Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2016 | May. 02, 2016 | |
Entity Information [Line Items] | ||
Entity Registrant Name | Targa Resources Partners LP | |
Entity Central Index Key | 1,379,661 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q1 | |
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2016 | |
Limited Partner Interest [Member] | ||
Entity Information [Line Items] | ||
Entity Common Stock, Shares Outstanding | 230,002,743 | |
General Partner Units [Member] | ||
Entity Information [Line Items] | ||
Entity Common Stock, Shares Outstanding | 4,693,933 |
CONSOLIDATED BALANCE SHEETS (Un
CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 103.3 | $ 135.4 |
Trade receivables, net of allowances of $0.1 million | 427.6 | 514.8 |
Inventories | 61.7 | 141 |
Assets from risk management activities | 82.4 | 92.2 |
Other current assets | 11.8 | 10 |
Total current assets | 686.8 | 893.4 |
Property, plant and equipment | 12,107.8 | 11,928.2 |
Accumulated depreciation | (2,373.2) | (2,225.6) |
Property, plant and equipment, net | 9,734.6 | 9,702.6 |
Intangible assets, net | 1,765.1 | 1,810.1 |
Goodwill, net of impairment provisions | 393 | 417 |
Long-term assets from risk management activities | 25.2 | 34.9 |
Investments in unconsolidated affiliates | 254.9 | 258.9 |
Other long-term assets | 9 | 9.9 |
Total assets | 12,868.6 | 13,126.8 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 514.8 | 635.8 |
Accounts payable to Targa Resources Corp. | 24.9 | 30.1 |
Liabilities from risk management activities | 2 | 5.2 |
Accounts receivable securitization facility | 150 | 219.3 |
Total current liabilities | 691.7 | 890.4 |
Long-term debt | 4,492.9 | 5,125.7 |
Long-term liabilities from risk management activities | 7.9 | 2.4 |
Deferred income taxes, net | 27 | 27.2 |
Other long-term liabilities | $ 149.5 | $ 178.2 |
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 5,000,000 outstanding as of March 31, 2016 and December 31, 2015) | $ 120.6 | $ 120.6 |
Common limited partners (230,002,743 and 185,083,420 units issued and 230,002,743 and 184,870,693 outstanding as of March 31, 2016 and December 31, 2015) | 5,164.8 | 4,550.4 |
General partner (4,693,934 and 3,772,871 units issued and 4,693,934 and 3,772,871 outstanding as of March 31, 2016 and December 31, 2015) | 1,717.9 | 1,735.3 |
Accumulated other comprehensive income (loss) | 69.3 | 86.8 |
Treasury units at cost (0 units and 212,727 units as of March 31, 2016 and December 31, 2015) | 0 | (10.3) |
Partners' Capital | 7,072.6 | 6,482.8 |
Noncontrolling interests in subsidiaries | 427 | 420.1 |
Total owners' equity | 7,499.6 | 6,902.9 |
Total liabilities and owners' equity | $ 12,868.6 | $ 13,126.8 |
CONSOLIDATED BALANCE SHEETS (U3
CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Trade receivables, allowances | $ 0.1 | $ 0.1 |
Owners' equity: | ||
Series A preferred limited partners units outstanding (in units) | 5,000,000 | |
Common limited partners units issued (in units) | 230,002,743 | 185,083,420 |
Common limited partners units outstanding (in units) | 230,002,743 | 184,870,693 |
General partner units issued (in units) | 4,693,934 | 3,772,871 |
General partner units outstanding (in units) | 4,693,934 | 3,772,871 |
Treasury units (in units) | 0 | 212,727 |
Series A Preferred Limited Partner Units [Member] | ||
Owners' equity: | ||
Series A preferred limited partners units issued (in units) | 5,000,000 | 5,000,000 |
Series A preferred limited partners units outstanding (in units) | 5,000,000 | 5,000,000 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Revenues: | ||
Sales of commodities | $ 1,171 | $ 1,402.2 |
Fees from midstream services | 271.4 | 277.5 |
Total revenues | 1,442.4 | 1,679.7 |
Costs and expenses: | ||
Product purchases | 1,011 | 1,258.6 |
Operating expenses | 132 | 121.1 |
Depreciation and amortization expenses | 193.5 | 118.6 |
General and administrative expenses | 43.4 | 40.2 |
Goodwill impairment | 24 | 0 |
Other operating (income) expense | 1 | 0.6 |
Income from operations | 37.5 | 140.6 |
Other income (expense): | ||
Interest expense, net | (46.9) | (50) |
Equity earnings (loss) | (4.8) | 1.9 |
Gain (loss) from financing activities | 24.7 | 0 |
Other | (0.1) | (13.6) |
Income (loss) before income taxes | 10.4 | 78.9 |
Income tax (expense) benefit | 0.2 | (1.1) |
Net income (loss) | 10.6 | 77.8 |
Less: Net income attributable to noncontrolling interests | 3 | 5 |
Net income (loss) attributable to Targa Resources Partners LP | 7.6 | 72.8 |
Net income attributable to preferred limited partners | 2.8 | 0 |
Net income attributable to general partner | 14.7 | 42.5 |
Net income (loss) attributable to common limited partners | $ (9.9) | $ 30.3 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Statement Of Income And Comprehensive Income [Abstract] | ||
Net income | $ 10.6 | $ 77.8 |
Commodity hedging contracts: | ||
Change in fair value | 6.7 | 30.3 |
Settlements reclassified to revenues | (24.2) | (13.2) |
Other comprehensive income (loss) | (17.5) | 17.1 |
Comprehensive income (loss) | (6.9) | 94.9 |
Less: Comprehensive income attributable to noncontrolling interests | 3 | 5 |
Comprehensive income attributable to Targa Resources Partners LP | $ (9.9) | $ 89.9 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY - USD ($) $ in Thousands | Total | Limited Partner Preferred [Member] | Limited Partners Common [Member] | General Partner Units [Member] | Receivables from Unit Issuances [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Treasury Units [Member] | Non-controlling Interests [Member] |
Balance at Dec. 31, 2014 | $ 2,688,400 | $ 0 | $ 2,384,100 | $ 78,600 | $ (1,000) | $ 60,300 | $ (4,800) | $ 171,200 |
Balance (in units) at Dec. 31, 2014 | 0 | 118,586,000 | 2,420,000 | 67,000 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Compensation on equity grants | 3,800 | $ 0 | $ 3,800 | $ 0 | 0 | 0 | $ 0 | 0 |
Compensation on equity grants (in units) | 0 | 0 | 0 | 0 | ||||
Issuance of common units under compensation program | 0 | $ 0 | $ 0 | $ 0 | 0 | 0 | $ 0 | 0 |
Issuance of common units under compensation program (in units) | 0 | 26,000 | 0 | 0 | ||||
Units tendered for tax withholding obligations | (600) | $ 0 | $ 0 | $ 0 | 0 | 0 | $ (600) | 0 |
Units tendered for tax withholding obligations (in units) | 0 | (13,000) | 0 | 13,000 | ||||
Acquisition of APL | 2,696,400 | $ 0 | $ 2,583,100 | $ 0 | 0 | 0 | $ 0 | 113,300 |
Acquisition of APL (in units) | 0 | 58,614,000 | 0 | |||||
Contributions from Targa Resources Corp. | 53,400 | $ 0 | $ 0 | $ 53,400 | 0 | 0 | $ 0 | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 1,222,000 | 0 | ||||
Equity offerings | 28,400 | $ 0 | $ 53,000 | $ 0 | (24,600) | 0 | $ 0 | 0 |
Equity offerings (in units) | 0 | 1,271,000 | 0 | 0 | ||||
Distributions to noncontrolling interests | (2,700) | $ 0 | $ 0 | $ 0 | 0 | 0 | $ 0 | (2,700) |
Contribution from noncontrolling interests | 3,400 | 0 | 0 | 0 | 0 | 0 | 0 | 3,400 |
Targa contribution - Special General Partner Interest | 1,612,400 | 0 | 0 | 1,612,400 | 0 | 0 | 0 | 0 |
Other comprehensive income (loss) | 17,100 | 0 | 0 | 0 | 0 | 17,100 | 0 | 0 |
Net income | 77,800 | 0 | 30,300 | 42,500 | 0 | 0 | 0 | 5,000 |
Distributions | (138,100) | 0 | (97,000) | (41,100) | 0 | 0 | 0 | 0 |
Balance at Mar. 31, 2015 | 7,039,700 | $ 0 | $ 4,957,300 | $ 1,745,800 | (25,600) | 77,400 | $ (5,400) | 290,200 |
Balance (in units) at Mar. 31, 2015 | 0 | 178,484,000 | 3,642,000 | 80,000 | ||||
Balance at Dec. 31, 2014 | 2,688,400 | $ 0 | $ 2,384,100 | $ 78,600 | (1,000) | 60,300 | $ (4,800) | 171,200 |
Balance (in units) at Dec. 31, 2014 | 0 | 118,586,000 | 2,420,000 | 67,000 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Other comprehensive income (loss) | 26,400 | |||||||
Balance at Dec. 31, 2015 | 6,902,900 | $ 120,600 | $ 4,550,400 | $ 1,735,300 | 0 | 86,800 | $ (10,300) | 420,100 |
Balance (in units) at Dec. 31, 2015 | 5,000,000 | 184,871,000 | 3,773,000 | 212,000 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Compensation on equity grants | 2,200 | $ 0 | $ 2,200 | $ 0 | 0 | 0 | $ 0 | 0 |
Compensation on equity grants (in units) | 0 | 0 | 0 | 0 | ||||
Distribution equivalent rights | (200) | $ 0 | $ (200) | $ 0 | 0 | 0 | $ 0 | 0 |
Issuance of common units under compensation program | $ 0 | $ 0 | $ 0 | 0 | 0 | $ 0 | 0 | |
Issuance of common units under compensation program (in units) | 0 | 30,000 | 0 | 0 | ||||
Units tendered for tax withholding obligations | (100) | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ (100) | 0 |
Units tendered for tax withholding obligations (in units) | 0 | (1,000) | 0 | 1,000 | ||||
Cancellation of treasury units | 0 | $ (10,200) | $ (200) | $ 10,400 | ||||
Cancellation of treasury units (in units) | 0 | 0 | (213,000) | |||||
Contributions from Targa Resources Corp. | 801,000 | $ 0 | $ 785,000 | $ 16,000 | $ 0 | $ 0 | $ 0 | 0 |
Contributions from Targa Resources Corp. (in units) | 0 | 45,103,000 | 921,000 | 0 | ||||
Distributions to noncontrolling interests | (2,100) | $ 0 | $ 0 | $ 0 | 0 | 0 | $ 0 | (2,100) |
Contribution from noncontrolling interests | 6,000 | 0 | 0 | 0 | 0 | 0 | 0 | 6,000 |
Other comprehensive income (loss) | (17,500) | 0 | 0 | 0 | 0 | (17,500) | 0 | 0 |
Net income | 10,600 | 2,800 | (9,900) | 14,700 | 0 | 0 | 0 | 3,000 |
Distributions | (203,200) | (2,800) | (152,500) | (47,900) | 0 | 0 | 0 | 0 |
Balance at Mar. 31, 2016 | $ 7,499,600 | $ 120,600 | $ 5,164,800 | $ 1,717,900 | $ 0 | $ 69,300 | $ 0 | $ 427,000 |
Balance (in units) at Mar. 31, 2016 | 5,000,000 | 230,003,000 | 4,694,000 | 0 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Cash flows from operating activities | ||
Net income (loss) | $ 10.6 | $ 77.8 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Amortization in interest expense | 3.4 | 2.9 |
Compensation on equity grants | 2.2 | 3.8 |
Depreciation and amortization expense | 193.5 | 118.6 |
Goodwill impairment | 24 | 0 |
Accretion of asset retirement obligations | 1.1 | 1.3 |
Change in redemption value of mandatorily redeemable preferred interest | (18.5) | 0 |
Deferred income tax expense (benefit) | (6.6) | 0.6 |
Equity (earnings) loss of unconsolidated affiliates | 4.8 | (1.9) |
Distributions received from unconsolidated affiliates | 0 | 2.1 |
Risk management activities | 4.4 | 6.5 |
(Gain) loss on sale or disposition of assets | 0.9 | 0.6 |
(Gain) loss from financing activities | (24.7) | (0.1) |
Changes in operating assets and liabilities, net of business acquisitions: | ||
Receivables and other assets | 99.3 | 78.1 |
Inventory | 62.1 | 102.5 |
Accounts payable and other liabilities | (114.5) | (102) |
Net cash provided by operating activities | 242 | 290.8 |
Cash flows from investing activities | ||
Outlays for property, plant and equipment | (190.1) | (187.6) |
Outlays for business acquisition, net of cash acquired | 0 | (828.7) |
Return of capital from unconsolidated affiliates | 3.4 | 0.6 |
Other, net | (1.3) | (0.6) |
Net cash used in investing activities | (188) | (1,016.3) |
Cash flows from financing activities | ||
Proceeds from borrowings under credit facility | 425 | 975 |
Repayments of credit facility | (705) | (135) |
Proceeds from accounts receivable securitization facility | 5.7 | 253.4 |
Repayments of accounts receivable securitization facility | (75) | (238.3) |
Proceeds from issuance of senior notes | 0 | 1,100 |
Open market purchases of senior notes | (330.6) | 0 |
Redemption of APL senior notes | 0 | (1,168.8) |
Costs incurred in connection with financing arrangements | (7.5) | (12.1) |
Proceeds from sale of common and preferred units | 0 | 28.8 |
Repurchase of common units under compensation plans | (0.1) | (0.6) |
Contributions received from General Partner | 16 | 53.4 |
Contributions received from TRC | 785 | 0 |
Contributions received from noncontrolling interests | 6 | 3.4 |
Distributions paid to unitholders | (203.2) | (138.1) |
Payments of distribution equivalent rights | (0.3) | 0 |
Distributions paid to noncontrolling interests | (2.1) | (2.7) |
Net cash provided by (used in) financing activities | (86.1) | 718.4 |
Net change in cash and cash equivalents | (32.1) | (7.1) |
Cash and cash equivalents, beginning of period | 135.4 | 72.3 |
Cash and cash equivalents, end of period | $ 103.3 | $ 65.2 |
Organization and Operations
Organization and Operations | 3 Months Ended |
Mar. 31, 2016 | |
Limited Liability Company Or Limited Partnership Business Organization And Operations [Abstract] | |
Organization and Operations | Note 1 — Organization and Operations Our Organization Targa Resources Partners LP is a Delaware limited partnership formed in October 2006 by our parent, Targa Resources Corp. (“Targa” or “TRC” or the “Company” or “Parent”). In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. On February 17, 2016, TRC completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transaction, the “TRC/TRP Merger”), by and among us, Targa Resources GP LLC (our “general partner”), TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”), pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub merged with and into TRP (the “TRC/TRP Merger”), with TRP continuing as the surviving entity and as a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units. At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares. Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause our common units to be delisted from the New York Stock Exchange (“NYSE”) and deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As a result of the completion of the TRC/TRP Merger, our common units are no longer publicly traded. The 5,000,000 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) 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; gathering, storing and terminaling crude oil; and storing, terminaling and selling refined petroleum products. See Note 17 – Segment Information for certain financial information for our business segments. The employees supporting our operations are employed by Targa. Our 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 | 3 Months Ended |
Mar. 31, 2016 | |
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 months ended March 31, 2016 and 2015, 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 months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the full year. The February 27, 2015 Atlas mergers involved two separate legal transactions involving different groups of equity holders. For GAAP reporting purposes, these two mergers are viewed as a single integrated transaction. As such, the financial effects of the Targa consideration related to the ATLS merger have been reflected in these financial statements. As described in Note 4 – Business Acquisitions, our Partnership Agreement was amended to provide for the issuance of the Special GP Interest in us equal to the tax basis of the APL GP Interests acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation. Revisions of Previously Reported Activity in our Statement of Changes in Comprehensive Income During the first quarter of 2016 we concluded that activity related to our commodity hedge contracts was not reported properly in our Statement of Changes in Other Comprehensive Income during 2015. The errors resulted in misstatements of the statement caption “Change in fair value” and equal offsetting misstatements of the caption “Settlements reclassified to revenues.” Related income tax effects were also misstated. We concluded that these misstatements were not material to any of the periods affected, as reported “Total Other Comprehensive Income” is unchanged. However, we have revised previous Statements of Changes in Comprehensive Income reported during 2015 to properly reflect changes in fair value and settlements reclassified to revenues. There is no impact on previously reported net income, total comprehensive income, cash flows, financial position or other profitability measures. The following table displays the impact of these revisions to activity reported in our Statement of Changes in Other Comprehensive Income during 2015. Three Months Ended March 31, 2015 March 31, 2015 June 30, 2015 June 30, 2015 September 30, 2015 September 30, 2015 As Reported As Corrected As Reported As Corrected As Reported As Corrected Commodity hedging contracts: Change in fair value $ 25.2 $ 30.3 $ (8.7 ) $ (3.6 ) $ 42.9 $ 50.7 Settlements reclassified to revenues (8.1 ) (13.2 ) (16.3 ) (21.4 ) (16.7 ) (24.5 ) Other comprehensive income (loss) $ 17.1 $ 17.1 $ (25.0 ) $ (25.0 ) $ 26.2 $ 26.2 Six Months Ended Nine Months Ended Total Year June 30, 2015 June 30, 2015 September 30, 2015 September 30, 2015 2015 2015 As Reported As Corrected As Reported As Corrected As Reported As Corrected Commodity hedging contracts: Change in fair value $ 16.5 $ 27.0 $ 59.4 $ 77.6 $ 81.2 $ 112.7 Settlements reclassified to revenues (24.4 ) (34.9 ) (41.1 ) (59.3 ) (54.8 ) (86.3 ) Other comprehensive income (loss) $ (7.9 ) $ (7.9 ) $ 18.3 $ 18.3 $ 26.4 $ 26.4 |
Significant Accounting Policies
Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2016 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies | Note 3 — Significant Accounting Policies 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 on Form 10-K. There were no significant updates or revisions to our policies during the three months ended March 31, 2016. Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Other Assets and Deferred Costs – Contracts with Customers With the issuance in August 2015 of ASU 2015-14 , Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations These amendments are effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact on our revenue recognition practices. In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. We expect to adopt the amendments in the second quarter of 2016 and are currently evaluating the impacts of the amendments to our financial statements and accounting practices for stock compensation. In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made. |
Business Acquisitions
Business Acquisitions | 3 Months Ended |
Mar. 31, 2016 | |
Business Combinations [Abstract] | |
