Document and Entity Information
Document and Entity Information | 9 Months Ended |
Sep. 30, 2018 | |
Document And Entity Information [Abstract] | |
Entity Registrant Name | Targa Resources Partners LP |
Trading Symbol | NGLS |
Entity Central Index Key | 1,379,661 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Non-accelerated Filer |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | Q3 |
Document Type | 10-Q |
Amendment Flag | false |
Document Period End Date | Sep. 30, 2018 |
Entity Small Business | false |
Entity Emerging Growth Company | false |
CONSOLIDATED BALANCE SHEETS (Un
CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 187.5 | $ 124.7 |
Trade receivables, net of allowances of $0.1 and $0.1 million at September 30, 2018 and December 31, 2017 | 1,036 | 825.7 |
Inventories | 177.9 | 204.5 |
Assets from risk management activities | 59.6 | 37.9 |
Other current assets | 66.4 | 55.8 |
Held for sale assets (see Note 4) | 165.7 | 0 |
Total current assets | 1,693.1 | 1,248.6 |
Property, plant and equipment | 16,214.6 | 14,198.6 |
Accumulated depreciation | (4,133.8) | (3,768.7) |
Property, plant and equipment, net | 12,080.8 | 10,429.9 |
Intangible assets, net | 2,029.6 | 2,165.8 |
Goodwill, net | 256.6 | 256.6 |
Long-term assets from risk management activities | 8.4 | 23.2 |
Investments in unconsolidated affiliates | 441.5 | 221.6 |
Other long-term assets | 16.5 | 13.3 |
Total assets | 16,526.5 | 14,359 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 1,984.1 | 1,106.6 |
Accounts payable to Targa Resources Corp. | 136.5 | 76.9 |
Liabilities from risk management activities | 176.3 | 79.7 |
Current debt obligations | 290 | 350 |
Held for sale liabilities (see Note 4) | 1.7 | 0 |
Total current liabilities | 2,588.6 | 1,613.2 |
Long-term debt | 5,243.9 | 4,268 |
Long-term liabilities from risk management activities | 67.5 | 19.6 |
Deferred income taxes, net | 24 | 24 |
Other long-term liabilities | 245.2 | 576 |
Contingencies (see Note 15) | ||
Owners' equity: | ||
Series A preferred limited partners (5,000,000 and 5,000,000 units issued and 5,000,000 and 5,00,000 outstanding as of September 30, 2018 and December 31, 2017) | 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 September 30, 2018 and December 31, 2017) | 6,525.5 | 6,500.3 |
General partner (5,629,136 and 5,629,136 units issued and 5,629,136 and 5,629,136 outstanding as of September 30, 2018 and December 31, 2017) | 808.7 | 808.2 |
Accumulated other comprehensive income (loss) | (165.7) | (46) |
Partners' Capital | 7,289.1 | 7,383.1 |
Noncontrolling interests in subsidiaries | 1,068.2 | 475.1 |
Total owners' equity | 8,357.3 | 7,858.2 |
Total liabilities and owners' equity | $ 16,526.5 | $ 14,359 |
CONSOLIDATED BALANCE SHEETS (_2
CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Current assets: | ||
Trade receivables, allowances | $ 0.1 | $ 0.1 |
Owners' equity: | ||
Common limited partners units issued (in units) | 275,168,410 | 275,168,410 |
Common limited partners units outstanding (in units) | 275,168,410 | 275,168,410 |
General partner units issued (in units) | 5,629,136 | 5,629,136 |
General partner units outstanding (in units) | 5,629,136 | 5,629,136 |
Series A Preferred Limited Partner Units [Member] | ||
Owners' equity: | ||
Series A preferred limited partners units issued (in units) | 5,000,000 | 5,000,000 |
Series A preferred limited partners units outstanding (in units) | 5,000,000 | 5,000,000 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues: | ||||
Total revenues | $ 2,986.4 | $ 2,131.8 | $ 7,886.3 | $ 6,112.1 |
Costs and expenses: | ||||
Product purchases (see Note 3) | 2,383.5 | 1,663.1 | 6,229.7 | 4,737.8 |
Operating expenses | 194.9 | 155.5 | 538.7 | 462.6 |
Depreciation and amortization expense | 206.3 | 208.3 | 607.1 | 602.8 |
General and administrative expense | 59.3 | 46.6 | 165 | 139.4 |
Impairment of property, plant and equipment | 0 | 378 | 0 | 378 |
Other operating (income) expense | 61.8 | 0.6 | 15.7 | 17.2 |
Income (loss) from operations | 80.6 | (320.3) | 330.1 | (225.7) |
Other income (expense): | ||||
Interest expense, net | (75.7) | (51.9) | (113.3) | (169.5) |
Equity earnings (loss) | 3 | 0.2 | 6.4 | (16.6) |
Gain (loss) from financing activities | 0 | 0 | (1.3) | (10.7) |
Change in contingent considerations | (16.6) | 126.8 | (12.1) | 125.6 |
Other, net | 0 | 0.2 | 0 | (2.7) |
Income (loss) before income taxes | (8.7) | (245) | 209.8 | (299.6) |
Income tax (expense) benefit | 0 | 0 | 0 | 4.2 |
Net income (loss) | (8.7) | (245) | 209.8 | (295.4) |
Less: Net income (loss) attributable to noncontrolling interests | 9.7 | 9.7 | 32 | 25.9 |
Net income (loss) attributable to Targa Resources Partners LP | (18.4) | (254.7) | 177.8 | (321.3) |
Net income attributable to preferred limited partners | 2.8 | 2.8 | 8.4 | 8.4 |
Net income (loss) attributable to general partner | (0.4) | (5.2) | 3.4 | (6.6) |
Net income (loss) attributable to common limited partners | (20.8) | (252.3) | 166 | (323.1) |
Net income (loss) attributable to Targa Resources Partners LP | (18.4) | (254.7) | 177.8 | (321.3) |
Sales of Commodities [Member] | ||||
Revenues: | ||||
Total revenues | 2,654.1 | 1,871.5 | 6,981.4 | 5,353.1 |
Fees from Midstream Services [Member] | ||||
Revenues: | ||||
Total revenues | $ 332.3 | $ 260.3 | $ 904.9 | $ 759 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Net income (loss) | $ (8.7) | $ (245) | $ 209.8 | $ (295.4) |
Other comprehensive income (loss): | ||||
Other comprehensive income (loss) | (115.7) | (104.7) | (119.7) | (8.3) |
Comprehensive income (loss) | (124.4) | (349.7) | 90.1 | (303.7) |
Less: Comprehensive income (loss) attributable to noncontrolling interests | 9.7 | 9.7 | 32 | 25.9 |
Comprehensive income (loss) attributable to Targa Resources Partners LP | (134.1) | (359.4) | 58.1 | (329.6) |
Commodity Contracts [Member] | ||||
Other comprehensive income (loss): | ||||
Change in fair value | (139.6) | (106.8) | (178) | (10.5) |
Settlements reclassified to revenues | $ 23.9 | $ 2.1 | $ 58.3 | $ 2.2 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY (Unaudited) - 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. | 1,620 | $ 0 | $ 1,587.5 | $ 32.5 | 0 | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 0 | |||
Distributions to noncontrolling interests | (33.4) | $ 0 | $ 0 | $ 0 | 0 | (33.4) |
Contributions from noncontrolling interests | 93.8 | 0 | 0 | 0 | 0 | 93.8 |
Purchase of noncontrolling interests in subsidiary | (12.5) | 0 | 0 | 0 | 0 | (12.5) |
Other comprehensive income (loss) | (8.3) | 0 | 0 | 0 | (8.3) | 0 |
Net income (loss) | (295.4) | 8.4 | (323.1) | (6.6) | 0 | 25.9 |
Distributions | (633.1) | (8.4) | (612.2) | (12.5) | 0 | 0 |
Balance at Sep. 30, 2017 | 7,881.7 | $ 120.6 | $ 6,592.1 | $ 810.1 | (70.1) | 429 |
Balance (in units) at Sep. 30, 2017 | 5,000 | 275,168 | 5,629 | |||
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. | 540 | $ 0 | $ 529.2 | $ 10.8 | 0 | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 0 | |||
Acquisition of related party (see Note 14) | 1.1 | $ 0 | $ 0 | $ 0 | 0 | 1.1 |
Distributions to noncontrolling interests | (51.5) | 0 | 0 | 0 | 0 | (51.5) |
Contributions from noncontrolling interests | 611.6 | 0 | 0 | 0 | 0 | 611.6 |
Purchase of noncontrolling interests in subsidiary | (0.1) | 0 | 0 | 0 | 0 | (0.1) |
Other comprehensive income (loss) | (119.7) | 0 | 0 | 0 | (119.7) | 0 |
Net income (loss) | 209.8 | 8.4 | 166 | 3.4 | 0 | 32 |
Distributions | (692.1) | (8.4) | (670) | (13.7) | 0 | 0 |
Balance at Sep. 30, 2018 | $ 8,357.3 | $ 120.6 | $ 6,525.5 | $ 808.7 | $ (165.7) | $ 1,068.2 |
Balance (in units) at Sep. 30, 2018 | 5,000 | 275,168 | 5,629 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | ||
Cash flows from operating activities | |||
Net income (loss) | $ 209.8 | $ (295.4) | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Amortization in interest expense | 6.8 | 7.1 | |
Depreciation and amortization expense | 607.1 | 602.8 | |
Impairment of property, plant and equipment | 0 | 378 | |
Accretion of asset retirement obligations | 2.8 | 3 | |
Increase (decrease) in redemption value of mandatorily redeemable preferred interests | (66.3) | 8.5 | |
Equity (earnings) loss of unconsolidated affiliates | (6.4) | 16.6 | |
Distributions of earnings received from unconsolidated affiliates | 16 | 8.4 | |
Risk management activities | 9.6 | 7.3 | |
(Gain) loss on sale or disposition of assets | [1] | 14.3 | 16.6 |
(Gain) loss from financing activities | 1.3 | 10.7 | |
Change in contingent considerations included in Other expense (income) | 12.1 | (125.6) | |
Changes in operating assets and liabilities, net of business acquisitions: | |||
Receivables and other assets | (221.7) | (91.5) | |
Inventories | (16.6) | (136.4) | |
Accounts payable and other liabilities | 374.7 | 53.1 | |
Net cash provided by operating activities | 943.5 | 463.2 | |
Cash flows from investing activities | |||
Outlays for property, plant and equipment | (2,033.6) | (866.6) | |
Outlays for business acquisition, net of cash acquired | 0 | (570.8) | |
Proceeds from sale of assets | 71.5 | 0 | |
Investments in unconsolidated affiliates | (223.7) | (7.5) | |
Return of capital from unconsolidated affiliates | 2.2 | 2.2 | |
Other, net | (9.2) | (14.8) | |
Net cash used in investing activities | (2,192.8) | (1,457.5) | |
Debt obligations: | |||
Proceeds from borrowings under credit facility | 950 | 1,496 | |
Repayments of credit facility | (970) | (1,216) | |
Proceeds from borrowings under accounts receivable securitization facility | 440 | 281.6 | |
Repayments of accounts receivable securitization facility | (500) | (278.5) | |
Proceeds from issuance of senior notes | 1,000 | 0 | |
Redemption of senior notes | 0 | (287.6) | |
Costs incurred in connection with financing arrangements | (15.8) | (0.1) | |
Purchase of noncontrolling interests in subsidiary | (0.1) | (12.5) | |
Contributions from general partner | 10.8 | 32.5 | |
Contributions from TRC | 529.2 | 1,587.5 | |
Contributions from noncontrolling interests | 611.6 | 93.8 | |
Distributions to noncontrolling interests | (51.5) | (33.4) | |
Distributions to unitholders | (692.1) | (633.1) | |
Net cash provided by (used in) financing activities | 1,312.1 | 1,030.2 | |
Net change in cash and cash equivalents | 62.8 | 35.9 | |
Cash and cash equivalents, beginning of period | 124.7 | 68 | |
Cash and cash equivalents, end of period | $ 187.5 | $ 103.9 | |
[1] | Comprised primarily of a $57.5 million loss on sale of our refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD during the third quarter of 2018 as disclosed in Note 4 — Newly-Formed Joint Ventures, Acquisitions and Divestitures, offset by a $48.1 million gain on sale of our inland marine barge business to a third party during the second quarter of 2018 as disclosed in Note 6 — Property, Plant and Equipment and Intangible Assets. Also includes a $16.1 million loss in the first quarter of 2017 due to the sale of our ownership interest in VGS. |
Organization and Operations
Organization and Operations | 9 Months Ended |
Sep. 30, 2018 | |
Limited Liability Company Or Limited Partnership Business Organization And Operations [Abstract] | |
Organization and Operations | Note 1 — Organization and Operations Our Organization Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “TRP,” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. Our common units are wholly owned by TRC and no longer publicly traded as a result of TRC’s 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 “Preferred Units”) that were issued in October 2015 remain outstanding as limited partner interests in us and continue to trade on the NYSE under the symbol “NGLS PRA.” Our Operations We are engaged in the business of: • gathering, compressing, treating, processing and selling natural gas; • storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters; • gathering, storing, terminaling and selling crude oil; and • storing, terminaling and selling refined petroleum products. See Note 19 – Segment Information for certain financial information regarding our business segments. The employees supporting our operations are employed by Targa. Our consolidated financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services. |
Basis of Presentation
Basis of Presentation | 9 Months Ended |
Sep. 30, 2018 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Basis of Presentation | Note 2 — Basis of Presentation We have prepared these unaudited consolidated financial statements in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report. The unaudited consolidated financial statements for the three and nine months ended September 30, 2018 include all adjustments that we believe are necessary for a fair statement of the results for interim periods. 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. Our financial results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the full year. |
Significant Accounting Policies
Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | Note 3 — Significant Accounting Policies Recent Accounting Pronouncements Recently issued accounting pronouncements not yet adopted Leases In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU 2018-10, Codification Improvements to Topic 842, Leases In July 2018, the FASB also issued ASU 2018-11, Leases (Topic 842): Targeted Improvements We expect to adopt Topic 842 on January 1, 2019, and intend to elect the land easement practical expedient as well as the optional additional transition method. We are currently in the process of gathering a complete population of our lease arrangements, implementing a software solution with respect to our leases, evaluating the impact of the new standard on our consolidated financial statements, and Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. have Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract In August 2018, the FASB issued ASU 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract Recently adopted accounting pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) • Embedded fees within commodity supply contracts where the counterparty is not deemed to be a customer are now reported as a reduction of “Product purchases.” Historically, such fees were reported as “Fees from midstream services.” • Noncash consideration in the form of commodities received in-kind from a customer is now recognized as service revenue within “Fees from midstream services” when the service is performed. Historically, the noncash consideration was only recognized as revenue upon sale to a third party without corresponding “Product purchases.” • For certain contracts structured as a purchase where we do not control the commodities, but rather are acting as an agent for the supplier, revenue is now recognized for the net amount of consideration we expect to retain in exchange for our service. Historically, the purchase from the supplier and subsequent sale were reported gross. The following tables summarize the effects of adoption on our consolidated financial statements: Three Months Ended September 30, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 2,738.7 $ (84.6 ) $ 2,654.1 Fees from midstream services 338.1 (5.8 ) 332.3 Total revenues 3,076.8 (90.4 ) 2,986.4 Costs and expenses: Product purchases 2,473.9 (90.4 ) 2,383.5 Income from operations 80.6 — 80.6 Income (loss) before income taxes (8.7 ) — (8.7 ) Net income (loss) $ (8.7 ) $ — $ (8.7 ) Nine Months Ended September 30, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 7,232.0 $ (250.6 ) $ 6,981.4 Fees from midstream services 923.5 (18.6 ) 904.9 Total revenues 8,155.5 (269.2 ) 7,886.3 Costs and expenses: Product purchases 6,498.9 (269.2 ) 6,229.7 Income from operations 330.1 — 330.1 Income (loss) before income taxes 209.8 — 209.8 Net income (loss) $ 209.8 $ — $ 209.8 See Note 16 – Revenue for information regarding our performance obligations and Note 19 – Segment Information for further disaggregation of our revenues. Targeted Improvements to Accounting for Hedge Activities In August 2017, FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities Cash Flow Classification In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) Other Income In February Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) Revenue from Contracts with Customers (Topic 606), These amendments were effective for us on January 1, 2018 and were adopted by applying the modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption did not result in a cumulative effect adjustment to retained earnings on January 1, 2018. Accounting Policy Updates The accounting policies that we follow are set forth in Note 3 – Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Annual Report. Besides those noted below, there were no other significant updates or revisions to our policies during the nine months ended September 30, 2018. Revenue Recognition Our operating revenues are primarily derived from the following activities: • sales of natural gas, NGLs, condensate, crude oil and petroleum products; • services related to compressing, gathering, treating and processing of natural gas; and • services related to NGL fractionation, terminaling and storage, transportation and treating. We have multiple types of contracts with commercial counterparties and many of these may result in cash inflows to Targa due to the structure of settlement provisions with embedded fees. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606. Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases. Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues. We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis. Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price. Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract. The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation. Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue. 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 Contract assets are presented separately from amounts presented as a receivable when or as a performance obligation(s) is satisfied and prior to having a right to payment that is unconditional at the end of the reporting period. 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. |
Newly-Formed Joint Ventures and
Newly-Formed Joint Ventures and Acquisitions | 9 Months Ended |
Sep. 30, 2018 | |
Business Combinations [Abstract] | |
