing capacity | 400,000,000 | |||
Funding under securitization facility | $ 370,000,000 | |||
[1] | As of DecemberĀ 31, 2019, we had $400.0 million of qualifying receivables under our $400.0 million Securitization Facility, resulting in availability of $30.0 million. |
Debt Obligations - Senior Unsec
Debt Obligations - Senior Unsecured Notes (Details) - Senior Unsecured Notes [Member] | 12 Months Ended |
Dec. 31, 2019 | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days |
Debt Obligations - Senior Uns_2
Debt Obligations - Senior Unsecured Notes Issuances (Details) - Senior Unsecured Notes [Member] - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||||
Nov. 30, 2019 | Jan. 31, 2019 | Apr. 30, 2018 | Oct. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | |
Debt Instrument [Line Items] | ||||||
Interest rate on fixed rate debt | 4.125% | |||||
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 5ā % 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 | |||||
6 1/2% Senior Notes due July 2027 [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 | $ 1,486.6 | |||||
6 7/8% Senior Notes due January 2029 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior notes issued | $ 750 | |||||
Interest rate on fixed rate debt | 6.875% | |||||
Maturity date | Jan. 31, 2029 | |||||
Senior Unsecured 5 1/2 % Notes due March 2030 [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior notes issued | $ 1,000 | |||||
Interest rate on fixed rate debt | 5.50% | 5.50% | ||||
Maturity date | Mar. 31, 2030 | Mar. 31, 2030 | ||||
Net proceeds from senior notes | $ 990.8 |
Debt Obligations - Debt Repurch
Debt Obligations - Debt Repurchases and Extinguishments (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||||
Jun. 30, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Feb. 28, 2019 | Jan. 31, 2019 | Oct. 31, 2017 | |
Debt Instrument [Line Items] | |||||||
Gain (loss) from financing activities | $ (1.4) | $ (1.3) | $ (10.9) | ||||
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 4 1/8% Notes due 2019 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate on fixed rate debt | 4.125% | ||||||
Write off debt issuance cost | $ 1.4 | ||||||
Senior Unsecured Notes [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate on fixed rate debt | 4.125% | ||||||
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 - Impact of De
Debt Obligations - Impact of Debt Repurchases and Extinguishments Summary (Details) - Senior Unsecured Notes [Member] - USD ($) $ in Millions | 10 Months Ended | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | |
Debt Instrument [Line Items] | |||
Write-off of debt issuance costs | $ 1.3 | ||
Loss (gain) from financing activities | $ 10.9 | $ 1.4 | $ 1.3 |
6ā % Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Premium over face value paid upon redemption | 8.9 | ||
Write-off of debt issuance costs | 1.8 | ||
4ā % Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Write-off of debt issuance costs | $ 1.4 | ||
5% Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Other Liabilities Noncurrent [Abstract] | |||
Asset retirement obligations | $ 65.8 | $ 55 | $ 50.3 |
Deferred revenue | 172 | 175.5 | $ 136.2 |
Operating lease liabilities | 18.2 | ||
Other liabilities | 4 | 3.3 | |
Total long-term liabilities | $ 260 | $ 233.8 |
Other Long-term Liabilities - C
Other Long-term Liabilities - Changes in Aggregate Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Beginning of period | $ 55 | $ 50.3 | ||
Additions | [1] | 11.8 | ||
Change in cash flow estimate | (5.1) | 1.8 | ||
Accretion expense | 4.7 | 3.7 | $ 3.9 | |
Retirement of ARO | (0.6) | (0.8) | ||
End of period | $ 65.8 | $ 55 | $ 50.3 | |
[1] | Amount reflects additions of ARO related to the commencement of operations of Grand Prix. |
Other Long-term Liabilities - M
Other Long-term Liabilities - Mandatorily Redeemable Preferred Interests (Details) | 12 Months Ended | ||
Dec. 31, 2019USD ($)JointVenture | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | |
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Interest expense, net | $ (320,800,000) | $ (170,000,000) | $ (217,800,000) |
Change in estimated redemption value of mandatorily redeemable preferred interests | 0 | 72,100,000 | (3,300,000) |
Mandatorily Redeemable Preferred Interests [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Interest expense, net | 10,200,000 | 9,700,000 | $ 10,300,000 |
Change in estimated redemption value of mandatorily redeemable preferred interests | 72,100,000 | ||
Income attributable to mandatorily redeemable preferred interests | $ 4,100,000 | ||
Estimated redemption value | $ 0 | ||
Mandatorily Redeemable Preferred Interests [Member] | Joint Ventures [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Number of joint ventures | JointVenture | 2 | ||
Notes receivable, face amount | $ 1,900,000,000 | ||
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) - USD ($) | 10 Months Ended | 12 Months Ended | |||||
Dec. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | May 31, 2019 | Mar. 02, 2017 | Dec. 31, 2016 | |
Deferred Revenue [Abstract] | |||||||
Revenue recognized | $ 3,900,000 | $ 3,900,000 | $ 3,100,000 | ||||
Deferred revenue | $ 136,200,000 | 172,000,000 | 175,500,000 | 136,200,000 | |||
Increase (decrease) in fair value of contingent consideration liability | 8,700,000 | (8,800,000) | (99,600,000) | ||||
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) | 8,900,000 | (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 | ||||
Fair value of earn-out payment | 317,100,000 | $ 317,100,000 | |||||
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] | |||||||
Deferred revenue | $ 129,000,000 | 129,000,000 | |||||
Noble Americas Corp [Member] | Channelview Splitter [Member] | |||||||
Deferred Revenue [Abstract] | |||||||
Deferred revenue | $ 129,000,000 | $ 129,000,000 | $ 129,000,000 | $ 129,000,000 |
Other Long-term Liabilities -_2
Other Long-term Liabilities - Components Of Deferred Revenue (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | $ 172 | $ 175.5 | $ 136.2 |
Other Deferred Revenue [Member] | |||
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | 3.2 | 4.3 | |
Gas Contract Amendment [Member] | |||
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | 39.8 | 42.2 | |
Channelview Splitter [Member] | |||
Deferred Revenue Arrangement [Line Items] | |||
Total deferred revenue | $ 129 | $ 129 |
Other Long-term Liabilities -_3
Other Long-term Liabilities - Changes In Deferred Revenue (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Other Liabilities Noncurrent [Abstract] | |||
Balance at December 31, 2018 | $ 175.5 | $ 136.2 | |
Additions | 0.4 | 43.2 | |
Revenue recognized | (3.9) | (3.9) | $ (3.1) |
Balance at December 31, 2019 | $ 172 | $ 175.5 | $ 136.2 |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | May 31, 2019 | |
Business Acquisition Contingent Consideration [Line Items] | |||||
Increase (decrease) in fair value, included in Other income (expense) | $ 8.7 | $ (8.8) | $ (99.6) | ||
Permian Acquisition [Member] | |||||
Business Acquisition Contingent Consideration [Line Items] | |||||