Business Acquisitions | Note 4 –Business Acquisitions 2015 Acquisition Atlas Mergers On February 27, 2015, Targa completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”), by and among (i) Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of Targa (“GP Merger Sub”), ATLS and Atlas Energy GP, LLC, a Delaware limited liability company and the general partner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the transactions contemplated by the Agreement and Plan of Merger (the “APL Merger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, the Partnership’s general partner, Trident MLP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of the Partnership (“MLP Merger Sub”), ATLS, APL and Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL (“APL GP”). Pursuant to the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged (the “ATLS merger”) with and into ATLS, with ATLS continuing as the surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth in the APL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APL continuing as the surviving entity and as a subsidiary of the Partnership. While the Atlas mergers were two separate legal transactions, for GAAP reporting purposes, they are viewed as a single integrated transaction. As such, the financial effects of the ATLS Merger Consideration (as defined below) paid by Targa have been reflected in these financial statements. In connection with the Atlas mergers, APL changed its name to “Targa Pipeline Partners LP,” which we refer to as TPL, and ATLS changed its name to “Targa Energy LP.” In addition, prior to the completion of the Atlas mergers, ATLS, pursuant to a separation and distribution agreement entered into by and among ATLS, ATLS GP and Atlas Energy Group, LLC, a Delaware limited liability company (“AEG”), on February 27, 2015, (i) transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro rata distribution to the ATLS unitholders of AEG common units representing a 100% interest in AEG (collectively, the “Spin-Off” and, together with the Atlas mergers, the “Atlas Transactions”). On February 27, 2015, the Partnership Agreement was amended to provide for the issuance of a special general partner interest in the Partnership (the “Special GP Interest”) representing the contribution to the Partnership of the APL GP interest acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation. We acquired all of the outstanding units of APL for a total purchase price of approximately $5.3 billion (including $1.8 billion of acquired debt and all other assumed liabilities). Of the $1.8 billion of debt acquired and other liabilities assumed, approximately $1.2 billion of the acquired debt was tendered and settled upon the closing of the Atlas mergers via our January 2015 cash tender offers. These tender offers were in connection with, and conditioned upon, the consummation of the merger with APL. The merger with APL, however, was not conditioned on the consummation of the tender offers. On that same date, Targa acquired ATLS for a total purchase price of approximately $1.6 billion (including all assumed liabilities). Pursuant to the APL Merger Agreement, our general partner entered into an amendment to our Partnership Agreement, which we refer to as the IDR Giveback Amendment, in order to reduce aggregate distributions to TRC, as the holder of the Partnership’s IDRs by (a) $9,375,000 per quarter during the first four quarters following the APL merger, (b) $6,250,000 per quarter for the next four quarters, (c) $2,500,000 per quarter for the next four quarters and (d) $1,250,000 per quarter for the next four quarters, with the amount of such reductions to be distributed pro rata to the holders of our outstanding common units. TPL is a provider of natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in south Texas. The Atlas mergers added TPL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing operations. In total, TPL added 2,053 MMcf/d of processing capacity and 12,220 miles of additional pipeline. The operating results of TPL are reported in our Gathering and Processing segment. The APL merger was a unit-for-unit transaction with an exchange ratio of 0.5846 of our common units (the “APL Unit Consideration”) and $1.26 in cash for each APL common unit (the “APL Cash Consideration” and, with the APL Unit Consideration, the “APL Merger Consideration”), a $128.0 million total cash payment, of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion of retained employees’ APL phantom awards. We issued 58,614,157 of our common units and awarded 629,231 replacement phantom unit awards with a combined value of approximately $2.6 billion as consideration for the APL merger (based on the $43.82 closing market price of a common unit on the NYSE on February 27, 2015). The cash component of the APL merger also included $701.4 million for the mandatory repayment and extinguishment at closing of the APL Senior Secured Revolving Credit Facility that was to mature in May 2017 (the “APL Revolver”), $28.8 million of payments related to change of control and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March 2015, Targa contributed $52.4 million to us to maintain its 2% general partner interest. In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the effective time of the APL merger. The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS Stock Consideration”), and $9.12 in cash for each ATLS common unit (the ATLS Cash Consideration” and, with the ATLS Stock Consideration, the “ATLS Merger Consideration”), (a $514.7 million total cash payment). Targa issued 10,126,532 of its common shares and awarded 81,740 replacement restricted stock units with a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSE on February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million of payments related to change of control and cash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for reimbursement of certain transaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vesting of a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date. ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Targa’s acquisition of ATLS resulted in Targa acquiring these common units (converted to 3,363,935 of our common units) valued at approximately $147.4 million (based on the $43.82 closing market price of our common units on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, which reduced the consolidated purchase price by approximately $154.7 million. All outstanding ATLS equity awards, whether vested or unvested, were adjusted in connection with the Spin-Off on the terms and conditions set forth in an Employee Matters Agreement entered into by ATLS, ATLS GP and AEG on February 27, 2015. Following the Spin-Off-related adjustment and at the effective time of the ATLS merger, each outstanding ATLS option and ATLS phantom unit award, whether vested or unvested, held by a person who became an employee of AEG became fully vested (to the extent not vested) and was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). Each outstanding vested ATLS option held by an employee of APL who became an employee of Targa in connection with the Atlas Transactions (a “Midstream Employee”) was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the vested ATLS option, net of the applicable exercise price. Each outstanding unvested ATLS option and each outstanding ATLS phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the ATLS Cash Consideration in respect of each ATLS common unit underlying such ATLS option or phantom unit award and (2) a TRC restricted stock unit award with respect to a number of shares of TRC Common Stock equal to the product of the ATLS Stock Consideration multiplied by the number of ATLS common units underlying such ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). In connection with the APL merger, each outstanding APL phantom unit award held by an employee of AEG became fully vested and was cancelled and converted into the right to receive the APL Merger Consideration in respect of each APL common unit underlying the APL phantom unit award. Each outstanding APL phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the APL Cash Consideration in respect of each APL common unit underlying such APL phantom unit award and (2) a Partnership phantom unit award with respect to a number of our common units equal to the product of the APL Unit Consideration multiplied by the number of APL common units underlying such APL phantom unit award. The acquired business contributed revenues of $160.6 million and net income of $3.4 million to us for the period from February 27, 2015 to March 31, 2015, and is reported in our Gathering and Processing segment. As of March 31, 2015, we had incurred $18.1 million of acquisition-related costs. These expenses are included in other expense in our Consolidated Statements of Operations for the three months ended March 31, 2015. As of March 31, 2016, cumulative acquisition-related costs totaled $19.3 million. Pro Forma Impact of Atlas Mergers on Consolidated Statements of Operations The following summarized unaudited pro forma Consolidated Statement of Operations information for the three months ended March 31, 2015.assumes that our acquisition of APL and Targa’s acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed the APL merger as of January 1, 2014, or that the results that will be attained in the future. Amounts presented below are in millions: March 31, 2015 Pro Forma Revenues $ 1,994.0 Net income 75.2 The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making adjustments to: · Reflect the change in amortization expense resulting from the difference between the historical balances of APL’s intangible assets, net, and the fair value of intangible assets acquired. · Reflect the change in depreciation expense resulting from the difference between the historical balances of APL’s property, plant and equipment, net, and the fair value of property, plant and equipment acquired. · Reflect the change in interest expense resulting from our financing activities directly related to the Atlas mergers as compared with APL’s historical interest expense. · Reflect the changes in stock-based compensation expense related to the fair value of the unvested portion of replacement Partnership Long Term Incentive Plan (“LTIP”) awards which were issued in connection with the acquisition to APL phantom unitholders who continue to provide service as Targa employees following the completion of the APL merger. · Remove the results of operations attributable to the February 2015 transfer to Atlas Resource Partners, L.P. of 100% of APL’s interest in gas gathering assets located in the Appalachian Basin of Tennessee. · Excludes $18.1 million of acquisition-related costs incurred as of March 31, 2015 from pro forma net income for the three months ended March 31, 2015. · Reflect the change in APL’s revenues and product purchases to report plant sales of Y-grade at contractual net values to conform to our accounting policy. The following table summarizes the consideration transferred to acquire ATLS and APL, which are viewed together as a single integrated transaction for GAAP reporting purposes: Fair Cash paid, net of cash acquired (1) $ 745.7 Common shares of TRC 1,008.5 Replacement restricted stock units awarded (3) 5.2 Less: value of APL common units owned by ATLS (147.4 ) Total $ 1,612.0 Fair Value of Consideration Transferred by Targa for APL: Cash paid, net of cash acquired (2) $ 828.7 Common units of TRP 2,568.5 Replacement phantom units awarded (3) 15.0 Total $ 3,412.2 Total fair value of consideration transferred $ 5,024.2 (1) Targa acquired $5.5 million of cash. (2) We acquired $35.3 million of cash. (3) The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. Our fair value determination related to the Atlas mergers was as follows: Fair value determination: February Trade and other current receivables, net $ 181.1 Other current assets 24.4 Assets from risk management activities 102.1 Property, plant and equipment 4,616.9 Investments in unconsolidated affiliates 214.5 Intangible assets 1,354.9 Other long-term assets 5.5 Current liabilities (258.8 ) Long-term debt (1,573.3 ) Deferred income tax liabilities, net (13.6 ) Other long-term liabilities (119.1 ) Total identifiable net assets 4,534.6 Noncontrolling interest in subsidiaries (216.9 ) Current liabilities retained by Targa (0.5 ) Goodwill 707.0 Total fair value consideration transferred $ 5,024.2 During the three months ended June 30, 2015, we recorded measurement-period adjustments to our acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. As a result, the Consolidated Statement of Operations for the three months ended March 31, 2015 was retrospectively adjusted for the impact of measurement-period adjustments to property, plant and equipment, intangible assets, and investments in unconsolidated affiliates. These adjustments resulted in a decrease in depreciation and amortization expense of $1.0 million, and an increase in equity earnings of $0.3 million from the amounts previously reported in our Form 10-Q for the quarter ended March 31, 2015. We adopted the amendments to ASU-2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 13 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation. The excess of the purchase price over the fair value of net assets acquired was approximately $707.0 million which was recorded as goodwill. The determination of goodwill is attributable to the workforce of the acquired business and the expected synergies with us and Targa. The goodwill is expected to be amortizable for tax purposes. The fair value of assets acquired includes trade receivables of $178.1 million. The gross amount due under contracts is $178.1 million, all of which is expected to be collectible. The fair value of assets acquired includes receivables of $3.0 million reported in current receivables and $4.5 million reported in other long-term assets related to a contractual settlement with a counterparty. Mandatorily Redeemable Preferred Interests Other long-term liabilities acquired includes $109.3 million related to mandatorily redeemable preferred interests held by our partner in two joint ventures (see Note 10 – Other Long-Term Liabilities). Contingent Consideration A liability arising from the contingent consideration for APL’s previous acquisition of a gas gathering system and related assets has been recognized at fair value. APL agreed to pay up to an additional $6.0 million if certain volumes are achieved on the acquired gathering system within a specified time period. The fair value of the remaining contingent payment is recorded within other long term liabilities on our Consolidated Balance Sheets. The range of the undiscounted amount that we could pay related to the remaining contingent payment is between $0.0 and $6.0 million. We finalized our acquisition analysis and modeling of this contingent liability during the three months ended June 30, 2015, which resulted in an acquisition date fair value of $4.2 million. Any future change in the fair value of this liability will be included in earnings. Replacement Phantom Units In connection with the Atlas mergers, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained unchanged from the existing APL awards, and will vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 33% per year over the original three year term. Each replacement phantom unit will entitle the grantee to one common unit on the vesting date and is an equity-settled award. The replacement phantom units include distribution equivalent rights (“DERs”). When we declare and pay cash distributions, the holders of replacement phantom units will be entitled within 60 days to receive cash payment of DERs in an amount equal to the cash distributions the holders would have received if they were the holders of record on the record date of the number of our common units related to the replacement phantom units. The fair value of the replacement phantom units was based on the closing price of our units at the close of trading on February 27, 2015. The fair value was allocated between the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award. Goodwill We recognized goodwill at a fair value of approximately $707.0 million associated with the Atlas mergers as of the acquisition date on February 27, 2015. Goodwill has been attributed to the WestTX, SouthTX and SouthOK reporting units in our Gathering and Processing segment. As a result, any level of decrease in the forecasted cash flows from the date of acquisition would likely result in the fair value of the reporting unit to fall below the carrying value of the reporting unit, and could result in an impairment of that reporting unit’s goodwill. As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. As of December 31, 2015, we had not completed our November 30, 2015 impairment assessment. Based on the results of that preliminary evaluation, we recorded a provisional goodwill impairment of $290.0 million during the fourth quarter of 2015. The provisional goodwill impairment reduced the carrying value of goodwill to $417.0 million on our Consolidated Balance Sheets as of December 31, 2015. During the first quarter of 2016, we finalized our evaluation of goodwill for impairment and have recorded additional impairment expense of $24.0 million in our Consolidated Statement of Operations and reduced the carrying value of goodwill to $393.0 million on our Consolidated Balance Sheets. The impairment of goodwill is primarily due to the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas. Our evaluation as of November 30, 2015 utilized the income approach (a discounted cash flow analysis (“DCF”)) to estimate the fair values of our reporting units. The future cash flows for our reporting units is based on our estimates, at that time, of future revenues, income from operations and other factors, such as working capital and capital expenditures. We take into account current and expected industry and market conditions, commodity pricing and volumetric forecasts in the basins in which the reporting units operate. The discount rates used in our DCF analysis are based on a weighted average cost of capital determined from relevant market comparisons. Changes in the gross amounts of our goodwill and impairment loss are as follows: WestTX SouthTX SouthOK Total Beginning of period January 1, 2015 $ — $ — $ — $ — Acquisition February 27, 2015 364.5 160.3 182.2 707.0 Provisional Impairment (37.6 ) (70.2 ) (182.2 ) (290.0 ) Goodwill December 31, 2015 326.9 90.1 — 417.0 Additional Impairment (14.4 ) (9.6 ) — (24.0 ) Goodwill March 31, 2016 $ 312.5 $ 80.5 $ — $ 393.0 The sustained decrease and uncertain outlook in commodity prices and volumes have adversely impacted our customers and their future capital and operating plans. A continued or prolonged period of lower commodity prices could result in further deterioration of reporting unit fair values and potential further impairment charges related to goodwill and property, plant and equipment. |
Inventories
Inventories | 3 Months Ended |
Mar. 31, 2016 | |
Inventory Disclosure [Abstract] | |
Inventories | Note 5 — Inventories March 31, 2016 December 31, 2015 Commodities $ 49.2 $ 128.3 Materials and supplies 12.5 12.7 $ 61.7 $ 141.0 |
Property, Plant and Equipment a
Property, Plant and Equipment and Intangible Assets | 3 Months Ended |
Mar. 31, 2016 | |
Property Plant And Equipment And Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | Note 6 — Property, Plant and Equipment and Intangible Assets Property, Plant and Equipment March 31, 2016 December 31, 2015 Estimated Useful Lives (In Years) Gathering systems $ 6,357.9 $ 6,304.5 5 to 20 Processing and fractionation facilities 2,996.5 2,988.5 5 to 25 Terminaling and storage facilities 1,173.9 1,115.0 5 to 25 Transportation assets 454.7 454.0 10 to 25 Other property, plant and equipment 215.2 220.9 3 to 25 Land 108.8 108.8 — Construction in progress 800.8 736.5 — Property, plant and equipment 12,107.8 11,928.2 Accumulated depreciation (2,373.2 ) (2,225.6 ) Property, plant and equipment, net $ 9,734.6 $ 9,702.6 Intangible assets $ 2,036.6 $ 2,036.6 20 Accumulated amortization (271.5 ) (226.5 ) Intangible assets, net $ 1,765.1 $ 1,810.1 Intangible assets consist of customer contracts and customer relationships acquired in the Atlas mergers in 2015 and our Badlands business acquisition in 2012. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate. The fair values of intangible assets acquired in the Atlas mergers have been recorded at a fair value of $1,354.9 million and are being amortized over a 20 year life using the straight-line method. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation. March 31, 2016 December 31, 2015 Beginning of period $ 1,810.1 $ 591.9 Additions from acquisition — 1,354.9 Amortization (45.0 ) (136.7 ) Intangible assets, net $ 1,765.1 $ 1,810.1 |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 3 Months Ended |
Mar. 31, 2016 | |
Equity Method Investments And Joint Ventures [Abstract] | |