Newly-Formed Joint Ventures and Acquisitions | Note 4 –Newly-Formed Joint Ventures, Acquisitions and Divestitures Joint Ventures Grand Prix Joint Venture In May 2017, we announced plans to construct Grand Prix, a new common carrier NGL pipeline. Grand Prix will transport volumes from the Permian Basin and our North Texas system to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supported by our volumes and other third-party customer volume commitments, and is expected to be fully in service in the second quarter of 2019. In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”), which owns the portion of Grand Prix extending from the Permian Basin to Mont Belvieu, Texas, Concurrent with the sale of the 25% interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC (“EagleClaw”), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement whereby EagleClaw has dedicated and committed significant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin. In March 2018, we announced an extension of Grand Prix from North Texas into southern Oklahoma. The pipeline expansion is supported by long-term commitments for both transportation and fractionation services from our existing and future processing plants in the Arkoma area in our SouthOK system and from third-party commitments, including a long-term commitment for transportation and fractionation with Valiant Midstream, LLC. The extension of Grand Prix into southern Oklahoma is not part of the Grand Prix Joint Venture and its expected cost of approximately $350 million will be funded exclusively by Targa. The capacity of the 24-inch pipeline segment from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d. The pipeline segment from the Permian Basin will be connected to a 30-inch diameter pipeline segment in North Texas, where Permian, North Texas and Oklahoma volumes will be connected to Mont Belvieu, and will have capacity of approximately 450 MBbl/d, expandable to 950 MBbl/d. The capacity from southern Oklahoma to North Texas will vary based on telescoping pipe size. Grand Prix economics related to volumes flowing on the pipeline from the Permian Basin to Mont Belvieu are included in the Blackstone and Grand Prix Development LLC (“Grand Prix DevCo JV”) joi The total cost for Grand Prix, including the extension into southern Oklahoma, is expected to be approximately $1.7 billion. Cayenne In July 2017, we entered into the Cayenne Pipeline, LLC joint venture (“Cayenne with American Midstream LLC to convert an existing 62-mile gas pipeline to an NGL pipeline connecting the VESCO plant in Venice, Louisiana to the Enterprise Products Operating LLC (“Enterprise”) pipeline at Toca, Louisiana, for delivery to Enterprise’s Norco Fractionator. We acquired a 50% interest in the Cayenne . The project commenced operations in December 2017. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the Cayenne Joint Venture. Gulf Coast Express Joint Venture In December 2017, Gulf Coast Express Pipeline (“GCX”), . The pipeline 50 In owner 1. ls. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the GCX Joint Venture. Little Missouri 4 Joint Venture In January 2018, we formed a 50/50 joint venture with Hess Midstream Partners LP to construct a new 200 MMcf/d natural gas processing plant (“LM4 Plant”) at the Partnership’s existing Little Missouri facility (“Little Missouri 4”). The LM4 Plant is anticipated to be completed in the second quarter of 2019. The Partnership is managing the construction of, and will operate, the LM4 Plant. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the Little Missouri 4 Joint Venture. DevCo Joint Ventures In February 2018 , we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of Grand Prix, GCX and an approximately 100 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). Stonepeak owns a 95% interest in the Grand Prix DevCo JV, which owns a 20% interest in the Grand Prix Joint Venture (which does not include the extension into southern Oklahoma). Stonepeak owns an 80% interest in both Targa GCX Pipeline LLC (“ GCX DevCo JV”), which owns our 25% interest in GCX , and Targa Train 6 LLC (“Train 6 DevCo JV”), which owns a 100% interest in certain assets associated with Train 6. The Train 6 DevCo JV does not include certain fractionation-related infrastructure such as brine and storage, which will be funded and owned 100% by us. We hold the remaining interests in the DevCo JVs as well as control the management, construction and operation of Grand Prix and Train 6. The following diagram displays the ownership structure of the DevCo JVs: For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, we have the option to acquire all or part of Stonepeak’s interests in the DevCo JVs. Targa may acquire up to 50% of Stonepeak’s invested capital in multiple increments with a minimum of $100 million, and Stonepeak’s remaining 50% interest in a single final purchase. The purchase price payable for such partial or full interests is based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs. Targa will control the management of the DevCo JVs unless and until Targa declines to exercise its option to acquire Stonepeak's interests. Train 6 is expected to begin operations in the first quarter of 2019. Grand Prix is expected to be fully in service in the second quarter of 2019 . X is expected to be in service in the fourth quarter of 2019, pending regulatory approvals. We . We continue to account for Grand Prix and Train 6 on a consolidated basis in o an equity method investment as disclosed in Note 7 – Investments in Unconsolidated Affiliates. Agua Blanca In April 2018, we joined WhiteWater Midstream, LLC (“WhiteWater Midstream”), WPX Energy, Inc., and Markwest Energy Partners, L.P., as joint venture partners in WhiteWater Midstream’s Delaware Basin Agua Blanca pipeline (“Agua Blanca Joint Venture”). The Agua Blanca pipeline is an approximately 160 mile natural gas residue pipeline with an initial capacity of 1.4 Bcf/d. The pipeline, which commenced operations in April 2018, runs from Orla, Texas to the Waha hub, servicing portions of Culberson, Loving, Pecos, Reeves and Ward counties with multiple direct downstream connections including to the Trans-Pecos Header. We acquired a 10% interest in the Agua Blanca for $3.5 million. See Note 7 – Investments in Unconsolidated Affiliates for activity related to the Agua Blanca Joint Venture. Carnero Joint Venture In May 2018, Sanchez Midstream Partners LP and we merged our respective 50% interests in the Carnero Gathering and Carnero Processing Joint Ventures, which own the high-pressure Carnero gathering line and Raptor natural gas processing plant, to form an expanded 50/50 joint venture in South Texas (the “Carnero Joint Venture”). In connection with the joint venture merger transactions, the Carnero Joint Venture acquired our 200 MMcf/d Silver Oak II natural gas processing plant located in Bee County Texas, which increased the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d. Additional enhancements to the prior joint ventures include dedication of over 315,000 additional gross acres in the Western Eagle Ford, operated by Sanchez Energy Corporation, under a new long-term firm gas gathering and processing agreement. Including the approximately 105,000 Catarina acreage, the joint venture now has over 420,000 gross acres dedicated long term. We operate the gas gathering and processing facilities in the joint venture. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. Whistler Pipeline In August 2018, we announced that we were involved in the development of the Whistler Pipeline (“Whistler”), consisting of a pipeline designed to transport natural gas from the Waha area of the Permian Basin to Agua Dulce in South Texas , with an additional segment continuing from Agua Dulce to Wharton County, TX Acquisitions Permian Acquisition On March 1, 2017, we completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern Delaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “Permian Acquisition”). We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the “initial purchase price”). Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellers of New Delaware and New Midland in potential earn-out payments. The first earn-out payment due in May 2018 expired with no required payment. The second potential earn-out payment would occur in May 2019 and will be based upon a multiple of realized gross margin from contracts that existed on March 1, 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 three and nine months ended September 30, 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. Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Pro Forma Pro Forma Revenues $ 2,131.8 $ 6,126.2 Net income (loss) (244.7 ) (297.0 ) The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to the unaudited results of the acquired businesses for the periods indicated: • Reflect the amortization expense resulting from the fair value of intangible assets recognized as part of the Permian Acquisition. • Reflect the change in depreciation expense resulting from the difference between the historical balances of the Permian Acquisition’s property, plant and equipment, net, and the fair value of property, plant and equipment acquired. • Exclude $5.6 million of acquisition-related costs incurred as of September 30, 2017 from pro forma net income for the three and nine months ended September 30, 2017. Contingent Consideration A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its fair value. We agreed to pay up to an additional $935.0 million in aggregate potential earn-out payments in May 2018 and May 2019. The acquisition date fair value of the potential earn-out payments of $416.3 million was originally recorded within Other long-term liabilities on our Consolidated Balance Sheets. 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). During the three months ended September 30, 2018 and 2017, we recognized $16.6 million expense and $126.6 million income, respectively, in Other income (expense) related to the change in fair value of the contingent consideration. The increase in fair value of the contingent consideration during the three months ended September 30, 2018 was During the nine months ended September 30 , 2018 and 2017, we recognized $12.0 million expense and $125.5 million income in Other income (expense) related to the change in fair value of the contingent consideration . The portion of the earn-out due in 2018 expired with no required payment. As of September 30, 2018, the fair value of the second potential earn-out payment of $329.0 million has been recorded as a component of Accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. See Note 13 – Fair Value Measurements for additional discussion of the fair value methodology. Divestitures Assets and liabilities held for sale During the third quarter of 2018, we executed agreements to sell our Downstream refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD, to a third party for approximately $160 million. The sale closed in the fourth quarter of 2018 and we intend to use the proceeds to repay debt and to fund a portion of our growth capital program. In relation to the sale, we classified our Tacoma and Baltimore refined products and crude oil storage and terminaling facilities assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $57.5 million included within Other operating income (expense) in our Consolidated Statements of Operations for the three and nine months ended September 30, 2018. The sale of these businesses does not qualify for reporting as discontinued operations as it did not represent a strategic shift that would have a major effect on our operations and financial results. The adjusted carrying amounts of the assets and liabilities held for sale as of September 30, 2018 are as follows: September 30, 2018 Current assets: Trade receivables $ 8.8 Inventories 5.5 Property, plant and equipment, net of accumulated depreciation and estimated loss on sale 151.4 Total assets held for sale $ 165.7 Current liabilities: Accounts payable and accrued liabilities $ (1.7 ) Total liabilities held for sale $ (1.7 ) |
Inventories
Inventories | 9 Months Ended |
Sep. 30, 2018 | |
Inventory Disclosure [Abstract] | |
Inventories | Note 5 — Inventories September 30, 2018 December 31, 2017 Commodities $ 163.3 $ 191.6 Materials and supplies 14.6 12.9 $ 177.9 $ 204.5 |
Property, Plant and Equipment a
Property, Plant and Equipment and Intangible Assets | 9 Months Ended |
Sep. 30, 2018 | |
Property Plant And Equipment And Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | Note 6 — Property, Plant and Equipment and Intangible Assets September 30, 2018 December 31, 2017 Estimated Useful Lives (In Years) Gathering systems $ 7,395.2 $ 7,037.2 5 to 20 Processing and fractionation facilities 3,842.4 3,563.0 5 to 25 Terminaling and storage facilities 1,068.1 1,244.1 5 to 25 Transportation assets 456.1 343.6 10 to 25 Other property, plant and equipment 313.6 303.5 3 to 25 Land 146.8 125.7 — Construction in progress 2,992.4 1,581.5 — Property, plant and equipment 16,214.6 14,198.6 Accumulated depreciation (4,133.8 ) (3,768.7 ) Property, plant and equipment, net $ 12,080.8 $ 10,429.9 Intangible assets $ 2,736.6 $ 2,736.6 10 to 20 Accumulated amortization (707.0 ) (570.8 ) Intangible assets, net $ 2,029.6 $ 2,165.8 Impairment of North Texas Gathering and Processing Assets We recorded a non-cash pre-tax impairment charge of $378.0 million in the third quarter of 2017 for the partial impairment of gas processing facilities and gathering systems associated with our North Texas operations in our Gathering and Processing segment. The impairment was a result of our assessment that forecasted undiscounted future net cash flows from operations, while positive, would not be sufficient to recover the existing total net book value of the underlying assets. Given the price environment at the time, we projected a continuing decline in natural gas production across the Barnett Shale in North Texas due in part to producers pursuing more attractive opportunities in other basins. We measured the impairment of property, plant and equipment using discounted estimated future cash flow analysis (“DCF”) including a terminal value (a Level 3 fair value measurement). The future cash flows were based on our estimates of future revenues, income from operations and other factors, such as timing of capital expenditures. We took into account current and expected industry and market conditions, including commodity prices and volumetric forecasts. The discount rate used in our DCF analysis was based on a weighted average cost of capital determined from relevant market comparisons. These carrying value adjustments are included in Impairment of property, plant and equipment in our Consolidated Statements of Operations. Intangible Assets Intangible assets consist of customer contracts and customer relationships acquired in the Permian Acquisition and the acquisition of the Flag City Plant assets in SouthTX in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlands acquisition in 2012. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate. Amortization expense attributable to these assets is recorded over the periods in which we benefit from services provided to customers. We are amortizing these assets over lives ranging from 10 to 20 years using a method that closely reflects the cash flow pattern underlying their intangible asset valuation, or the straight-line method, if a reliably determinable pattern of amortization could not be identified. The estimated annual amortization expense for intangible assets is approximately $182.6 million, $171.6 million, $159.4 million, $149.5 million and $141.2 million for each of the years 2018 through 2022. The changes in our intangible assets are as follows: Balance at December 31, 2017 $ 2,165.8 Amortization (136.2 ) Balance at September 30, 2018 $ 2,029.6 Asset Sales During the second quarter of 2018, we sold our inland marine barge business to a third party for $69.3 million. |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 9 Months Ended |
Sep. 30, 2018 | |
Equity Method Investments And Joint Ventures [Abstract] | |
Investments in Unconsolidated Affiliates | Note 7 – Investments in Unconsolidated Affiliates Our investments in unconsolidated affiliates consist of the following: • a • three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), a gas gathering company; a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), a gas gathering company; and a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 EF Cogen”), which owns a cogeneration facility, (together the “T2 Joint Ventures”); • a 50% operated ownership interest in the Cayenne ; • a 25% non-operated ownership interest in GCX; • a 50% operated ownership interest in Little Missouri 4; and • a 10% non-operated ownership interest in the Agua Blanca Joint Venture . 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 – Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the formation of our GCX Joint Venture and Little Missouri 4 Joint Venture, and our acquisition of interests in the Cayenne Joint Venture and the Agua Blanca Joint Venture. The following table shows the activity related to our investments in unconsolidated affiliates: Balance at December 31, 2017 Equity Earnings (Loss) Cash Distributions (1) Acquisition Contributions (2) Balance at September 30, 2018 GCF $ 45.8 $ 14.2 $ (16.3 ) $ — $ — $ 43.7 T2 LaSalle (3) 54.1 (3.8 ) — — 0.1 50.4 T2 Eagle Ford (3) 109.2 (7.6 ) — — — 101.6 T2 EF Cogen 3.9 (1.3 ) — — — 2.6 Cayenne 8.6 4.6 (1.9 ) — 5.5 16.8 GCX — 0.1 — — 154.8 154.9 Little Missouri 4 — — (8.0 ) — 75.3 67.3 Agua Blanca — 0.2 — 3.5 0.5 4.2 Total $ 221.6 $ 6.4 $ (26.2 ) $ 3.5 $ 236.2 $ 441.5 _________________ (1) Includes $2.2 million in distributions received from GCF in excess of our share of cumulative earnings for the nine months ended September 30, 2018. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur. Also 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 See Note 18 – Supplemental Cash Flow Information. (3) The carrying values of the T2 Joint Venture |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 9 Months Ended |
Sep. 30, 2018 | |
Payables And Accruals [Abstract] | |
Accounts Payable and Accrued Liabilities | Note 8 — Accounts Payable and Accrued Liabilities September 30, 2018 December 31, 2017 Commodities $ 975.5 $ 711.9 Other goods and services 499.8 286.9 Interest 83.3 54.1 Permian Acquisition contingent consideration, estimated current portion 329.0 6.8 Income and other taxes 88.6 26.3 Other 7.9 20.6 $ 1,984.1 $ 1,106.6 Accounts payable and accrued liabilities includes $53.8 million and $49.7 million of liabilities to creditors to whom we have issued checks that remained outstanding as of September 30, 2018 and December 31, 2017. The current portion of the Permian Acquisition contingent consideration represents the estimated fair value of the earn-out payments due within twelve months of the respective balance sheet dates. |
Debt Obligations
Debt Obligations | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Debt Obligations | Note 9 — Debt Obligations September 30, 2018 December 31, 2017 Current: Accounts receivable securitization facility, due December 2018 (1) $ 290.0 $ 350.0 Long-term: Senior secured revolving credit facility, variable rate, due June 2023 (2) — 20.0 Senior unsecured notes: 4⅛% fixed rate, due November 2019 749.4 749.4 5¼% fixed rate, due May 2023 559.6 559.6 4¼% fixed rate, due November 2023 583.9 583.9 6¾% fixed rate, due March 2024 580.1 580.1 5⅛% fixed rate, due February 2025 500.0 500.0 5⅞% fixed rate, due April 2026 1,000.0 — 5⅜% fixed rate, due February 2027 500.0 500.0 5% fixed rate, due January 2028 750.0 750.0 TPL notes, 4¾% fixed rate, due November 2021 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 48.1 48.1 Unamortized premium 0.3 0.4 5,277.9 4,298.0 Debt issuance costs, net of amortization (34.0 ) (30.0 ) Long-term debt 5,243.9 4,268.0 Total debt obligations $ 5,533.9 $ 4,618.0 Irrevocable standby letters of credit outstanding $ 76.6 $ 27.2 (1) As of September 30, 2018, we had $350.0 million of qualifying receivables under our $350.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. (2) As of September 30, 2018, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $2,123.4 million. The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the nine months ended September 30, 2018: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 3.4% - 5.5% 3.8% Accounts receivable securitization facility 2.6% - 3.2% 2.9% Compliance with Debt Covenants As of September 30, 2018, we were in compliance with the covenants contained in our various debt agreements. Senior Unsecured Notes In April 2018, we issued $1.0 billion aggregate principal amount of 5 ⅞ ⅞ ⅞ TRP Revolver Amendment In June 2018, we entered into an agreement to amend and restate the TRP Revolver, which extended the maturity date from October 2020 to June 2023, increased available commitments from $1.6 billion to $2.2 billion and lowered the applicable margin range and commitment fee range used in the calculation of interest. Our ability to request additional commitments of $500.0 million remained unchanged. The TRP Revolver bears interest, at our option, either at the base rate or the Eurodollar rate. The base rate is equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin (a) before the collateral release date, ranging from 0.25% to 1.25% dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA and (b) upon and after the collateral release date, ranging from 0.125% to 0.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The Eurodollar rate is equal to LIBOR rate plus an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. We are required to pay a commitment fee equal to an applicable rate ranging from (a) before the collateral release date, 0.25% to 0.375% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA) and (b) upon and after the collateral release date, 0.125% to 0.35% (dependent on our non-credit-enhanced senior unsecured long-term debt ratings) times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25% dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA and (ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on our non-credit-enhanced senior unsecured long-term debt ratings. The TRP Revolver’s covenants remained substantially the same. During the nine months ended September 30, 2018, we incurred a loss of $1.3 million to partially write-off debt issuance costs associated with the TRP Revolver amendment as a result of a change in syndicate members. The remaining debt issuance costs, along with debt issuance costs incurred with this amendment, will be amortized on a straight-line basis over the TRP Revolver’s new term. |
Other Long-term Liabilities
Other Long-term Liabilities | 9 Months Ended |
Sep. 30, 2018 | |
Other Liabilities Noncurrent [Abstract] | |