Beginning of period | $ 416.3 | 308.2 | 317 | ||
Increase (decrease) in fair value, included in Other income (expense) | (99.3) | 8.9 | (8.8) | ||
Earn-out payment | $ (317.1) | $ (317.1) | |||
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 |
Leases - Additional Information
Leases - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2019 | |
Lessee Lease Description [Line Items] | |||
Weighted average remaining lease term for operating lease | 4 years | ||
Weighted average remaining lease term for finance lease | 3 years | ||
Weighted average discount rate for operating leases | 3.90% | ||
Weighted average discount rate for finance leases | 3.90% | ||
Compressors and Equipment [Member] | |||
Lessee Lease Description [Line Items] | |||
Total operating leases expense | $ 51.9 | $ 46.2 | |
Minimum [Member] | |||
Lessee Lease Description [Line Items] | |||
Leases, remaining lease term | 1 year | ||
Maximum [Member] | |||
Lessee Lease Description [Line Items] | |||
Leases, remaining lease term | 5 years | ||
Options to extend lease term | 10 years |
Leases - Summary of Balances of
Leases - Summary of Balances of Right-of-Use Assets and Liabilities of Finance and Operating Leases (Details) $ in Millions | Dec. 31, 2019USD ($) |
Right-of-use assets | |
Operating leases, gross | $ 31.6 |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List] | us-gaap:OtherAssetsNoncurrent |
Finance leases, gross | $ 48.8 |
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List] | us-gaap:PropertyPlantAndEquipmentGross |
Current: | |
Operating leases | $ 6.5 |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | us-gaap:AccountsPayableAndAccruedLiabilitiesCurrent |
Finance leases | $ 12.2 |
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List] | us-gaap:LiabilitiesCurrent |
Non-current: | |
Operating leases | $ 18.2 |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | us-gaap:OtherLiabilitiesNoncurrent |
Finance leases | $ 25.8 |
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | us-gaap:LiabilitiesNoncurrent |
Leases - Components of Lease Ex
Leases - Components of Lease Expense (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Lease cost | |
Operating lease cost | $ 8.2 |
Short-term lease cost | 30 |
Variable lease cost | 4.9 |
Finance lease cost | |
Amortization of right-of-use assets | 13.1 |
Interest expense | 1.6 |
Total lease cost | $ 57.8 |
Leases - Summary of Other Suppl
Leases - Summary of Other Supplemental Information Related to Leases (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash paid for amounts included in the measurement of lease liabilities: | |||
Operating cash flows for operating leases | $ 8.2 | ||
Operating cash flows for finance leases | 1.6 | ||
Financing cash flows for finance leases | $ 11.5 | $ 0 | $ 0 |
Leases - Summary of Maturities
Leases - Summary of Maturities of Lease Liabilities under Non-cancellable Leases (Details) $ in Millions | Dec. 31, 2019USD ($) |
Future Minimum Lease Payments - Operating Leases | |
2019 | $ 7.4 |
2020 | 6.8 |
2021 | 5.7 |
2022 | 4.2 |
2023 | 2.3 |
Thereafter | 0.4 |
Total undiscounted cash flows | 26.8 |
Less imputed interest | (2.1) |
Total lease liabilities | 24.7 |
Future Minimum Lease Payments - Finance Leases | |
2019 | 13.4 |
2020 | 11.7 |
2021 | 10.2 |
2022 | 4.7 |
2023 | 0.5 |
Total undiscounted cash flows | 40.5 |
Less imputed interest | (2.5) |
Total lease liabilities | $ 38 |
Leases - Summary of Future Mini
Leases - Summary of Future Minimum Payments under Non-cancellable Leases (Details) $ in Millions | Dec. 31, 2018USD ($) |
Future non-cancelable commitments for each of the next five fiscal years and in Aggregate Thereafter [Abstract] | |
2019 | $ 20.5 |
2020 | 17.7 |
2021 | 14.9 |
2022 | 12.6 |
2023 | 6 |
Thereafter | 1.7 |
Total payments | $ 73.4 |
Partnership Units and Related_3
Partnership Units and Related Matters - Distributions (Details) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||
Date Paid | May 11, 2017 | Feb. 13, 2020 | Nov. 13, 2019 | Aug. 13, 2019 | Apr. 5, 2019 | Feb. 13, 2019 | Nov. 13, 2018 | Aug. 13, 2018 | May 11, 2018 | Feb. 12, 2018 | Nov. 10, 2017 | Aug. 10, 2017 | |||
Total Distributions | $ 1,163.7 | $ 929.8 | $ 858.6 | ||||||||||||
Distributions Paid [Member] | |||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||
Total Distributions | $ 209.6 | $ 241.9 | $ 242.1 | $ 242.4 | $ 437.8 | $ 241.3 | $ 237.6 | $ 234 | $ 229.7 | $ 228.5 | $ 225.4 | $ 225.4 | |||
Distributions to Targa Resources Corp. | $ 206.8 | $ 239.1 | $ 239.3 | $ 239.6 | $ 435 | $ 238.5 | $ 234.8 | $ 231.2 | $ 226.9 | $ 225.7 | $ 222.6 | $ 222.6 |
Partnership Units and Related_4
Partnership Units and Related Matters (Details) - USD ($) $ / shares in Units, $ in Millions | Mar. 31, 2017 | Feb. 29, 2020 | Jan. 31, 2020 | Oct. 31, 2015 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Limited Partners Capital Account [Line Items] | ||||||||||||||||||
Contributions from Targa Resources Corp. | $ 200 | $ 600.1 | $ 1,720 | |||||||||||||||
Distribution to holders of preferred units | $ 11.3 | $ 11.3 | 11.3 | |||||||||||||||
Distributions payable date | May 11, 2017 | Feb. 13, 2020 | Nov. 13, 2019 | Aug. 13, 2019 | Apr. 5, 2019 | Feb. 13, 2019 | Nov. 13, 2018 | Aug. 13, 2018 | May 11, 2018 | Feb. 12, 2018 | Nov. 10, 2017 | Aug. 10, 2017 | ||||||
Subsequent Event [Member] | ||||||||||||||||||
Limited Partners Capital Account [Line Items] | ||||||||||||||||||
Date of declaration for cash distribution | 2020-02 | 2020-01 | ||||||||||||||||
Cash distribution declared per unit (in dollars per share) | $ 0.1875 | $ 0.1875 | ||||||||||||||||
Distributions to Targa Resources Corp. | $ 0.9 | $ 0.9 | ||||||||||||||||
Distributions payable date | Mar. 16, 2020 | Feb. 18, 2020 | ||||||||||||||||
Series A Preferred Limited Partner Units [Member] | ||||||||||||||||||
Limited Partners Capital Account [Line Items] | ||||||||||||||||||
Series A preferred limited partners units issued (in units) | 5,000,000 | 5,000,000 | 5,000,000 | 5,000,000 | ||||||||||||||
Preferred units dividend percentage | 9.00% | 9.00% | ||||||||||||||||
Series A preferred limited partners units outstanding (in units) | 5,000,000 | 5,000,000 | 5,000,000 | 5,000,000 | ||||||||||||||
Series A Preferred Limited Partner Units [Member] | London Interbank Offered Rate (LIBOR) | ||||||||||||||||||
Limited Partners Capital Account [Line Items] | ||||||||||||||||||
Percentage of variable interest rate for distribution on preferred units upon maturity | 7.71% | |||||||||||||||||
Series A Preferred Units due November 1, 2020 [Member] | ||||||||||||||||||
Limited Partners Capital Account [Line Items] | ||||||||||||||||||
Preferred unit, redemption price (in dollars per share) | $ 25 | $ 25 | ||||||||||||||||
TRC/TRP Merger [Member] | Limited Partners [Member] | ||||||||||||||||||
Limited Partners Capital Account [Line Items] | ||||||||||||||||||
Percentage of capital contribution towards partner's interest maintained | 98.00% | |||||||||||||||||
TRC/TRP Merger [Member] | Targa Resources GP LLC [Member] | ||||||||||||||||||