Investments in Unconsolidated Affiliates | Note 7 — Investments in Unconsolidated Affiliates Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: 75% interest in T2 LaSalle; 50% interest in T2 Eagle Ford; and 50% interest in T2 EF Co-Gen (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting. Our maximum exposure to loss as a result of our involvement with the T2 Joint Ventures includes our equity investment, any additional capital contribution commitments, and our share of any operating expenses incurred by the T2 Joint Ventures. The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 Cogen Total December 31, 2015 $ 49.5 $ 63.6 $ 123.8 $ 22.0 $ 258.9 Equity earnings (loss) (1.0 ) (1.6 ) (1.3 ) (0.9 ) (4.8 ) Cash distributions (1) (3.0 ) — — (0.4 ) (3.4 ) Cash calls for expansion projects — — 4.2 — 4.2 March 31, 2016 $ 45.5 $ 62.0 $ 126.7 $ 20.7 $ 254.9 (1) Includes $3.4 million in distributions received from GCF and T2 Joint Ventures in excess of our share of cumulative earnings for the three months ended March 31, 2016. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows. The recorded value of the T2 Joint Ventures is based on fair values at the date of acquisition which results in an excess fair value of $39.9 million over the book value of the joint venture capital accounts. This basis difference is attributable to depreciable tangible assets and is being amortized over the estimated useful lives of the underlying assets of 20 years on a straight-line basis and is included as a component of equity earnings. See Note 4 – Business Acquisitions for further information regarding the fair value determinations related to the Atlas mergers. |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 3 Months Ended |
Mar. 31, 2016 | |
Payables And Accruals [Abstract] | |
Accounts Payable and Accrued Liabilities | Note 8 — Accounts Payable and Accrued Liabilities March 31, 2016 December 31, 2015 Commodities $ 322.6 $ 385.3 Other goods and services 92.6 141.3 Interest 65.3 80.3 Compensation and benefits - 0.4 Income and other taxes 19.0 10.4 Other 15.3 18.1 $ 514.8 $ 635.8 Accounts payable and accrued liabilities includes $24.1 million and $34.0 million of liabilities to creditors to whom we have issued checks that remain outstanding as of March 31, 2016 and December 31, 2015. |
Debt
Debt | 3 Months Ended |
Mar. 31, 2016 | |
Debt Disclosure [Abstract] | |
Debt Obligations | Note 9 — Debt Obligations March 31, 2016 December 31, 2015 Current: Accounts receivable securitization facility, due December 2016 $ 150.0 $ 219.3 Long-term: Senior secured revolving credit facility, variable rate, due October 2017 (1) - 280.0 Senior unsecured notes, 5% fixed rate, due January 2018 935.1 1,100.0 Senior unsecured notes, 4 ⅛ November 2019 749.4 800.0 Senior unsecured notes, 6 ⅝ October 2020 (2) 309.9 342.1 Unamortized premium 4.3 5.0 Senior unsecured notes, 6 ⅞ February 2021 478.6 483.6 Unamortized discount (20.9 ) (22.1 ) Senior unsecured notes, 6 ⅜ August 2022 278.7 300.0 Senior unsecured notes, 5 ¼ 559.6 583.7 Senior unsecured notes, 4¼% fixed rate, due November 2023 583.9 623.5 Senior unsecured notes, 6¾% fixed rate, due March 2024 580.1 600.0 Senior unsecured APL notes, 6 ⅝ due October 2020 (2)(3) 12.9 12.9 Unamortized premium 0.2 0.2 Senior unsecured APL notes, 4¾% fixed rate, due November 2021 (3) 6.5 6.5 Senior unsecured APL notes, 5⅞% fixed rate, due August 2023 (3) 48.1 48.1 Unamortized premium 0.5 0.5 4,526.9 5,164.0 Debt issuance costs (34.0 ) (38.3 ) Total long-term debt 4,492.9 5,125.7 Total debt $ 4,642.9 $ 5,345.0 Irrevocable standby letters of credit outstanding $ 12.2 $ 12.9 (1) As of March 31, 2016, availability under our $1.6 billion senior secured revolving credit facility was $1.6 billion. (2) In May 2015, we exchanged the TRP 6⅝% Senior Notes with the same economic terms to the holders of the 2020 6⅝% Notes that validly tendered such notes for exchange to us. (3) APL debt is not guaranteed by the Partnership. The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2016: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred Senior secured revolving credit facility 2.6% - 4.8% 2.7% Accounts receivable securitization facility 1.2% 1.2% Compliance with Debt Covenants As of March 31, 2016, we were in compliance with the covenants contained in our various debt agreements. Debt Repurchases During the quarter ended March 31, 2016, we repurchased on the open market a portion of our outstanding Senior Notes as follows: Debt Issue Repurchased Book Value Payment Gain/Loss Write-off of Debt Issue Costs Net Gain (loss) 5¼% Senior Notes $ 24.1 $ (20.1 ) $ 4.0 $ (0.2 ) $ 3.8 4¼% Senior Notes 39.5 (31.8 ) 7.7 (0.3 ) 7.4 6⅞% Senior Notes 4.8 (4.3 ) 0.5 (0.1 ) 0.4 6⅝% Senior Notes 32.6 (29.5 ) 3.1 - 3.1 6⅜% Senior Notes 21.3 (18.7 ) 2.6 (0.2 ) 2.4 6¾% Senior Notes 19.9 (17.5 ) 2.4 (0.2 ) 2.2 5% Senior Notes 164.9 (164.5 ) 0.4 (1.0 ) (0.6 ) 4⅛% Senior Notes 50.6 (44.2 ) 6.4 (0.4 ) 6.0 $ 357.7 $ (330.6 ) $ 27.1 $ (2.4 ) $ 24.7 We may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Contractual Obligations The following table summarizes payment obligations for debt instruments after giving effect to 2016 debt repurchases. Payments Due By Period Less Than More Than Total 1 Year 1-3 Years 3-5 Years 5 Years Senior Unsecured Debt: Debt obligations (1) $ 4,542.8 $ - $ 935.1 $ 1,550.8 $ 2,056.9 Interest on debt obligations (2) 1,378.1 191.9 476.5 376.5 333.2 $ 5,920.9 $ 191.9 $ 1,411.6 $ 1,927.3 $ 2,390.1 (1) Represents scheduled future maturities of consolidated debt obligations for the periods indicated. (2) Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing March 31, 2016 rates for floating debt. Subsequent Events In April 2016, we repurchased on the open market a portion of our outstanding 5% Senior Notes paying $96.4 million to repurchase $96.0 million of the outstanding balance of the 5% Senior Notes. |
Other Long-term Liabilities
Other Long-term Liabilities | 3 Months Ended |
Mar. 31, 2016 | |
Other Liabilities Noncurrent [Abstract] | |
Other Long-term Liabilities | Note 10 — Other Long-term Liabilities Other long-term liabilities are comprised of the following obligations: March 31, 2016 December 31, 2015 Asset retirement obligations $ 61.9 $ 69.9 Mandatorily redeemable preferred interests 64.1 82.9 Deferred revenue and other 23.5 25.4 Total long-term liabilities $ 149.5 $ 178.2 Asset Retirement Obligations Our asset retirement obligations (“ARO”) primarily relate to certain gas gathering pipelines and processing facilities, and are included in our Consolidated Balance Sheets as a component of other long-term liabilities. The changes in our ARO are as follows: March 31, 2016 Beginning of period $ 69.9 Change in cash flow estimate (9.1 ) Accretion expense 1.1 End of period $ 61.9 Mandatorily Redeemable Preferred Interests The following table shows the changes attributable to mandatorily redeemable preferred interests: March 31, 2016 Beginning of period $ 82.9 Income (loss) attributable to mandatorily redeemable preferred interests (0.3 ) Change in estimated redemption value (18.5 ) End of period $ 64.1 |
Partnership Units and Related M
Partnership Units and Related Matters | 3 Months Ended |
Mar. 31, 2016 | |
Partners Capital [Abstract] | |
Partnership Units and Related Matters | Note 11 — Partnership Units and Related Matters TRC/TRP Merger On February 17, 2016, TRC completed the TRC/TRP Merger with TRP continuing as the surviving entity and a subsidiary of TRC. As a result of the TRC/TRP Merger, TRC owns all of our outstanding common units. At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of TRC shares. No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares. Pursuant to the TRC/TRP Merger Agreement, our common units were delisted from the NYSE and deregistered under the Exchange Act and our common units are no longer publicly traded. The 5,000,000 Preferred Units remain outstanding as limited partner interests in us and continue to trade on the NYSE. We paid $2.8 million to preferred unitholders during the three months ended March 31, 2016. We have accrued distributions to our preferred unitholders of $0.9 million for the three months ended March 31, 2016. These distributions were subsequently paid on April 20, 2016. During the quarter ended March 31, 2016, Targa made capital contributions to us of $801.0 million. We issued 45,103,140 common units and 920,472 general partner units to Targa related to these capital contributions. Targa Resource Partners Long Term Incentive Plan The TRC/TRP Merger did not trigger the acceleration of any time-based vesting of any of our outstanding long-term equity incentive compensation awards under the Targa Resource Partners Long-Term Incentive Plan. Upon completion of the TRC/TRP Merger, on February 17, 2016, Targa assumed, adopted and amended the Targa Resource Partners Long-Term Incentive Plan (“TRP LTIP”), and has changed the name of the plan to the Targa Resources Corp. Equity Compensation Plan (the “Plan”). All outstanding performance unit awards previously granted under the TRP LTIP, were converted and restated into comparable awards based on Targa’s common shares. Specifically, each outstanding performance unit award was converted and restated, effective as of the effective time of the TRC/TRP Merger, into an award to acquire, pursuant to the same time-based vesting schedule and forfeiture and termination provisions, a comparable number of Targa common shares determined by multiplying the number of performance units subject to each award by the exchange ratio in the TRC/TRP Merger (0.62), rounded down to the nearest whole share. The performance factor has been eliminated as it was based on the performance of our common units versus peer MLPs. All amounts previously credited as distribution equivalent rights under any outstanding performance unit award continue to remain so credited and will be payable on the payment date set forth in the applicable award agreement, subject to the same time-based vesting schedule previously included in the performance unit award, but without application of any performance factor. Cash-Settled Performance Units Targa Resources Long-Term Incentive Plan Equity-Settled Performance Units Replacement Phantom Units 2015 2014 2013 Before Conversion 675,745 349,451 192,390 119,900 139,700 After Conversion 418,903 216,561 119,178 74,248 86,538 The conversion on February 17, 2016 of outstanding equity-settled performance units and replacement phantom units outstanding to equity-settled restricted stock units and replacement phantom shares was considered modification of awards under ASC 718, Accounting for Stock-Based Compensation The conversion on February 17, 2016 of outstanding cash-settled performance units outstanding to cash-settled restricted stock units was considered modification of awards under ASC 718. The incremental change in fair value between the original grant date fair value and the fair value as of February 17, 2016 resulted in recognition of additional compensation costs during the current quarter of $4.8 million. The remaining compensation cost will be recognized in general and administrative expense over the remaining service period of each award. Distributions We must distribute all of our available cash, after distributions to the Preferred Units, as defined in the Partnership Agreement, and as determined by the general partner, to common unitholders of record within 45 days after the end of each quarter. As a result of the TRC/TRP Merger, which was completed on February 17, 2016, Targa owns all of our outstanding common units. As a result, all of our distributions, after the distributions on the Preferred Units, all future distributions will be paid to TRC. The following table details the distributions to common unitholders declared and/or paid by for the three months ended March 31, 2016 Distributions Limited Partners General Partner Three Months Ended Date Paid or to be Paid Common Incentive 2% Total Distributions per Limited Partner Unit (In millions, except per unit amounts) December 31, 2015 February 9, 2016 $ 152.5 $ 43.9 $ 4.0 $ 200.4 $ 0.8250 Total distributions declared as of March 31, 2016 to be paid to Targa on May 12, 2016 are $154.8 million. As a result of the TRC/TRPMerger. Targa is entitled to receive all available Partnership cash for the quarter ended March 31, 2016 and all future quarters. Subsequent Event On April 19, 2016, our board of directors declared a monthly cash distribution of $0.1875 per preferred Series A Unit for April 2016. This distribution will be paid on May 16, 2016. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 3 Months Ended |
Mar. 31, 2016 | |
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 hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in our Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Gathering and Processing segment, that result from percent-of-proceeds processing arrangements. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flow hedges for accounting purposes. The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixture of specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations. We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes. As part of the Atlas mergers, outstanding APL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to us and included in the acquisition date fair value of assets acquired. Derivative settlements of $67.9 million related to these novated contracts were received during the year ended December 31, 2015 and $8.7 million related to these novated contracts were received during the quarter ended March 31, 2016 and The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Additionally, for the quarters ended March 31, 2016 and 2015, we recorded less than $0.1 million and $1.0 million of ineffectiveness gains related to otherwise qualifying APL derivatives, primarily natural gas swaps. At March 31, 2016, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2016 2017 2018 Natural Gas Swaps MMBtu/d 91,840 53,982 30,900 Natural Gas Basis Swaps MMBtu/d 43,309 18,082 - Natural Gas Options MMBtu/d 22,900 22,900 9,486 NGL Swaps Bbl/d 4,812 1,688 818 NGL Futures Bbl/d 4,331 274 - NGL Options Bbl/d 920 920 32 Condensate Swaps Bbl/d 2,375 1,400 900 Condensate Options Bbl/d 790 790 101 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. Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of March 31, 2016 Fair Value as of December 31, 2015 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 82.4 $ 1.7 $ 92.1 $ 2.1 Long-term 25.2 7.9 34.9 2.4 Total derivatives designated as hedging instruments $ 107.6 $ 9.6 $ 127.0 $ 4.5 Derivatives not designated as hedging instruments Commodity contracts Current $ — $ 0.3 $ 0.1 $ 3.1 Total derivatives not designated as hedging instruments $ — $ 0.3 $ 0.1 $ 3.1 Total current position $ 82.4 $ 2.0 $ 92.2 $ 5.2 Total long-term position 25.2 7.9 34.9 2.4 Total derivatives $ 107.6 $ 9.9 $ 127.1 $ 7.6 The pro forma impact of reporting derivatives in the Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro forma net presentation March 31, 2016 Asset Liability Asset Liability Current Position Counterparties with offsetting positions $ 79.4 $ 2.0 $ 77.4 $ - Counterparties without offsetting positions - assets 3.0 - 3.0 - Counterparties without offsetting positions - liabilities - - - - 82.4 2.0 80.4 - Long Term Position Counterparties with offsetting positions 25.2 7.7 17.5 - Counterparties without offsetting positions - assets - - - - Counterparties without offsetting positions - liabilities - 0.2 - 0.2 25.2 7.9 17.5 0.2 Total Derivatives Counterparties with offsetting positions 104.6 9.7 94.9 - Counterparties without offsetting positions - assets 3.0 - 3.0 - Counterparties without offsetting positions - liabilities - 0.2 - 0.2 $ 107.6 $ 9.9 $ 97.9 $ 0.2 Gross Presentation Pro forma net presentation December 31, 2015 Asset Liability Asset Liability Current Position Counterparties with offsetting positions $ 86.9 $ 5.2 $ 81.7 $ - Counterparties without offsetting positions - assets 5.3 - 5.3 - Counterparties without offsetting positions - liabilities - - - - 92.2 5.2 87.0 - Long Term Position Counterparties with offsetting positions 34.2 2.4 31.8 - Counterparties without offsetting positions - assets 0.7 - 0.7 - Counterparties without offsetting positions - liabilities - - - - 34.9 2.4 32.5 - Total Derivatives Counterparties with offsetting positions 121.1 7.6 113.5 - Counterparties without offsetting positions - assets 6.0 - 6.0 - Counterparties without offsetting positions - liabilities - - - - $ 127.1 $ 7.6 $ 119.5 $ - Our payment obligations in connection with substantially all of these hedging transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness 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 counterparty that clears the hedges through an exchange. The payment obligations on these futures are settled daily. The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net asset of $97.7 million as of March 31, 2016. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are settled daily and do not require any credit adjustment. The following tables reflect amounts recorded in Other Comprehensive Income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated: Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Derivatives in Cash Flow Three Months Ended March 31, Hedging Relationships 2016 2015 Commodity contracts $ 6.7 $ 30.3 Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) Three Months Ended March 31, 2016 2015 Revenues $ (24.2 ) $ (13.2 ) $ (24.2 ) $ (13.2 ) 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 Recognized in Income on Three Months Ended March 31, Derivatives Not Designated as Hedging Instruments Derivatives 2016 2015 Commodity contracts Revenue $ 1.8 $ 7.2 The following table shows the deferred gains (losses) included in accumulated OCI, which will be reclassified into earnings through the end of 2018 based on valuations as of the balance sheet date: March 31, 2016 December 31, 2015 Commodity hedges, before tax (1) $ 69.3 $ 86.8 (1) Includes deferred net gains of $58.9 million as of March 31, 2016 related to contracts that will be settled and reclassified to revenue over the next 12 months. See Note 13 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities. |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 31, 2016 | |