Other Long-term Liabilities | Note 10 — Other Long-term Liabilities Other long-term liabilities are comprised of the following obligations: September 30, 2018 December 31, 2017 Asset retirement obligations $ 53.4 $ 50.3 Mandatorily redeemable preferred interests 10.3 76.2 Deferred revenue 176.4 136.2 Permian Acquisition contingent consideration, noncurrent portion — 310.2 Other liabilities 5.1 3.1 Total long-term liabilities $ 245.2 $ 576.0 Asset Retirement Obligations Our asset retirement obligations (“ARO”) primarily relate to certain gas gathering pipelines and processing facilities. Mandatorily Redeemable Preferred Interests Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037. For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. As redemption cannot occur before 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate of redemption value as of September 30, 2018. 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 nine months ended September 30, 2018, the change in the estimated redemption value of the mandatorily redeemable preferred interests is primarily attributable to the amendments. Deferred Revenue We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided. Deferred revenue includes consideration received related to the construction and operation of a crude oil and condensate splitter. On December 27, 2015, Targa Terminals LLC and Noble Americas Corp., then a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (the “Splitter Agreement”) under which we will build and operate a crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (the “Channelview Splitter”) and provide approximately 730,000 Bbl of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 Bbl/d of crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel and liquefied petroleum gas and will provide segregated storage for the crude, condensate and components. The Channelview Splitter project is expected to be substantially completed in December 2018, and has an estimated total cost of approximately $150 million. In January 2018, Vitol US Holding Co. acquired Noble Americas Corp. As of September 30, 2018, the first three annual payments due under the Splitter Agreement, totaling $129.0 million, have been received. Deferred revenue also includes nonmonetary consideration received in a 2015 amendment to a gas gathering and processing agreement and consideration received for other construction activities of facilities connected to our systems. The following table shows the changes in deferred revenue: Balance at December 31, 2017 $ 136.2 Additions 43.1 Revenue recognized (2.9 ) Balance at September 30, 2018 $ 176.4 Permian Acquisition Contingent Consideration Upon closing of the Permian Acquisition, a contingent consideration liability arising from potential earn-out provisions was recognized at its preliminary fair value. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures. The first potential earn-out payment would have occurred in May 2018 while the second potential earn-out payment would occur in May 2019. The acquisition date fair value of the contingent consideration of $416.3 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets. For the period from the acquisition date to December 31, 2017, the fair value of the contingent consideration decreased by $99.3 million, 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 September 30, 2018, the fair value of the contingent consideration increased |
Partnership Units and Related M
Partnership Units and Related Matters | 9 Months Ended |
Sep. 30, 2018 | |
Partners Capital [Abstract] | |
Partnership Units and Related Matters | Note 11 — Partnership Units and Related Matters Distributions TRC is entitled to receive all Partnership distributions after payment of preferred distributions each quarter. The following table details the distributions declared and/or paid by us for the nine months ended September 30, 2018: Three Months Ended Date Paid Or to Be Paid Total Distributions Distributions to Targa Resources Corp. 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 December 31, 2017 February 12, 2018 228.5 225.7 Contributions All capital contributions to us continue to be allocated 98% to the limited partner and 2% to our general partner; however, no units will be issued for those contributions. During the nine months ended September 30, 2018, TRC made total capital contributions to us of $540.0 million. Preferred Units Our Preferred Units rank senior to our common units with respect to distribution rights. 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%. We paid $2.8 million and $8.4 million of distributions to the holders of preferred units (“Preferred Unitholders”) for the three and nine months ended September 30, 2018. Subsequent Event In October 2018, 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 that will be paid on November 15, 2018. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 9 Months Ended |
Sep. 30, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities | Note 12 — 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 and (ii) future commodity purchases and sales in our Logistics and Marketing segment. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flow hedges for accounting purposes. The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations. We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This 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 September 30, 2018, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2018 2019 2020 2021 2022 2023 Natural Gas Swaps MMBtu/d 210,109 158,246 31,630 11,821 - - Natural Gas Basis Swaps MMBtu/d 158,478 109,281 70,417 56,658 40,000 20,000 NGL Swaps Bbl/d 19,820 16,269 11,607 2,434 - - NGL Futures Bbl/d 33,620 2,890 3,115 - - - NGL Options Bbl/d 1,310 410 - - - - Condensate Swaps Bbl/d 4,990 3,413 1,170 388 - - Condensate Options Bbl/d 590 590 - - - - Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of September 30, 2018 Fair Value as of December 31, 2017 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 57.5 $ 164.1 $ 37.9 $ 78.6 Long-term 6.9 65.2 23.2 18.7 Total derivatives designated as hedging instruments $ 64.4 $ 229.3 $ 61.1 $ 97.3 Derivatives not designated as hedging instruments Commodity contracts Current $ 2.1 $ 12.2 $ — $ 1.1 Long-term 1.5 2.3 — 0.9 Total derivatives not designated as hedging instruments $ 3.6 $ 14.5 $ — $ 2.0 Total current position $ 59.6 $ 176.3 $ 37.9 $ 79.7 Total long-term position 8.4 67.5 23.2 19.6 Total derivatives $ 68.0 $ 243.8 $ 61.1 $ 99.3 The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro Forma Net Presentation September 30, 2018 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 59.6 $ (163.6 ) $ 39.0 $ 11.3 $ (76.3 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (12.7 ) - - (12.7 ) 59.6 (176.3 ) 39.0 11.3 (89.0 ) Long Term Position Counterparties with offsetting positions or collateral 8.4 (42.2 ) - - (33.8 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (25.3 ) - - (25.3 ) 8.4 (67.5 ) - - (59.1 ) Total Derivatives Counterparties with offsetting positions or collateral 68.0 (205.8 ) 39.0 11.3 (110.1 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (38.0 ) - - (38.0 ) $ 68.0 $ (243.8 ) $ 39.0 $ 11.3 $ (148.1 ) Gross Presentation Pro Forma Net Presentation December 31, 2017 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 37.9 $ (74.7 ) $ 22.9 $ 13.8 $ (27.7 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (5.0 ) - - (5.0 ) 37.9 (79.7 ) 22.9 13.8 (32.7 ) Long Term Position Counterparties with offsetting positions or collateral 23.2 (17.3 ) - 14.8 (8.9 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (2.3 ) - - (2.3 ) 23.2 (19.6 ) - 14.8 (11.2 ) Total Derivatives Counterparties with offsetting positions or collateral 61.1 (92.0 ) 22.9 28.6 (36.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.3 ) - - (7.3 ) $ 61.1 $ (99.3 ) $ 22.9 $ 28.6 $ (43.9 ) Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolver that ranks equal in right of payment with liens granted in favor of our senior secured lenders. Some of our hedges are futures contracts executed through a broker that clears the hedges through an exchange. We maintain a margin deposit with the broker in an amount sufficient enough to cover the fair value of our open futures positions. The margin deposit is considered collateral, which is located within other current assets on our Consolidated Balance Sheets and is not offset against the fair values of our derivative instruments. The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net liability of $175.8 million as of September 30, 2018. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment. The following tables reflect amounts recorded in Other Comprehensive Income and amounts reclassified from OCI to revenue and expense for the periods indicated: Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Derivatives in Cash Flow Three Months Ended September 30, Nine Months Ended September 30, Hedging Relationships 2018 2017 2018 2017 Commodity contracts $ (139.6 ) $ (106.8 ) $ (178.0 ) $ (10.5 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended September 30, Nine Months Ended September 30, Location of Gain (Loss) 2018 2017 2018 2017 Revenues $ (23.9 ) $ (2.1 ) $ (58.3 ) $ (2.2 ) 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. Location of Gain Gain (Loss) Recognized in Income on Derivatives Derivatives Not Designated Recognized in Income on Three Months Ended September 30, Nine Months Ended September 30, as Hedging Instruments Derivatives 2018 2017 2018 2017 Commodity contracts Revenue $ (1.1 ) $ (1.5 ) $ (14.1 ) $ (2.9 ) Based on valuations as of September 30, 2018, we expect to reclassify commodity hedge-related deferred losses of $164.9 million included in accumulated other comprehensive income into earnings before income taxes through the end of 2021, with $106.6 million of losses to be reclassified over the next twelve months. See Note 13 – Fair Value Measurements and Note 19 – Segment Information for additional disclosures related to derivative instruments and hedging activities. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 13 — Fair Value Measurements Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value on our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments. Fair Value of Derivative Financial Instruments Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold. The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of these derivatives at September 30, 2018, a net liability position of $175.8 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 $281.7 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 liability of $69.9 million, ignoring an adjustment for counterparty credit risk. Fair Value of Other Financial Instruments Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows: • The TRP Revolver and the accounts receivable securitization facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and • Senior unsecured notes are based on quoted market prices derived from trades of the debt. Contingent consideration liabilities related to business acquisitions are carried at fair value. Fair Value Hierarchy We categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value: • Level 1 – observable inputs such as quoted prices in active markets; • Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and • Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions. The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: September 30, 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) $ 67.7 $ 67.7 $ — $ 67.7 $ — Liabilities from commodity derivative contracts (1) 243.5 243.5 — 231.0 12.5 Permian Acquisition contingent consideration (2) 329.0 329.0 — — 329.0 TPL contingent consideration (3) 2.5 2.5 — — 2.5 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 187.5 187.5 — — — TRP Revolver — — — — — Senior unsecured notes 5,277.9 5,322.8 — 5,322.8 — Accounts receivable securitization facility 290.0 290.0 — 290.0 — December 31, 2017 Fair Value Carrying Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 60.3 $ 60.3 $ — $ 58.8 $ 1.5 Liabilities from commodity derivative contracts (1) 98.5 98.5 — 93.3 5.2 Permian Acquisition contingent consideration (2) 317.0 317.0 — — 317.0 TPL contingent consideration (3) 2.4 2.4 — — 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 124.7 124.7 — — — TRP Revolver 20.0 20.0 — 20.0 — Senior unsecured notes 4,278.0 4,362.4 — 4,362.4 — Accounts receivable securitization facility 350.0 350.0 — 350.0 — (1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 12– Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes. (2) We have a contingent consideration liability related to the Permian Acquisition, which is carried at fair value. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures. (3) We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value. Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance Sheets We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable implied volatilities or market prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract length extends into unobservable periods. The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available. As of September 30, 2018, we had 16 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term is beyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial. The fair value of the Permian Acquisition contingent consideration was determined using a Monte Carlo simulation model. Significant inputs used in the fair value measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, risk adjusted discount rate and volatility associated with the underlying assets. A significant decrease in expected gross margin during the earn-out period, or significant increase in the discount rate or volatility would result in a lower fair value estimate. The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs for both models are not observable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. Changes in the fair value of these liabilities are included in Other income (expense) in our Consolidated Statements of Operations. The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts Contingent Asset/(Liability) Liability Balance, December 31, 2017 $ (3.8 ) $ (319.4 ) Change in fair value of TPL contingent consideration - (0.1 ) Change in fair value of Permian Acquisition contingent consideration (1) - (12.0 ) New Level 3 derivative instruments (1.0 ) - Settlements included in Revenue 2.6 - Unrealized gain/(loss) included in OCI (10.3 ) - Balance, September 30, 2018 $ (12.5 ) $ (331.5 ) (1) Represents the change in fair value between December 31, 2017 and September 30, 2018 of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the initial fair value. |
Related Party Transactions - Ta
Related Party Transactions - Targa | 9 Months Ended |
Sep. 30, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions - Targa | Note 14 — Related Party Transactions – Targa Relationship with Targa We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay. The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable. Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Targa billings of payroll and related costs included in operating expenses $ 61.3 $ 54.0 $ 177.7 $ 148.6 Targa allocation of general and administrative expense 54.6 43.2 149.3 126.6 Cash distributions to Targa based on general partner and limited partner ownership 231.2 222.6 683.7 624.7 Cash contributions from Targa related to limited partner ownership (1) 450.7 14.7 529.2 1,587.5 Cash contributions from Targa to maintain its 2% general partner ownership 9.2 0.3 10.8 32.5 __________________________________________________________________________________________________________ (1) The cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to general partner. See Note 11 – Partnership Units and Related Matters. Relationship with Sajet Resources LLC In December 2010, immediately prior to Targa’s initial public offering, Sajet Resources LLC (“Sajet”) was spun-off from Targa. Certain directors and executive officers of Targa are also directors and executive officers of Sajet. The primary assets of Sajet are real property. Sajet also holds (i) an ownership interest in Floridian Natural Gas Storage Company, LLC through a December 2016 merger with Tesla Resources LLC, (ii) an ownership interest in Allied CNG Ventures LLC and (iii) certain technology rights. Former holders of Targa’s pre-IPO common equity, including certain of Targa’s current and former executives, managers and directors collectively own an 18% interest in Sajet. We provide general and administrative services to Sajet and are reimbursed for these amounts. Services provided to Sajet totaled less than $0.1 million in January and February of 2018. In March 2018, we acquired the 82% interest in Sajet that was held by Warburg Pincus sponsored funds for $5.0 million in cash (the “Warburg Funds Transaction”) and extinguished Sajet’s third-party debt in exchange for a promissory note from Sajet of $9.9 million. Minority shareholders had the right to join the transaction and sell up to 100% of their membership interests in Sajet to us at substantially the same terms and price as the Warburg Funds Transaction (the “Tag-Along Rights”). Minority shareholders who currently hold, or formerly held, executive positions at Targa, and minority shareholders who are board members of Targa, agreed not to exercise their Tag-Along Rights resulting from the Warburg Funds Transaction. Certain minority shareholders chose to sell interests totaling 1.6% for approximately $0.1 million in April 2018. Since March 2018, Sajet has been accounted for on a consolidated basis in our consolidated financial statements. |
Contingencies
Contingencies | 9 Months Ended |
Sep. 30, 2018 | |
Commitments And Contingencies Disclosure [Abstract] | |
Contingencies | Note 15 – Contingencies Legal Proceedings We are a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. We are also a party to various proceedings with governmental environmental agencies in 2018, including but not limited to the Environmental Protection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department of Environmental Quality and North Dakota Department of Health, Environmental Health Section, which assert penalties for alleged violations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in the ordinary course of our business. |
Revenue
Revenue | 9 Months Ended |
Sep. 30, 2018 | |
Revenue From Contract With Customer [Abstract] | |
Revenue | Note 16 – 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 fractionation, export, terminaling and storage agreements. 2018 2019 2020 and after Fixed consideration to be recognized as of September 30, 2018 $ 116.5 $ 500.1 $ 2,790.7 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 16 years. In addition, variability exists in the consideration excluded due to the unknown quantity and composition of volumes to be serviced or sold as well as fluctuations in the market price of commodities to be received as consideration or sold over the applicable remaining contract terms. Such variability is resolved at the end of each future month or quarter. For additional information on our revenue recognition policy and the adoption of ASU No. 2014-09, see Note 3 – Significant Accounting Policies. For disclosures related to disaggregated revenue, see Note 19 – Segment Information. |
Other Operating (Income) Expens
Other Operating (Income) Expense | 9 Months Ended |
Sep. 30, 2018 | |
Other Income And Expenses [Abstract] | |
Other Operating (Income) Expense | Note 17 – Other Operating (Income) Expense Other operating (income) expense is comprised of the following: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Gain) loss on sale or disposal of assets (1) $ 61.1 $ 0.3 $ 14.3 $ 16.6 Miscellaneous business tax 0.4 0.3 1.0 0.6 Other 0.3 - 0.4 - $ 61.8 $ 0.6 $ 15.7 $ 17.2 (1) Comprised primarily of a $57.5 million loss on sale of our refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD during the third quarter of 2018 as disclosed in Note 4 — Newly-Formed Joint Ventures, Acquisitions and Divestitures, offset by a $48.1 million gain on sale of our inland marine barge business to a third party during the second quarter of 2018 as disclosed in Note 6 — Property, Plant and Equipment and Intangible Assets. Also includes a $16.1 million loss in the first quarter of 2017 due to the sale of our ownership interest in VGS. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 9 Months Ended |
Sep. 30, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Note 18 — Supplemental Cash Flow Information Nine Months Ended September 30, 2018 2017 Cash: Interest paid, net of capitalized interest (1) $ 140.5 $ 154.5 Income taxes paid, net of refunds 0.2 (4.9 ) Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 39.4 $ 8.3 Impact of capital expenditure accruals on property, plant and equipment 283.9 118.3 Transfers from materials and supplies inventory to property, plant and equipment 8.9 2.8 Contribution of property, plant and equipment to investments in unconsolidated affiliates 16.0 1.0 Change in ARO liability and property, plant and equipment due to revised cash flow estimate 1.2 3.1 Non-cash balance sheet movements related to assets held for sale (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): Trade receivables $ 8.8 $ — Inventories 5.5 — Property, plant and equipment, net 151.4 — Accounts payable and accrued liabilities (1.7 ) — Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): Contingent consideration recorded at the acquisition date $ — $ 416.3 Non-cash balance sheet movements related to acquisition of related party: Noncontrolling interest 1.1 — __________________ (1) Interest capitalized on major projects was $30.8 million and $8.3 million for the nine months ended September 30, 2018 and 2017. |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting [Abstract] | |