Limited Partners Capital Account [Line Items] | ||||||||||||||||||
Percentage of general partner's interest maintained | 2.00% | |||||||||||||||||
Contributions from Targa Resources Corp. (in units) | 0 | |||||||||||||||||
TRC/TRP Merger [Member] | Targa Resources Corp [Member] | ||||||||||||||||||
Limited Partners Capital Account [Line Items] | ||||||||||||||||||
Contributions from Targa Resources Corp. | $ 200 | $ 600 | $ 1,720 |
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, 2019MMBTUbbl | |
Year 2020 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 127,230 |
Year 2020 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 23,105 |
Year 2020 [Member] | Swaps [Member] | Condensate | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 5,471 |
Year 2020 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 364,275 |
Year 2020 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 16,844 |
Year 2021 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 123,751 |
Year 2021 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 11,196 |
Year 2021 [Member] | Swaps [Member] | Condensate | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 3,654 |
Year 2021 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 344,292 |
Year 2021 [Member] | Future | NGL [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 | 46,100 |
Year 2022 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 6,036 |
Year 2022 [Member] | Swaps [Member] | Condensate | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 1,610 |
Year 2022 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 210,000 |
Year 2022 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2024 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 |
Year 2024 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2024 [Member] | Swaps [Member] | Condensate | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2024 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 40,000 |
Year 2024 [Member] | Future | NGL [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] | Swaps [Member] | Condensate | |
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 | 200,000 |
Year 2023 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
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, 2019 | Dec. 31, 2018 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets | $ 138.8 | $ 149.4 |
Derivative assets | 103.3 | 115.3 |
Derivative assets | 35.5 | 34.1 |
Derivative liabilities | 144.9 | 36.7 |
Derivative liabilities | 104.1 | 33.6 |
Derivative liabilities | 40.8 | 3.1 |
Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 135.8 | 144.1 |
Derivative liabilities | 18 | 20.4 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 102.1 | 112.5 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 33.7 | 31.6 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 11.6 | 18.9 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Position [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 6.4 | 1.5 |
Not Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 3 | 5.3 |
Derivative liabilities | 126.9 | 16.3 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 1.2 | 2.8 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 1.8 | 2.5 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 92.5 | 14.7 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Position [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | $ 34.4 | $ 1.6 |
Derivative Instruments and He_5
Derivative Instruments and Hedging Activities - Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Derivative Asset [Abstract] | ||
Gross asset | $ 138.8 | $ 149.4 |
Pro forma net presentation, asset, total | 79.8 | 116.4 |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 133.1 | 108.9 |
Pro forma net presentation, asset | 74.1 | 75.9 |
Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 5.7 | 40.5 |
Pro forma net presentation, asset | 5.7 | 40.5 |
Current Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 103.3 | 115.3 |
Pro forma net presentation, asset, current | 59.5 | 85.3 |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 99.8 | 100 |
Pro forma net presentation, asset | 56 | 70 |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 3.5 | 15.3 |
Pro forma net presentation, asset | 3.5 | 15.3 |
Long-term Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 35.5 | 34.1 |
Pro forma net presentation, asset, noncurrent | 20.3 | 31.1 |
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 33.3 | 8.9 |
Pro forma net presentation, asset | 18.1 | 5.9 |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 2.2 | 25.2 |
Pro forma net presentation, asset | $ 2.2 | $ 25.2 |
Derivative Instruments and He_6
Derivative Instruments and Hedging Activities - Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Derivative Liability [Abstract] | ||
Gross liability | $ (144.9) | $ (36.7) |
Pro forma net presentation, liability, total | (90.8) | (17.9) |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (125.5) | (36.7) |
Pro forma net presentation, liability, total | (71.4) | (17.9) |
Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (19.4) | |
Pro forma net presentation, liability, total | (19.4) | |
Current Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (104.1) | (33.6) |
Pro forma net presentation, liability, current | (65.2) | (17.8) |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (85) | (33.6) |
Pro forma net presentation, liability, current | (46.1) | (17.8) |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (19.1) | |
Pro forma net presentation, liability, current | (19.1) | |
Long-term Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (40.8) | (3.1) |
Pro forma net presentation, liability, noncurrent | (25.6) | (0.1) |
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (40.5) | (3.1) |
Pro forma net presentation, liability, noncurrent | (25.3) | $ (0.1) |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (0.3) | |
Pro forma net presentation, liability, noncurrent | $ (0.3) |
Derivative Instruments and He_7
Derivative Instruments and Hedging Activities - Pro Forma Impact - Offsetting Collateral (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Derivative Asset [Abstract] | ||
Gross collateral | $ (4.9) | $ (14.2) |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross collateral | (4.9) | (14.2) |
Current Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross collateral | (4.9) | (14.2) |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross collateral | $ (4.9) | $ (14.2) |
Derivative Instruments and He_8
Derivative Instruments and Hedging Activities - Additional Information (Details) $ in Millions | Dec. 31, 2019USD ($) |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Estimated fair value of derivative instruments, net liability | $ 6.1 |
Amount expected to reclassify commodity hedge related deferred gains to earnings before income taxes | 117.7 |
Amount of deferred gains to be reclassified into earnings before income taxes over next twelve months | $ 90.9 |