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 in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments. Fair Value of Derivative Financial Instruments Our derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believe we have obtained the most accurate information available for the types of derivative contracts we hold. The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. This financial position of these derivatives at March 31, 2016, a net asset position of $97.7 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net asset of $68.1 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $126.0 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 senior secured revolving credit facility (the “TRP Revolver”) and the Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and · Senior unsecured notes are based on quoted market prices derived from trades of the debt. We have a contingent consideration liability for APL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value (see Note 4 – Business Acquisitions). Fair Value Hierarchy We categorize the inputs to the fair value measurements of financial assets and liabilities using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value: · Level 1 – observable inputs such as quoted prices in active markets; · Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and · Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions. The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: March 31, 2016 Fair Value Carrying Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 104.4 $ 104.4 $ — $ 101.0 $ 3.4 Liabilities from commodity derivative contracts (1) 6.7 6.7 — 5.9 0.8 TPL contingent consideration (2) 3.0 3.0 — — 3.0 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 103.3 103.3 — — — Senior unsecured notes 4,526.9 4,357.1 — 4,357.1 — Accounts receivable securitization facility 150.0 150.0 — 150.0 — December 31, 2015 Fair Value Carrying Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 127.1 $ 127.1 $ — $ 123.1 $ 4.0 Liabilities from commodity derivative contracts (1) 7.6 7.6 — 7.3 0.3 TPL contingent consideration (2) 3.0 3.0 — — 3.0 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 135.4 135.4 — — — Senior secured revolving credit facility 280.0 280.0 — 280.0 — Senior unsecured notes 4,884.0 4,192.0 — 4,192.0 — Accounts receivable securitization facility 219.3 219.3 — 219.3 — (1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 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) See Note 4 – Business Acquisitions. Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable 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 March 31, 2016, we had 15 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 the forward natural gas curves, for which a significant portion of the derivative’s term is beyond available forward pricing. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial. The fair value of the contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. These probability-based inputs are not observable; the entire valuation of the contingent consideration is categorized in Level 3. Changes in the fair value of this liability are included in Other Income on the Consolidated Statements of Operations. The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts Contingent (Asset)/Liability Liability Balance, December 31, 2015 $ 3.7 $ 3.0 New Level 3 instruments (0.2 ) - Settlements included in Revenue (0.5 ) - Unrealized gain/(loss) included in OCI (0.4 ) - Balance, March 31, 2016 $ 2.6 $ 3.0 For the three months ended March 31, 2016, we had no transfers of derivative liabilities out of Level 3 and into Level 2. Transfers relate to long-term over-the-counter swaps for natural gas and NGL products with deliveries for which observable market prices were available. |
Related Party Transactions - Ta
Related Party Transactions - Targa | 3 Months Ended |
Mar. 31, 2016 | |
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 March 31, 2016 2015 Targa billings of payroll and related costs included in operating expense $ 40.2 $ 34.9 Targa allocation of general and administrative expense 39.9 38.3 Cash distributions to Targa based on IDR and unit ownership 61.4 51.6 Cash contributions from Targa for issuance of common units 785.0 — Cash contributions from Targa to maintain its 2% general partner ownership 16.0 28.8 |
Contingencies
Contingencies | 3 Months Ended |
Mar. 31, 2016 | |
Loss Contingency [Abstract] | |
Contingencies | Note 15 - Contingencies Legal Proceedings Litigation related to TRC/TRP Merger On December 16, 2015, two purported unitholders of TRP (the “State Court Plaintiffs”) filed a putative class action and derivative lawsuit challenging the TRC/TRP Merger against TRC, TRP (as a nominal defendant), TRP GP, the members of the board of the general partner (the “TRP GP Board”) and Merger Sub (collectively, the “State Court Defendants”). This lawsuit is styled Leslie Blumberg et al. v. TRC Resources Corp., et al. The State Court Plaintiffs allege several causes of action challenging the TRC/TRP Merger. Generally, the State Court Plaintiffs allege that (i) the members of the TRP GP Board breached express and/or implied duties under the TRP partnership agreement and (ii) TRC, TRP’s general partner, and Merger Sub aided and abetted in these alleged breaches of duties. The State Court Plaintiffs further allege, in general, that (a) the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair and (e) the TRP GP Board has conflicts of interest due to TRC’s control of TRP’s general partner. Based on these allegations, the State Court Plaintiffs sought to enjoin the State Court Defendants from proceeding with or consummating the TRC/TRP Merger unless and until the TRP GP Board adopted and implemented processes to obtain the best possible terms for TRP common unitholders. The State Court Plaintiffs now seek to have the TRC/TRP Merger rescinded and seek attorneys’ fees. On February 26 and 29, 2016, the State Court Defendants filed general denials and asserted affirmative defenses. The State Court Defendants cannot predict the outcome of this or any other lawsuits that might be filed subsequent to the date of the filing of this report, nor can the State Court Defendants predict the amount of time and expense that will be required to resolve such litigation. The State Court Defendants believe the State Court Lawsuit is without merit and intend to defend vigorously against this lawsuit and any other actions challenging the TRC/TRP Merger. On January 6 and 19, 2016, two additional purported unitholders of TRP (the “Federal Court Plaintiffs”) filed two putative class action lawsuits challenging the disclosures made in connection with the TRC/TRP Merger against TRP and the members of the TRP GP Board (the “Federal Court Defendants”). These lawsuits have been consolidated as In re Targa Resources Partners, L.P. Securities Litigation The Federal Court Plaintiffs alleged that (i) the Federal Court Defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and (ii) the members of the TRP GP Board have violated Section 20(a) of the Exchange Act. The Federal Court Plaintiffs alleged, in general, that the preliminary and definitive joint proxy statements/prospectuses filed in connection with the TRC/TRP Merger failed, among other things, to disclose allegedly material information concerning (i) the TRP GP Conflicts Committee’s financial advisor’s and TRC’s financial advisor’s analyses in connection with the TRC/TRP Merger, (ii) certain TRC and TRP projections, and (iii) the events leading up to the TRC/TRP Merger. The Federal Court Plaintiffs further alleged, in general, that (a) the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair and (e) the TRP GP Board has conflicts of interest due to TRC’s control of the general partner. Based on these allegations, the Federal Court Plaintiffs sought to enjoin the Federal Court Defendants from proceeding with or consummating the TRC/TRP Merger unless and until the Federal Court Defendants disclosed the allegedly omitted information summarized above. The Federal Court Plaintiffs also sought damages, attorneys’ fees, and to have the TRC/TRP Merger rescinded. One of the Federal Court Plaintiffs sought a Temporary Restraining Order (“TRO”) to prevent the Federal Court Defendants from proceeding with the TRC/TRP vote and/or merger. On January 29, 2016, this Plaintiff was denied his request for a TRO. On April 20, 2016, the court dismissed the Federal Court Lawsuits without prejudice. Atlas Unitholder Litigation Between October and December 2014, five public unitholders of APL (the “APL Plaintiffs”) filed putative class action lawsuits against APL, ATLS, APL GP, its managers, Targa, the Partnership, the general partner and MLP Merger Sub (the “APL Lawsuit Defendants”). These lawsuits were styled (a) Michael Evnin v. Atlas Pipeline Partners, L.P., et al William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al Mike Welborn v. Atlas Pipeline Partners, L.P., et al., Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., Evnin, Greenthal, Welborn and Feldbaum In re Atlas Pipeline Partners, L.P. Unitholder Litigation Rick Kane v. Atlas Energy, L.P., et al. Jeffrey Ayers v. Atlas Energy, L.P., et al. In re Atlas Energy, L.P. Unitholder Litigation Kane The Atlas Lawsuit Plaintiffs alleged a variety of causes of action challenging the Atlas mergers. Generally, the APL Plaintiffs alleged that (a) APL GP’s managers have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, the Partnership, the general partner, MLP Merger Sub, APL, ATLS and APL GP have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The APL Plaintiffs further alleged that (a) the premium offered to APL’s unitholders was inadequate, (b) APL agreed to contractual terms that would allegedly dissuade other potential acquirers from seeking to acquire APL, and (c) APL GP’s managers favored their self-interests over the interests of APL’s unitholders. The APL Plaintiffs in the Consolidated APL Lawsuit also alleged that the registration statement filed on November 19, 2014 failed, among other things, to disclose allegedly material details concerning (i) Stifel, Nicolaus & Company, Incorporated’s analysis of the Atlas mergers; (ii) APL and the Partnership’s financial projections; and (iii) the background of the Atlas mergers. Generally, the ATLS Plaintiffs alleged that (a) ATLS GP’s directors have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, GP Merger Sub, and ATLS have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The ATLS Plaintiffs further alleged that (a) the premium offered to the ATLS unitholders was inadequate, (b) ATLS agreed to contractual terms that would allegedly dissuade other potential acquirers from seeking to acquire ATLS, (c) ATLS GP’s directors favored their self-interests over the interests of the ATLS unitholders and (d) the registration statement failed to disclose allegedly material details concerning, among other things, (i) Wells Fargo Securities, LLC, Stifel, Nicolaus & Company, Incorporated, and Deutsche Bank Securities Inc.’s analyses of the Atlas mergers; (ii) the Partnership, Targa, APL, and ATLS’ financial projections; and (iii) the background of the Atlas mergers. Based on these allegations, the Atlas Lawsuit Plaintiffs sought to enjoin the Atlas Lawsuit Defendants from proceeding with or consummating the Atlas mergers unless and until APL and ATLS adopted and implemented processes to obtain the best possible terms for their respective unitholders. The Atlas Lawsuit Plaintiffs also sought rescission, damages, and attorneys’ fees. The parties to the Consolidated Atlas Lawsuits agreed to settle the Consolidated Atlas Lawsuits on February 9, 2015. In general, the settlements provide that in consideration for the dismissal of the Consolidated Atlas Lawsuits, ATLS and APL would provide supplemental disclosures regarding the Atlas mergers in a filing with the SEC on Form 8-K, which ATLS and APL did on February 11, 2015. The Atlas Lawsuit Defendants agreed to make such supplemental disclosures solely to avoid the uncertainty, risk, burden, and expense inherent in litigation and deny that any supplemental disclosure was or is required under any applicable rule, statute, regulation or law. On January 21, 2016, the Court granted final approval of the settlements in the Consolidated Atlas Lawsuits and dismissed the Consolidated Atlas Lawsuits with prejudice. Environmental Proceedings On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014. The Monument Gas Plant is operated by the Partnership and owned by Versado Gas Processors, L.L.C., which is a joint venture in which we own a 63% interest. The Partnership is in discussions with the New Mexico Environment Department to resolve the alleged violations. The Partnership anticipates that this matter could result in a monetary sanction in excess of $100,000 but less than $300,000. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 3 Months Ended |
Mar. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Note 16 — Supplemental Cash Flow Information Three Months Ended March 31, 2016 2015 Cash: Interest paid, net of capitalized interest (1) $ 77.3 $ 28.9 Income taxes paid, net of refunds 1.1 0.1 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment 16.9 — Impact of capital expenditure accruals on property, plant and equipment 13.7 30.9 Transfers from materials and supplies inventory to property, plant and equipment 0.5 0.6 Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate (9.1 ) 3.7 Non-cash financing activities: Cancellation of Treasury stock (10.2 ) Accrued distributions on unvested equity awards under share compensation arrangements 0.2 — Receivables from equity issuances — 24.6 Non-cash balance sheet movements related to Atlas Merger: (See Note 4 - Business Acquisitions) Non-cash merger consideration - common units and replacement equity awards — 2,583.5 Special GP Interest — 1,612.4 Current liabilities retained by Targa — (0.4 ) Net non-cash balance sheet movements excluded from consolidated statements of cash flows — 4,195.5 Net cash merger consideration included in investing activities — 828.7 Total fair value of consideration transferred $ — $ 5,024.2 (1) Interest capitalized on major projects was $4.8 million and $2.4 million for the three months ended March 31, 2016 and March 31, 2015. |
Segment Information
Segment Information | 3 Months Ended |
Mar. 31, 2016 | |
Segment Reporting [Abstract] | |
Segment Information | Note 17 — Segment Information We operate in two primary segments (previously referred to as divisions): (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business). Concurrent with the completion of the TRC/TRP Merger, management reevaluated our reportable segments and determined that our previously disclosed divisions are the appropriate level of disclosure for our reportable segments. The increase in activity within Field Gathering and Processing due to the Atlas mergers coupled with the decline in activity in our Gulf Coast region makes the disaggregation of Field Gathering and Processing and Coastal Gathering and Processing no longer warranted. Management also determined that further disaggregation of our Logistics and Marketing segment is no longer appropriate due to the integrated nature of the operations within our Downstream Business Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico. Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our other businesses including services to LPG exporters. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs. Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segments and are predominantly located in Mont Belvieu and Galena Park, Texas, Lake Charles, Louisiana and Tacoma, Washington. Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin. and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in the corporate and eliminations column. Reportable segment information is shown in the following tables: Three Months Ended March 31, 2016 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 110.3 $ 1,033.9 $ 26.8 $ — $ 1,171.0 Fees from midstream services 115.8 155.6 — — 271.4 226.1 1,189.5 26.8 — 1,442.4 Intersegment revenues Sales of commodities 412.6 47.3 — (459.9 ) — Fees from midstream services 2.1 4.1 — (6.2 ) — 414.7 51.4 — $ (466.1 ) $ — Revenues $ 640.8 $ 1,240.9 $ 26.8 $ (466.1 ) $ 1,442.4 Operating margin $ 115.6 $ 157.0 $ 26.8 $ — $ 299.4 Other financial information: Total assets (1) $ 10,219.0 $ 2,501.0 $ 105.7 $ 42.9 $ 12,868.6 Goodwill (2) $ 393.0 $ — $ — $ — $ 393.0 Capital expenditures $ 103.0 $ 73.1 $ — $ 0.8 $ 176.9 (1) Corporate assets at the Segment level primarily include tax-related assets, cash and prepaids. (2) Total assets include goodwill. Goodwill has been attributed to our Gathering and Processing segment. Three Months Ended March 31, 2015 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 220.9 $ 1,159.7 $ 21.7 $ (0.1 ) $ 1,402.2 Fees from midstream services 72.0 205.4 — 0.1 277.5 292.9 1,365.1 21.7 $ — $ 1,679.7 Intersegment revenues Sales of commodities 278.1 55.9 — (334.0 ) — Fees from midstream services 2.0 4.5 — (6.5 ) — 280.1 60.4 — $ (340.5 ) $ — Revenues $ 573.0 $ 1,425.5 $ 21.7 $ (340.5 ) $ 1,679.7 Operating margin $ 87.0 $ 191.3 $ 21.7 $ — $ 300.0 Other financial information: Total assets (1) $ 10,671.8 $ 2,302.5 $ 177.3 $ 39.2 $ 13,190.8 Goodwill (2) $ 557.9 $ — $ — $ — $ 557.9 Capital expenditures $ 95.5 $ 60.7 $ — $ 1.1 $ 157.3 Business acquisition $ 5,024.2 $ — $ — $ — $ 5,024.2 (1) Corporate assets at the Segment level primarily include tax-related assets, cash and prepaids. (2) Total assets include goodwill. Goodwill has been attributed to our Gathering and Processing segment. The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended March 31, 2016 2015 Sales of commodities: Natural gas $ 326.9 $ 302.1 NGL 785.5 1,030.7 Condensate 22.2 21.3 Petroleum products 9.6 26.4 Derivative activities 26.8 21.7 1,171.0 1,402.2 Fees from midstream services: Fractionating and treating 30.2 49.8 Storage, terminaling, transportation and export 118.4 136.2 Gathering and processing 105.0 68.4 Other 17.8 23.1 271.4 277.5 Total revenues $ 1,442.4 $ 1,679.7 The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: Three Months Ended March 31, 2016 2015 Reconciliation of operating margin to net income: Operating margin $ 299.4 $ 300.0 Depreciation and amortization expense (193.5 ) (118.6 ) General and administrative expense (43.4 ) (40.2 ) Goodwill impairment (24.0 ) - Interest expense, net (46.9 ) (50.0 ) Other, net 18.8 (12.3 ) Income tax expense 0.2 (1.1 ) Net income $ 10.6 $ 77.8 |
Significant Accounting Polici25
Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2016 | |
Accounting Policies [Abstract] | |
Accounting Policy Updates | 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 on Form 10-K. There were no significant updates or revisions to our policies during the three months ended March 31, 2016. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue Recognition Other Assets and Deferred Costs – Contracts with Customers With the issuance in August 2015 of ASU 2015-14 , Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) We expect to adopt the amendments in the first quarter of 2019 and are currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations These amendments are effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact on our revenue recognition practices. In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. We expect to adopt the amendments in the second quarter of 2016 and are currently evaluating the impacts of the amendments to our financial statements and accounting practices for stock compensation. In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing. These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have to decide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to account for the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services. In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made. |
Impact of Revisions to Activity
Impact of Revisions to Activity Reported in Statement of Changes in Other Comprehensive Income (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Impact of Revisions to Activity Reported in Statement of Changes in Other Comprehensive Income | The following table displays the impact of these revisions to activity reported in our Statement of Changes in Other Comprehensive Income during 2015. Three Months Ended March 31, 2015 March 31, 2015 June 30, 2015 June 30, 2015 September 30, 2015 September 30, 2015 As Reported As Corrected As Reported As Corrected As Reported As Corrected Commodity hedging contracts: Change in fair value $ 25.2 $ 30.3 $ (8.7 ) $ (3.6 ) $ 42.9 $ 50.7 Settlements reclassified to revenues (8.1 ) (13.2 ) (16.3 ) (21.4 ) (16.7 ) (24.5 ) Other comprehensive income (loss) $ 17.1 $ 17.1 $ (25.0 ) $ (25.0 ) $ 26.2 $ 26.2 Six Months Ended Nine Months Ended Total Year June 30, 2015 June 30, 2015 September 30, 2015 September 30, 2015 2015 2015 As Reported As Corrected As Reported As Corrected As Reported As Corrected Commodity hedging contracts: Change in fair value $ 16.5 $ 27.0 $ 59.4 $ 77.6 $ 81.2 $ 112.7 Settlements reclassified to revenues (24.4 ) (34.9 ) (41.1 ) (59.3 ) (54.8 ) (86.3 ) Other comprehensive income (loss) $ (7.9 ) $ (7.9 ) $ 18.3 $ 18.3 $ 26.4 $ 26.4 |