Segment Information | Note 19 — Segment Information We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business). Our reportable segments include operating segments that have been aggregated based on the nature of the products and services provided. Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including exposure to the SCOOP and STACK plays) and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico. Our Logistics and Marketing segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assets and value-added services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPG exporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Marketing segment includes Grand Prix, which is currently under construction. The associated assets are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipeline projects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana. Other contains the results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operating margin and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column. Reportable segment information is shown in the following tables: Three Months Ended September 30, 2018 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 296.7 $ 2,378.2 $ (20.8 ) $ — $ 2,654.1 Fees from midstream services 199.3 133.0 — — 332.3 496.0 2,511.2 (20.8 ) — 2,986.4 Intersegment revenues Sales of commodities 1,069.7 15.5 — (1,085.2 ) — Fees from midstream services 1.5 8.5 — (10.0 ) — 1,071.2 24.0 — (1,095.2 ) — Revenues $ 1,567.2 $ 2,535.2 $ (20.8 ) $ (1,095.2 ) $ 2,986.4 Operating margin $ 255.3 $ 173.5 $ (20.8 ) $ — $ 408.0 Other financial information: Total assets (1) $ 11,331.5 $ 5,019.0 $ 64.2 $ 111.8 $ 16,526.5 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 453.0 $ 560.7 $ — $ 4.0 $ 1,017.7 __________________________________________________________________________________________ (1) Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Three Months Ended September 30, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 200.3 $ 1,672.2 $ (1.0 ) $ — $ 1,871.5 Fees from midstream services 148.5 111.8 — — 260.3 348.8 1,784.0 (1.0 ) — 2,131.8 Intersegment revenues Sales of commodities 783.7 80.6 — (864.3 ) — Fees from midstream services 1.7 7.0 — (8.7 ) — 785.4 87.6 — (873.0 ) — Revenues $ 1,134.2 $ 1,871.6 $ (1.0 ) $ (873.0 ) $ 2,131.8 Operating margin $ 198.3 $ 115.9 $ (1.0 ) $ — $ 313.2 Other financial information: Total assets (1) $ 10,644.3 $ 3,240.9 $ 30.8 $ 56.2 $ 13,972.2 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 295.9 $ 71.0 $ — $ 11.8 $ 378.7 ____________________________________________________________________________________________ (1) Assets included in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Nine Months Ended September 30, 2018 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 835.3 $ 6,188.3 $ (42.2 ) $ — $ 6,981.4 Fees from midstream services 536.8 368.1 — — 904.9 1,372.1 6,556.4 (42.2 ) — 7,886.3 Intersegment revenues Sales of commodities 2,848.9 147.0 — (2,995.9 ) — Fees from midstream services 5.4 24.3 — (29.7 ) — 2,854.3 171.3 — (3,025.6 ) — Revenues $ 4,226.4 $ 6,727.7 $ (42.2 ) $ (3,025.6 ) $ 7,886.3 Operating margin $ 718.4 $ 441.7 $ (42.2 ) $ — $ 1,117.9 Other financial information: Total assets (1) $ 11,331.5 $ 5,019.0 $ 64.2 $ 111.8 $ 16,526.5 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 1,008.2 $ 1,229.9 $ — $ 72.3 $ 2,310.4 __________________________________________________________________________________________ (1) Assets included in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Nine Months Ended September 30, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 544.4 $ 4,804.8 $ 3.9 $ — $ 5,353.1 Fees from midstream services 399.3 359.7 — — 759.0 943.7 5,164.5 3.9 — 6,112.1 Intersegment revenues Sales of commodities 2,209.2 237.8 — (2,447.0 ) — Fees from midstream services 5.1 21.1 — (26.2 ) — 2,214.3 258.9 — (2,473.2 ) — Revenues $ 3,158.0 $ 5,423.4 $ 3.9 $ (2,473.2 ) $ 6,112.1 Operating margin $ 549.3 $ 358.5 $ 3.9 $ — $ 911.7 Other financial information: Total assets (1) $ 10,644.3 $ 3,240.9 $ 30.8 $ 56.2 $ 13,972.2 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 730.7 $ 241.8 $ — $ 15.2 $ 987.7 Business acquisition $ 987.1 $ — $ — $ — $ 987.1 __________________________________________________________________________________________ (1) Assets included 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 disaggregated by product and service for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $ 451.9 $ 505.4 $ 1,338.5 $ 1,485.2 NGL 2,063.2 1,276.2 5,254.4 3,628.5 Condensate 95.7 44.9 286.1 135.8 Petroleum products 68.2 48.6 176.0 108.5 2,679.0 1,875.1 7,055.0 5,358.0 Non-customer revenue: Derivative activities - Hedge (23.8 ) (2.1 ) (59.6 ) (2.0 ) Derivative activities - Non-hedge (1) (1.1 ) (1.5 ) (14.0 ) (2.9 ) (24.9 ) (3.6 ) (73.6 ) (4.9 ) Total sales of commodities 2,654.1 1,871.5 6,981.4 5,353.1 Fees from midstream services: Revenue recognized from contracts with customers: Fractionating and treating 31.1 29.8 90.3 92.8 Storage, terminaling, transportation and export 86.9 75.0 260.8 247.8 Gathering and processing 196.5 138.0 522.3 368.5 Other 17.8 17.5 31.5 49.9 Total fees from midstream services 332.3 260.3 904.9 759.0 Total revenues $ 2,986.4 $ 2,131.8 $ 7,886.3 $ 6,112.1 __________________________________________________________________________________________ (1) Represents derivative activities that are not designated as hedging instruments under ASC 815. The following table shows a reconciliation of reportable segment operating margin to income (loss) before income taxes for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Reconciliation of reportable segment operating margin to income (loss) before income taxes: Gathering and Processing operating margin $ 255.3 $ 198.3 $ 718.4 $ 549.3 Logistics and Marketing operating margin 173.5 115.9 441.7 358.5 Other operating margin (20.8 ) (1.0 ) (42.2 ) 3.9 Depreciation and amortization expenses (206.3 ) (208.3 ) (607.1 ) (602.8 ) General and administrative expenses (59.3 ) (46.6 ) (165.0 ) (139.4 ) Impairment of property, plant and equipment — (378.0 ) — (378.0 ) Interest expense, net (75.7 ) (51.9 ) (113.3 ) (169.5 ) Change in contingent considerations (16.6 ) 126.8 (12.1 ) 125.6 Other, net (58.8 ) (0.2 ) (10.6 ) (47.2 ) Income (loss) before income taxes $ (8.7 ) $ (245.0 ) $ 209.8 $ (299.6 ) |
Significant Accounting Polici_2
Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Recently issued accounting pronouncements not yet adopted Leases In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842) In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU 2018-10, Codification Improvements to Topic 842, Leases In July 2018, the FASB also issued ASU 2018-11, Leases (Topic 842): Targeted Improvements We expect to adopt Topic 842 on January 1, 2019, and intend to elect the land easement practical expedient as well as the optional additional transition method. We are currently in the process of gathering a complete population of our lease arrangements, implementing a software solution with respect to our leases, evaluating the impact of the new standard on our consolidated financial statements, and Measurement of Credit Losses on Financial Instruments In June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. have Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract In August 2018, the FASB issued ASU 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract Recently adopted accounting pronouncements Revenue from Contracts with Customers In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) • Embedded fees within commodity supply contracts where the counterparty is not deemed to be a customer are now reported as a reduction of “Product purchases.” Historically, such fees were reported as “Fees from midstream services.” • Noncash consideration in the form of commodities received in-kind from a customer is now recognized as service revenue within “Fees from midstream services” when the service is performed. Historically, the noncash consideration was only recognized as revenue upon sale to a third party without corresponding “Product purchases.” • For certain contracts structured as a purchase where we do not control the commodities, but rather are acting as an agent for the supplier, revenue is now recognized for the net amount of consideration we expect to retain in exchange for our service. Historically, the purchase from the supplier and subsequent sale were reported gross. The following tables summarize the effects of adoption on our consolidated financial statements: Three Months Ended September 30, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 2,738.7 $ (84.6 ) $ 2,654.1 Fees from midstream services 338.1 (5.8 ) 332.3 Total revenues 3,076.8 (90.4 ) 2,986.4 Costs and expenses: Product purchases 2,473.9 (90.4 ) 2,383.5 Income from operations 80.6 — 80.6 Income (loss) before income taxes (8.7 ) — (8.7 ) Net income (loss) $ (8.7 ) $ — $ (8.7 ) Nine Months Ended September 30, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 7,232.0 $ (250.6 ) $ 6,981.4 Fees from midstream services 923.5 (18.6 ) 904.9 Total revenues 8,155.5 (269.2 ) 7,886.3 Costs and expenses: Product purchases 6,498.9 (269.2 ) 6,229.7 Income from operations 330.1 — 330.1 Income (loss) before income taxes 209.8 — 209.8 Net income (loss) $ 209.8 $ — $ 209.8 See Note 16 – Revenue for information regarding our performance obligations and Note 19 – Segment Information for further disaggregation of our revenues. Targeted Improvements to Accounting for Hedge Activities In August 2017, FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities Cash Flow Classification In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) Other Income In February Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20) Revenue from Contracts with Customers (Topic 606), These amendments were effective for us on January 1, 2018 and were adopted by applying the modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption did not result in a cumulative effect adjustment to retained earnings on January 1, 2018. |
Revenue Recognition | Revenue Recognition Our operating revenues are primarily derived from the following activities: • sales of natural gas, NGLs, condensate, crude oil and petroleum products; • services related to compressing, gathering, treating and processing of natural gas; and • services related to NGL fractionation, terminaling and storage, transportation and treating. We have multiple types of contracts with commercial counterparties and many of these may result in cash inflows to Targa due to the structure of settlement provisions with embedded fees. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, and therefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606. Any cash inflows or fees that are realized on these supply type contracts are reported as a reduction of Product purchases. Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when we satisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on and concurrent with revenue-producing activities, are excluded from revenues. We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent to the supplier, are reported as a single revenue transaction on a combined net basis. Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customer is a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price. Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated service and not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract. The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and composition of the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation. Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment is typically due within 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue. 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 Contract assets are presented separately from amounts presented as a receivable when or as a performance obligation(s) is satisfied and prior to having a right to payment that is unconditional at the end of the reporting period. 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. |
Significant Accounting Polici_3
Significant Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
Summary of Effect of Adoption on Consolidated Financial Statements | The following tables summarize the effects of adoption on our consolidated financial statements: Three Months Ended September 30, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 2,738.7 $ (84.6 ) $ 2,654.1 Fees from midstream services 338.1 (5.8 ) 332.3 Total revenues 3,076.8 (90.4 ) 2,986.4 Costs and expenses: Product purchases 2,473.9 (90.4 ) 2,383.5 Income from operations 80.6 — 80.6 Income (loss) before income taxes (8.7 ) — (8.7 ) Net income (loss) $ (8.7 ) $ — $ (8.7 ) Nine Months Ended September 30, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $ 7,232.0 $ (250.6 ) $ 6,981.4 Fees from midstream services 923.5 (18.6 ) 904.9 Total revenues 8,155.5 (269.2 ) 7,886.3 Costs and expenses: Product purchases 6,498.9 (269.2 ) 6,229.7 Income from operations 330.1 — 330.1 Income (loss) before income taxes 209.8 — 209.8 Net income (loss) $ 209.8 $ — $ 209.8 |
Newly-Formed Joint Ventures, Ac
Newly-Formed Joint Ventures, Acquisitions and Divestitures (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Business Combinations [Abstract] | |
Pro Forma Consolidated Information of Operations | The following summarized unaudited pro forma Consolidated Statements of Operations information for the three and nine months ended September 30, 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. Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Pro Forma Pro Forma Revenues $ 2,131.8 $ 6,126.2 Net income (loss) (244.7 ) (297.0 ) |
Summary of Adjusted Carrying Amounts of Assets and Liabilities Held for Sale | The adjusted carrying amounts of the assets and liabilities held for sale as of September 30, 2018 are as follows: September 30, 2018 Current assets: Trade receivables $ 8.8 Inventories 5.5 Property, plant and equipment, net of accumulated depreciation and estimated loss on sale 151.4 Total assets held for sale $ 165.7 Current liabilities: Accounts payable and accrued liabilities $ (1.7 ) Total liabilities held for sale $ (1.7 ) |
Inventories (Tables)
Inventories (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Inventory Disclosure [Abstract] | |
Components of Inventories | September 30, 2018 December 31, 2017 Commodities $ 163.3 $ 191.6 Materials and supplies 14.6 12.9 $ 177.9 $ 204.5 |
Property, Plant and Equipment_2
Property, Plant and Equipment and Intangible Assets (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Property Plant And Equipment And Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | September 30, 2018 December 31, 2017 Estimated Useful Lives (In Years) Gathering systems $ 7,395.2 $ 7,037.2 5 to 20 Processing and fractionation facilities 3,842.4 3,563.0 5 to 25 Terminaling and storage facilities 1,068.1 1,244.1 5 to 25 Transportation assets 456.1 343.6 10 to 25 Other property, plant and equipment 313.6 303.5 3 to 25 Land 146.8 125.7 — Construction in progress 2,992.4 1,581.5 — Property, plant and equipment 16,214.6 14,198.6 Accumulated depreciation (4,133.8 ) (3,768.7 ) Property, plant and equipment, net $ 12,080.8 $ 10,429.9 Intangible assets $ 2,736.6 $ 2,736.6 10 to 20 Accumulated amortization (707.0 ) (570.8 ) Intangible assets, net $ 2,029.6 $ 2,165.8 |
Schedule of Changes in Intangible Assets | The changes in our intangible assets are as follows: Balance at December 31, 2017 $ 2,165.8 Amortization (136.2 ) Balance at September 30, 2018 $ 2,029.6 |
Investments in Unconsolidated_2
Investments in Unconsolidated Affiliates (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Equity Method Investments And Joint Ventures [Abstract] | |
Activity Related to Partnership's Investment in Unconsolidated Affiliate | The following table shows the activity related to our investments in unconsolidated affiliates: Balance at December 31, 2017 Equity Earnings (Loss) Cash Distributions (1) Acquisition Contributions (2) Balance at September 30, 2018 GCF $ 45.8 $ 14.2 $ (16.3 ) $ — $ — $ 43.7 T2 LaSalle (3) 54.1 (3.8 ) — — 0.1 50.4 T2 Eagle Ford (3) 109.2 (7.6 ) — — — 101.6 T2 EF Cogen 3.9 (1.3 ) — — — 2.6 Cayenne 8.6 4.6 (1.9 ) — 5.5 16.8 GCX — 0.1 — — 154.8 154.9 Little Missouri 4 — — (8.0 ) — 75.3 67.3 Agua Blanca — 0.2 — 3.5 0.5 4.2 Total $ 221.6 $ 6.4 $ (26.2 ) $ 3.5 $ 236.2 $ 441.5 _________________ (1) Includes $2.2 million in distributions received from GCF in excess of our share of cumulative earnings for the nine months ended September 30, 2018. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur. Also 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 See Note 18 – Supplemental Cash Flow Information. (3) The carrying values of the T2 Joint Venture |
Accounts Payable and Accrued _2
Accounts Payable and Accrued Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Payables And Accruals [Abstract] | |
Schedule of Accounts Payable and Accrued Liabilities | September 30, 2018 December 31, 2017 Commodities $ 975.5 $ 711.9 Other goods and services 499.8 286.9 Interest 83.3 54.1 Permian Acquisition contingent consideration, estimated current portion 329.0 6.8 Income and other taxes 88.6 26.3 Other 7.9 20.6 $ 1,984.1 $ 1,106.6 |
Debt Obligations (Tables)
Debt Obligations (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Outstanding Debt | September 30, 2018 December 31, 2017 Current: Accounts receivable securitization facility, due December 2018 (1) $ 290.0 $ 350.0 Long-term: Senior secured revolving credit facility, variable rate, due June 2023 (2) — 20.0 Senior unsecured notes: 4⅛% fixed rate, due November 2019 749.4 749.4 5¼% fixed rate, due May 2023 559.6 559.6 4¼% fixed rate, due November 2023 583.9 583.9 6¾% fixed rate, due March 2024 580.1 580.1 5⅛% fixed rate, due February 2025 500.0 500.0 5⅞% fixed rate, due April 2026 1,000.0 — 5⅜% fixed rate, due February 2027 500.0 500.0 5% fixed rate, due January 2028 750.0 750.0 TPL notes, 4¾% fixed rate, due November 2021 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 48.1 48.1 Unamortized premium 0.3 0.4 5,277.9 4,298.0 Debt issuance costs, net of amortization (34.0 ) (30.0 ) Long-term debt 5,243.9 4,268.0 Total debt obligations $ 5,533.9 $ 4,618.0 Irrevocable standby letters of credit outstanding $ 76.6 $ 27.2 (1) As of September 30, 2018, we had $350.0 million of qualifying receivables under our $350.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. (2) As of September 30, 2018, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $2,123.4 million. |
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 nine months ended September 30, 2018: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred TRP Revolver 3.4% - 5.5% 3.8% Accounts receivable securitization facility 2.6% - 3.2% 2.9% |
Other Long-term Liabilities (Ta
Other Long-term Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Other Liabilities Noncurrent [Abstract] | |
Other Long-term Liabilities | Other long-term liabilities are comprised of the following obligations: September 30, 2018 December 31, 2017 Asset retirement obligations $ 53.4 $ 50.3 Mandatorily redeemable preferred interests 10.3 76.2 Deferred revenue 176.4 136.2 Permian Acquisition contingent consideration, noncurrent portion — 310.2 Other liabilities 5.1 3.1 Total long-term liabilities $ 245.2 $ 576.0 |
Changes in Deferred Revenue | The following table shows the changes in deferred revenue: Balance at December 31, 2017 $ 136.2 Additions 43.1 Revenue recognized (2.9 ) Balance at September 30, 2018 $ 176.4 |
Partnership Units and Related_2
Partnership Units and Related Matters (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Partners Capital [Abstract] | |
Schedule of Distributions | The following table details the distributions declared and/or paid by us for the nine months ended September 30, 2018: Three Months Ended Date Paid Or to Be Paid Total Distributions Distributions to Targa Resources Corp. 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 December 31, 2017 February 12, 2018 228.5 225.7 |
Derivative Instruments and He_2
Derivative Instruments and Hedging Activities (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Notional Volume of Commodity Hedges | At September 30, 2018, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2018 2019 2020 2021 2022 2023 Natural Gas Swaps MMBtu/d 210,109 158,246 31,630 11,821 - - Natural Gas Basis Swaps MMBtu/d 158,478 109,281 70,417 56,658 40,000 20,000 NGL Swaps Bbl/d 19,820 16,269 11,607 2,434 - - NGL Futures Bbl/d 33,620 2,890 3,115 - - - NGL Options Bbl/d 1,310 410 - - - - Condensate Swaps Bbl/d 4,990 3,413 1,170 388 - - Condensate Options Bbl/d 590 590 - - - - |
Fair Values of Derivative Instruments | The following schedules reflect the fair values of our derivative instruments and their location on our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of September 30, 2018 Fair Value as of December 31, 2017 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 57.5 $ 164.1 $ 37.9 $ 78.6 Long-term 6.9 65.2 23.2 18.7 Total derivatives designated as hedging instruments $ 64.4 $ 229.3 $ 61.1 $ 97.3 Derivatives not designated as hedging instruments Commodity contracts Current $ 2.1 $ 12.2 $ — $ 1.1 Long-term 1.5 2.3 — 0.9 Total derivatives not designated as hedging instruments $ 3.6 $ 14.5 $ — $ 2.0 Total current position $ 59.6 $ 176.3 $ 37.9 $ 79.7 Total long-term position 8.4 67.5 23.2 19.6 Total derivatives $ 68.0 $ 243.8 $ 61.1 $ 99.3 |