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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (Loss) Reclassified from OCI into Income (Effective Portion) | $ 138 | $ (38.4) | $ (44.6) |
Commodity Contracts [Member] | Revenues [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (Loss) Recognized in Income on Derivatives | (142.1) | (32.5) | (5.1) |
Cash Flow Hedging [Member] | Commodity Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) | $ 135.6 | $ 132.5 | $ (28.8) |
Fair Value Measurements - Addit
Fair Value Measurements - Additional Information (Details) $ in Millions | Dec. 31, 2019USD ($)Swap | May 31, 2019USD ($) |
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||
Derivatives financial instruments, fair value, net | $ 6.1 | |
Derivative fair value of net liability if commodity price increases by 10 percent | 114.2 | |
Derivative fair value of net asset if commodity price decreases by 10 percent | $ 102.1 | |
Number of natural gas basis swaps categorized as Level 3 | Swap | 9 | |
Permian Acquisition [Member] | ||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||
Fair value of earn-out payment | $ 317.1 | $ 317.1 |
Fair Value Measurements - Break
Fair Value Measurements - Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2019 | 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 | $ 79.8 | $ 116.4 | |||
Liabilities from commodity derivative contracts | 90.8 | 17.9 | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||||
Accounts receivable securitization facility | [1] | 370 | 280 | ||
Permian Acquisition [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||||
Contingent consideration | 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] | 136.5 | 144.4 | ||
Liabilities from commodity derivative contracts | [2] | 142.6 | 31.7 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||||
Cash and cash equivalents | 291.1 | 203.3 | |||
Accounts receivable securitization facility | 370 | 280 | |||
Carrying Value [Member] | Permian Acquisition [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||||
Contingent consideration | [3] | 308.2 | |||
Carrying Value [Member] | TRP Revolver [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||||
Long-term debt | 700 | ||||
Carrying Value [Member] | Targa Pipeline Partners LP [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||||
Contingent consideration | [4] | 2.3 | 2.4 | ||
Carrying Value [Member] | Senior Unsecured Notes [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||||
Long-term debt | 7,028.5 | 5,277.9 | |||
Fair Value [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||||
Assets from commodity derivative contracts | [2] | 136.5 | 144.4 | ||
Liabilities from commodity derivative contracts | [2] | 142.6 | 31.7 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||||
Cash and cash equivalents | 291.1 | 203.3 | |||
Accounts receivable securitization facility | 370 | 280 | |||
Fair Value [Member] | Permian Acquisition [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||||
Contingent consideration | [3] | 308.2 | |||
Fair Value [Member] | TRP Revolver [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||||
Long-term debt | 700 | ||||
Fair Value [Member] | Targa Pipeline Partners LP [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||||
Contingent consideration | [4] | 2.3 | 2.4 | ||
Fair Value [Member] | Senior Unsecured Notes [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||||
Long-term debt | 7,376.9 | 5,088.9 | |||
Fair Value [Member] | Level 2 [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||||
Assets from commodity derivative contracts | [2] | 136.2 | 137.5 | ||
Liabilities from commodity derivative contracts | [2] | 142 | 31.3 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||||
Accounts receivable securitization facility | 370 | 280 | |||
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 | ||||
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 | 7,376.9 | 5,088.9 | |||
Fair Value [Member] | Level 3 [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||||
Assets from commodity derivative contracts | [2] | 0.3 | 6.9 | ||
Liabilities from commodity derivative contracts | [2] | 0.6 | 0.4 | ||
Fair Value [Member] | Level 3 [Member] | Permian Acquisition [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||||
Contingent consideration | [3] | 308.2 | |||
Fair Value [Member] | Level 3 [Member] | Targa Pipeline Partners LP [Member] | |||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||||
Contingent consideration | [4] | $ 2.3 | $ 2.4 | ||
[1] | As of DecemberĀ 31, 2019, we had $400.0 million of qualifying receivables under our $400.0 million Securitization Facility, resulting in availability of $30.0 million. | ||||
[2] | The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 14 ā Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes. | ||||
[3] | We had a contingent consideration liability related to the Permian Acquisition, which was carried at fair value. See Note 4 ā Joint Ventures, Acquisitions and Divestitures . | ||||
[4] | We have a contingent consideration liability for TPLās previous acquisition of a gas gathering system and related assets, which is carried at fair value. |
Fair Value Measurements - Chang
Fair Value Measurements - Changes in Fair Value of Financial Instruments Classified as Level 3 (Details) - USD ($) $ in Millions | 10 Months Ended | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |||||
Change in contingent considerations | $ 8.7 | $ (8.8) | $ (99.6) | ||
Contingent Consideration [Member] | |||||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |||||
Balance, beginning of period | (310.6) | ||||
Balance, end of period | (2.3) | (310.6) | |||
Targa Pipeline Partners LP [Member] | Contingent Consideration [Member] | |||||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |||||
Change in contingent considerations | 0.1 | ||||
Permian Acquisition [Member] | |||||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |||||
Change in contingent considerations | $ (99.3) | 8.9 | (8.8) | ||
Permian Acquisition [Member] | Contingent Consideration [Member] | |||||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |||||
Completion of contingent consideration earn-out period | 308.2 | ||||
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 | 6.5 | ||||
New Level 3 derivative instruments | (0.7) | ||||
Transfers out of Level 3 | [1] | (6.5) | |||
Unrealized gain/(loss) included in OCI | 0.4 | ||||
Balance, end of period | $ (0.3) | $ 6.5 | |||
[1] | Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term. |
Related Party Transactions - Su
Related Party Transactions - Summary of Transactions with Unconsolidated Affiliates (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Related Party Transaction [Line Items] | |||
Revenues | $ 11 | $ 5.6 | $ 2.4 |
Product purchases | (40.5) | (14.1) | (5.5) |
Operating expenses | (3.4) | (3.6) | (3.8) |
General and administrative expenses | (0.3) | ||
Gulf Coast Fractionators LP [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues | 0.3 | 0.3 | 0.3 |
Product purchases | (7.9) | (5.1) | (4.4) |
T2 Joint Ventures [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues | 3.7 | 5.2 | 2.1 |