Business Acquisitions (Tables)
Business Acquisitions (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Business Combinations [Abstract] | |
Pro Forma Consolidated Results of Operations | Pro Forma Impact of Atlas Mergers on Consolidated Statements of Operations The following summarized unaudited pro forma Consolidated Statement of Operations information for the three months ended March 31, 2015.assumes that our acquisition of APL and Targa’s acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited pro forma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that would have occurred if we had completed the APL merger as of January 1, 2014, or that the results that will be attained in the future. Amounts presented below are in millions: March 31, 2015 Pro Forma Revenues $ 1,994.0 Net income 75.2 |
Consideration Transferred to Acquire ATLS and APL | The following table summarizes the consideration transferred to acquire ATLS and APL, which are viewed together as a single integrated transaction for GAAP reporting purposes: Fair Cash paid, net of cash acquired (1) $ 745.7 Common shares of TRC 1,008.5 Replacement restricted stock units awarded (3) 5.2 Less: value of APL common units owned by ATLS (147.4 ) Total $ 1,612.0 Fair Value of Consideration Transferred by Targa for APL: Cash paid, net of cash acquired (2) $ 828.7 Common units of TRP 2,568.5 Replacement phantom units awarded (3) 15.0 Total $ 3,412.2 Total fair value of consideration transferred $ 5,024.2 (1) Targa acquired $5.5 million of cash. (2) We acquired $35.3 million of cash. (3) The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. |
Fair Value Determination Related to the Atlas Mergers | Our fair value determination related to the Atlas mergers was as follows: Fair value determination: February Trade and other current receivables, net $ 181.1 Other current assets 24.4 Assets from risk management activities 102.1 Property, plant and equipment 4,616.9 Investments in unconsolidated affiliates 214.5 Intangible assets 1,354.9 Other long-term assets 5.5 Current liabilities (258.8 ) Long-term debt (1,573.3 ) Deferred income tax liabilities, net (13.6 ) Other long-term liabilities (119.1 ) Total identifiable net assets 4,534.6 Noncontrolling interest in subsidiaries (216.9 ) Current liabilities retained by Targa (0.5 ) Goodwill 707.0 Total fair value consideration transferred $ 5,024.2 |
Changes in Gross Amounts of Goodwill and Impairment Loss | Changes in the gross amounts of our goodwill and impairment loss are as follows: WestTX SouthTX SouthOK Total Beginning of period January 1, 2015 $ — $ — $ — $ — Acquisition February 27, 2015 364.5 160.3 182.2 707.0 Provisional Impairment (37.6 ) (70.2 ) (182.2 ) (290.0 ) Goodwill December 31, 2015 326.9 90.1 — 417.0 Additional Impairment (14.4 ) (9.6 ) — (24.0 ) Goodwill March 31, 2016 $ 312.5 $ 80.5 $ — $ 393.0 |
Inventories (Tables)
Inventories (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Inventory Disclosure [Abstract] | |
Components of Inventories | March 31, 2016 December 31, 2015 Commodities $ 49.2 $ 128.3 Materials and supplies 12.5 12.7 $ 61.7 $ 141.0 |
Property, Plant and Equipment29
Property, Plant and Equipment and Intangible Assets (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Property Plant And Equipment And Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | Property, Plant and Equipment March 31, 2016 December 31, 2015 Estimated Useful Lives (In Years) Gathering systems $ 6,357.9 $ 6,304.5 5 to 20 Processing and fractionation facilities 2,996.5 2,988.5 5 to 25 Terminaling and storage facilities 1,173.9 1,115.0 5 to 25 Transportation assets 454.7 454.0 10 to 25 Other property, plant and equipment 215.2 220.9 3 to 25 Land 108.8 108.8 — Construction in progress 800.8 736.5 — Property, plant and equipment 12,107.8 11,928.2 Accumulated depreciation (2,373.2 ) (2,225.6 ) Property, plant and equipment, net $ 9,734.6 $ 9,702.6 Intangible assets $ 2,036.6 $ 2,036.6 20 Accumulated amortization (271.5 ) (226.5 ) Intangible assets, net $ 1,765.1 $ 1,810.1 |
Schedule of Intangible Assets | The fair values of intangible assets acquired in the Atlas mergers have been recorded at a fair value of $1,354.9 million and are being amortized over a 20 year life using the straight-line method. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation. March 31, 2016 December 31, 2015 Beginning of period $ 1,810.1 $ 591.9 Additions from acquisition — 1,354.9 Amortization (45.0 ) (136.7 ) Intangible assets, net $ 1,765.1 $ 1,810.1 |
Investment in Unconsolidated Af
Investment in Unconsolidated Affiliate (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Equity Method Investments And Joint Ventures [Abstract] | |
Activity Related to Partnership's Investment in Unconsolidated Affiliate | The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 Cogen Total December 31, 2015 $ 49.5 $ 63.6 $ 123.8 $ 22.0 $ 258.9 Equity earnings (loss) (1.0 ) (1.6 ) (1.3 ) (0.9 ) (4.8 ) Cash distributions (1) (3.0 ) — — (0.4 ) (3.4 ) Cash calls for expansion projects — — 4.2 — 4.2 March 31, 2016 $ 45.5 $ 62.0 $ 126.7 $ 20.7 $ 254.9 (1) Includes $3.4 million in distributions received from GCF and T2 Joint Ventures in excess of our share of cumulative earnings for the three months ended March 31, 2016. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows. |
Accounts Payable and Accrued 31
Accounts Payable and Accrued Liabilities (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Payables And Accruals [Abstract] | |
Schedule of Accounts Payable and Accrued Liabilities | March 31, 2016 December 31, 2015 Commodities $ 322.6 $ 385.3 Other goods and services 92.6 141.3 Interest 65.3 80.3 Compensation and benefits - 0.4 Income and other taxes 19.0 10.4 Other 15.3 18.1 $ 514.8 $ 635.8 |
Debt Obligations (Tables)
Debt Obligations (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of Outstanding Debt | March 31, 2016 December 31, 2015 Current: Accounts receivable securitization facility, due December 2016 $ 150.0 $ 219.3 Long-term: Senior secured revolving credit facility, variable rate, due October 2017 (1) - 280.0 Senior unsecured notes, 5% fixed rate, due January 2018 935.1 1,100.0 Senior unsecured notes, 4 ⅛ November 2019 749.4 800.0 Senior unsecured notes, 6 ⅝ October 2020 (2) 309.9 342.1 Unamortized premium 4.3 5.0 Senior unsecured notes, 6 ⅞ February 2021 478.6 483.6 Unamortized discount (20.9 ) (22.1 ) Senior unsecured notes, 6 ⅜ August 2022 278.7 300.0 Senior unsecured notes, 5 ¼ 559.6 583.7 Senior unsecured notes, 4¼% fixed rate, due November 2023 583.9 623.5 Senior unsecured notes, 6¾% fixed rate, due March 2024 580.1 600.0 Senior unsecured APL notes, 6 ⅝ due October 2020 (2)(3) 12.9 12.9 Unamortized premium 0.2 0.2 Senior unsecured APL notes, 4¾% fixed rate, due November 2021 (3) 6.5 6.5 Senior unsecured APL notes, 5⅞% fixed rate, due August 2023 (3) 48.1 48.1 Unamortized premium 0.5 0.5 4,526.9 5,164.0 Debt issuance costs (34.0 ) (38.3 ) Total long-term debt 4,492.9 5,125.7 Total debt $ 4,642.9 $ 5,345.0 Irrevocable standby letters of credit outstanding $ 12.2 $ 12.9 (1) As of March 31, 2016, availability under our $1.6 billion senior secured revolving credit facility was $1.6 billion. (2) In May 2015, we exchanged the TRP 6⅝% Senior Notes with the same economic terms to the holders of the 2020 6⅝% Notes that validly tendered such notes for exchange to us. (3) APL debt is not guaranteed by the Partnership. |
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 three months ended March 31, 2016: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred Senior secured revolving credit facility 2.6% - 4.8% 2.7% Accounts receivable securitization facility 1.2% 1.2% |
Summary of Debt Repurchased on Open Market Portion of Outstanding Senior Notes | During the quarter ended March 31, 2016, we repurchased on the open market a portion of our outstanding Senior Notes as follows: Debt Issue Repurchased Book Value Payment Gain/Loss Write-off of Debt Issue Costs Net Gain (loss) 5¼% Senior Notes $ 24.1 $ (20.1 ) $ 4.0 $ (0.2 ) $ 3.8 4¼% Senior Notes 39.5 (31.8 ) 7.7 (0.3 ) 7.4 6⅞% Senior Notes 4.8 (4.3 ) 0.5 (0.1 ) 0.4 6⅝% Senior Notes 32.6 (29.5 ) 3.1 - 3.1 6⅜% Senior Notes 21.3 (18.7 ) 2.6 (0.2 ) 2.4 6¾% Senior Notes 19.9 (17.5 ) 2.4 (0.2 ) 2.2 5% Senior Notes 164.9 (164.5 ) 0.4 (1.0 ) (0.6 ) 4⅛% Senior Notes 50.6 (44.2 ) 6.4 (0.4 ) 6.0 $ 357.7 $ (330.6 ) $ 27.1 $ (2.4 ) $ 24.7 |
Schedule of Contractual Obligations Previously Reported | The following table summarizes payment obligations for debt instruments after giving effect to 2016 debt repurchases. Payments Due By Period Less Than More Than Total 1 Year 1-3 Years 3-5 Years 5 Years Senior Unsecured Debt: Debt obligations (1) $ 4,542.8 $ - $ 935.1 $ 1,550.8 $ 2,056.9 Interest on debt obligations (2) 1,378.1 191.9 476.5 376.5 333.2 $ 5,920.9 $ 191.9 $ 1,411.6 $ 1,927.3 $ 2,390.1 (1) Represents scheduled future maturities of consolidated debt obligations for the periods indicated. (2) Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing March 31, 2016 rates for floating debt. |
Other Long-term Liabilities (Ta
Other Long-term Liabilities (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Other Liabilities Noncurrent [Abstract] | |
Other Long-term Liabilities | Other long-term liabilities are comprised of the following obligations: March 31, 2016 December 31, 2015 Asset retirement obligations $ 61.9 $ 69.9 Mandatorily redeemable preferred interests 64.1 82.9 Deferred revenue and other 23.5 25.4 Total long-term liabilities $ 149.5 $ 178.2 |
Changes in Aggregate Asset Retirement Obligations | The changes in our ARO are as follows March 31, 2016 Beginning of period $ 69.9 Change in cash flow estimate (9.1 ) Accretion expense 1.1 End of period $ 61.9 |
Schedule of Changes in Long-term Liability Attributable to Mandatorily Redeemable Preferred Interests | Mandatorily Redeemable Preferred Interests The following table shows the changes attributable to mandatorily redeemable preferred interests: March 31, 2016 Beginning of period $ 82.9 Income (loss) attributable to mandatorily redeemable preferred interests (0.3 ) Change in estimated redemption value (18.5 ) End of period $ 64.1 |
Partnership Units and Related34
Partnership Units and Related Matters (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Partners Capital [Abstract] | |
Long-Term Incentive Plan | Cash-Settled Performance Units Targa Resources Long-Term Incentive Plan Equity-Settled Performance Units Replacement Phantom Units 2015 2014 2013 Before Conversion 675,745 349,451 192,390 119,900 139,700 After Conversion 418,903 216,561 119,178 74,248 86,538 |
Schedule of Distributions | As a result of the TRC/TRP Merger, which was completed on February 17, 2016, Targa owns all of our outstanding common units. As a result, all of our distributions, after the distributions on the Preferred Units, all future distributions will be paid to TRC. The following table details the distributions to common unitholders declared and/or paid by for the three months ended March 31, 2016 Distributions Limited Partners General Partner Three Months Ended Date Paid or to be Paid Common Incentive 2% Total Distributions per Limited Partner Unit (In millions, except per unit amounts) December 31, 2015 February 9, 2016 $ 152.5 $ 43.9 $ 4.0 $ 200.4 $ 0.8250 |
Derivative Instruments and He35
Derivative Instruments and Hedging Activities (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Notional Volume of Commodity Hedges | At March 31, 2016, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2016 2017 2018 Natural Gas Swaps MMBtu/d 91,840 53,982 30,900 Natural Gas Basis Swaps MMBtu/d 43,309 18,082 - Natural Gas Options MMBtu/d 22,900 22,900 9,486 NGL Swaps Bbl/d 4,812 1,688 818 NGL Futures Bbl/d 4,331 274 - NGL Options Bbl/d 920 920 32 Condensate Swaps Bbl/d 2,375 1,400 900 Condensate Options Bbl/d 790 790 101 |
Fair Values of Derivative Instruments | The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of March 31, 2016 Fair Value as of December 31, 2015 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 82.4 $ 1.7 $ 92.1 $ 2.1 Long-term 25.2 7.9 34.9 2.4 Total derivatives designated as hedging instruments $ 107.6 $ 9.6 $ 127.0 $ 4.5 Derivatives not designated as hedging instruments Commodity contracts Current $ — $ 0.3 $ 0.1 $ 3.1 Total derivatives not designated as hedging instruments $ — $ 0.3 $ 0.1 $ 3.1 Total current position $ 82.4 $ 2.0 $ 92.2 $ 5.2 Total long-term position 25.2 7.9 34.9 2.4 Total derivatives $ 107.6 $ 9.9 $ 127.1 $ 7.6 |
Pro Forma Impact of Derivatives Net in Consolidated Balance Sheet | The pro forma impact of reporting derivatives in the Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro forma net presentation March 31, 2016 Asset Liability Asset Liability Current Position Counterparties with offsetting positions $ 79.4 $ 2.0 $ 77.4 $ - Counterparties without offsetting positions - assets 3.0 - 3.0 - Counterparties without offsetting positions - liabilities - - - - 82.4 2.0 80.4 - Long Term Position Counterparties with offsetting positions 25.2 7.7 17.5 - Counterparties without offsetting positions - assets - - - - Counterparties without offsetting positions - liabilities - 0.2 - 0.2 25.2 7.9 17.5 0.2 Total Derivatives Counterparties with offsetting positions 104.6 9.7 94.9 - Counterparties without offsetting positions - assets 3.0 - 3.0 - Counterparties without offsetting positions - liabilities - 0.2 - 0.2 $ 107.6 $ 9.9 $ 97.9 $ 0.2 Gross Presentation Pro forma net presentation December 31, 2015 Asset Liability Asset Liability Current Position Counterparties with offsetting positions $ 86.9 $ 5.2 $ 81.7 $ - Counterparties without offsetting positions - assets 5.3 - 5.3 - Counterparties without offsetting positions - liabilities - - - - 92.2 5.2 87.0 - Long Term Position Counterparties with offsetting positions 34.2 2.4 31.8 - Counterparties without offsetting positions - assets 0.7 - 0.7 - Counterparties without offsetting positions - liabilities - - - - 34.9 2.4 32.5 - Total Derivatives Counterparties with offsetting positions 121.1 7.6 113.5 - Counterparties without offsetting positions - assets 6.0 - 6.0 - Counterparties without offsetting positions - liabilities - - - - $ 127.1 $ 7.6 $ 119.5 $ - |
Amounts Recorded in OCI and Amounts Reclassified from OCI to Revenue and Expense | The following tables reflect amounts recorded in Other Comprehensive Income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated: Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Derivatives in Cash Flow Three Months Ended March 31, Hedging Relationships 2016 2015 Commodity contracts $ 6.7 $ 30.3 Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) Three Months Ended March 31, 2016 2015 Revenues $ (24.2 ) $ (13.2 ) $ (24.2 ) $ (13.2 ) |
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 Recognized in Income on Three Months Ended March 31, Derivatives Not Designated as Hedging Instruments Derivatives 2016 2015 Commodity contracts Revenue $ 1.8 $ 7.2 |
Deferred Gains (Losses) Included in Accumulated OCI | The following table shows the deferred gains (losses) included in accumulated OCI, which will be reclassified into earnings through the end of 2018 based on valuations as of the balance sheet date: March 31, 2016 December 31, 2015 Commodity hedges, before tax (1) $ 69.3 $ 86.8 (1) Includes deferred net gains of $58.9 million as of March 31, 2016 related to contracts that will be settled and reclassified to revenue over the next 12 months |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value of Assets and Liabilities Measured on a Recurring Basis | The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: March 31, 2016 Fair Value Carrying Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 104.4 $ 104.4 $ — $ 101.0 $ 3.4 Liabilities from commodity derivative contracts (1) 6.7 6.7 — 5.9 0.8 TPL contingent consideration (2) 3.0 3.0 — — 3.0 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 103.3 103.3 — — — Senior unsecured notes 4,526.9 4,357.1 — 4,357.1 — Accounts receivable securitization facility 150.0 150.0 — 150.0 — December 31, 2015 Fair Value Carrying Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 127.1 $ 127.1 $ — $ 123.1 $ 4.0 Liabilities from commodity derivative contracts (1) 7.6 7.6 — 7.3 0.3 TPL contingent consideration (2) 3.0 3.0 — — 3.0 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 135.4 135.4 — — — Senior secured revolving credit facility 280.0 280.0 — 280.0 — Senior unsecured notes 4,884.0 4,192.0 — 4,192.0 — Accounts receivable securitization facility 219.3 219.3 — 219.3 — (1) The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 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) See Note 4 – Business Acquisitions. |
Reconciliation of Changes in Fair Value of Financial Instruments Classified as Level 3 | The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts Contingent (Asset)/Liability Liability Balance, December 31, 2015 $ 3.7 $ 3.0 New Level 3 instruments (0.2 ) - Settlements included in Revenue (0.5 ) - Unrealized gain/(loss) included in OCI (0.4 ) - Balance, March 31, 2016 $ 2.6 $ 3.0 |
Related Party Transactions - 37
Related Party Transactions - Targa (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Related Party Transactions [Abstract] | |
Summary of Transactions with Affiliates | The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable. Three Months Ended March 31, 2016 2015 Targa billings of payroll and related costs included in operating expense $ 40.2 $ 34.9 Targa allocation of general and administrative expense 39.9 38.3 Cash distributions to Targa based on IDR and unit ownership 61.4 51.6 Cash contributions from Targa for issuance of common units 785.0 — Cash contributions from Targa to maintain its 2% general partner ownership 16.0 28.8 |
Supplemental Cash Flow Inform38
Supplemental Cash Flow Information (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Three Months Ended March 31, 2016 2015 Cash: Interest paid, net of capitalized interest (1) $ 77.3 $ 28.9 Income taxes paid, net of refunds 1.1 0.1 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment 16.9 — Impact of capital expenditure accruals on property, plant and equipment 13.7 30.9 Transfers from materials and supplies inventory to property, plant and equipment 0.5 0.6 Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate (9.1 ) 3.7 Non-cash financing activities: Cancellation of Treasury stock (10.2 ) Accrued distributions on unvested equity awards under share compensation arrangements 0.2 — Receivables from equity issuances — 24.6 Non-cash balance sheet movements related to Atlas Merger: (See Note 4 - Business Acquisitions) Non-cash merger consideration - common units and replacement equity awards — 2,583.5 Special GP Interest — 1,612.4 Current liabilities retained by Targa — (0.4 ) Net non-cash balance sheet movements excluded from consolidated statements of cash flows — 4,195.5 Net cash merger consideration included in investing activities — 828.7 Total fair value of consideration transferred $ — $ 5,024.2 (1) Interest capitalized on major projects was $4.8 million and $2.4 million for the three months ended March 31, 2016 and March 31, 2015. |
Segment Information (Tables)
Segment Information (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Segment Reporting [Abstract] | |