Pro Forma Impact of Derivatives Net in Consolidated Balance Sheet | The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro Forma Net Presentation September 30, 2018 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 59.6 $ (163.6 ) $ 39.0 $ 11.3 $ (76.3 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (12.7 ) - - (12.7 ) 59.6 (176.3 ) 39.0 11.3 (89.0 ) Long Term Position Counterparties with offsetting positions or collateral 8.4 (42.2 ) - - (33.8 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (25.3 ) - - (25.3 ) 8.4 (67.5 ) - - (59.1 ) Total Derivatives Counterparties with offsetting positions or collateral 68.0 (205.8 ) 39.0 11.3 (110.1 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (38.0 ) - - (38.0 ) $ 68.0 $ (243.8 ) $ 39.0 $ 11.3 $ (148.1 ) Gross Presentation Pro Forma Net Presentation December 31, 2017 Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral $ 37.9 $ (74.7 ) $ 22.9 $ 13.8 $ (27.7 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (5.0 ) - - (5.0 ) 37.9 (79.7 ) 22.9 13.8 (32.7 ) Long Term Position Counterparties with offsetting positions or collateral 23.2 (17.3 ) - 14.8 (8.9 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (2.3 ) - - (2.3 ) 23.2 (19.6 ) - 14.8 (11.2 ) Total Derivatives Counterparties with offsetting positions or collateral 61.1 (92.0 ) 22.9 28.6 (36.6 ) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.3 ) - - (7.3 ) $ 61.1 $ (99.3 ) $ 22.9 $ 28.6 $ (43.9 ) |
Amounts Recorded in Other Comprehensive Income and Amounts Reclassified from OCI to Revenue and Expense | The following tables reflect amounts recorded in Other Comprehensive Income and amounts reclassified from OCI to revenue and expense for the periods indicated: Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Derivatives in Cash Flow Three Months Ended September 30, Nine Months Ended September 30, Hedging Relationships 2018 2017 2018 2017 Commodity contracts $ (139.6 ) $ (106.8 ) $ (178.0 ) $ (10.5 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended September 30, Nine Months Ended September 30, Location of Gain (Loss) 2018 2017 2018 2017 Revenues $ (23.9 ) $ (2.1 ) $ (58.3 ) $ (2.2 ) |
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. Location of Gain Gain (Loss) Recognized in Income on Derivatives Derivatives Not Designated Recognized in Income on Three Months Ended September 30, Nine Months Ended September 30, as Hedging Instruments Derivatives 2018 2017 2018 2017 Commodity contracts Revenue $ (1.1 ) $ (1.5 ) $ (14.1 ) $ (2.9 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Breakdown by Fair Value Hierarchy Category for Financial Instruments Included on Consolidated Balance Sheets | The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: September 30, 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) $ 67.7 $ 67.7 $ — $ 67.7 $ — Liabilities from commodity derivative contracts (1) 243.5 243.5 — 231.0 12.5 Permian Acquisition contingent consideration (2) 329.0 329.0 — — 329.0 TPL contingent consideration (3) 2.5 2.5 — — 2.5 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 187.5 187.5 — — — TRP Revolver — — — — — Senior unsecured notes 5,277.9 5,322.8 — 5,322.8 — Accounts receivable securitization facility 290.0 290.0 — 290.0 — December 31, 2017 Fair Value Carrying Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 60.3 $ 60.3 $ — $ 58.8 $ 1.5 Liabilities from commodity derivative contracts (1) 98.5 98.5 — 93.3 5.2 Permian Acquisition contingent consideration (2) 317.0 317.0 — — 317.0 TPL contingent consideration (3) 2.4 2.4 — — 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 124.7 124.7 — — — TRP Revolver 20.0 20.0 — 20.0 — Senior unsecured notes 4,278.0 4,362.4 — 4,362.4 — Accounts receivable securitization facility 350.0 350.0 — 350.0 — (1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 12– Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes. (2) We have a contingent consideration liability related to the Permian Acquisition, which is carried at fair value. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures. (3) We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value. |
Reconciliation of Changes in Fair Value of Financial Instruments Classified as Level 3 | The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts Contingent Asset/(Liability) Liability Balance, December 31, 2017 $ (3.8 ) $ (319.4 ) Change in fair value of TPL contingent consideration - (0.1 ) Change in fair value of Permian Acquisition contingent consideration (1) - (12.0 ) New Level 3 derivative instruments (1.0 ) - Settlements included in Revenue 2.6 - Unrealized gain/(loss) included in OCI (10.3 ) - Balance, September 30, 2018 $ (12.5 ) $ (331.5 ) (1) Represents the change in fair value between December 31, 2017 and September 30, 2018 of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the initial fair value. |
Related Party Transactions - _2
Related Party Transactions - Targa (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Related Party Transactions [Abstract] | |
Summary of Transactions with Affiliates | The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable. Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Targa billings of payroll and related costs included in operating expenses $ 61.3 $ 54.0 $ 177.7 $ 148.6 Targa allocation of general and administrative expense 54.6 43.2 149.3 126.6 Cash distributions to Targa based on general partner and limited partner ownership 231.2 222.6 683.7 624.7 Cash contributions from Targa related to limited partner ownership (1) 450.7 14.7 529.2 1,587.5 Cash contributions from Targa to maintain its 2% general partner ownership 9.2 0.3 10.8 32.5 __________________________________________________________________________________________________________ (1) The cash contributions from Targa related to limited partner ownership were allocated 98% to the limited partner and 2% to general partner. See Note 11 – Partnership Units and Related Matters. |
Revenue (Tables)
Revenue (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue From Contract With Customer [Abstract] | |
Summary of Estimated Minimum Revenue Expected to be Recognized in Future Related to Unsatisfied Performance Obligations | The following table includes the estimated minimum revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and is comprised of fixed consideration primarily attributable to contracts with minimum volume commitments and for which a guaranteed amount of revenue can be calculated . These contracts are comprised primarily of fractionation, export, terminaling and storage agreements. 2018 2019 2020 and after Fixed consideration to be recognized as of September 30, 2018 $ 116.5 $ 500.1 $ 2,790.7 |
Other Operating (Income) Expe_2
Other Operating (Income) Expense (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Other Income And Expenses [Abstract] | |
Other Operating (Income) Expense | Other operating (income) expense is comprised of the following: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Gain) loss on sale or disposal of assets (1) $ 61.1 $ 0.3 $ 14.3 $ 16.6 Miscellaneous business tax 0.4 0.3 1.0 0.6 Other 0.3 - 0.4 - $ 61.8 $ 0.6 $ 15.7 $ 17.2 (1) Comprised primarily of a $57.5 million loss on sale of our refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD during the third quarter of 2018 as disclosed in Note 4 — Newly-Formed Joint Ventures, Acquisitions and Divestitures, offset by a $48.1 million gain on sale of our inland marine barge business to a third party during the second quarter of 2018 as disclosed in Note 6 — Property, Plant and Equipment and Intangible Assets. Also includes a $16.1 million loss in the first quarter of 2017 due to the sale of our ownership interest in VGS. |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Nine Months Ended September 30, 2018 2017 Cash: Interest paid, net of capitalized interest (1) $ 140.5 $ 154.5 Income taxes paid, net of refunds 0.2 (4.9 ) Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment $ 39.4 $ 8.3 Impact of capital expenditure accruals on property, plant and equipment 283.9 118.3 Transfers from materials and supplies inventory to property, plant and equipment 8.9 2.8 Contribution of property, plant and equipment to investments in unconsolidated affiliates 16.0 1.0 Change in ARO liability and property, plant and equipment due to revised cash flow estimate 1.2 3.1 Non-cash balance sheet movements related to assets held for sale (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): Trade receivables $ 8.8 $ — Inventories 5.5 — Property, plant and equipment, net 151.4 — Accounts payable and accrued liabilities (1.7 ) — Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): Contingent consideration recorded at the acquisition date $ — $ 416.3 Non-cash balance sheet movements related to acquisition of related party: Noncontrolling interest 1.1 — __________________ (1) Interest capitalized on major projects was $30.8 million and $8.3 million for the nine months ended September 30, 2018 and 2017. |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting [Abstract] | |
Information by Segment | Reportable segment information is shown in the following tables: Three Months Ended September 30, 2018 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 296.7 $ 2,378.2 $ (20.8 ) $ — $ 2,654.1 Fees from midstream services 199.3 133.0 — — 332.3 496.0 2,511.2 (20.8 ) — 2,986.4 Intersegment revenues Sales of commodities 1,069.7 15.5 — (1,085.2 ) — Fees from midstream services 1.5 8.5 — (10.0 ) — 1,071.2 24.0 — (1,095.2 ) — Revenues $ 1,567.2 $ 2,535.2 $ (20.8 ) $ (1,095.2 ) $ 2,986.4 Operating margin $ 255.3 $ 173.5 $ (20.8 ) $ — $ 408.0 Other financial information: Total assets (1) $ 11,331.5 $ 5,019.0 $ 64.2 $ 111.8 $ 16,526.5 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 453.0 $ 560.7 $ — $ 4.0 $ 1,017.7 __________________________________________________________________________________________ (1) Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Three Months Ended September 30, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 200.3 $ 1,672.2 $ (1.0 ) $ — $ 1,871.5 Fees from midstream services 148.5 111.8 — — 260.3 348.8 1,784.0 (1.0 ) — 2,131.8 Intersegment revenues Sales of commodities 783.7 80.6 — (864.3 ) — Fees from midstream services 1.7 7.0 — (8.7 ) — 785.4 87.6 — (873.0 ) — Revenues $ 1,134.2 $ 1,871.6 $ (1.0 ) $ (873.0 ) $ 2,131.8 Operating margin $ 198.3 $ 115.9 $ (1.0 ) $ — $ 313.2 Other financial information: Total assets (1) $ 10,644.3 $ 3,240.9 $ 30.8 $ 56.2 $ 13,972.2 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 295.9 $ 71.0 $ — $ 11.8 $ 378.7 ____________________________________________________________________________________________ (1) Assets included in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Nine Months Ended September 30, 2018 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 835.3 $ 6,188.3 $ (42.2 ) $ — $ 6,981.4 Fees from midstream services 536.8 368.1 — — 904.9 1,372.1 6,556.4 (42.2 ) — 7,886.3 Intersegment revenues Sales of commodities 2,848.9 147.0 — (2,995.9 ) — Fees from midstream services 5.4 24.3 — (29.7 ) — 2,854.3 171.3 — (3,025.6 ) — Revenues $ 4,226.4 $ 6,727.7 $ (42.2 ) $ (3,025.6 ) $ 7,886.3 Operating margin $ 718.4 $ 441.7 $ (42.2 ) $ — $ 1,117.9 Other financial information: Total assets (1) $ 11,331.5 $ 5,019.0 $ 64.2 $ 111.8 $ 16,526.5 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 1,008.2 $ 1,229.9 $ — $ 72.3 $ 2,310.4 __________________________________________________________________________________________ (1) Assets included in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. Nine Months Ended September 30, 2017 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 544.4 $ 4,804.8 $ 3.9 $ — $ 5,353.1 Fees from midstream services 399.3 359.7 — — 759.0 943.7 5,164.5 3.9 — 6,112.1 Intersegment revenues Sales of commodities 2,209.2 237.8 — (2,447.0 ) — Fees from midstream services 5.1 21.1 — (26.2 ) — 2,214.3 258.9 — (2,473.2 ) — Revenues $ 3,158.0 $ 5,423.4 $ 3.9 $ (2,473.2 ) $ 6,112.1 Operating margin $ 549.3 $ 358.5 $ 3.9 $ — $ 911.7 Other financial information: Total assets (1) $ 10,644.3 $ 3,240.9 $ 30.8 $ 56.2 $ 13,972.2 Goodwill $ 256.6 $ — $ — $ — $ 256.6 Capital expenditures $ 730.7 $ 241.8 $ — $ 15.2 $ 987.7 Business acquisition $ 987.1 $ — $ — $ — $ 987.1 __________________________________________________________________________________________ (1) Assets included in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. |
Revenues Disaggregated by Product and Service | The following table shows our consolidated revenues disaggregated by product and service for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $ 451.9 $ 505.4 $ 1,338.5 $ 1,485.2 NGL 2,063.2 1,276.2 5,254.4 3,628.5 Condensate 95.7 44.9 286.1 135.8 Petroleum products 68.2 48.6 176.0 108.5 2,679.0 1,875.1 7,055.0 5,358.0 Non-customer revenue: Derivative activities - Hedge (23.8 ) (2.1 ) (59.6 ) (2.0 ) Derivative activities - Non-hedge (1) (1.1 ) (1.5 ) (14.0 ) (2.9 ) (24.9 ) (3.6 ) (73.6 ) (4.9 ) Total sales of commodities 2,654.1 1,871.5 6,981.4 5,353.1 Fees from midstream services: Revenue recognized from contracts with customers: Fractionating and treating 31.1 29.8 90.3 92.8 Storage, terminaling, transportation and export 86.9 75.0 260.8 247.8 Gathering and processing 196.5 138.0 522.3 368.5 Other 17.8 17.5 31.5 49.9 Total fees from midstream services 332.3 260.3 904.9 759.0 Total revenues $ 2,986.4 $ 2,131.8 $ 7,886.3 $ 6,112.1 __________________________________________________________________________________________ (1) Represents derivative activities that are not designated as hedging instruments under ASC 815. |
Reconciliation of Reportable Segment Operating Margin to Income (Loss) Before Income Taxes | The following table shows a reconciliation of reportable segment operating margin to income (loss) before income taxes for the periods presented: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Reconciliation of reportable segment operating margin to income (loss) before income taxes: Gathering and Processing operating margin $ 255.3 $ 198.3 $ 718.4 $ 549.3 Logistics and Marketing operating margin 173.5 115.9 441.7 358.5 Other operating margin (20.8 ) (1.0 ) (42.2 ) 3.9 Depreciation and amortization expenses (206.3 ) (208.3 ) (607.1 ) (602.8 ) General and administrative expenses (59.3 ) (46.6 ) (165.0 ) (139.4 ) Impairment of property, plant and equipment — (378.0 ) — (378.0 ) Interest expense, net (75.7 ) (51.9 ) (113.3 ) (169.5 ) Change in contingent considerations (16.6 ) 126.8 (12.1 ) 125.6 Other, net (58.8 ) (0.2 ) (10.6 ) (47.2 ) Income (loss) before income taxes $ (8.7 ) $ (245.0 ) $ 209.8 $ (299.6 ) |
Organization and Operations (De
Organization and Operations (Details) - Series A Cumulative Redeemable Perpetual Preferred Units [Member] - shares | 1 Months Ended | 9 Months Ended | |
Oct. 31, 2015 | Sep. 30, 2018 | Dec. 31, 2017 | |
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_4
Significant Accounting Policies - Summary of Effect of Adoption on Our Consolidated Financial Statements (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues: | ||||
Total revenues | $ 2,986.4 | $ 2,131.8 | $ 7,886.3 | $ 6,112.1 |
Costs and expenses: | ||||
Product purchases | 2,383.5 | 1,663.1 | 6,229.7 | 4,737.8 |
Income from operations | 80.6 | (320.3) | 330.1 | (225.7) |
Income (loss) before income taxes | (8.7) | (245) | 209.8 | (299.6) |
Net income (loss) | (8.7) | (245) | 209.8 | (295.4) |
Sales of Commodities [Member] | ||||
Revenues: | ||||
Total revenues | 2,654.1 | 1,871.5 | 6,981.4 | 5,353.1 |
Fees from Midstream Services [Member] | ||||
Revenues: | ||||
Total revenues | 332.3 | $ 260.3 | 904.9 | $ 759 |
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | ||||
Revenues: | ||||
Total revenues | 2,986.4 | 7,886.3 | ||
Costs and expenses: | ||||
Product purchases | 2,383.5 | 6,229.7 | ||
Income from operations | 80.6 | 330.1 | ||
Income (loss) before income taxes | (8.7) | 209.8 | ||
Net income (loss) | (8.7) | 209.8 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Sales of Commodities [Member] | ||||
Revenues: | ||||
Total revenues | 2,654.1 | 6,981.4 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Fees from Midstream Services [Member] | ||||
Revenues: | ||||
Total revenues | 332.3 | 904.9 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Pre-Adoption [Member] | ||||
Revenues: | ||||
Total revenues | 3,076.8 | 8,155.5 | ||
Costs and expenses: | ||||
Product purchases | 2,473.9 | 6,498.9 | ||
Income from operations | 80.6 | 330.1 | ||
Income (loss) before income taxes | (8.7) | 209.8 | ||
Net income (loss) | (8.7) | 209.8 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Pre-Adoption [Member] | Sales of Commodities [Member] | ||||
Revenues: | ||||
Total revenues | 2,738.7 | 7,232 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Pre-Adoption [Member] | Fees from Midstream Services [Member] | ||||
Revenues: | ||||
Total revenues | 338.1 | 923.5 | ||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Effect of Adoption [Member] | ||||
Revenues: | ||||
Total revenues | (90.4) | (269.2) | ||
Costs and expenses: | ||||
Product purchases | (90.4) | (269.2) | ||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Effect of Adoption [Member] | Sales of Commodities [Member] | ||||
Revenues: | ||||
Total revenues | (84.6) | (250.6) | ||
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | Accounting Standards Update 2014-09 [Member] | Effect of Adoption [Member] | Fees from Midstream Services [Member] | ||||
Revenues: | ||||
Total revenues | $ (5.8) | $ (18.6) |
Significant Accounting Polici_5
Significant Accounting Policies (Details) - USD ($) | Jan. 01, 2018 | Sep. 30, 2018 |
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 | |
Accounting Standards Update 2017-12 [Member] | ||
New Accounting Pronouncements Or Change In Accounting Principle [Line Items] | ||
Effect on retained earnings | $ 0 | |
Derivative hedge accumulated ineffectiveness | $ 0 |
Newly-Formed Joint Ventures, _2
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Joint Ventures (Details) $ in Millions | Jan. 01, 2020USD ($) | Feb. 06, 2018MBbls / dJointVenture | May 31, 2018aMMcf / d | Apr. 30, 2018USD ($)MBbls / dmi | Mar. 31, 2018USD ($) | Jan. 31, 2018MMcf / d | Jul. 31, 2017USD ($)mi | May 31, 2017MBbls / d | Apr. 30, 2018MMcf / dmi | Sep. 30, 2018MBbls / din | Dec. 31, 2017USD ($)Bcf | Sep. 30, 2017 |
Business Acquisition [Line Items] | ||||||||||||
Fractionation-related infrastructure funded and owned percentage | 100.00% | |||||||||||
Stonepeak Infrastructure Partners [Member] | DevCo JVs [Member] | Scenario Forecast [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 | |||||||||||
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] | GCX [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 25.00% | |||||||||||
Grand Prix DevCo JV [Member] | Grand Prix Joint Venture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 20.00% | |||||||||||
Mont Belvieu, Texas [Member] | Train 6 [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of pipeline | MBbls / d | 100 | |||||||||||
Mont Belvieu, Texas [Member] | Train 6 DevCo JV [Member] | Train 6 [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest in assets | 100.00% | |||||||||||
Grand Prix Joint Venture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Expected cost of joint venture | $ | $ 1,700 | |||||||||||
Grand Prix Joint Venture [Member] | North Texas [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of pipeline | MBbls / d | 450 | |||||||||||
Grand Prix Joint Venture [Member] | Southern Oklahoma [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Expected cost of joint venture | $ | $ 350 | |||||||||||
Grand Prix Joint Venture [Member] | Blackstone Energy Partners [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Percentage of joint venture interest sold | 25.00% | |||||||||||
Grand Prix Joint Venture [Member] | Permian Basin [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of pipeline | MBbls / d | 300 | 300 | ||||||||||
Length of pipeline | in | 24 | |||||||||||
Grand Prix Joint Venture [Member] | Permian Basin [Member] | North Texas [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Diameter of pipeline | in | 30 | |||||||||||
Cayenne Joint Venture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Conversion of existing mile gas pipeline | mi | 62 | |||||||||||
Percentage of ownership interest aquired | 50.00% | |||||||||||
Amount of business aquired | $ | $ 5 | |||||||||||
Project commencement date | 2017-12 | |||||||||||
Ownership interest | 50.00% | |||||||||||
GCX [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 25.00% | |||||||||||
Natural gas transportation cost expected | $ | $ 1,750 | |||||||||||
GCX [Member] | DCP [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 25.00% | |||||||||||
GCX [Member] | KMTP [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 50.00% | |||||||||||
Agua Blanca Joint Venture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Percentage of ownership interest aquired | 10.00% | 10.00% | ||||||||||
Amount of business aquired | $ | $ 3.5 | |||||||||||
Miles of natural gas residue pipeline | mi | 160 | 160 | ||||||||||
Initial capacity of pipeline | MBbls / d | 1.4 | |||||||||||
Carnero Joint Venture [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 50.00% | |||||||||||
Processing capacity | MMcf / d | 460 | 260 | ||||||||||
Area of gas gathering and processing facilities | a | 420,000 | |||||||||||
Carnero Joint Venture [Member] | LM4 Plant [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of gas processing plant acquired | MMcf / d | 200 | |||||||||||