Product purchases | (0.6) | (1.1) | |
Operating expenses | (2) | (3.6) | $ (3.8) |
Cayenne [Member] | |||
Related Party Transaction [Line Items] | |||
Product purchases | (7.9) | (7.2) | |
Operating expenses | (0.2) | ||
GCX [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues | 0.8 | 0.1 | |
Product purchases | (24.7) | $ (1.2) | |
Little Missouri 4 [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues | 6.3 | ||
General and administrative expenses | (0.3) | ||
Agua Blanca [Member] | |||
Related Party Transaction [Line Items] | |||
Operating expenses | $ (1.2) |
Related Party Transactions - _2
Related Party Transactions - Summary of Transactions with Affiliates (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Summary of transactions with Targa [Abstract] | ||||
Targa allocation of general and administrative expense | $ 0.3 | |||
Cash distributions to Targa based on general partner and limited partner ownership | 1,163.7 | $ 929.8 | $ 858.6 | |
Cash contributions from Targa related to limited partner ownership | 196 | 588.1 | 1,685.5 | |
Targa Resources Corp. [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Targa billings of payroll and related costs included in operating expenses | 248.8 | 236.8 | 204.4 | |
Targa allocation of general and administrative expense | 237.2 | 221.4 | 175.2 | |
Cash distributions to Targa based on general partner and limited partner ownership | 1,152.4 | 918.5 | 847.3 | |
Cash contributions from Targa related to limited partner ownership | [1] | 196 | 588.1 | 1,685.5 |
Contributions from Targa Resources Corp | $ 4 | $ 12 | $ 34.5 | |
Targa Resources Corp. [Member] | Targa Resources GP LLC [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Percentage of general partner's interest maintained | 2.00% | 2.00% | 2.00% | |
[1] | The cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to the general partner. See Note 13 ā 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, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Limited Partners [Member] | |||
Related Party Transaction [Line Items] | |||
Percentage of capital contribution towards partner's interest maintained | 98.00% | 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% | 2.00% |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |||||
Mar. 31, 2018USD ($) | Dec. 31, 2019USD ($)PromissoryNote | Apr. 30, 2018USD ($) | Feb. 28, 2018USD ($) | Jan. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2010 | |
Warburg Funds Transaction [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Percentage of ownership interest acquired | 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 | ||||||
Extinguishment of debt in exchange for promissory note | $ 9.9 | ||||||
Minority shareholders interest sold | 1.60% | ||||||
Minority shareholders interest amount | $ 0.1 | ||||||
Number of outstanding promissory notes | PromissoryNote | 3 | ||||||
SAJET Resources LLC [Member] | Promissory Note One [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Promissory notes outstanding | $ 9.9 | ||||||
Basis spread on variable rate | 6.00% | ||||||
Variable rate basis | prime rate | ||||||
SAJET Resources LLC [Member] | Promissory Note Two [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Promissory notes outstanding | $ 0.5 | ||||||
Basis spread on variable rate | 6.00% | ||||||
Variable rate basis | prime rate | ||||||
SAJET Resources LLC [Member] | Promissory Note Three [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Promissory notes outstanding | $ 0.2 | ||||||
Basis spread on variable rate | 6.00% | ||||||
Variable rate basis | prime rate | ||||||
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) - Land Sites and Rights of Way [Member] - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Future non-cancelable commitments for each of the next five fiscal years and in Aggregate Thereafter [Abstract] | ||||
In Aggregate | [1] | $ 150.4 | ||
2020 | [1] | 3.8 | ||
2021 | [1] | 4 | ||
2022 | [1] | 4.4 | ||
2023 | [1] | 4.3 | ||
2024 | [1] | 4.5 | ||
Thereafter | [1] | 129.4 | ||
Total expenses on non-cancelable commitments | $ 6.1 | $ 6.1 | $ 5.2 | |
[1] | 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. |
Significant Risks and Uncerta_2
Significant Risks and Uncertainties (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Concentration Risk [Line Items] | |||
Reduction of maximum loss due to counterparty credit risk by master netting provision | $ 21,000,000 | ||
Allowance for doubtful accounts | $ 0 | $ 100,000 | |
Sales Revenue, Net [Member] | Petredec (Europe) Limited [Member] | Customer Concentration Risk [Member] | |||
Concentration Risk [Line Items] | |||
Percentage of consolidated revenues | 12.00% | 15.00% | |
Concentration risk, percentage | 10.00% | ||
Minimum [Member] | |||
Concentration Risk [Line Items] | |||
Potential loss attributable to individual counterparties | $ 200,000 | ||
Maximum [Member] | |||
Concentration Risk [Line Items] | |||
Potential loss attributable to individual counterparties | $ 21,800,000 |
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, 2019USD ($) |
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 | $ 495.1 |
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 | $ 500 |
Estimated remaining duration of contracts | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2022-01-01 | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Fixed consideration to be recognized | $ 3,209.8 |
Estimated remaining duration of contracts |
Revenue - Additional Informatio
Revenue - Additional Information (Details) - Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01 | Dec. 31, 2019 |
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 | 19 years |
Other Operating (Income) Expe_3
Other Operating (Income) Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Other Income And Expenses [Abstract] | |||
(Gain) loss on sale of disposition of business and assets | $ 71.1 | $ (0.1) | $ 15.9 |
Miscellaneous business tax | 0.2 | 3.2 | 0.8 |
Other | 0.4 | 0.7 | |
Total other operating (income) expense | $ 71.3 | $ 3.5 | $ 17.4 |
Other Operating (Income) Expe_4
Other Operating (Income) Expense - Summary of (Gain) Loss on Sale or Disposal of Business and Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Other Operating Income Expense [Line Items] | |||
(Gain) loss on sale or disposition of business and assets | $ 71.1 | $ (0.1) | $ 15.9 |
Delaware Crude Gathering [Member] | |||
Other Operating Income Expense [Line Items] | |||
(Gain) loss on sale or disposition of business and assets | 59.5 | ||
Inland Marine Barge Business [Member] | |||
Other Operating Income Expense [Line Items] | |||
(Gain) loss on sale or disposition of business and assets | (48.1) | ||
Versado Gathering System [Member] | |||
Other Operating Income Expense [Line Items] | |||
(Gain) loss on sale or disposition of business and assets | (44.4) | ||
Storage and Terminaling Facilities [Member] | |||
Other Operating Income Expense [Line Items] | |||
(Gain) loss on sale or disposition of business and assets | 59.1 | ||
Benzene Treating Unit [Member] | |||