Information by Segment | Reportable segment information is shown in the following tables: Three Months Ended March 31, 2016 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 110.3 $ 1,033.9 $ 26.8 $ — $ 1,171.0 Fees from midstream services 115.8 155.6 — — 271.4 226.1 1,189.5 26.8 — 1,442.4 Intersegment revenues Sales of commodities 412.6 47.3 — (459.9 ) — Fees from midstream services 2.1 4.1 — (6.2 ) — 414.7 51.4 — $ (466.1 ) $ — Revenues $ 640.8 $ 1,240.9 $ 26.8 $ (466.1 ) $ 1,442.4 Operating margin $ 115.6 $ 157.0 $ 26.8 $ — $ 299.4 Other financial information: Total assets (1) $ 10,219.0 $ 2,501.0 $ 105.7 $ 42.9 $ 12,868.6 Goodwill (2) $ 393.0 $ — $ — $ — $ 393.0 Capital expenditures $ 103.0 $ 73.1 $ — $ 0.8 $ 176.9 (1) Corporate assets at the Segment level primarily include tax-related assets, cash and prepaids. (2) Total assets include goodwill. Goodwill has been attributed to our Gathering and Processing segment. Three Months Ended March 31, 2015 Gathering and Processing Logistics and Marketing Other Corporate and Eliminations Total Revenues Sales of commodities $ 220.9 $ 1,159.7 $ 21.7 $ (0.1 ) $ 1,402.2 Fees from midstream services 72.0 205.4 — 0.1 277.5 292.9 1,365.1 21.7 $ — $ 1,679.7 Intersegment revenues Sales of commodities 278.1 55.9 — (334.0 ) — Fees from midstream services 2.0 4.5 — (6.5 ) — 280.1 60.4 — $ (340.5 ) $ — Revenues $ 573.0 $ 1,425.5 $ 21.7 $ (340.5 ) $ 1,679.7 Operating margin $ 87.0 $ 191.3 $ 21.7 $ — $ 300.0 Other financial information: Total assets (1) $ 10,671.8 $ 2,302.5 $ 177.3 $ 39.2 $ 13,190.8 Goodwill (2) $ 557.9 $ — $ — $ — $ 557.9 Capital expenditures $ 95.5 $ 60.7 $ — $ 1.1 $ 157.3 Business acquisition $ 5,024.2 $ — $ — $ — $ 5,024.2 (1) Corporate assets at the Segment level primarily include tax-related assets, cash and prepaids. (2) Total assets include goodwill. Goodwill has been attributed to our Gathering and Processing segment. |
Revenues by Product and Service | The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended March 31, 2016 2015 Sales of commodities: Natural gas $ 326.9 $ 302.1 NGL 785.5 1,030.7 Condensate 22.2 21.3 Petroleum products 9.6 26.4 Derivative activities 26.8 21.7 1,171.0 1,402.2 Fees from midstream services: Fractionating and treating 30.2 49.8 Storage, terminaling, transportation and export 118.4 136.2 Gathering and processing 105.0 68.4 Other 17.8 23.1 271.4 277.5 Total revenues $ 1,442.4 $ 1,679.7 |
Reconciliation of Operating Margin to Net Income (Loss) | The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: Three Months Ended March 31, 2016 2015 Reconciliation of operating margin to net income: Operating margin $ 299.4 $ 300.0 Depreciation and amortization expense (193.5 ) (118.6 ) General and administrative expense (43.4 ) (40.2 ) Goodwill impairment (24.0 ) - Interest expense, net (46.9 ) (50.0 ) Other, net 18.8 (12.3 ) Income tax expense 0.2 (1.1 ) Net income $ 10.6 $ 77.8 |
Organization and Operations (De
Organization and Operations (Details) | Feb. 17, 2016$ / shares | Mar. 31, 2016shares | Dec. 31, 2015shares |
Subsidiary Of Limited Liability Company Or Limited Partnership [Line Items] | |||
Conversion ratio in stock-for-unit transaction | 0.62 | ||
Common stock, par value (in dollars per share) | $ / shares | $ 0.001 | ||
Series A Cumulative Redeemable Perpetual Preferred Units [Member] | |||
Subsidiary Of Limited Liability Company Or Limited Partnership [Line Items] | |||
Preferred units issued (in units) | shares | 5,000,000 | 5,000,000 | |
Preferred units dividend percentage | 9.00% |
Basis of Presentation (Details)
Basis of Presentation (Details) $ in Billions | Feb. 27, 2015USD ($)Transaction |
Business Acquisition [Line Items] | |
Number of legal transactions involved in mergers | Transaction | 2 |
Atlas Energy [Member] | |
Business Acquisition [Line Items] | |
Total general partner interest acquired | $ | $ 1.6 |
Impact of Revisions to Activi42
Impact of Revisions to Activity Reported in Statement of Changes in Other Comprehensive Income (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 9 Months Ended | 12 Months Ended | |||
Mar. 31, 2016 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Jun. 30, 2015 | Sep. 30, 2015 | Dec. 31, 2015 | |
Commodity hedging contracts: | |||||||
Change in fair value | $ 50.7 | $ (3.6) | $ 30.3 | $ 27 | $ 77.6 | $ 112.7 | |
Settlements reclassified to revenues | (24.5) | (21.4) | (13.2) | (34.9) | (59.3) | (86.3) | |
Other comprehensive income (loss) | $ (17.5) | 26.2 | (25) | 17.1 | (7.9) | 18.3 | 26.4 |
Scenario, Previously Reported | |||||||
Commodity hedging contracts: | |||||||
Change in fair value | 42.9 | (8.7) | 25.2 | 16.5 | 59.4 | 81.2 | |
Settlements reclassified to revenues | (16.7) | (16.3) | (8.1) | (24.4) | (41.1) | (54.8) | |
Other comprehensive income (loss) | $ 26.2 | $ (25) | $ 17.1 | $ (7.9) | $ 18.3 | $ 26.4 |
Significant Accounting Polici43
Significant Accounting Policies (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Mar. 31, 2016 | |
Accounting Policies [Abstract] | ||
Reclassification of unamortized debt issuance costs | $ 38.3 | |
Unamortized debt issuance costs | $ 34 |
Business Acquisitions (Details)
Business Acquisitions (Details) | Feb. 27, 2015USD ($)Transaction$ / sharesshares | Mar. 31, 2015USD ($) | Mar. 31, 2016USD ($)MMcf / dmi | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($) | Feb. 17, 2016$ / shares |
Business Acquisition [Line Items] | ||||||
Number of legal transactions involved in mergers | Transaction | 2 | |||||
Common units par value (in dollars per share) | $ / shares | $ 0.001 | |||||
Acquisition-related expenses | $ 19,300,000 | $ 18,100,000 | $ 18,100,000 | |||
Revenues from acquired business | $ 160,600,000 | |||||
Net income (loss) from acquired business | 3,400,000 | |||||
Targa Pipeline Partners LP [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Processing capacity | MMcf / d | 2,053 | |||||
Length of additional pipelines | mi | 12,220 | |||||
Targa Resources Corp [Member] | Atlas Energy [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Total general partner interest acquired | $ 1,600,000,000 | |||||
Atlas Energy [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Total general partner interest acquired | 1,600,000,000 | |||||
Cash payment related to one-time cash payments and cash settlements of equity awards | 7,300,000 | |||||
Reduction in purchase price | (154,700,000) | |||||
Atlas Energy [Member] | Phantom Unit Awards [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payment related to one-time cash payments and cash settlements of equity awards | 4,500,000 | |||||
Atlas Energy [Member] | Common Units [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Common units acquired | $ 147,400,000 | |||||
Atlas Energy [Member] | Targa Pipeline Partners LP [Member] | Common Units [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Total distribution of common shares (in shares) | shares | 3,363,935 | |||||
Atlas Energy [Member] | Targa Resources Corp [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Percentage of interest in common units | 100.00% | |||||
Distribution of common units/shares for each common unit (in shares) | shares | 0.1809 | |||||
Cash payment (in dollars per common unit) | $ / shares | $ 9.12 | |||||
Cash payments related to acquisition | $ 514,700,000 | |||||
Common units acquired | $ 1,000,000,000 | |||||
Closing market price of common share (in dollars per share) | $ / shares | $ 99.58 | |||||
Common units par value (in dollars per share) | $ / shares | $ 0.001 | |||||
Acquisition-related expenses | $ 11,000,000 | |||||
Atlas Energy [Member] | Targa Resources Corp [Member] | Change Of Control Payments [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payments related to acquisition | 149,200,000 | |||||
Atlas Energy [Member] | Targa Resources Corp [Member] | Equity Award Settlements [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payments related to acquisition | $ 88,000,000 | |||||
Atlas Energy [Member] | Targa Resources Corp [Member] | Restricted Stock Units (RSUs) [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Total distribution of common shares (in shares) | shares | 81,740 | |||||
Atlas Energy [Member] | Targa Resources Corp [Member] | Common Units [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Total distribution of common shares (in shares) | shares | 10,126,532 | |||||
Common units acquired | $ 147,400,000 | |||||
Atlas Pipeline Partners [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Total general partner interest acquired | 5,300,000,000 | |||||
Acquired debt and all other assumed liabilities included purchase consideration | 1,800,000,000 | |||||
Payments for notes tendered and settled upon closing of merger | $ 1,200,000,000 | |||||
Distribution of common units/shares for each common unit (in shares) | shares | 0.5846 | |||||
Cash payment (in dollars per common unit) | $ / shares | $ 1.26 | |||||
Common units acquired | $ 2,600,000,000 | |||||
Closing market price of common share (in dollars per share) | $ / shares | $ 43.82 | |||||
Cash paid in lieu of unit issuances | $ 6,400,000 | |||||
Atlas Pipeline Partners [Member] | Class E Preferred Units [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Percentage of cumulative redeemable perpetual preferred units | 8.25% | |||||
Atlas Pipeline Partners [Member] | Change Of Control Payments [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payments related to acquisition | $ 28,800,000 | |||||
Atlas Pipeline Partners [Member] | Revolving Credit Facility [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payments related to acquisition | 701,400,000 | |||||
Atlas Pipeline Partners [Member] | Phantom Unit Awards [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payment representing accelerated vesting of a portion of employees APL phantom awards | $ 600,000 | |||||
Total distribution of common shares (in shares) | shares | 629,231 | |||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 1 [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Reduction in incentive distribution | $ 9,375,000 | |||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 2 [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Reduction in incentive distribution | 6,250,000 | |||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 3 [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Reduction in incentive distribution | 2,500,000 | |||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 4 [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Reduction in incentive distribution | $ 1,250,000 | |||||
Atlas Pipeline Partners [Member] | Atlas Energy [Member] | Common Units [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Common units owned by parent prior to closing (in units) | shares | 5,754,253 | |||||
Atlas Pipeline Partners [Member] | Common Unit Holders [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payments related to acquisition | $ 128,000,000 | |||||
Total distribution of common shares (in shares) | shares | 58,614,157 | |||||
Atlas Pipeline Partners [Member] | Targa Resources Corp [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Contribution made by Targa to general partner's interest | $ 52,400,000 | |||||
Percentage of general partner's interest maintained | 2.00% |
Business Acquisitions, Pro form
Business Acquisitions, Pro forma Impact of Atlas Mergers on Consolidated Statements of Operations (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Pro forma consolidated results of operations [Abstract] | |||
Revenues | $ 1,994 | ||
Net income | 75.2 | ||
Acquisition-related costs | $ 19.3 | $ 18.1 | $ 18.1 |
Atlas Resource Partners, LP [Member] | |||
Pro forma consolidated results of operations [Abstract] | |||
Percentage of equity interest sold | 100.00% |
Business Acquisitions, Fair Val
Business Acquisitions, Fair Value of Consideration Transferred (Details) - USD ($) $ in Millions | Feb. 27, 2015 | Mar. 31, 2016 | Mar. 31, 2015 | |
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Cash paid, net of cash acquired | $ 0 | $ 828.7 | ||
Total fair value of consideration transferred | $ 5,024.2 | |||
Atlas Pipeline Partners [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Cash paid, net of cash acquired | [1] | 828.7 | ||
Less: value of APL common units owned by ATLS | (2,600) | |||
Total fair value of consideration transferred | 3,412.2 | |||
Cash acquired from acquisition | 35.3 | |||
Phantom Unit Awards [Member] | Atlas Pipeline Partners [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Common shares of TRC | [2] | 15 | ||
Targa Resources Corp [Member] | Atlas Energy [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Cash paid, net of cash acquired | [3] | 745.7 | ||
Less: value of APL common units owned by ATLS | (1,000) | |||
Total fair value of consideration transferred | 1,612 | |||
Cash acquired from acquisition | 5.5 | |||
Targa Resources Corp [Member] | Replacement Restricted Stock Units RSUs [Member] | Atlas Energy [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Common shares of TRC | [2] | 5.2 | ||
Common Stock [Member] | Targa Resources Corp [Member] | Atlas Energy [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Common shares of TRC | 1,008.5 | |||
Common Units [Member] | Atlas Energy [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Less: value of APL common units owned by ATLS | (147.4) | |||
Common Units [Member] | Atlas Pipeline Partners [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Common shares of TRC | 2,568.5 | |||
Common Units [Member] | Targa Resources Corp [Member] | Atlas Energy [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Less: value of APL common units owned by ATLS | $ (147.4) | |||
[1] | We acquired $35.3 million of cash. | |||
[2] | The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. | |||
[3] | Targa acquired $5.5 million of cash. |
Business Acquisitions, Fair V47
Business Acquisitions, Fair Value Determination (Details) - USD ($) $ in Millions | 3 Months Ended | ||||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | Feb. 27, 2015 | Dec. 31, 2014 | |
Fair value determination [Abstract] | |||||
Trade and other current receivables, net | $ 181.1 | ||||
Other current assets | 24.4 | ||||
Assets from risk management activities | 102.1 | ||||
Property, plant and equipment | 4,616.9 | ||||
Investments in unconsolidated affiliates | 214.5 | ||||
Intangible assets | 1,354.9 | ||||
Other long-term assets | 5.5 | ||||
Current liabilities | (258.8) | ||||
Long-term debt | (1,573.3) | ||||
Deferred income tax liabilities, net | (13.6) | ||||
Other long-term liabilities | (119.1) | ||||
Total identifiable net assets | 4,534.6 | ||||
Noncontrolling interest in subsidiaries | (216.9) | ||||
Current liabilities retained by Targa | (0.5) | ||||
Goodwill, net of impairment provisions | $ 393 | $ 417 | 707 | $ 0 | |
Total fair value of consideration transferred | 5,024.2 | ||||
Measurement-period adjustments to preliminary acquisition date fair values [Abstract] | |||||
Depreciation and amortization expense | 193.5 | $ 118.6 | |||
Equity earnings (loss) | $ (4.8) | 1.9 | |||
Trade receivables, fair value | 178.1 | ||||
Trade receivables, gross amount | 178.1 | ||||
Contractual receivables included in current receivables | 3 | ||||
Contractual receivables included in other long term assets | $ 4.5 | ||||
Measurement Period Adjustments [Member] | |||||
Measurement-period adjustments to preliminary acquisition date fair values [Abstract] | |||||
Depreciation and amortization expense | (1) | ||||
Equity earnings (loss) | $ 0.3 |
Business Acquisitions, Mandator
Business Acquisitions, Mandatorily Redeemable Preferred Interests (Details) - Mandatorily Redeemable Noncontrolling Interests [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($)JointVenture | |
Redeemable Noncontrolling Interest [Line Items] | |
Number of joint ventures | JointVenture | 2 |
Acquired other long-term liabilities | $ | $ 109.3 |
Business Acquisitions, Continge
Business Acquisitions, Contingent Consideration and Replacement Phantom Units (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Jun. 30, 2015 | |
Replacement Phantom Units [Member] | ||
Business Acquisition [Line Items] | ||
Number of common units called by replacement equity unit (in shares) | 1 | |
Dividend payment period | 60 days | |
Replacement Phantom Units [Member] | Vesting Term One [Member] | ||
Business Acquisition [Line Items] | ||
Vesting percentage original term | 25.00% | |
Vesting period of original term | 4 years | |
Replacement Phantom Units [Member] | Vesting Term Two [Member] | ||
Business Acquisition [Line Items] | ||
Vesting percentage original term | 33.00% | |
Vesting period of original term | 3 years | |
Atlas Pipeline Partners [Member] | ||
Business Acquisition [Line Items] | ||
Contingent consideration additional amount | $ 6 | |
Contingent consideration liability lower range | 0 | |
Contingent consideration liability higher range | $ 6 | |
Contingent liability acquisition date fair value | $ 4.2 |
Business Acquisitions, Goodwill
Business Acquisitions, Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2016 | Dec. 31, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | |
Goodwill [Roll Forward] | ||||
Beginning of period | $ 417 | $ 0 | $ 0 | |
Acquisition | 707 | |||
Impairment | (24) | $ (290) | 0 | (290) |
Additional Impairment | (24) | |||
Goodwill | 393 | 417 | 417 | |
WestTX [Member] | ||||
Goodwill [Roll Forward] | ||||
Beginning of period | 326.9 | 0 | 0 | |
Acquisition | 364.5 | |||
Impairment | (37.6) | |||
Additional Impairment | (14.4) | |||
Goodwill | 312.5 | 326.9 | 326.9 | |
SouthTX [Member] | ||||
Goodwill [Roll Forward] | ||||
Beginning of period | 90.1 | 0 | 0 | |
Acquisition | 160.3 | |||
Impairment | (70.2) | |||
Additional Impairment | (9.6) | |||
Goodwill | $ 80.5 | $ 90.1 | 90.1 | |
SouthOK [Member] | ||||
Goodwill [Roll Forward] | ||||
Beginning of period | $ 0 | 0 | ||
Acquisition | 182.2 | |||
Impairment | $ (182.2) |
Inventories (Details)
Inventories (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Inventory Disclosure [Abstract] | ||
Commodities | $ 49.2 | $ 128.3 |
Materials and supplies | 12.5 | 12.7 |
Total inventory | $ 61.7 | $ 141 |
Property, Plant and Equipment52
Property, Plant and Equipment and Intangible Assets, Property, Plant and Equipment (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 12,107.8 | $ 11,928.2 | |
Accumulated depreciation | (2,373.2) | (2,225.6) | |
Property, plant and equipment, net | 9,734.6 | 9,702.6 | |
Intangible assets | 2,036.6 | 2,036.6 | |
Accumulated amortization | (271.5) | (226.5) | |
Intangible assets, net | $ 1,765.1 | 1,810.1 | $ 591.9 |
Estimated useful life | 20 years | ||
Additions from acquisition | 1,354.9 | ||
Gathering Systems [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 6,357.9 | 6,304.5 | |
Gathering Systems [Member] | Minimum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 5 years | ||
Gathering Systems [Member] | Maximum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 20 years | ||
Processing and Fractionation Facilities [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 2,996.5 | 2,988.5 | |
Processing and Fractionation Facilities [Member] | Minimum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 5 years | ||
Processing and Fractionation Facilities [Member] | Maximum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 25 years | ||
Terminaling and Storage Facilities [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 1,173.9 | 1,115 | |
Terminaling and Storage Facilities [Member] | Minimum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 5 years | ||