Carnero Joint Venture [Member] | Western Eagle Ford [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Area of gas gathering and processing facilities | a | 315,000 | |||||||||||
Carnero Joint Venture [Member] | Catarina [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Area of gas gathering and processing facilities | a | 105,000 | |||||||||||
Maximum [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Ownership interest | 100.00% | |||||||||||
Maximum [Member] | Apache Corporation [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Percentage of option to purchase equity stake | 15.00% | |||||||||||
Maximum [Member] | Stonepeak Infrastructure Partners [Member] | DevCo JVs [Member] | Scenario Forecast [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Percentage of option to purchase equity stake | 50.00% | |||||||||||
Maximum [Member] | Grand Prix Joint Venture [Member] | North Texas [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of pipeline | MBbls / d | 950 | |||||||||||
Maximum [Member] | Grand Prix Joint Venture [Member] | Permian Basin [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of pipeline | MBbls / d | 550 | 550 | ||||||||||
Maximum [Member] | GCX [Member] | ||||||||||||
Business Acquisition [Line Items] | ||||||||||||
Capacity of natural gas transported per day | Bcf | 1.98 |
Newly-Formed Joint Ventures, _3
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Acquisitions (Details) - Permian Acquisition [Member] - USD ($) | May 30, 2017 | Mar. 02, 2017 | Sep. 30, 2017 | Sep. 30, 2017 | Dec. 31, 2017 |
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 | ||||
Pro forma consolidated results of operations [Abstract] | |||||
Acquisition-related costs | $ 5,600,000 | $ 5,600,000 | |||
Maximum [Member] | |||||
Business Acquisition [Line Items] | |||||
Additional cash that has been paid based on potential earn-out payment | $ 935,000,000 | ||||
Targa Resources Corp. [Member] | |||||
Business Acquisition [Line Items] | |||||
Percentage of ownership interest aquired | 100.00% |
Newly-Formed Joint Ventures, _4
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Pro Forma Impact of Permian Acquisition on Consolidated Statement of Operations (Details) - Permian Acquisition [Member] - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2017 | Sep. 30, 2017 | |
Pro forma consolidated results of operations [Abstract] | ||
Revenues | $ 2,131.8 | $ 6,126.2 |
Net income (loss) | $ (244.7) | $ (297) |
Newly-Formed Joint Ventures, _5
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Contingent Liability (Details) - USD ($) | 3 Months Ended | 9 Months Ended | 10 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Mar. 02, 2017 | |
Business Acquisition [Line Items] | ||||||
Change in contingent considerations included in Other expense (income) | $ 16,600,000 | $ (126,800,000) | $ 12,100,000 | $ (125,600,000) | ||
Permian Acquisition [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Additional cash that may be paid based on potential earn-out payment | $ 317,000,000 | |||||
Potential earn-out payments acquisition date fair value | 416,300,000 | 416,300,000 | ||||
Change in contingent considerations included in Other expense (income) | 16,600,000 | $ (126,600,000) | 12,000,000 | $ (125,500,000) | $ (99,300,000) | |
Permian Acquisition [Member] | Maximum [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Additional cash that may be paid based on potential earn-out payment | $ 935,000,000 | |||||
Permian Acquisition [Member] | Other Long-term Liabilities [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Potential earn-out payments acquisition date fair value | 416,300,000 | 416,300,000 | ||||
Permian Acquisition [Member] | Accounts Payable and Accrued Liabilities [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Change in contingent considerations included in Other expense (income) | 12,000,000 | |||||
Fair value of first potential earn-out payment | 0 | 0 | ||||
Second potential earn-out payments acquisition date fair value | $ 329,000,000 | $ 329,000,000 |
Newly-Formed Joint Ventures, _6
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Additional Information Divestitures (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | ||
Business Acquisition [Line Items] | |||||
Loss on sale or disposal of assets | [1] | $ (61.1) | $ (0.3) | $ (14.3) | $ (16.6) |
Refined Products And Crude Oil Storage And Terminaling Facilities [Member] | Tacoma, WA, And Baltimore, MD [Member] | |||||
Business Acquisition [Line Items] | |||||
Selling price of property upon agreement | 160 | ||||
Loss on sale or disposal of assets | (57.5) | ||||
Refined Products And Crude Oil Storage And Terminaling Facilities [Member] | Tacoma, WA, And Baltimore, MD [Member] | Other Income (Expense) [Member] | |||||
Business Acquisition [Line Items] | |||||
Loss on sale or disposal of assets | $ (57.5) | $ (57.5) | |||
[1] | Comprised primarily of a $57.5 million loss on sale of our refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD during the third quarter of 2018 as disclosed in Note 4 — Newly-Formed Joint Ventures, Acquisitions and Divestitures, offset by a $48.1 million gain on sale of our inland marine barge business to a third party during the second quarter of 2018 as disclosed in Note 6 — Property, Plant and Equipment and Intangible Assets. Also includes a $16.1 million loss in the first quarter of 2017 due to the sale of our ownership interest in VGS. |
Newly-Formed Joint Ventures, _7
Newly-Formed Joint Ventures, Acquisitions and Divestitures - Summary of Adjusted Carrying Amounts of Assets and Liabilities Held for Sale (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Current assets: | ||
Trade receivables | $ 8.8 | |
Inventories | 5.5 | |
Property, plant and equipment, net of accumulated depreciation and estimated loss on sale | 151.4 | |
Total assets held for sale | 165.7 | $ 0 |
Current liabilities: | ||
Accounts payable and accrued liabilities | (1.7) | |
Total liabilities held for sale | $ (1.7) | $ 0 |
Inventories (Details)
Inventories (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Inventory Disclosure [Abstract] | ||
Commodities | $ 163.3 | $ 191.6 |
Materials and supplies | 14.6 | 12.9 |
Total inventory | $ 177.9 | $ 204.5 |
Property, Plant and Equipment_3
Property, Plant and Equipment and Intangible Assets, Property, Plant and Equipment (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2018 | Dec. 31, 2017 | |
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment | $ 16,214.6 | $ 14,198.6 |
Accumulated depreciation | (4,133.8) | (3,768.7) |
Property, plant and equipment, net | 12,080.8 | 10,429.9 |
Intangible assets | 2,736.6 | 2,736.6 |
Accumulated amortization | (707) | (570.8) |
Intangible assets, net | $ 2,029.6 | 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 | $ 7,395.2 | 7,037.2 |
Gathering Systems [Member] | Minimum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful life | 5 years | |
Gathering Systems [Member] | Maximum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful life | 20 years | |
Processing and Fractionation Facilities [Member] | ||
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment | $ 3,842.4 | 3,563 |
Processing and Fractionation Facilities [Member] | Minimum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful life | 5 years | |
Processing and Fractionation Facilities [Member] | Maximum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful life | 25 years | |
Terminaling and Storage Facilities [Member] | ||
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment | $ 1,068.1 | 1,244.1 |
Terminaling and Storage Facilities [Member] | Minimum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful life | 5 years | |
Terminaling and Storage Facilities [Member] | Maximum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful life | 25 years | |
Transportation Assets [Member] | ||
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment | $ 456.1 | 343.6 |
Transportation Assets [Member] | Minimum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful life | 10 years | |
Transportation Assets [Member] | Maximum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful life | 25 years | |
Other Property, Plant and Equipment [Member] | ||
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment | $ 313.6 | 303.5 |
Other Property, Plant and Equipment [Member] | Minimum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful life | 3 years | |
Other Property, Plant and Equipment [Member] | Maximum [Member] | ||
Property Plant And Equipment [Line Items] | ||
Estimated useful life | 25 years | |
Land [Member] | ||
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment | $ 146.8 | 125.7 |
Construction in Progress [Member] | ||
Property Plant And Equipment [Line Items] | ||
Property, plant and equipment | $ 2,992.4 | $ 1,581.5 |
Property, Plant and Equipment_4
Property, Plant and Equipment and Intangible Assets - Impairment of North Texas Gathering and Processing Assets (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Property Plant And Equipment And Intangible Assets [Abstract] | ||||
Non-cash pre-tax impairment charges | $ 0 | $ 378 | $ 0 | $ 378 |
Property, Plant and Equipment_5
Property, Plant and Equipment and Intangible Assets, Intangible Assets (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2018USD ($) | |
Estimated amortization expense for intangible assets [Abstract] | |
2,018 | $ 182.6 |
2,019 | 171.6 |
2,020 | 159.4 |
2,021 | 149.5 |
2,022 | $ 141.2 |
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 |
Property, Plant and Equipment_6
Property, Plant and Equipment and Intangible Assets, Schedule of Changes in Intangible Assets (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2018USD ($) | |
Intangible Assets, net [Roll Forward] | |
Balance at December 31, 2017 | $ 2,165.8 |
Amortization | (136.2) |
Balance at September 30, 2018 | $ 2,029.6 |
Property, Plant and Equipment_7
Property, Plant and Equipment and Intangible Assets - Additional Information (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Jun. 30, 2018 | Sep. 30, 2018 | |
Property Plant And Equipment And Intangible Assets [Abstract] | ||
Proceeds from sale of property | $ 69.3 | |
Gain on sale of inland marine barge business | $ 48.1 | $ 48.1 |
Investments in Unconsolidated_3
Investments in Unconsolidated Affiliates - Additional Information (Details) | Sep. 30, 2018JointVenture |
Gulf Coast Fractionators LP [Member] | |
Schedule Of Equity Method Investments [Line Items] | |
Ownership interest | 38.80% |
T2 Joint Ventures [Member] | |
Schedule Of Equity Method Investments [Line Items] | |
Number of non-operated joint ventures acquired in Atlas mergers | 3 |
T2 La Salle [Member] | |
Schedule Of Equity Method Investments [Line Items] | |
Ownership interest | 75.00% |
T2 Eagle Ford [Member] | |
Schedule Of Equity Method Investments [Line Items] | |
Ownership interest | 50.00% |
T2 EF Cogen [Member] | |
Schedule Of Equity Method Investments [Line Items] | |
Ownership interest | 50.00% |
Cayenne Joint Venture [Member] | |
Schedule Of Equity Method Investments [Line Items] | |
Ownership interest | 50.00% |
GCX [Member] | |
Schedule Of Equity Method Investments [Line Items] | |
Ownership interest | 25.00% |
Little Missouri [Member] | |
Schedule Of Equity Method Investments [Line Items] | |
Ownership interest | 50.00% |
Agua Blanca [Member] | |
Schedule Of Equity Method Investments [Line Items] | |
Ownership interest | 10.00% |
Investments in Unconsolidated_4
Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | ||
Schedule Of Equity Method Investments [Line Items] | |||||
Balance at beginning of period | $ 221.6 | ||||
Equity earnings (loss) | $ 3 | $ 0.2 | 6.4 | $ (16.6) | |
Cash Distributions | [1] | (26.2) | |||
Acquisition | 3.5 | ||||
Contributions | [2] | 236.2 | |||
Balance at end of period | 441.5 | 441.5 | |||
Gulf Coast Fractionators LP [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Balance at beginning of period | 45.8 | ||||
Equity earnings (loss) | 14.2 | ||||
Cash Distributions | [1] | (16.3) | |||
Acquisition | 0 | ||||
Contributions | [2] | 0 | |||
Balance at end of period | 43.7 | 43.7 | |||
T2 La Salle [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Balance at beginning of period | [3] | 54.1 | |||
Equity earnings (loss) | [3] | (3.8) | |||
Cash Distributions | [1],[3] | 0 | |||
Acquisition | [3] | 0 | |||
Contributions | [2],[3] | 0.1 | |||
Balance at end of period | [3] | 50.4 | 50.4 | ||
T2 Eagle Ford [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Balance at beginning of period | [3] | 109.2 | |||
Equity earnings (loss) | [3] | (7.6) | |||
Cash Distributions | [1],[3] | 0 | |||
Acquisition | [3] | 0 | |||
Contributions | [2],[3] | 0 | |||
Balance at end of period | [3] | 101.6 | 101.6 | ||
T2 EF Cogen [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Balance at beginning of period | 3.9 | ||||
Equity earnings (loss) | (1.3) | ||||
Cash Distributions | [1] | 0 | |||
Acquisition | 0 | ||||
Contributions | [2] | 0 | |||
Balance at end of period | 2.6 | 2.6 | |||
Cayenne Joint Venture [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Balance at beginning of period | 8.6 | ||||
Equity earnings (loss) | 4.6 | ||||
Cash Distributions | [1] | (1.9) | |||
Acquisition | 0 | ||||
Contributions | [2] | 5.5 | |||
Balance at end of period | 16.8 | 16.8 | |||
GCX [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Balance at beginning of period | 0 | ||||
Equity earnings (loss) | 0.1 | ||||
Cash Distributions | [1] | 0 | |||
Acquisition | 0 | ||||
Contributions | [2] | 154.8 | |||
Balance at end of period | 154.9 | 154.9 | |||
Little Missouri [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Balance at beginning of period | 0 | ||||
Equity earnings (loss) | 0 | ||||
Cash Distributions | [1] | (8) | |||
Acquisition | 0 | ||||
Contributions | [2] | 75.3 | |||
Balance at end of period | 67.3 | 67.3 | |||
Agua Blanca [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Balance at beginning of period | 0 | ||||
Equity earnings (loss) | 0.2 | ||||
Cash Distributions | [1] | 0 | |||
Acquisition | 3.5 | ||||
Contributions | [2] | 0.5 | |||
Balance at end of period | $ 4.2 | $ 4.2 | |||
[1] | Includes $2.2 million in distributions received from GCF in excess of our share of cumulative earnings for the nine months ended September 30, 2018. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows in the period in which they occur. Also 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. See Note 18 – Supplemental Cash Flow Information. The carrying values of the T2 Joint Ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of September 30, 2018, $25.0 million of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20-year useful lives of the underlying assets. | ||||
[3] | The carrying values of the T2 Joint Ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date of acquisition. As of September 30, 2018, $25.0 million of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capital accounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20-year useful lives of the underlying assets. |
Investments in Unconsolidated_5
Investments in Unconsolidated Affiliates - Activity Related to Partnership's Investments in Unconsolidated Affiliates (Parenthetical) (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Schedule Of Equity Method Investments [Line Items] | ||
Return of capital from unconsolidated affiliate | $ 2.2 | $ 2.2 |
Contribution of property, plant and equipment to investment in unconsolidated affiliates | 16 | $ 1 |
Gulf Coast Fractionators LP [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Return of capital from unconsolidated affiliate | 2.2 | |
Little Missouri [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Return of capital from unconsolidated affiliate | 8 | |
T2 Joint Ventures [Member] | ||
Schedule Of Equity Method Investments [Line Items] | ||
Unamortized excess fair value | $ 25 | |
Preliminary estimated useful lives of the underlying assets | 20 years |
Accounts Payable and Accrued _3
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Components of accounts payable and accrued liabilities [Abstract] | ||
Commodities | $ 975.5 | $ 711.9 |
Other goods and services | 499.8 | 286.9 |
Interest | 83.3 | 54.1 |
Income and other taxes | 88.6 | 26.3 |
Other | 7.9 | 20.6 |
Accounts payable and accrued liabilities | 1,984.1 | 1,106.6 |
Permian Acquisition [Member] | ||
Components of accounts payable and accrued liabilities [Abstract] | ||
Permian Acquisition contingent consideration, estimated current portion | $ 329 | $ 6.8 |
Accounts Payable and Accrued _4
Accounts Payable and Accrued Liabilities - Additional Information (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Payables And Accruals [Abstract] | ||
Outstanding checks | $ 53.8 | $ 49.7 |
Debt Obligations (Details)
Debt Obligations (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 | |
Current: | |||
Accounts receivable securitization facility, due December 2018 | [1] | $ 290 | $ 350 |
Long-term [Abstract] | |||
Long-term debt | 5,243.9 | 4,268 | |
Long-term debt including unamortized premium (discount) | 5,277.9 | 4,298 | |
Debt issuance costs, net of amortization | (34) | (30) | |
Total debt obligations | 5,533.9 | 4,618 | |
Irrevocable standby letters of credit outstanding | 76.6 | 27.2 | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 749.4 | 749.4 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 559.6 | 559.6 | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 583.9 | 583.9 | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 580.1 | 580.1 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 2025 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 500 | 500 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5⅞% Notes due April 2026 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 1,000 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 2027 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 500 | 500 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2028 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 750 | 750 | |
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 6.5 | 6.5 | |
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | 48.1 | 48.1 | |
Unamortized premium | $ 0.3 | 0.4 | |
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due June 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [2] | $ 20 | |
[1] | As of September 30, 2018, we had $350.0 million of qualifying receivables under our $350.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. | ||
[2] | As of September 30, 2018, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $2,123.4 million. |
Debt Obligations (Parenthetical
Debt Obligations (Parenthetical) (Details) - USD ($) | 1 Months Ended | 9 Months Ended | |||
Apr. 30, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | ||
Debt Instrument [Line Items] | |||||
Proceeds from borrowings under accounts receivable securitization facility | $ 440,000,000 | $ 281,600,000 | |||
Accounts receivable securitization facility | [1] | $ 290,000,000 | $ 350,000,000 | ||
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | [2] | Jun. 30, 2023 | |||
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due June 2023 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maximum borrowing capacity | $ 2,200,000,000 | ||||
Remaining borrowing capacity | 2,123,400,000 | ||||
Accounts Receivable Securitization Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Proceeds from borrowings under accounts receivable securitization facility | 350,000,000 | ||||
Accounts receivable securitization facility | 350,000,000 | ||||
Availability amount under accounts receivable securitization | $ 60,000,000 | ||||
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | [1] | Dec. 31, 2018 | |||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | Nov. 30, 2019 | ||||
Interest rate on fixed rate debt | 4.125% | ||||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | May 31, 2023 | ||||
Interest rate on fixed rate debt | 5.25% | ||||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | Nov. 30, 2023 | ||||
Interest rate on fixed rate debt | 4.25% | ||||
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | Mar. 31, 2024 | ||||
Interest rate on fixed rate debt | 6.75% | ||||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/8% Notes due February 2025 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | Feb. 28, 2025 | ||||
Interest rate on fixed rate debt | 5.125% | ||||
Senior Unsecured Notes [Member] | Senior Unsecured 5⅞% Notes due April 2026 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | Apr. 30, 2026 | Apr. 30, 2026 | |||
Interest rate on fixed rate debt | 5.875% | 5.875% | |||
Senior Unsecured Notes [Member] | Senior Unsecured 5 3/8% Notes due February 2027 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | Feb. 28, 2027 | ||||
Interest rate on fixed rate debt | 5.375% | ||||
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2028 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | Jan. 31, 2028 | ||||
Interest rate on fixed rate debt | 5.00% | ||||
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | Nov. 30, 2021 | ||||