Other Operating Income Expense [Line Items] | |||
(Gain) loss on sale or disposition of business and assets | 20.5 | ||
Venice Gathering System, L.L.C. [Member] | |||
Other Operating Income Expense [Line Items] | |||
(Gain) loss on sale or disposition of business and assets | 16.1 | ||
Other [Member] | |||
Other Operating Income Expense [Line Items] | |||
(Gain) loss on sale or disposition of business and assets | $ 11.6 | $ 12.8 | $ (0.2) |
Income Tax - Summary of Income
Income Tax - Summary of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income tax (expense) benefit: | |||
Current expense (benefit) | $ 0 | $ 0 | $ (4.5) |
Deferred expense (benefit) | (0.9) | (0.1) | (2.9) |
Total income tax expense (benefit) | $ (0.9) | $ (0.1) | $ (7.4) |
Income Tax - Additional Informa
Income Tax - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Operating Loss Carryforwards [Line Items] | |||
Federal statutory income tax rate, percent | 21.00% | 35.00% | |
Percentage of tax deduction for interest expense to adjusted taxable income | 30.00% | ||
Percentage of tax deduction for net operating loss to current year taxable income | 80.00% | ||
Reclassification of alternative minimum tax credits from deferred tax assets to long term assets | $ 300,000 | ||
Refund received | $ 200,000 | ||
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] | |||
Net operating loss carryforwards | $ 51,700,000 | ||
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, 2039 | ||
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, 2019 | Dec. 31, 2018 |
Deferred tax assets: | ||
Net operating loss carryforwards | $ 13.4 | $ 12.9 |
Deferred tax liabilities: | ||
Property, plant, and equipment | (36.4) | (36.8) |
Net deferred tax asset (liability) | $ (23) | $ (23.9) |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Cash: | ||||
Interest paid, net of capitalized interest | [1] | $ 271.5 | $ 203.2 | $ 198.7 |
Income taxes paid, net of refunds | (1.8) | 0.2 | (4.9) | |
Non-cash investing activities: | ||||
Deadstock commodity inventory transferred to property, plant and equipment | 21.8 | 49 | 9 | |
Impact of capital expenditure accruals on property, plant and equipment | (193.9) | 216.9 | 205.4 | |
Transfers from materials and supplies inventory to property, plant and equipment | 25.1 | 12.7 | 3.6 | |
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 and additions | 6.7 | 1.8 | 3.9 | |
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: | ||||
Accrued distributions to noncontrolling interests | 91.7 | |||
Non-cash balance sheet movements related to assets held for sale (See Note 4 - Joint Ventures, Acquisitions and Divestitures): | ||||
Trade receivables | 6.9 | |||
Intangible assets, net accumulated amortization and estimated loss on sale | 52.1 | |||
Goodwill | 1.4 | |||
Property, plant and equipment, net of accumulated depreciation and estimated loss on sale | 77.3 | |||
Accounts payable and accrued liabilities | 6.2 | |||
Other long-term obligations | 0.2 | |||
Lease liabilities arising from recognition of right-of-use assets: | ||||
Operating lease | 6.9 | |||
Finance lease | $ 10.1 | |||
Permian Acquisition [Member] | ||||
Non-cash balance sheet movements related to the Permian Acquisition - See Note 4 - Joint Ventures, Acquisitions and Divestitures): | ||||
Contingent consideration recorded at the acquisition date | $ 416.3 | |||
[1] | Interest capitalized on major projects was $61.8 million, $46.3 million and $14.3 million for the years ended December 31, 2019, 2018 and 2017. |
Supplemental Cash Flow Inform_4
Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |||
Interest capitalized on major projects | $ 61.8 | $ 46.3 | $ 14.3 |
Compensation Plans - RSUs (Deta
Compensation Plans - RSUs (Details) - Restricted Stock Units (RSUs) [Member] - TRC Equity Compensation Plan [Member] | 12 Months Ended |
Dec. 31, 2019$ / sharesshares | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | shares | 301,691 |
Vested (in shares) | shares | (294,237) |
Outstanding, end of period (in shares) | shares | 7,454 |
Weighted-average grant-date fair value [Roll Forward] | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 27.10 |
Vested (in dollars per share) | $ / shares | 26.48 |
Outstanding, end of period (in dollars per share) | $ / shares | $ 51.49 |
Compensation Plans - TRC Long T
Compensation Plans - TRC Long Term Incentive Plan (Details) - Cash-Settled Performance Units [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award [Table] | ||
Cash-settled awards vested | 112,550 | |
Cash settled for awards | $ 6.9 | |
Partnership Long-term Incentive Plan [Member] | ||
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award [Table] | ||
Cash settled for awards | $ 6.9 | $ 4.1 |
Compensation Plans - 2010 TRC S
Compensation Plans - 2010 TRC Stock Incentive Plan (Details) - USD ($) | Jan. 01, 2018 | Jan. 31, 2020 | Oct. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | May 31, 2017 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Stock compensation expense | $ 61,800,000 | $ 59,000,000 | $ 44,200,000 | ||||
Unrecognized compensation expense | $ 97,700,000 | ||||||
Weighted average recognition period for unrecognized compensation cost | 2 years 2 months 12 days | ||||||
Fair value of units vested | $ 55,400,000 | 18,800,000 | 14,400,000 | ||||
Cash dividends paid for vested awards | $ 15,000,000 | $ 3,500,000 | $ 2,500,000 | ||||
Director Grants [Member] | Subsequent Event [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Cash-settled awards vested | 25,344 | ||||||
Shares withheld to satisfy tax withholding obligations | 0 | ||||||
Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Cash-settled awards vested | 111,808 | ||||||
Shares withheld to satisfy tax withholding obligations | 29,199 | ||||||
Performance Units [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Expected volatility, minimum | 32.00% | 29.00% | 55.00% | ||||
Expected volatility, maximum | 37.00% | 53.00% | 61.00% | ||||
Performance Units [Member] | Subsequent Event [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Cash-settled awards vested | 121,239 | ||||||
Shares withheld to satisfy tax withholding obligations | 30,804 | ||||||
Cash Settled Restricted Stock Units [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Cash settled for awards | $ 2,900,000 | $ 0 | |||||
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) | 29,472 | ||||||
Vesting date of awards | 2021-01 | ||||||
2010 TRC Stock Incentive Plan [Member] | Director Grants [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Granted (in shares) | 25,344 | 16,955 | 13,818 | ||||
Granted (in dollars per shares) | $ 42.83 | $ 51.21 | $ 60.48 | ||||
Vesting period of awards | 1 year | ||||||
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) | 1,042,344 | 1,393,812 | 1,193,942 | ||||
Granted (in dollars per shares) | $ 39.95 | $ 51.71 | $ 54.18 | ||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Executive Management [Member] | 2020 [Member] | Stock Awards Vesting, Tranche Three [Member] | Subsequent Event [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Granted (in shares) | 283,015 | ||||||