Terminaling and Storage Facilities [Member] | Maximum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 25 years | ||
Transportation Assets [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 454.7 | 454 | |
Transportation Assets [Member] | Minimum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 10 years | ||
Transportation Assets [Member] | Maximum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 25 years | ||
Other Property, Plant and Equipment [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 215.2 | 220.9 | |
Other Property, Plant and Equipment [Member] | Minimum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 3 years | ||
Other Property, Plant and Equipment [Member] | Maximum [Member] | |||
Property Plant And Equipment [Line Items] | |||
Estimated useful life | 25 years | ||
Land [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 108.8 | 108.8 | |
Construction in Progress [Member] | |||
Property Plant And Equipment [Line Items] | |||
Property, plant and equipment | $ 800.8 | $ 736.5 |
Property, Plant and Equipment53
Property, Plant and Equipment and Intangible Assets, Intangible Assets (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2016 | Dec. 31, 2015 | |
Intangible Assets, net [Roll Forward] | ||
Beginning of period | $ 1,810.1 | $ 591.9 |
Additions from acquisition | 1,354.9 | |
Amortization | (45) | (136.7) |
Intangible assets, net | $ 1,765.1 | $ 1,810.1 |
Investment in Unconsolidated 54
Investment in Unconsolidated Affiliate (Details) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016USD ($)JointVenture | Mar. 31, 2015USD ($) | ||
Schedule Of Equity Method Investments [Line Items] | |||
Beginning of period | $ 258.9 | ||
Equity earnings (loss) | (4.8) | $ 1.9 | |
Cash distributions | [1] | (3.4) | |
Cash calls for expansion projects | 4.2 | ||
End of period | 254.9 | ||
Return of capital from unconsolidated affiliate | $ 3.4 | $ 0.6 | |
Gulf Coast Fractionators LP [Member] | |||
Schedule Of Equity Method Investments [Line Items] | |||
Ownership interest | 38.80% | ||
Beginning of period | $ 49.5 | ||
Equity earnings (loss) | (1) | ||
Cash distributions | [1] | (3) | |
Cash calls for expansion projects | 0 | ||
End of period | $ 45.5 | ||
T2 Joint Ventures [Member] | |||
Schedule Of Equity Method Investments [Line Items] | |||
Number of non-operated joint ventures acquired in Atlas mergers | JointVenture | 3 | ||
Basis difference on preliminary fair values | $ 39.9 | ||
Preliminary estimated useful lives of the underlying assets | 20 years | ||
T2 La Salle [Member] | |||
Schedule Of Equity Method Investments [Line Items] | |||
Ownership interest | 75.00% | ||
Beginning of period | $ 63.6 | ||
Equity earnings (loss) | (1.6) | ||
Cash distributions | [1] | 0 | |
Cash calls for expansion projects | 0 | ||
End of period | $ 62 | ||
T2 Eagle Ford [Member] | |||
Schedule Of Equity Method Investments [Line Items] | |||
Ownership interest | 50.00% | ||
Beginning of period | $ 123.8 | ||
Equity earnings (loss) | (1.3) | ||
Cash distributions | [1] | 0 | |
Cash calls for expansion projects | 4.2 | ||
End of period | $ 126.7 | ||
T2 EF Co-Gen [Member] | |||
Schedule Of Equity Method Investments [Line Items] | |||
Ownership interest | 50.00% | ||
Beginning of period | $ 22 | ||
Equity earnings (loss) | (0.9) | ||
Cash distributions | [1] | (0.4) | |
Cash calls for expansion projects | 0 | ||
End of period | $ 20.7 | ||
[1] | Includes $3.4 million in distributions received from GCF and T2 Joint Ventures in excess of our share of cumulative earnings for the three months ended March 31, 2016. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows. |
Accounts Payable and Accrued 55
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Components of accounts payable and accrued liabilities [Abstract] | ||
Commodities | $ 322.6 | $ 385.3 |
Other goods and services | 92.6 | 141.3 |
Interest | 65.3 | 80.3 |
Compensation and benefits | 0.4 | |
Income and other taxes | 19 | 10.4 |
Other | 15.3 | 18.1 |
Accounts payable and accrued liabilities | 514.8 | 635.8 |
Outstanding checks | $ 24.1 | $ 34 |
Debt Obligations (Details)
Debt Obligations (Details) - USD ($) $ in Millions | Apr. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | |
Current: | ||||
Accounts receivable securitization facility, due December 2016 | $ 150 | $ 219.3 | ||
Long-term [Abstract] | ||||
Long-term debt | 4,492.9 | 5,125.7 | ||
Debt issuance costs | (34) | (38.3) | ||
Total debt | 4,642.9 | 5,345 | ||
Irrevocable standby letters of credit outstanding | 12.2 | 12.9 | ||
5% Senior Notes [Member] | Subsequent Event | ||||
Long-term [Abstract] | ||||
Partnership outstanding senior note repurchased on open market | $ 96.4 | |||
Accrued interest paid to repurchase outstanding balance of senior note | $ 96 | |||
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | 935.1 | 1,100 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | 749.4 | 800 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | [1] | 309.9 | 342.1 | |
Unamortized premium | 4.3 | 5 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | 478.6 | 483.6 | ||
Unamortized discount | (20.9) | (22.1) | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | 278.7 | 300 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | 559.6 | 583.7 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | 583.9 | 623.5 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | 580.1 | 600 | ||
Senior Unsecured Notes [Member] | Atlas Pipeline Partners, L.P. Acquisition [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | [1],[2] | 12.9 | 12.9 | |
Unamortized premium | 0.2 | 0.2 | ||
Senior Unsecured Notes [Member] | Atlas Pipeline Partners, L.P. Acquisition [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | [2] | 6.5 | 6.5 | |
Senior Unsecured Notes [Member] | Atlas Pipeline Partners, L.P. Acquisition [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | [2] | 48.1 | 48.1 | |
Unamortized premium | 0.5 | 0.5 | ||
Senior Secured and Unsecured Notes [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | 4,526.9 | 5,164 | ||
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2017 [Member] | ||||
Long-term [Abstract] | ||||
Long-term debt | [3] | 280 | ||
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2016 [Member] | ||||
Current: | ||||
Accounts receivable securitization facility, due December 2016 | $ 150 | $ 219.3 | ||
[1] | In May 2015, we exchanged the TRP 6⅝% Senior Notes with the same economic terms to the holders of the 2020 6⅝% Notes that validly tendered such notes for exchange to us. | |||
[2] | APL debt is not guaranteed by the Partnership. | |||
[3] | As of March 31, 2016, availability under our $1.6 billion senior secured revolving credit facility was $1.6 billion. |
Debt Obligations (Parenthetical
Debt Obligations (Parenthetical) (Details) | 3 Months Ended | |
Mar. 31, 2016USD ($) | ||
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2017 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Oct. 3, 2017 | [1] |
Maximum borrowing capacity | $ 1,600,000,000 | |
Remaining borrowing capacity | $ 1,600,000,000 | |
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2016 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Dec. 31, 2016 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Jan. 15, 2018 | |
Interest rate on fixed rate debt | 5.00% | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Nov. 15, 2019 | |
Interest rate on fixed rate debt | 4.125% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Oct. 1, 2020 | [2] |
Interest rate on fixed rate debt | 6.625% | [2] |
Senior Unsecured Notes [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Feb. 1, 2021 | |
Interest rate on fixed rate debt | 6.875% | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Aug. 1, 2022 | |
Interest rate on fixed rate debt | 6.375% | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | May 1, 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. 15, 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. 15, 2024 | |
Interest rate on fixed rate debt | 6.75% | |
Senior Unsecured Notes [Member] | Atlas Pipeline Partners, L.P. Acquisition [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Oct. 1, 2020 | [2],[3] |
Interest rate on fixed rate debt | 6.625% | [2],[3] |
Senior Unsecured Notes [Member] | Atlas Pipeline Partners, L.P. Acquisition [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Nov. 15, 2021 | [3] |
Interest rate on fixed rate debt | 4.75% | [3] |
Senior Unsecured Notes [Member] | Atlas Pipeline Partners, L.P. Acquisition [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Aug. 1, 2023 | [3] |
Interest rate on fixed rate debt | 5.875% | [3] |
[1] | As of March 31, 2016, availability under our $1.6 billion senior secured revolving credit facility was $1.6 billion. | |
[2] | In May 2015, we exchanged the TRP 6⅝% Senior Notes with the same economic terms to the holders of the 2020 6⅝% Notes that validly tendered such notes for exchange to us. | |
[3] | APL debt is not guaranteed by the Partnership. |
Debt Obligations, Interest Rate
Debt Obligations, Interest Rates on Variable-Rate Debt Obligations (Details) | 3 Months Ended |
Mar. 31, 2016 | |
Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Weighted average interest rate incurred | 1.20% |
Range of interest rates incurred | 1.20% |
Revolving Credit Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred, minimum | 2.60% |
Range of interest rates incurred, maximum | 4.80% |
Weighted average interest rate incurred | 2.70% |
Debt Obligations, Summary of De
Debt Obligations, Summary of Debt Repurchased on Open Market Portion of Outstanding Senior Notes (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | $ 357.7 | |
Open market purchases of senior notes | (330.6) | $ 0 |
Gain/Loss on Debt Repurchase | 27.1 | |
Debt Repurchase, Write-off of Debt Issue Costs | (2.4) | |
Net Gain (loss) on Debt Repurchase | 24.7 | |
5¼% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 24.1 | |
Open market purchases of senior notes | (20.1) | |
Gain/Loss on Debt Repurchase | 4 | |
Debt Repurchase, Write-off of Debt Issue Costs | (0.2) | |
Net Gain (loss) on Debt Repurchase | 3.8 | |
4¼% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 39.5 | |
Open market purchases of senior notes | (31.8) | |
Gain/Loss on Debt Repurchase | 7.7 | |
Debt Repurchase, Write-off of Debt Issue Costs | (0.3) | |
Net Gain (loss) on Debt Repurchase | 7.4 | |
6⅞% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 4.8 | |
Open market purchases of senior notes | (4.3) | |
Gain/Loss on Debt Repurchase | 0.5 | |
Debt Repurchase, Write-off of Debt Issue Costs | (0.1) | |
Net Gain (loss) on Debt Repurchase | 0.4 | |
6⅝% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 32.6 | |
Open market purchases of senior notes | (29.5) | |
Gain/Loss on Debt Repurchase | 3.1 | |
Net Gain (loss) on Debt Repurchase | 3.1 | |
6⅜% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 21.3 | |
Open market purchases of senior notes | (18.7) | |
Gain/Loss on Debt Repurchase | 2.6 | |
Debt Repurchase, Write-off of Debt Issue Costs | (0.2) | |
Net Gain (loss) on Debt Repurchase | 2.4 | |
6¾% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 19.9 | |
Open market purchases of senior notes | (17.5) | |
Gain/Loss on Debt Repurchase | 2.4 | |
Debt Repurchase, Write-off of Debt Issue Costs | (0.2) | |
Net Gain (loss) on Debt Repurchase | 2.2 | |
5% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 164.9 | |
Open market purchases of senior notes | (164.5) | |
Gain/Loss on Debt Repurchase | 0.4 | |
Debt Repurchase, Write-off of Debt Issue Costs | (1) | |
Net Gain (loss) on Debt Repurchase | (0.6) | |
4⅛% Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt Repurchase, Book Value | 50.6 | |
Open market purchases of senior notes | (44.2) | |
Gain/Loss on Debt Repurchase | 6.4 | |
Debt Repurchase, Write-off of Debt Issue Costs | (0.4) | |
Net Gain (loss) on Debt Repurchase | $ 6 |
Debt Obligations, Schedule of C
Debt Obligations, Schedule of Contractual Obligations (Details) - Senior Unsecured Debt [Member] $ in Millions | Mar. 31, 2016USD ($) |
Contractual Obligation [Line Items] | |
Total | $ 5,920.9 |
Less Than 1 Year | 191.9 |
1-3 Years | 1,411.6 |
3-5 Years | 1,927.3 |
More Than 5 Years | 2,390.1 |
Debt Obligations [Member] | |
Contractual Obligation [Line Items] | |
Total | 4,542.8 |
1-3 Years | 935.1 |
3-5 Years | 1,550.8 |
More Than 5 Years | 2,056.9 |
Interest on Debt Obligations [Member] | |
Contractual Obligation [Line Items] | |
Total | 1,378.1 |
Less Than 1 Year | 191.9 |
1-3 Years | 476.5 |
3-5 Years | 376.5 |
More Than 5 Years | $ 333.2 |
Other Long-term Liabilities (De
Other Long-term Liabilities (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Other Liabilities Noncurrent [Abstract] | ||
Asset retirement obligations | $ 61.9 | $ 69.9 |
Mandatorily redeemable preferred interests | 64.1 | 82.9 |
Deferred revenue and other | 23.5 | 25.4 |
Total long-term liabilities | $ 149.5 | $ 178.2 |
Other Long-term Liabilities, As
Other Long-term Liabilities, Asset Retirement Obligations (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning of period | $ 69.9 | |
Change in cash flow estimate | (9.1) | $ 3.7 |
Accretion expense | 1.1 | $ 1.3 |
End of period | $ 61.9 |
Other Long-term Liabilities, Ma
Other Long-term Liabilities, Mandatorily Redeemable Preferred Interests (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | ||
Beginning of period | $ 82.9 | |
Income (loss) attributable to mandatorily redeemable preferred interests | 3 | $ 5 |
Change in redemption value of mandatorily redeemable preferred interest | (18.5) | $ 0 |
End of period | 64.1 | |
Mandatorily Redeemable Preferred Interests [Member] | ||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | ||
Beginning of period | 82.9 | |
Income (loss) attributable to mandatorily redeemable preferred interests | (0.3) | |
Change in redemption value of mandatorily redeemable preferred interest | (18.5) | |
End of period | $ 64.1 |
Partnership Units and Related64
Partnership Units and Related Matters, Long Term Incentive Plan (Details) $ in Millions | Feb. 27, 2016USD ($) | Feb. 17, 2016shares | Mar. 31, 2016USD ($)shares | Mar. 31, 2015USD ($) | Dec. 31, 2015shares |
Schedule Of Equity Method Investments [Line Items] | |||||
Conversion ratio in stock-for-unit transaction | 0.62 | ||||
Series A preferred limited partners units outstanding (in units) | 5,000,000 | ||||
Distributions to limited partners common | $ | $ 2.8 | ||||
Accrued distributions of preferred unit | $ | $ 0.9 | ||||
Common limited partners units issued (in units) | 230,002,743 | 185,083,420 | |||
General partner units issued (in units) | 4,693,934 | 3,772,871 | |||
Total distributions to general and limited partners | $ | $ 203.2 | $ 138.1 | |||
Equity-Settled Performance Units [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Compensation costs | $ | $ 3.9 | ||||
Phantom Unit Awards [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Outstanding shares | 349,451 | ||||
Converted outstanding shares | 216,561 | ||||
Cash-Settled Performance Units [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Compensation costs | $ | 4.8 | ||||
Partnership Long-term Incentive Plan [Member] | Equity-Settled Performance Units [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Outstanding shares | 675,745 | ||||
Converted outstanding shares | 418,903 | ||||
2015 Long Term Incentive Plan [Member] | Cash-Settled Performance Units [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Outstanding shares | 192,390 | ||||
Converted outstanding shares | 119,178 | ||||
2014 Long Term Incentive Plan [Member] | Cash-Settled Performance Units [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Outstanding shares | 119,900 | ||||
Converted outstanding shares | 74,248 | ||||
2013 Long Term Incentive Plan [Member] | Cash-Settled Performance Units [Member] | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Outstanding shares | 139,700 | ||||
Converted outstanding shares | 86,538 | ||||
TRC/TRP Merger | |||||
Schedule Of Equity Method Investments [Line Items] | |||||
Contributions from Targa Resources Corp. | $ | $ 801 | ||||
Common limited partners units issued (in units) | 45,103,140 | ||||
General partner units issued (in units) | 920,472 | ||||
Total distributions to general and limited partners | $ | $ 154.8 | ||||
Date Paid or to be Paid | May 12, 2016 |
Partnership Units and Related65
Partnership Units and Related Matters, Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | Apr. 19, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Mar. 31, 2015 |
Partnership Equity [Abstract] | ||||
Number of days from end of each quarter by when cash is distributed to unitholders | 45 days | |||
Distributions declared and/or paid by the Partnership [Abstract] | ||||
Distributions to limited partners common | $ 2.8 | |||
Total distributions to general and limited partners | $ 203.2 | $ 138.1 | ||
Series A Preferred Units [Member] | ||||
Distributions declared and/or paid by the Partnership [Abstract] | ||||
Date of declaration for cash distribution | Apr. 19, 2016 | |||
Payment date for cash distribution | May 16, 2016 | |||
Series A Preferred Units [Member] | Subsequent Event | ||||
Distributions declared and/or paid by the Partnership [Abstract] | ||||
Cash distribution declared per unit (in dollars per share) | $ 0.1875 | |||
Distributions Declared [Member] | ||||
Distributions declared and/or paid by the Partnership [Abstract] | ||||
Date Paid or to be Paid | Feb. 9, 2016 | |||
Distributions to limited partners common | $ 152.5 | |||
Distributions to general partners (incentive) | 43.9 | |||
Distributions to general partners (2%) | 4 | |||
Total distributions to general and limited partners | $ 200.4 | |||
Distributions per limited partner unit (in dollars per unit) | $ 0.8250 |
Derivative Instruments and He66
Derivative Instruments and Hedging Activities (Details) | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2016USD ($)MMBTUbbl | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($) | Feb. 27, 2015USD ($) | |
Derivative [Line Items] | ||||
Fair value of derivative assets | $ | $ 102,100,000 | |||
Estimated fair value of derivative instruments, net asset | $ | $ 97,700,000 | |||
Swaps [Member] | Natural Gas [Member] | Year 2016 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 91,840 | |||
Swaps [Member] | Natural Gas [Member] | Year 2017 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 53,982 | |||
Swaps [Member] | Natural Gas [Member] | Year 2018 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 30,900 | |||
Swaps [Member] | NGL [Member] | Year 2016 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 4,812 | |||
Swaps [Member] | NGL [Member] | Year 2017 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 1,688 | |||
Swaps [Member] | NGL [Member] | Year 2018 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 818 | |||
Swaps [Member] | Condensate [Member] | Year 2016 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 2,375 | |||
Swaps [Member] | Condensate [Member] | Year 2017 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 1,400 | |||
Swaps [Member] | Condensate [Member] | Year 2018 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 900 | |||
Basis Swaps [Member] | Natural Gas [Member] | Year 2016 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 43,309 | |||
Basis Swaps [Member] | Natural Gas [Member] | Year 2017 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 18,082 | |||
Basis Swaps [Member] | Natural Gas [Member] | Year 2018 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 | |||
Options [Member] | Natural Gas [Member] | Year 2016 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 22,900 | |||