Interest rate on fixed rate debt | 4.75% | ||||
Senior Unsecured Notes [Member] | Targa Pipeline Partners LP [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date | Aug. 31, 2023 | ||||
Interest rate on fixed rate debt | 5.875% | ||||
[1] | As of September 30, 2018, we had $350.0 million of qualifying receivables under our $350.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. | ||||
[2] | As of September 30, 2018, availability under our $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $2,123.4 million. |
Debt Obligations, Interest Rate
Debt Obligations, Interest Rates on Variable-Rate Debt Obligations (Details) | Sep. 30, 2018 |
Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Weighted average interest rate incurred | 2.90% |
Minimum [Member] | Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred | 2.60% |
Maximum [Member] | Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred | 3.20% |
TRP Revolver [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Weighted average interest rate incurred | 3.80% |
TRP Revolver [Member] | Minimum [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred | 3.40% |
TRP Revolver [Member] | Maximum [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred | 5.50% |
Debt Obligations - Additional I
Debt Obligations - Additional Information (Details) - USD ($) | 1 Months Ended | 9 Months Ended | ||
Apr. 30, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | May 31, 2018 | |
TRP Revolver [Member] | ||||
Debt Instrument [Line Items] | ||||
Maximum borrowing capacity | $ 2,200,000,000 | $ 1,600,000,000 | ||
Additional commitment increase available upon request | $ 500,000,000 | |||
Write off debt issuance cost | $ 1,300,000 | |||
TRP Revolver [Member] | Federal Funds Rate [Member] | ||||
Debt Instrument [Line Items] | ||||
Basis spread on variable rate | 0.50% | |||
TRP Revolver [Member] | London Interbank Offered Rate (LIBOR) | ||||
Debt Instrument [Line Items] | ||||
Basis spread on variable rate | 1.00% | |||
TRP Revolver [Member] | Minimum [Member] | ||||
Debt Instrument [Line Items] | ||||
Commitment fee percentage | 0.25% | |||
TRP Revolver [Member] | Minimum [Member] | Letters of Credit [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest rate on fixed rate debt | 1.25% | |||
TRP Revolver [Member] | Minimum [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | ||||
Debt Instrument [Line Items] | ||||
Commitment fee percentage | 0.125% | |||
TRP Revolver [Member] | Minimum [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | Letters of Credit [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest rate on fixed rate debt | 1.125% | |||
TRP Revolver [Member] | Minimum [Member] | Base Rate [Member] | ||||
Debt Instrument [Line Items] | ||||
Basis spread on variable rate | 0.25% | |||
TRP Revolver [Member] | Minimum [Member] | Base Rate [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | ||||
Debt Instrument [Line Items] | ||||
Basis spread on variable rate | 0.125% | |||
TRP Revolver [Member] | Minimum [Member] | Eurodollar [Member] | ||||
Debt Instrument [Line Items] | ||||
Basis spread on variable rate | 1.25% | |||
TRP Revolver [Member] | Minimum [Member] | Eurodollar [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | ||||
Debt Instrument [Line Items] | ||||
Basis spread on variable rate | 1.125% | |||
TRP Revolver [Member] | Maximum [Member] | ||||
Debt Instrument [Line Items] | ||||
Commitment fee percentage | 0.375% | |||
TRP Revolver [Member] | Maximum [Member] | Letters of Credit [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest rate on fixed rate debt | 2.25% | |||
TRP Revolver [Member] | Maximum [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | ||||
Debt Instrument [Line Items] | ||||
Commitment fee percentage | 0.35% | |||
TRP Revolver [Member] | Maximum [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | Letters of Credit [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest rate on fixed rate debt | 1.75% | |||
TRP Revolver [Member] | Maximum [Member] | Base Rate [Member] | ||||
Debt Instrument [Line Items] | ||||
Basis spread on variable rate | 1.25% | |||
TRP Revolver [Member] | Maximum [Member] | Base Rate [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | ||||
Debt Instrument [Line Items] | ||||
Basis spread on variable rate | 0.75% | |||
TRP Revolver [Member] | Maximum [Member] | Eurodollar [Member] | ||||
Debt Instrument [Line Items] | ||||
Basis spread on variable rate | 2.25% | |||
TRP Revolver [Member] | Maximum [Member] | Eurodollar [Member] | Non-Credit-Enhanced Senior Unsecured Long-Term Debt Ratings [Member] | ||||
Debt Instrument [Line Items] | ||||
Basis spread on variable rate | 1.75% | |||
Senior Unsecured Notes [Member] | Senior Unsecured 5⅞% Notes due April 2026 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior notes issued | $ 1,000,000,000 | |||
Interest rate on fixed rate debt | 5.875% | 5.875% | ||
Maturity date | Apr. 30, 2026 | Apr. 30, 2026 | ||
Net proceeds from senior notes | $ 991,900,000 |
Other Long-term Liabilities - S
Other Long-term Liabilities - Schedule of Other Long-term Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Other Liabilities Noncurrent [Line Items] | ||
Asset retirement obligations | $ 53.4 | $ 50.3 |
Mandatorily redeemable preferred interests | 10.3 | 76.2 |
Deferred revenue | 176.4 | 136.2 |
Other liabilities | 5.1 | 3.1 |
Total long-term liabilities | $ 245.2 | 576 |
Permian Acquisition [Member] | ||
Other Liabilities Noncurrent [Line Items] | ||
Permian Acquisition contingent consideration, noncurrent portion | $ 310.2 |
Other Long-term Liabilities - A
Other Long-term Liabilities - Additional Information (Details) | 3 Months Ended | 9 Months Ended | 10 Months Ended | |||
Sep. 30, 2018USD ($)JointVenture | Sep. 30, 2017USD ($) | Sep. 30, 2018USD ($)JointVenture | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($) | Dec. 27, 2015bbl | |
Deferred Revenue [Abstract] | ||||||
Channelview Splitter project estimated total cost | $ 2,383,500,000 | $ 1,663,100,000 | $ 6,229,700,000 | $ 4,737,800,000 | ||
Deferred revenue | 176,400,000 | 176,400,000 | $ 136,200,000 | |||
Increase (decrease) in fair value of contingent consideration liability | 16,600,000 | (126,800,000) | $ 12,100,000 | (125,600,000) | ||
Channelview Splitter [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Storage capacity of Channelview Terminal | bbl | 730,000 | |||||
Channelview Splitter capability to split crude oil and condensate barrel per day | bbl | 35,000 | |||||
Channelview Splitter project expected substantially completion period | December 2,018 | |||||
Deferred revenue | 129,000,000 | $ 129,000,000 | ||||
Channelview Splitter [Member] | Oil and Gas Operation and Maintenance [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Channelview Splitter project estimated total cost | 150,000,000 | |||||
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 | 16,600,000 | $ (126,600,000) | 12,000,000 | $ (125,500,000) | (99,300,000) | |
Additional cash that may be paid based on potential earn-out payment | 317,000,000 | |||||
Contingent consideration current liability | 329,000,000 | 329,000,000 | $ 6,800,000 | |||
Permian Acquisition [Member] | Other Long-term Liabilities [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Preliminary acquisition date fair value of the contingent consideration | 416,300,000 | 416,300,000 | ||||
Permian Acquisition [Member] | Accounts Payable and Accrued Liabilities [Member] | ||||||
Deferred Revenue [Abstract] | ||||||
Increase (decrease) in fair value of contingent consideration liability | 12,000,000 | |||||
Fair value of first potential earn-out payment | 0 | 0 | ||||
Fair value of second potential earn-out payment | $ 329,000,000 | $ 329,000,000 | ||||
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 | 2 | ||||
Mandatorily Redeemable Preferred Interests [Member] | WestOK [Member] | ||||||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | ||||||
Ownership interest | 100.00% | 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% | 72.80% |
Other Long-term Liabilities, Ch
Other Long-term Liabilities, Changes In Deferred Revenue (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2018USD ($) | |
Other Liabilities Noncurrent [Abstract] | |
Balance at December 31, 2017 | $ 136.2 |
Additions | 43.1 |
Revenue recognized | (2.9) |
Balance at September 30, 2018 | $ 176.4 |
Partnership Units and Related_3
Partnership Units and Related Matters, Distributions (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Distributions declared and/or paid by the Partnership [Abstract] | ||||||
Date Paid Or to Be Paid | Nov. 13, 2018 | Aug. 13, 2018 | May 11, 2018 | Feb. 12, 2018 | ||
Total Distributions | $ 692.1 | $ 633.1 | ||||
Distributions Paid [Member] | ||||||
Distributions declared and/or paid by the Partnership [Abstract] | ||||||
Total Distributions | $ 237.6 | $ 234 | $ 229.7 | $ 228.5 | ||
Distributions to Targa Resources Corp. | $ 234.8 | $ 231.2 | $ 226.9 | $ 225.7 |
Partnership Units and Related_4
Partnership Units and Related Matters (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||||
Oct. 31, 2018 | Oct. 31, 2015 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Limited Partners Capital Account [Line Items] | ||||||||
Contributions from Targa Resources Corp. | $ 540 | $ 1,620 | ||||||
Distributions declared and/or paid by the Partnership [Abstract] | ||||||||
Date Paid Or to Be Paid | Nov. 13, 2018 | Aug. 13, 2018 | May 11, 2018 | Feb. 12, 2018 | ||||
Subsequent Event [Member] | ||||||||
Distributions declared and/or paid by the Partnership [Abstract] | ||||||||
Date of declaration for cash distribution | 2018-10 | |||||||
Cash distribution declared per unit (in dollars per share) | $ 0.1875 | |||||||
Distributions to Targa Resources Corp. | $ 0.9 | |||||||
Date Paid Or to Be Paid | Nov. 15, 2018 | |||||||
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 | |||||
Preferred units dividend percentage | 9.00% | 9.00% | ||||||
Distribution to holders of preferred units | $ 2.8 | $ 8.4 | ||||||
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% | |||||||
TRC/TRP Merger | ||||||||
Limited Partners Capital Account [Line Items] | ||||||||
Percentage of capital contribution towards partner's interest maintained | 98.00% | |||||||
Percentage of general partner's interest maintained | 2.00% | |||||||
TRC/TRP Merger | Targa Resources Corp [Member] | ||||||||
Limited Partners Capital Account [Line Items] | ||||||||
Contributions from Targa Resources Corp. (in units) | 0 | |||||||
Contributions from Targa Resources Corp. | $ 540 |
Derivative Instruments and He_3
Derivative Instruments and Hedging Activities - Notional Volumes Of The Partnership's Commodity Derivative Contracts (Details) | 9 Months Ended |
Sep. 30, 2018MMBTUbbl | |
Year 2020 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 1,170 |
Year 2020 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 31,630 |
Year 2020 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 11,607 |
Year 2020 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 70,417 |
Year 2020 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 3,115 |
Year 2020 [Member] | Options [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2020 [Member] | Options [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2021 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 388 |
Year 2021 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 11,821 |
Year 2021 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 2,434 |
Year 2021 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 56,658 |
Year 2021 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2021 [Member] | Options [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2021 [Member] | Options [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2022 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2022 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 |
Year 2022 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2022 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 40,000 |
Year 2022 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2022 [Member] | Options [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2022 [Member] | Options [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2018 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 4,990 |
Year 2018 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 210,109 |
Year 2018 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 19,820 |
Year 2018 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 158,478 |
Year 2018 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 33,620 |
Year 2018 [Member] | Options [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 590 |
Year 2018 [Member] | Options [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 1,310 |
Year 2023 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2023 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 |
Year 2023 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2023 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 20,000 |
Year 2023 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2023 [Member] | Options [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2023 [Member] | Options [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 0 |
Year 2019 [Member] | Swaps [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 3,413 |
Year 2019 [Member] | Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 158,246 |
Year 2019 [Member] | Swaps [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 16,269 |
Year 2019 [Member] | Basis Swaps [Member] | Natural Gas [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 109,281 |
Year 2019 [Member] | Future | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 2,890 |
Year 2019 [Member] | Options [Member] | Condensate [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 590 |
Year 2019 [Member] | Options [Member] | NGL [Member] | |
Derivative [Line Items] | |
Notional volumes of commodity hedges (in Bbl per day) | 410 |
Derivative Instruments and He_4
Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets | $ 68 | $ 61.1 |
Derivative assets | 59.6 | 37.9 |
Derivative assets | 8.4 | 23.2 |
Derivative liabilities | 243.8 | 99.3 |
Derivative liabilities | 176.3 | 79.7 |
Derivative liabilities | 67.5 | 19.6 |
Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 64.4 | 61.1 |
Derivative liabilities | 229.3 | 97.3 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 57.5 | 37.9 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 6.9 | 23.2 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 164.1 | 78.6 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Position [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 65.2 | 18.7 |
Not Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 3.6 | 0 |
Derivative liabilities | 14.5 | 2 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 2.1 | 0 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 1.5 | 0 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 12.2 | 1.1 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Position [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | $ 2.3 | $ 0.9 |
Derivative Instruments and He_5
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Derivative Asset [Abstract] | ||
Gross asset | $ 68 | $ 61.1 |
Pro forma net presentation, asset, total | 11.3 | 28.6 |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 68 | 61.1 |
Pro forma net presentation, asset | 11.3 | 28.6 |
Current Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 59.6 | 37.9 |
Pro forma net presentation, asset, current | 11.3 | 13.8 |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 59.6 | 37.9 |
Pro forma net presentation, asset | 11.3 | 13.8 |
Long-term Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 8.4 | 23.2 |
Pro forma net presentation, asset, noncurrent | 14.8 | |
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | $ 8.4 | 23.2 |
Pro forma net presentation, asset | $ 14.8 |
Derivative Instruments and He_6
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Derivative Liability [Abstract] | ||
Gross liability | $ (243.8) | $ (99.3) |
Pro forma net presentation, liability, total | (148.1) | (43.9) |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (205.8) | (92) |
Pro forma net presentation, liability, total | (110.1) | (36.6) |
Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (38) | (7.3) |
Pro forma net presentation, liability, total | (38) | (7.3) |
Current Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (176.3) | (79.7) |
Pro forma net presentation, liability, current | (89) | (32.7) |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (163.6) | (74.7) |
Pro forma net presentation, liability, current | (76.3) | (27.7) |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (12.7) | (5) |
Pro forma net presentation, liability, current | (12.7) | (5) |
Long-term Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (67.5) | (19.6) |
Pro forma net presentation, liability, noncurrent | (59.1) | (11.2) |
Long-term Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (42.2) | (17.3) |
Pro forma net presentation, liability, noncurrent | (33.8) | (8.9) |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | (25.3) | (2.3) |
Pro forma net presentation, liability, noncurrent | $ (25.3) | $ (2.3) |
Derivative Instruments and He_7
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Collateral (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Derivative Asset [Abstract] | ||
Gross collateral | $ 39 | $ 22.9 |
Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross collateral | 39 | 22.9 |
Current Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross collateral | 39 | 22.9 |
Current Position [Member] | Counterparties with Offsetting Position or Collateral [Member] | ||
Derivative Asset [Abstract] | ||
Gross collateral | $ 39 | $ 22.9 |
Derivative Instruments and He_8
Derivative Instruments and Hedging Activities - Additional Information (Details) $ in Millions | Sep. 30, 2018USD ($) |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Estimated fair value of derivative instruments, net liability | $ 175.8 |
Amount expected to reclassify commodity hedge related deferred losses to earnings before income taxes | 164.9 |
Amount of deferred losses to be reclassified into earnings before income taxes over next twelve months | $ 106.6 |
Derivative Instruments and He_9
Derivative Instruments and Hedging Activities, Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) Reclassified from OCI into Income (Effective Portion) | $ (23.9) | $ (2.1) | $ (58.3) | $ (2.2) |
Commodity Contracts [Member] | Revenues [Member] | Not Designated as Hedging Instrument [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) recognized in income on derivatives | (1.1) | (1.5) | (14.1) | (2.9) |
Cash Flow Hedging [Member] | Commodity Contracts [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) | $ (139.6) | $ (106.8) | $ (178) | $ (10.5) |
Fair Value Measurements - Addit
Fair Value Measurements - Additional Information (Details) $ in Millions | Sep. 30, 2018USD ($)Swap |
Fair Value Disclosures [Abstract] | |
Derivatives financial instruments, fair value, net | $ 175.8 |
Derivative fair value of net liability if commodity price increases by 10 percent | 281.7 |
Derivative fair value of net liability if commodity price decreases by 10 percent | $ 69.9 |
Number of natural gas basis swaps categorized as Level 3 | Swap | 16 |
Fair Value Measurements, Breakd
Fair Value Measurements, Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | $ 11.3 | $ 28.6 | |
Liabilities from commodity derivative contracts | 148.1 | 43.9 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Accounts receivable securitization facility | [1] | 290 | 350 |
Permian Acquisition [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Additional cash that may be paid based on potential earn-out payment | 317 | ||
Carrying Value [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [2] | 67.7 | 60.3 |
Liabilities from commodity derivative contracts | [2] | 243.5 | 98.5 |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 187.5 | 124.7 | |
Accounts receivable securitization facility | 290 | 350 | |
Carrying Value [Member] | Permian Acquisition [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Additional cash that may be paid based on potential earn-out payment | [3] | 329 | 317 |
Carrying Value [Member] | TRP Revolver [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 20 | ||
Carrying Value [Member] | Targa Pipeline Partners LP [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Additional cash that may be paid based on potential earn-out payment | [4] | 2.5 | 2.4 |
Carrying Value [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 5,277.9 | 4,278 | |
Fair Value [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [2] | 67.7 | 60.3 |
Liabilities from commodity derivative contracts | [2] | 243.5 | 98.5 |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 187.5 | 124.7 | |
Accounts receivable securitization facility | 290 | 350 | |
Fair Value [Member] | Permian Acquisition [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Additional cash that may be paid based on potential earn-out payment | [3] | 329 | 317 |