Vesting date of awards | 2023-01 | ||||||
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 | 6 years | ||||||
2010 TRC Stock Incentive Plan [Member] | RSUs Under New Retention Program [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Granted (in shares) | 85,547 | 275,076 | |||||
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] | |||||||
Granted (in shares) | 95,687 | 112,438 | 84,221 | ||||
Granted (in dollars per shares) | $ 42.83 | $ 51.09 | $ 55.94 | ||||
Vesting period of awards | 3 years | ||||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock in Lieu of Bonus [Member] | Executive Management [Member] | 2020 [Member] | Subsequent Event [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Granted (in shares) | 81,336 | ||||||
Vesting date of awards | 2021-01 | ||||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Granted (in shares) | 261,245 | ||||||
Granted (in dollars per shares) | $ 64.46 | ||||||
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) | 261,245 | 182,849 | 113,901 | ||||
Vesting date of awards | 2022-01 | 2021-01 | 2020-01 | ||||
2010 TRC Stock Incentive Plan [Member] | Performance Units [Member] | Executive Management [Member] | 2020 [Member] | Subsequent Event [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Granted (in shares) | 283,015 | ||||||
Vesting date of awards | 2023-01 | ||||||
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] | 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] | |||||||
Granted (in shares) | 69,042 | 7,836 | |||||
Vesting period of awards | 1 year | ||||||
Cash-settled awards vested | 54,313 |
Compensation Plans - Restricted
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, 2019$ / sharesshares | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | shares | 3,594,135 |
Granted (in shares) | shares | 1,067,688 |
Forfeited (in shares) | shares | (175,861) |
Vested (in shares) | shares | (1,093,901) |
Outstanding, end of period (in shares) | shares | 3,392,061 |
Weighted-average grant-date fair value [Roll Forward] | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 45.31 |
Granted (in dollars per shares) | $ / shares | 40.02 |
Forfeited (in dollars per share) | $ / shares | 51.90 |
Vested (in dollars per share) | $ / shares | 28.31 |
Outstanding, end of period (in dollars per share) | $ / shares | $ 48.79 |
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, 2019$ / sharesshares | |
Nonvested, number of shares [Roll Forward] | |
Outstanding, beginning of period (in shares) | shares | 296,750 |
Granted (in shares) | shares | 261,245 |
Forfeited (in shares) | shares | (29,276) |
Outstanding, end of period (in shares) | shares | 528,719 |
Weighted-average grant-date fair value [Roll Forward] | |
Outstanding, beginning of period (in dollars per share) | $ / shares | $ 88.19 |
Granted (in dollars per shares) | $ / shares | 64.46 |
Forfeited (in dollars per share) | $ / shares | 86.57 |
Outstanding, end of period (in dollars per share) | $ / shares | $ 76.56 |
Compensation Plans - 2010 TRC C
Compensation Plans - 2010 TRC Cash-Settled Restricted Stock Units (Details) - Cash Settled Restricted Stock Units [Member] - 2010 TRC Stock Incentive Plan [Member] - shares | 1 Months Ended | 12 Months Ended |
Oct. 31, 2018 | Dec. 31, 2019 | |
Nonvested, number of shares [Roll Forward] | ||
Outstanding, beginning of period (in shares) | 50,228 | |
Granted (in shares) | 69,042 | 7,836 |
Vested and paid (in shares) | (54,313) | |
Forfeited (in shares) | (3,672) | |
Outstanding, end of period (in shares) | 79 |
Segment Information - Additiona
Segment Information - Additional Information (Details) | 12 Months Ended |
Dec. 31, 2019Segment | |
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, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Revenues [Abstract] | |||||||||||
Revenues | $ 2,473.9 | $ 1,902.5 | $ 1,995.3 | $ 2,299.4 | $ 2,597.6 | $ 2,986.4 | $ 2,444.4 | $ 2,455.6 | $ 8,671.1 | $ 10,484 | $ 8,814.9 |
Operating margin | 1,759.8 | 1,523.8 | 1,286 | ||||||||
Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 7,393.8 | 9,278.7 | 7,751.1 | ||||||||
Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 1,277.3 | 1,205.3 | 1,063.8 | ||||||||
Gathering and Processing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 4,465.4 | 5,587 | 4,501.4 | ||||||||
Operating margin | 1,006.5 | 939.2 | 776.4 | ||||||||
Logistics and Transportation [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 7,116.3 | 8,896 | 7,826.7 | ||||||||
Operating margin | 867.2 | 592.5 | 511.8 | ||||||||
Other [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (113.9) | (7.9) | (2.2) | ||||||||
Operating margin | (113.9) | (7.9) | (2.2) | ||||||||
Corporate and Elimination [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (2,796.7) | (3,991.1) | (3,511) | ||||||||
Operating Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 8,671.1 | 10,484 | 8,814.9 | ||||||||
Operating Segments [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 7,393.8 | 9,278.7 | 7,751.1 | ||||||||
Operating Segments [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 1,277.3 | 1,205.3 | 1,063.8 | ||||||||
Operating Segments [Member] | Gathering and Processing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 1,829.6 | 1,943.8 | 1,340.3 | ||||||||
Operating Segments [Member] | Gathering and Processing [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 1,101.6 | 1,228.2 | 774 | ||||||||
Operating Segments [Member] | Gathering and Processing [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 728 | 715.6 | 566.3 | ||||||||
Operating Segments [Member] | Logistics and Transportation [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 6,955.4 | 8,548.1 | 7,476.8 | ||||||||
Operating Segments [Member] | Logistics and Transportation [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 6,406.1 | 8,058.4 | 6,979.3 | ||||||||
Operating Segments [Member] | Logistics and Transportation [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 549.3 | 489.7 | 497.5 | ||||||||
Operating Segments [Member] | Other [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (113.9) | (7.9) | (2.2) | ||||||||
Operating Segments [Member] | Other [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (113.9) | (7.9) | (2.2) | ||||||||
Intersegment Eliminations [Member] | Gathering and Processing [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 2,635.8 | 3,643.2 | 3,161.1 | ||||||||
Intersegment Eliminations [Member] | Gathering and Processing [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 2,628.4 | 3,636 | 3,154.2 | ||||||||
Intersegment Eliminations [Member] | Gathering and Processing [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 7.4 | 7.2 | 6.9 | ||||||||
Intersegment Eliminations [Member] | Logistics and Transportation [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 160.9 | 347.9 | 349.9 | ||||||||
Intersegment Eliminations [Member] | Logistics and Transportation [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 132.2 | 317.1 | 321.9 | ||||||||