Options [Member] | Natural Gas [Member] | Year 2017 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 22,900 | |||
Options [Member] | Natural Gas [Member] | Year 2018 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 9,486 | |||
Options [Member] | NGL [Member] | Year 2016 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 920 | |||
Options [Member] | NGL [Member] | Year 2017 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 920 | |||
Options [Member] | NGL [Member] | Year 2018 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 32 | |||
Options [Member] | Condensate [Member] | Year 2016 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 790 | |||
Options [Member] | Condensate [Member] | Year 2017 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 790 | |||
Options [Member] | Condensate [Member] | Year 2018 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 101 | |||
Future [Member] | NGL [Member] | Year 2016 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 4,331 | |||
Future [Member] | NGL [Member] | Year 2017 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 274 | |||
Future [Member] | NGL [Member] | Year 2018 [Member] | ||||
Derivative [Line Items] | ||||
Notional volumes of commodity hedges (in Bbl per day) | 0 | |||
Atlas Pipeline Partners [Member] | ||||
Derivative [Line Items] | ||||
Fair value of derivative assets | $ | $ 102,100,000 | |||
Fair value of derivative contracts received as component of derivative contract settlement | $ | $ 8,700,000 | $ 67,900,000 | ||
Ineffectiveness gains | $ | $ 1,000,000 | |||
Atlas Pipeline Partners [Member] | Maximum [Member] | ||||
Derivative [Line Items] | ||||
Ineffectiveness gains | $ | $ 100,000 |
Derivative Instruments and He67
Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets | $ 107.6 | $ 127.1 |
Derivative liabilities | 9.9 | 7.6 |
Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 82.4 | 92.2 |
Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 25.2 | 34.9 |
Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 2 | 5.2 |
Long-term Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 7.9 | 2.4 |
Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 107.6 | 127 |
Derivative liabilities | 9.6 | 4.5 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 82.4 | 92.1 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 25.2 | 34.9 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 1.7 | 2.1 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 7.9 | 2.4 |
Not Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 0 | 0.1 |
Derivative liabilities | 0.3 | 3.1 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 0 | 0.1 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | $ 0.3 | $ 3.1 |
Derivative Instruments and He68
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Derivative Asset [Abstract] | ||
Derivative assets | $ 107.6 | $ 127.1 |
Pro forma net presentation, asset, total | 97.9 | 119.5 |
Counterparties with Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 104.6 | 121.1 |
Pro forma net presentation, asset | 94.9 | 113.5 |
Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 3 | 6 |
Pro forma net presentation, asset | 3 | 6 |
Current Position [Member] | ||
Derivative Asset [Abstract] | ||
Derivative assets | 82.4 | 92.2 |
Pro forma net presentation, asset, current | 80.4 | 87 |
Current Position [Member] | Counterparties with Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 79.4 | 86.9 |
Pro forma net presentation, asset | 77.4 | 81.7 |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 3 | 5.3 |
Pro forma net presentation, asset | 3 | 5.3 |
Long-term Position [Member] | ||
Derivative Asset [Abstract] | ||
Derivative assets | 25.2 | 34.9 |
Pro forma net presentation, asset, noncurrent | 17.5 | 32.5 |
Long-term Position [Member] | Counterparties with Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 25.2 | 34.2 |
Pro forma net presentation, asset | 17.5 | 31.8 |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | $ 0 | $ 0.7 |
Derivative Instruments and He69
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Derivative Liability [Abstract] | ||
Gross liability | $ 9.9 | $ 7.6 |
Pro forma net presentation, liability, total | 0.2 | |
Counterparties with Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 9.7 | 7.6 |
Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 0.2 | |
Pro forma net presentation, liability, total | 0.2 | |
Current Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 2 | 5.2 |
Current Position [Member] | Counterparties with Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 2 | 5.2 |
Long-term Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 7.9 | 2.4 |
Pro forma net presentation, liability, noncurrent | 0.2 | |
Long-term Position [Member] | Counterparties with Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 7.7 | $ 2.4 |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 0.2 | |
Pro forma net presentation, liability, noncurrent | $ 0.2 |
Derivative Instruments and He70
Derivative Instruments and Hedging Activities, Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) Reclassified from OCI into Income (Effective Portion) | $ (24.2) | $ (13.2) | ||
Net gains on commodity hedges recorded in OCI that are expected to be reclassified to revenue within twelve months | 58.9 | |||
Revenues [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) Reclassified from OCI into Income (Effective Portion) | (24.2) | (13.2) | ||
Commodity Contracts [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Deferred gains (losses) included in accumulated OCI | [1] | 69.3 | $ 86.8 | |
Commodity Contracts [Member] | Revenues [Member] | Not Designated as Hedging Instrument [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) Recognized in Income on Derivatives | 1.8 | 7.2 | ||
Cash Flow Hedging [Member] | Commodity Contracts [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) | $ 6.7 | $ 30.3 | ||
[1] | Includes deferred net gains of $58.9 million as of March 31, 2016 related to contracts that will be settled and reclassified to revenue over the next 12 months |
Fair Value Measurements, Breakd
Fair Value Measurements, Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 | |
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | |||
Derivatives financial instruments, fair value, net | $ 97.7 | ||
Derivative fair value of net asset if commodity price increases by 10 percent | 68.1 | ||
Derivative fair value of net asset if commodity price decreases by 10 percent | 126 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | 97.9 | $ 119.5 | |
Liabilities from commodity derivative contracts | 0.2 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Accounts receivable securitization facility | 150 | 219.3 | |
Carrying Value [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 104.4 | 127.1 |
Liabilities from commodity derivative contracts | [1] | 6.7 | 7.6 |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 103.3 | 135.4 | |
Accounts receivable securitization facility | 150 | 219.3 | |
Carrying Value [Member] | Senior Secured Revolving Credit Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 280 | ||
Carrying Value [Member] | Targa Pipeline Partners LP [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Contingent consideration | [2] | 3 | 3 |
Carrying Value [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 4,526.9 | 4,884 | |
Fair Value [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 104.4 | 127.1 |
Liabilities from commodity derivative contracts | [1] | 6.7 | 7.6 |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 103.3 | 135.4 | |
Accounts receivable securitization facility | 150 | 219.3 | |
Fair Value [Member] | Senior Secured Revolving Credit Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 280 | ||
Fair Value [Member] | Targa Pipeline Partners LP [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Contingent consideration | [2] | 3 | 3 |
Fair Value [Member] | Level 2 [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 101 | 123.1 |
Liabilities from commodity derivative contracts | [1] | 5.9 | 7.3 |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Accounts receivable securitization facility | 150 | 219.3 | |
Fair Value [Member] | Level 2 [Member] | Senior Secured Revolving Credit Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 280.2 | ||
Fair Value [Member] | Level 3 [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 3.4 | 4 |
Liabilities from commodity derivative contracts | [1] | 0.8 | 0.3 |
Fair Value [Member] | Level 3 [Member] | Targa Pipeline Partners LP [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Contingent consideration | [2] | 3 | 3 |
Fair Value [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 4,357.1 | 4,192 | |
Fair Value [Member] | Senior Unsecured Notes [Member] | Level 2 [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | $ 4,357.1 | $ 4,192 | |
[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] | See Note 4 – Business Acquisitions. |
Fair Value Measurements, Change
Fair Value Measurements, Changes in Fair Value of Financial Instruments Classified as Level 3 (Details) | 3 Months Ended |
Mar. 31, 2016USD ($) | |
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items] | |
Transfers out of Level 3 | $ 0 |
Contingent Liability [Member] | |
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items] | |
Balance, beginning of period | 3,000,000 |
Balance, end of period | 3,000,000 |
Commodity Contracts [Member] | |
Fair Value Net Derivative Asset Liability Measured On Recurring Basis Unobservable Input Reconciliation [Line Items] | |
Balance, beginning of period | 3,700,000 |
New Level 3 instruments | (200,000) |
Settlements included in Revenue | (500,000) |
Unrealized gain/(loss) included in OCI | (400,000) |
Balance, end of period | $ 2,600,000 |
Related Party Transactions - 73
Related Party Transactions - Targa (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Summary of transactions with Targa [Abstract] | ||
Cash contributions from Targa for issuance of common units | $ 785 | $ 0 |
Targa Resources Corp. [Member] | ||
Summary of transactions with Targa [Abstract] | ||
Targa billings of payroll and related costs included in operating expense | 40.2 | 34.9 |
Targa allocation of general and administrative expense | 39.9 | 38.3 |
Cash distributions to Targa based on IDR and unit ownership | 61.4 | 51.6 |
Cash contributions from Targa for issuance of common units | 785 | 0 |
Contributions from Targa Resources Corp. | $ 16 | $ 28.8 |
General partner ownership interest | 2.00% |
Contingencies (Details)
Contingencies (Details) | Jan. 06, 2016PlaintiffLawsuit | Dec. 16, 2015Plaintiff | Jun. 18, 2015USD ($) | Nov. 30, 2014Plaintiff | Dec. 31, 2014Plaintiff |
State Court Lawsuit [Member] | |||||
Loss Contingencies [Line Items] | |||||
Number of plaintiffs | 2 | ||||
Federal Court Lawsuits [Member] | |||||
Loss Contingencies [Line Items] | |||||
Number of plaintiffs | 2 | ||||
Number of putative class action lawsuits filed | Lawsuit | 2 | ||||
Atlas Unitholder Litigation [Member] | Atlas Pipeline Partners [Member] | |||||
Loss Contingencies [Line Items] | |||||
Number of plaintiffs | 5 | ||||
Atlas Unitholder Litigation [Member] | Atlas Energy [Member] | |||||
Loss Contingencies [Line Items] | |||||
Number of plaintiffs | 2 | ||||
Environment Proceeding [Member] | Versado Gas Processors LLC [Member] | |||||
Loss Contingencies [Line Items] | |||||
Ownership interest in joint venture | 63.00% | ||||
Environment Proceeding [Member] | Minimum [Member] | |||||
Loss Contingencies [Line Items] | |||||
Litigation settlement amount | $ | $ 100,000 | ||||
Environment Proceeding [Member] | Maximum [Member] | |||||
Loss Contingencies [Line Items] | |||||
Litigation settlement amount | $ | $ 300,000 |
Supplemental Cash Flow Inform75
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | ||
Cash [Abstract] | |||
Interest paid, net of capitalized interest | [1] | $ 77.3 | $ 28.9 |
Income taxes paid, net of refunds | 1.1 | 0.1 | |
Non-cash investing activities [Abstract] | |||
Deadstock commodity inventory transferred to property, plant and equipment | 16.9 | 0 | |
Impact of capital expenditure accruals on property, plant and equipment | 13.7 | 30.9 | |
Transfers from materials and supplies inventory to property, plant and equipment | 0.5 | 0.6 | |
Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate | (9.1) | 3.7 | |
Non-cash financing activities [Abstract] | |||
Cancellation of Treasury stock | (10.2) | 0 | |
Accrued distributions on unvested equity awards under share compensation arrangements | 0.2 | 0 | |
Receivables from equity issuances | 0 | 24.6 | |
Non-cash balance sheet movements related to Atlas Merger: (See Note 4 - Business Acquisitions) [Abstract] | |||
Non-cash merger consideration - common units and replacement equity awards | 0 | 2,583.5 | |
Special GP Interest | 0 | 1,612.4 | |
Current liabilities retained by Targa | 0 | (0.4) | |
Net non-cash balance sheet movements excluded from consolidated statements of cash flows | 0 | 4,195.5 | |
Net cash merger consideration included in investing activities | 0 | 828.7 | |
Total fair value of consideration transferred | 0 | 5,024.2 | |
Interest capitalized on major projects | $ 4.8 | $ 2.4 | |
[1] | Interest capitalized on major projects was $4.8 million and $2.4 million for the three months ended March 31, 2016 and March 31, 2015. |
Segment Information, Revenues a
Segment Information, Revenues and Operating Margin (Details) $ in Millions | 3 Months Ended | |
Mar. 31, 2016USD ($)Segment | Mar. 31, 2015USD ($) | |
Segment Reporting Information [Line Items] | ||
Number of segments | Segment | 2 | |
Revenues [Abstract] | ||
Sales of commodities | $ 1,171 | $ 1,402.2 |
Fees from midstream services | 271.4 | 277.5 |
Revenues | 1,442.4 | 1,679.7 |
Operating margin | 299.4 | 300 |
Operating Segments [Member] | ||
Revenues [Abstract] | ||
Sales of commodities | 1,171 | 1,402.2 |
Fees from midstream services | 271.4 | 277.5 |
Revenues | $ 1,442.4 | 1,679.7 |
Gathering and Processing [Member] | ||
Segment Reporting Information [Line Items] | ||
Number of reportable segments per division | Segment | 2 | |
Revenues [Abstract] | ||
Revenues | $ 640.8 | 573 |
Operating margin | 115.6 | 87 |
Gathering and Processing [Member] | Operating Segments [Member] | ||
Revenues [Abstract] | ||
Sales of commodities | 110.3 | 220.9 |
Fees from midstream services | 115.8 | 72 |
Revenues | 226.1 | 292.9 |
Gathering and Processing [Member] | Intersegment Eliminations [Member] | ||
Revenues [Abstract] | ||
Sales of commodities | 412.6 | 278.1 |
Fees from midstream services | 2.1 | 2 |
Revenues | $ 414.7 | 280.1 |
Logistics and Marketing [Member] | ||
Segment Reporting Information [Line Items] | ||
Number of reportable segments per division | Segment | 2 | |
Revenues [Abstract] | ||
Revenues | $ 1,240.9 | 1,425.5 |
Operating margin | 157 | 191.3 |
Logistics and Marketing [Member] | Operating Segments [Member] | ||
Revenues [Abstract] | ||
Sales of commodities | 1,033.9 | 1,159.7 |
Fees from midstream services | 155.6 | 205.4 |
Revenues | 1,189.5 | 1,365.1 |
Logistics and Marketing [Member] | Intersegment Eliminations [Member] | ||
Revenues [Abstract] | ||
Sales of commodities | 47.3 | 55.9 |
Fees from midstream services | 4.1 | 4.5 |
Revenues | 51.4 | 60.4 |
Other [Member] | ||
Revenues [Abstract] | ||
Revenues | 26.8 | 21.7 |
Operating margin | 26.8 | 21.7 |
Other [Member] | Operating Segments [Member] | ||
Revenues [Abstract] | ||
Sales of commodities | 26.8 | 21.7 |
Revenues | 26.8 | 21.7 |
Corporate and Elimination [Member] | ||
Revenues [Abstract] | ||
Revenues | (466.1) | (340.5) |
Corporate and Elimination [Member] | Operating Segments [Member] | ||
Revenues [Abstract] | ||
Sales of commodities | (0.1) | |
Fees from midstream services | 0.1 | |
Corporate and Elimination [Member] | Intersegment Eliminations [Member] | ||
Revenues [Abstract] | ||
Sales of commodities | (459.9) | (334) |
Fees from midstream services | (6.2) | (6.5) |
Revenues | $ (466.1) | $ (340.5) |
Segment Information, Other Fina
Segment Information, Other Financial Information (Details) - USD ($) $ in Millions | 3 Months Ended | |||||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | Feb. 27, 2015 | Dec. 31, 2014 | ||
Other financial information [Abstract] | ||||||
Total assets | $ 12,868.6 | $ 13,126.8 | ||||
Goodwill | 393 | $ 417 | $ 707 | $ 0 | ||
Business acquisition | $ 5,024.2 | |||||
Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 12,868.6 | $ 13,190.8 | |||
Goodwill | [2] | 393 | 557.9 | |||
Capital expenditures | 176.9 | 157.3 | ||||
Business acquisition | 5,024.2 | |||||
Gathering and Processing [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 10,219 | 10,671.8 | |||
Goodwill | [2] | 393 | 557.9 | |||
Capital expenditures | 103 | 95.5 | ||||
Business acquisition | 5,024.2 | |||||
Logistics Assets And Marketing | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 2,501 | 2,302.5 | |||
Capital expenditures | 73.1 | 60.7 | ||||
Other [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 105.7 | 177.3 | |||
Corporate and Elimination [Member] | Operating Segments [Member] | ||||||
Other financial information [Abstract] | ||||||
Total assets | [1] | 42.9 | 39.2 | |||
Capital expenditures | $ 0.8 | $ 1.1 | ||||
[1] | Corporate assets at the Segment level primarily include tax-related assets, cash and prepaids. | |||||
[2] | Total assets include goodwill. Goodwill has been attributed to our Gathering and Processing segment. |
Segment Information, Revenues b
Segment Information, Revenues by Product and Service (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Revenue from External Customer [Line Items] | ||
Sales of commodities | $ 1,171 | $ 1,402.2 |
Fees from midstream services | 271.4 | 277.5 |
Total revenues | 1,442.4 | 1,679.7 |
Natural Gas [Member] | ||
Revenue from External Customer [Line Items] | ||
Sales of commodities | 326.9 | 302.1 |
NGL [Member] | ||
Revenue from External Customer [Line Items] | ||
Sales of commodities | 785.5 | 1,030.7 |
Condensate [Member] | ||
Revenue from External Customer [Line Items] | ||
Sales of commodities | 22.2 | 21.3 |
Petroleum Products [Member] | ||
Revenue from External Customer [Line Items] | ||
Sales of commodities | 9.6 | 26.4 |
Derivative Activities [Member] | ||
Revenue from External Customer [Line Items] | ||
Sales of commodities | 26.8 | 21.7 |
Fractionating and Treating [Member] | ||
Revenue from External Customer [Line Items] | ||
Fees from midstream services | 30.2 | 49.8 |
Storage, Terminaling, Transportation and Export [Member] | ||
Revenue from External Customer [Line Items] | ||
Fees from midstream services | 118.4 | 136.2 |
Gathering and Processing [Member] | ||
Revenue from External Customer [Line Items] | ||
Fees from midstream services | 105 | 68.4 |
Other [Member] | ||
Revenue from External Customer [Line Items] | ||
Fees from midstream services | $ 17.8 | $ 23.1 |
Segment Information, Reconcilia
Segment Information, Reconciliation of Operating Margin to Net Income (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2016 | Dec. 31, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | |
Reconciliation of operating margin to net income (loss) [Abstract] | ||||
Operating margin | $ 299.4 | $ 300 | ||
Depreciation and amortization expense | (193.5) | (118.6) | ||
General and administrative expense | (43.4) | (40.2) | ||
Impairment | (24) | $ (290) | 0 | $ (290) |
Interest expense, net | (46.9) | (50) | ||
Other, net | 18.8 | (12.3) | ||
Income tax (expense) benefit | 0.2 | (1.1) | ||
Net income (loss) | $ 10.6 | $ 77.8 |