Fair Value [Member] | TRP Revolver [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 20 | ||
Fair Value [Member] | Targa Pipeline Partners LP [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Additional cash that may be paid based on potential earn-out payment | [4] | 2.5 | 2.4 |
Fair Value [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 5,322.8 | 4,362.4 | |
Fair Value [Member] | Level 2 [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [2] | 67.7 | 58.8 |
Liabilities from commodity derivative contracts | [2] | 231 | 93.3 |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Accounts receivable securitization facility | 290 | 350 | |
Fair Value [Member] | Level 2 [Member] | TRP Revolver [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 20 | ||
Fair Value [Member] | Level 2 [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 5,322.8 | 4,362.4 | |
Fair Value [Member] | Level 3 [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [2] | 1.5 | |
Liabilities from commodity derivative contracts | [2] | 12.5 | 5.2 |
Fair Value [Member] | Level 3 [Member] | Permian Acquisition [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Additional cash that may be paid based on potential earn-out payment | [3] | 329 | 317 |
Fair Value [Member] | Level 3 [Member] | Targa Pipeline Partners LP [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Additional cash that may be paid based on potential earn-out payment | [4] | $ 2.5 | $ 2.4 |
[1] | As of September 30, 2018, we had $350.0 million of qualifying receivables under our $350.0 million accounts receivable securitization facility, resulting in availability of $60.0 million. | ||
[2] | The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 12– Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes. | ||
[3] | We have a contingent consideration liability related to the Permian Acquisition, which is carried at fair value. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures. | ||
[4] | We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value. |
Fair Value Measurements, Change
Fair Value Measurements, Changes in Fair Value of Financial Instruments Classified as Level 3 (Details) $ in Millions | 9 Months Ended | |
Sep. 30, 2018USD ($) | ||
Contingent Liability [Member] | ||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | ||
Balance, beginning of period | $ (319.4) | |
New Level 3 derivative instruments | 0 | |
Settlements included in Revenue | 0 | |
Unrealized gain/(loss) included in OCI | 0 | |
Balance, end of period | (331.5) | |
Targa Pipeline Partners LP [Member] | Contingent Liability [Member] | ||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | ||
Change in fair value of contingent consideration | (0.1) | |
Permian Acquisition [Member] | Contingent Liability [Member] | ||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | ||
Change in fair value of contingent consideration | (12) | [1] |
Commodity Derivative Contracts Asset/(Liability) [Member] | ||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | ||
Balance, beginning of period | (3.8) | |
New Level 3 derivative instruments | (1) | |
Settlements included in Revenue | 2.6 | |
Unrealized gain/(loss) included in OCI | (10.3) | |
Balance, end of period | (12.5) | |
Commodity Derivative Contracts Asset/(Liability) [Member] | Targa Pipeline Partners LP [Member] | ||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | ||
Change in fair value of contingent consideration | 0 | |
Commodity Derivative Contracts Asset/(Liability) [Member] | Permian Acquisition [Member] | ||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | ||
Change in fair value of contingent consideration | $ 0 | [1] |
[1] | Represents the change in fair value between December 31, 2017 and September 30, 2018 of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the initial fair value. |
Related Party Transactions - _3
Related Party Transactions - Targa (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | ||
Summary of transactions with Targa [Abstract] | |||||
Cash distributions to Targa based on general partner and limited partner ownership | $ 692.1 | $ 633.1 | |||
Cash contributions from Targa related to limited partner ownership | 529.2 | 1,587.5 | |||
Targa Resources Corp. [Member] | |||||
Summary of transactions with Targa [Abstract] | |||||
Targa billings of payroll and related costs included in operating expenses | $ 61.3 | $ 54 | 177.7 | 148.6 | |
Targa allocation of general and administrative expense | 54.6 | 43.2 | 149.3 | 126.6 | |
Cash distributions to Targa based on general partner and limited partner ownership | 231.2 | 222.6 | 683.7 | 624.7 | |
Cash contributions from Targa related to limited partner ownership | [1] | 450.7 | 14.7 | 529.2 | 1,587.5 |
Contributions from Targa Resources Corp | $ 9.2 | $ 0.3 | $ 10.8 | $ 32.5 | |
Percentage of general partner's interest maintained | 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 general partner. See Note 11 – Partnership Units and Related Matters. |
Related Party Transactions - _4
Related Party Transactions - Targa (Parenthetical) (Details) - Targa Resources Corp. [Member] | 3 Months Ended | 9 Months Ended |
Sep. 30, 2018 | Sep. 30, 2018 | |
Related Party Transaction [Line Items] | ||
Percentage of capital contribution towards partner's interest maintained | 98.00% | |
Percentage of general partner's interest maintained | 2.00% | 2.00% |
Related Party Transactions - _5
Related Party Transactions - Targa - Additional Information (Details) - USD ($) $ in Millions | 1 Months Ended | ||||
Mar. 31, 2018 | Apr. 30, 2018 | Feb. 28, 2018 | Jan. 31, 2018 | Dec. 31, 2010 | |
Maximum [Member] | |||||
Related Party Transaction [Line Items] | |||||
Ownership interest | 100.00% | ||||
SAJET Resources LLC [Member] | |||||
Related Party Transaction [Line Items] | |||||
Extinguishment of debt in exchange for promissory note | $ 9.9 | ||||
Minority shareholders interest sold | 1.60% | ||||
Minority shareholders interest amount | $ 0.1 | ||||
SAJET Resources LLC [Member] | Maximum [Member] | |||||
Related Party Transaction [Line Items] | |||||
Amount charged to related parties for service. | $ 0.1 | $ 0.1 | |||
SAJET Resources LLC [Member] | Current and Former Executives, Managers and Directors [Member] | |||||
Related Party Transaction [Line Items] | |||||
Collective own interest rate | 18.00% | ||||
Warburg Funds Transaction [Member] | |||||
Related Party Transaction [Line Items] | |||||
Percentage of ownership interest aquired | 82.00% | ||||
Cash payments related to acquisition | $ 5 |
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 | Sep. 30, 2018USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2018-07-01 | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Fixed consideration to be recognized | $ 116.5 |
Estimated remaining duration of contracts | 6 months |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2019-01-01 | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Fixed consideration to be recognized | $ 500.1 |
Estimated remaining duration of contracts | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date: 2020-01-01 | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Fixed consideration to be recognized | $ 2,790.7 |
Estimated remaining duration of contracts |
Revenue - Additional Informatio
Revenue - Additional Information (Details) | Sep. 30, 2018 |
Minimum [Member] | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Estimated remaining duration of contracts | 1 year |
Maximum [Member] | |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | |
Estimated remaining duration of contracts | 16 years |
Other Operating (Income) Expe_3
Other Operating (Income) Expense (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | ||
Other Income And Expenses [Abstract] | |||||
(Gain) loss on sale or disposal of assets | [1] | $ 61.1 | $ 0.3 | $ 14.3 | $ 16.6 |
Miscellaneous business tax | 0.4 | 0.3 | 1 | 0.6 | |
Other | 0.3 | 0.4 | |||
Total other operating (income) expense | $ 61.8 | $ 0.6 | $ 15.7 | $ 17.2 | |
[1] | Comprised primarily of a $57.5 million loss on sale of our refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD during the third quarter of 2018 as disclosed in Note 4 — Newly-Formed Joint Ventures, Acquisitions and Divestitures, offset by a $48.1 million gain on sale of our inland marine barge business to a third party during the second quarter of 2018 as disclosed in Note 6 — Property, Plant and Equipment and Intangible Assets. Also includes a $16.1 million loss in the first quarter of 2017 due to the sale of our ownership interest in VGS. |
Other Operating (Income) Expe_4
Other Operating (Income) Expense (Parenthetical) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||||
Sep. 30, 2018 | Jun. 30, 2018 | Sep. 30, 2017 | Mar. 31, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | ||
Other Operating Income Expense [Line Items] | |||||||
Loss on sale or disposal of assets | [1] | $ (61.1) | $ (0.3) | $ (14.3) | $ (16.6) | ||
Gain on sale of inland marine barge business | $ 48.1 | $ 48.1 | |||||
Refined Products And Crude Oil Storage And Terminaling Facilities [Member] | Tacoma, WA, And Baltimore, MD [Member] | |||||||
Other Operating Income Expense [Line Items] | |||||||
Loss on sale or disposal of assets | $ (57.5) | ||||||
VGS [Member] | Disposal Group, Not Discontinued Operations [Member] | |||||||
Other Operating Income Expense [Line Items] | |||||||
Loss on sale or disposal of assets | $ (16.1) | ||||||
[1] | Comprised primarily of a $57.5 million loss on sale of our refined products and crude oil storage and terminaling facilities in Tacoma, WA, and Baltimore, MD during the third quarter of 2018 as disclosed in Note 4 — Newly-Formed Joint Ventures, Acquisitions and Divestitures, offset by a $48.1 million gain on sale of our inland marine barge business to a third party during the second quarter of 2018 as disclosed in Note 6 — Property, Plant and Equipment and Intangible Assets. Also includes a $16.1 million loss in the first quarter of 2017 due to the sale of our ownership interest in VGS. |
Supplemental Cash Flow Inform_3
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | ||
Cash [Abstract] | |||
Interest paid, net of capitalized interest | [1] | $ 140.5 | $ 154.5 |
Income taxes paid, net of refunds | 0.2 | (4.9) | |
Non-cash investing activities [Abstract] | |||
Deadstock commodity inventory transferred to property, plant and equipment | 39.4 | 8.3 | |
Impact of capital expenditure accruals on property, plant and equipment | 283.9 | 118.3 | |
Transfers from materials and supplies inventory to property, plant and equipment | 8.9 | 2.8 | |
Contribution of property, plant and equipment to investments in unconsolidated affiliates | 16 | 1 | |
Change in ARO liability and property, plant and equipment due to revised cash flow estimate | 1.2 | 3.1 | |
Non-cash balance sheet movements related to assets held for sale (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): | |||
Trade receivables | 8.8 | ||
Inventories | 5.5 | ||
Property, plant and equipment, net | 151.4 | ||
Accounts payable and accrued liabilities | (1.7) | ||
Non-cash balance sheet movements related to acquisition of related party: | |||
Noncontrolling interest | $ 1.1 | ||
Permian Acquisition [Member] | |||
Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - Newly-Formed Joint Ventures, Acquisitions and Divestitures): | |||
Contingent consideration recorded at the acquisition date | $ 416.3 | ||
[1] | Interest capitalized on major projects was $30.8 million and $8.3 million for the nine months ended September 30, 2018 and 2017. |
Supplemental Cash Flow Inform_4
Supplemental Cash Flow Information (Parenthetical) (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Supplemental Cash Flow Information [Abstract] | ||
Interest capitalized on major projects | $ 30.8 | $ 8.3 |
Segment Information - Additiona
Segment Information - Additional Information (Details) | 9 Months Ended |
Sep. 30, 2018Segment | |
Segment Reporting [Abstract] | |
Number of reportable segments | 2 |
Segment Information, Revenues a
Segment Information, Revenues and Operating Margin (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues [Abstract] | ||||
Revenues | $ 2,986.4 | $ 2,131.8 | $ 7,886.3 | $ 6,112.1 |
Operating margin | 408 | 313.2 | 1,117.9 | 911.7 |
Sales of Commodities [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 2,654.1 | 1,871.5 | 6,981.4 | 5,353.1 |
Fees from Midstream Services [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 332.3 | 260.3 | 904.9 | 759 |
Gathering and Processing [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 1,567.2 | 1,134.2 | 4,226.4 | 3,158 |
Operating margin | 255.3 | 198.3 | 718.4 | 549.3 |
Logistics and Marketing [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 2,535.2 | 1,871.6 | 6,727.7 | 5,423.4 |
Operating margin | 173.5 | 115.9 | 441.7 | 358.5 |
Other [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (20.8) | (1) | (42.2) | 3.9 |
Operating margin | (20.8) | (1) | (42.2) | 3.9 |
Corporate and Elimination [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (1,095.2) | (873) | (3,025.6) | (2,473.2) |
Operating Segments [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 2,986.4 | 2,131.8 | 7,886.3 | 6,112.1 |
Operating Segments [Member] | Sales of Commodities [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 2,654.1 | 1,871.5 | 6,981.4 | 5,353.1 |
Operating Segments [Member] | Fees from Midstream Services [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 332.3 | 260.3 | 904.9 | 759 |
Operating Segments [Member] | Gathering and Processing [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 496 | 348.8 | 1,372.1 | 943.7 |
Operating Segments [Member] | Gathering and Processing [Member] | Sales of Commodities [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 296.7 | 200.3 | 835.3 | 544.4 |
Operating Segments [Member] | Gathering and Processing [Member] | Fees from Midstream Services [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 199.3 | 148.5 | 536.8 | 399.3 |
Operating Segments [Member] | Logistics and Marketing [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 2,511.2 | 1,784 | 6,556.4 | 5,164.5 |
Operating Segments [Member] | Logistics and Marketing [Member] | Sales of Commodities [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 2,378.2 | 1,672.2 | 6,188.3 | 4,804.8 |
Operating Segments [Member] | Logistics and Marketing [Member] | Fees from Midstream Services [Member] | ||||
Revenues [Abstract] | ||||
Revenues | 133 | 111.8 | 368.1 | 359.7 |
Operating Segments [Member] | Other [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (20.8) | (1) | (42.2) | 3.9 |
Operating Segments [Member] | Other [Member] | Sales of Commodities [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (20.8) | (1) | (42.2) | 3.9 |
Intersegment Eliminations [Member] | Gathering and Processing [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (1,071.2) | (785.4) | (2,854.3) | (2,214.3) |
Intersegment Eliminations [Member] | Gathering and Processing [Member] | Sales of Commodities [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (1,069.7) | (783.7) | (2,848.9) | (2,209.2) |
Intersegment Eliminations [Member] | Gathering and Processing [Member] | Fees from Midstream Services [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (1.5) | (1.7) | (5.4) | (5.1) |
Intersegment Eliminations [Member] | Logistics and Marketing [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (24) | (87.6) | (171.3) | (258.9) |
Intersegment Eliminations [Member] | Logistics and Marketing [Member] | Sales of Commodities [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (15.5) | (80.6) | (147) | (237.8) |
Intersegment Eliminations [Member] | Logistics and Marketing [Member] | Fees from Midstream Services [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (8.5) | (7) | (24.3) | (21.1) |
Intersegment Eliminations [Member] | Corporate and Elimination [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (1,095.2) | (873) | (3,025.6) | (2,473.2) |
Intersegment Eliminations [Member] | Corporate and Elimination [Member] | Sales of Commodities [Member] | ||||
Revenues [Abstract] | ||||
Revenues | (1,085.2) | (864.3) | (2,995.9) | (2,447) |
Intersegment Eliminations [Member] | Corporate and Elimination [Member] | Fees from Midstream Services [Member] | ||||
Revenues [Abstract] | ||||
Revenues | $ (10) | $ (8.7) | $ (29.7) | $ (26.2) |
Segment Information, Other Fina
Segment Information, Other Financial Information (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | ||
Other financial information [Abstract] | ||||||
Total assets | $ 16,526.5 | $ 16,526.5 | $ 14,359 | |||
Goodwill | 256.6 | 256.6 | $ 256.6 | |||
Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 16,526.5 | $ 13,972.2 | 16,526.5 | $ 13,972.2 | |
Goodwill | 256.6 | 256.6 | 256.6 | 256.6 | ||
Capital expenditures | 1,017.7 | 378.7 | 2,310.4 | 987.7 | ||
Business acquisition | 987.1 | 987.1 | ||||
Gathering and Processing [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 11,331.5 | 10,644.3 | 11,331.5 | 10,644.3 | |
Goodwill | 256.6 | 256.6 | 256.6 | 256.6 | ||
Capital expenditures | 453 | 295.9 | 1,008.2 | 730.7 | ||
Business acquisition | 987.1 | 987.1 | ||||
Logistics and Marketing [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 5,019 | 3,240.9 | 5,019 | 3,240.9 | |
Capital expenditures | 560.7 | 71 | 1,229.9 | 241.8 | ||
Other [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 64.2 | 30.8 | 64.2 | 30.8 | |
Corporate and Elimination [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 111.8 | 56.2 | 111.8 | 56.2 | |
Capital expenditures | $ 4 | $ 11.8 | $ 72.3 | $ 15.2 | ||
[1] | Assets in the Corporate and Eliminations column primarily include cash, prepaids and debt issuance costs for our TRP Revolver. |
Segment Information, Revenues D
Segment Information, Revenues Disaggregated by Product and Service (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | ||
Revenue from External Customer [Line Items] | |||||
Revenue recognized from customer and non-customer | $ 2,679 | $ 1,875.1 | $ 7,055 | $ 5,358 | |
Non-customer revenue | (24.9) | (3.6) | (73.6) | (4.9) | |
Total revenues | 2,986.4 | 2,131.8 | 7,886.3 | 6,112.1 | |
Designated as Hedging Instrument [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Non-customer revenue | (23.8) | (2.1) | (59.6) | (2) | |
Not Designated as Hedging Instrument [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Non-customer revenue | [1] | (1.1) | (1.5) | (14) | (2.9) |
Natural Gas [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Revenue recognized from customer and non-customer | 451.9 | 505.4 | 1,338.5 | 1,485.2 | |
NGL [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Revenue recognized from customer and non-customer | 2,063.2 | 1,276.2 | 5,254.4 | 3,628.5 | |
Condensate [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Revenue recognized from customer and non-customer | 95.7 | 44.9 | 286.1 | 135.8 | |
Petroleum Products [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Revenue recognized from customer and non-customer | 68.2 | 48.6 | 176 | 108.5 | |
Fractionating and Treating [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Total revenues | 31.1 | 29.8 | 90.3 | 92.8 | |
Storage, Terminaling, Transportation and Export [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Total revenues | 86.9 | 75 | 260.8 | 247.8 | |
Gathering and Processing [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Total revenues | 196.5 | 138 | 522.3 | 368.5 | |
Sales of Commodities [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Total revenues | 2,654.1 | 1,871.5 | 6,981.4 | 5,353.1 | |
Other [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Total revenues | 17.8 | 17.5 | 31.5 | 49.9 | |
Fees from Midstream Services [Member] | |||||
Revenue from External Customer [Line Items] | |||||
Total revenues | $ 332.3 | $ 260.3 | $ 904.9 | $ 759 | |
[1] | Represents derivative activities that are not designated as hedging instruments under ASC 815. |
Segment Information, Reconcilia
Segment Information, Reconciliation of Reportable Segment Operating Margin to Income (Loss) Before Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | ||||
Operating margin | $ 408 | $ 313.2 | $ 1,117.9 | $ 911.7 |
Depreciation and amortization expenses | (206.3) | (208.3) | (607.1) | (602.8) |
General and administrative expenses | (59.3) | (46.6) | (165) | (139.4) |
Impairment of property, plant and equipment | 0 | (378) | 0 | (378) |
Interest expense, net | (75.7) | (51.9) | (113.3) | (169.5) |
Change in contingent considerations | (16.6) | 126.8 | (12.1) | 125.6 |
Other, net | (58.8) | (0.2) | (10.6) | (47.2) |
Income (loss) before income taxes | (8.7) | (245) | 209.8 | (299.6) |
Gathering and Processing [Member] | ||||
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | ||||
Operating margin | 255.3 | 198.3 | 718.4 | 549.3 |
Logistics and Marketing [Member] | ||||
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | ||||
Operating margin | 173.5 | 115.9 | 441.7 | 358.5 |
Other [Member] | ||||
Reconciliation of reportable segment operating margin to income (loss) before income taxes: | ||||
Operating margin | $ (20.8) | $ (1) | $ (42.2) | $ 3.9 |