Intersegment Eliminations [Member] | Logistics and Transportation [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 28.7 | 30.8 | 28 | ||||||||
Intersegment Eliminations [Member] | Corporate and Elimination [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (2,796.7) | (3,991.1) | (3,511) | ||||||||
Intersegment Eliminations [Member] | Corporate and Elimination [Member] | Sales of Commodities [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (2,760.6) | (3,953.1) | (3,476.1) | ||||||||
Intersegment Eliminations [Member] | Corporate and Elimination [Member] | Fees from Midstream Services [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | $ (36.1) | $ (38) | $ (34.9) |
Segment Information - Other Fin
Segment Information - Other Financial Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Mar. 01, 2017 | ||
Other financial information [Abstract] | |||||
Total assets | $ 18,744.5 | $ 16,890.1 | |||
Goodwill | 45.2 | 46.6 | $ 256.6 | $ 46.6 | |
Operating Segments [Member] | |||||
Other financial information [Abstract] | |||||
Total assets | [1] | 18,744.5 | 16,890.1 | 14,359 | |
Goodwill | 45.2 | 46.6 | 256.6 | ||
Capital expenditures | 2,709 | 3,327.7 | 1,506.5 | ||
Business acquisitions | 987.1 | ||||
Gathering and Processing [Member] | Operating Segments [Member] | |||||
Other financial information [Abstract] | |||||
Total assets | [1] | 11,929.8 | 11,602.7 | 10,787.7 | |
Goodwill | 45.2 | 46.6 | 256.6 | ||
Capital expenditures | 1,273.3 | 1,548.6 | 1,008.9 | ||
Business acquisitions | 987.1 | ||||
Logistics and Transportation [Member] | Operating Segments [Member] | |||||
Other financial information [Abstract] | |||||
Total assets | [1] | 6,741.8 | 5,180.6 | 3,507.4 | |
Capital expenditures | 1,412.2 | 1,767 | 470.4 | ||
Other [Member] | Operating Segments [Member] | |||||
Other financial information [Abstract] | |||||
Total assets | [1] | 1 | 3.2 | 1.4 | |
Corporate and Elimination [Member] | Operating Segments [Member] | |||||
Other financial information [Abstract] | |||||
Total assets | [1] | 71.9 | 103.6 | 62.5 | |
Capital expenditures | $ 23.5 | $ 12.1 | $ 27.2 | ||
[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, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | ||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | $ 7,397.9 | $ 9,350.9 | $ 7,800.8 | |||||||||
Non-customer revenue | (4.1) | (72.2) | (49.7) | |||||||||
Total revenues | $ 2,473.9 | $ 1,902.5 | $ 1,995.3 | $ 2,299.4 | $ 2,597.6 | $ 2,986.4 | $ 2,444.4 | $ 2,455.6 | 8,671.1 | 10,484 | 8,814.9 | |
Designated as Hedging Instrument [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Non-customer revenue | 138 | (39.7) | (44.7) | |||||||||
Not Designated as Hedging Instrument [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Non-customer revenue | [1] | (142.1) | (32.5) | (5) | ||||||||
Natural Gas [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 1,321.7 | 1,810 | 2,005.9 | |||||||||
NGL [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 5,233.8 | 6,886.9 | 5,454.2 | |||||||||
Condensate and Crude Oil [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 716.1 | 457.9 | 196 | |||||||||
Petroleum Products [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 126.3 | 196.1 | 144.7 | |||||||||
Sales of Commodities [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Total revenues | 7,393.8 | 9,278.7 | 7,751.1 | |||||||||
NGL Transportation, Fractionation and Services [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 169.4 | 154.6 | 170.7 | |||||||||
Gathering and Processing [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 722.4 | 698.1 | 523.3 | |||||||||
Storage, Terminaling and Export [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 356.4 | 313 | 300.8 | |||||||||
Other [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 29.1 | 39.6 | 69 | |||||||||
Fees from Midstream Services [Member] | ||||||||||||
Revenue from External Customer [Line Items] | ||||||||||||
Revenue recognized from customer and non-customer | 1,277.3 | 1,205.3 | 1,063.8 | |||||||||
Total revenues | $ 1,277.3 | $ 1,205.3 | $ 1,063.8 | |||||||||
[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 ($) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | |||||
Operating margin | $ 1,759,800,000 | $ 1,523,800,000 | $ 1,286,000,000 | ||
Depreciation and amortization expense | (971,700,000) | (815,900,000) | (809,500,000) | ||
General and administrative expense | (267,500,000) | (240,800,000) | (190,500,000) | ||
Impairment of property, plant and equipment | $ (229,000,000) | (243,200,000) | 0 | (378,000,000) | |
Impairment of goodwill | $ (210,000,000) | 0 | (210,000,000) | 0 | |
Interest expense, net | (320,800,000) | (170,000,000) | (217,800,000) | ||
Equity earnings (loss) | 39,000,000 | 7,300,000 | (17,000,000) | ||
Gain recognized in exchange of assets | (71,100,000) | 100,000 | (15,900,000) | ||
Gain (loss) from sale of equity-method investment | 69,300,000 | 0 | 0 | ||
Gain (loss) from financing activities | (1,400,000) | (1,300,000) | (10,900,000) | ||
Change in contingent considerations | (8,700,000) | 8,800,000 | 99,600,000 | ||
Other, net | (200,000) | (3,500,000) | (4,000,000) | ||
Income (loss) before income taxes | (16,500,000) | 98,500,000 | (258,000,000) | ||
Gathering and Processing [Member] | |||||
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | |||||
Operating margin | 1,006,500,000 | 939,200,000 | 776,400,000 | ||
Logistics and Transportation [Member] | |||||
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | |||||
Operating margin | 867,200,000 | 592,500,000 | 511,800,000 | ||
Other [Member] | |||||
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | |||||
Operating margin | $ (113,900,000) | $ (7,900,000) | $ (2,200,000) |
Selected Quarterly Financial _3
Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |||||||||||
Selected Quarterly Financial Information [Abstract] | |||||||||||||||||||||
Revenues | $ 2,473.9 | $ 1,902.5 | $ 1,995.3 | $ 2,299.4 | $ 2,597.6 | $ 2,986.4 | $ 2,444.4 | $ 2,455.6 | $ 8,671.1 | $ 10,484 | $ 8,814.9 | ||||||||||
Gross margin | 771.1 | 574.4 | 633.7 | 573.4 | 589.2 | 602.9 | 539.1 | 514.6 | 2,552.6 | 2,245.8 | |||||||||||
Income (loss) from operations | (21.7) | [1] | 45.9 | [1] | 117.2 | [1] | 64.7 | [1] | (76.6) | [2] | 80.6 | [2] | 159.2 | [2] | 90.4 | [2] | 206.1 | [1] | 253.6 | [2] | (109.4) |
Net income (loss) | (85.8) | 37.5 | 51.7 | (19) | (111.3) | (8.7) | 162.6 | 56 | (15.6) | 98.6 | (250.6) | ||||||||||
Net income (loss) attributable to common limited partners | $ (179.9) | $ (41) | $ (7.3) | $ (32.5) | $ (127.1) | $ (20.8) | $ 147.6 | $ 39.2 | $ (260.7) | $ 38.9 | $ (294.8) | ||||||||||
[1] | Includes | ||||||||||||||||||||
[2] | Includes |
Selected Quarterly Financial _4
Selected Quarterly Financial Data (Unaudited) (Parenthetical) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Selected Quarterly Financial Information [Abstract] | |||||
Non-cash pre-tax impairment charges | $ 229,000,000 | $ 243,200,000 | $ 0 | $ 378,000,000 | |
Impairment of goodwill | $ 210,000,000 | $ 0 | $ 210,000,000 | $ 0 |