Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2015 | Jul. 31, 2015 | |
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 Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q2 | |
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2015 | |
Limited Partner Interest [Member] | ||
Entity Information [Line Items] | ||
Entity Common Stock, Shares Outstanding | 184,838,099 | |
General Partner Units [Member] | ||
Entity Information [Line Items] | ||
Entity Common Stock, Shares Outstanding | 3,772,206 |
CONSOLIDATED BALANCE SHEETS (Un
CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 | |
Current assets: | |||
Cash and cash equivalents | $ 85.5 | $ 72.3 | |
Trade receivables, net of allowances of $0.0 million | 602 | 566.8 | |
Inventories | 124.8 | 168.9 | |
Assets from risk management activities | 91.8 | 44.4 | |
Other current assets | 5.2 | 3.8 | |
Total current assets | 909.3 | 856.2 | |
Property, plant and equipment | 11,595.2 | 6,514.3 | |
Accumulated depreciation | (1,910.9) | (1,689.7) | |
Property, plant and equipment, net | 9,684.3 | 4,824.6 | |
Goodwill | 557.9 | [1] | 0 |
Intangible assets, net | 1,735.6 | 591.9 | |
Long-term assets from risk management activities | 40.3 | 15.8 | |
Investments in unconsolidated affiliates | 258 | 50.2 | |
Other long-term assets | 52.2 | 38.5 | |
Total assets | 13,237.6 | [2] | 6,377.2 |
Current liabilities: | |||
Accounts payable and accrued liabilities | 652.7 | 592.7 | |
Accounts payable to Targa Resources Corp. | 31.7 | 53.2 | |
Accounts receivable securitization facility | 124.2 | 182.8 | |
Liabilities from risk management activities | 1.9 | 5.2 | |
Total current liabilities | 810.5 | 833.9 | |
Long-term debt | 5,178.8 | 2,783.4 | |
Long-term liabilities from risk management activities | 5.3 | 0 | |
Deferred income taxes, net | 22.7 | 13.7 | |
Other long-term liabilities | $ 73 | $ 57.8 | |
Contingencies (see Note 16) | |||
Owners' equity: | |||
Limited partners (184,214,062 and 118,652,798 common units issued and 184,097,560 and 118,586,056 common units outstanding as of June 30, 2015 and December 31, 2014, respectively) | $ 5,055.3 | $ 2,384.1 | |
General partner (3,757,093 and 2,420,124 units issued and outstanding as of June 30, 2015 and December 31, 2014, respectively) | 1,750 | 78.6 | |
Receivables from unit issuances | (0.9) | (1) | |
Accumulated other comprehensive income (loss) | 52.4 | 60.3 | |
Treasury units at cost (116,502 units as of June 30, 2015, and 66,742 as of December 31, 2014) | (6.9) | (4.8) | |
Partners' Capital | 6,849.9 | 2,517.2 | |
Noncontrolling interests in subsidiaries | 297.4 | 171.2 | |
Total owners' equity | 7,147.3 | 2,688.4 | |
Total liabilities and owners' equity | $ 13,237.6 | $ 6,377.2 | |
[1] | Total assets include goodwill. | ||
[2] | Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our debt obligations. |
CONSOLIDATED BALANCE SHEETS (U3
CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Current assets: | ||
Allowance for receivables | $ 0 | $ 0 |
Owners' equity: | ||
Limited partners common units issued (in units) | 184,214,062 | 118,652,798 |
Limited partners common units outstanding (in units) | 184,097,560 | 118,586,056 |
General partner units issued (in units) | 3,757,093 | 2,420,124 |
General partner units outstanding (in units) | 3,757,093 | 2,420,124 |
Treasury units at cost (in units) | 116,502 | 66,742 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |||
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) [Abstract] | ||||||
Revenues | $ 1,699.4 | $ 2,000.6 | $ 3,379.1 | $ 4,295.3 | ||
Costs and expenses: | ||||||
Product purchases | 1,237 | 1,616.6 | 2,505.3 | 3,531.7 | ||
Operating expenses | 136.9 | 106.6 | 248.2 | 210.9 | ||
Depreciation and amortization expenses | 163.9 | 85.8 | 282.5 | 165.3 | ||
General and administrative expenses | 46.8 | 39.1 | 87.1 | 74.8 | ||
Other operating (income) expense | 0 | (0.4) | 0.5 | (1) | ||
Income from operations | 114.8 | 152.9 | 255.5 | 313.6 | ||
Other income (expense): | ||||||
Interest expense, net | (62.2) | (34.9) | (113.1) | (68.1) | ||
Equity earnings (loss) | (1.5) | 4.2 | 0.5 | [1] | 9.1 | |
Other | 1.9 | 0 | (11) | 0 | ||
Income before income taxes | 53 | 122.2 | 131.9 | 254.6 | ||
Income tax (expense) benefit: | ||||||
Current | 0 | (1) | (0.5) | (1.7) | ||
Deferred | 0.3 | (0.3) | (0.3) | (0.7) | ||
Total Income tax (expense) benefit | 0.3 | (1.3) | (0.8) | (2.4) | ||
Net income | 53.3 | 120.9 | 131.1 | 252.2 | ||
Less: Net income attributable to noncontrolling interests | 7.5 | 12.1 | 12.5 | 21 | ||
Net income attributable to Targa Resources Partners LP | 45.8 | 108.8 | 118.6 | 231.2 | ||
Net income attributable to general partner | 44.6 | 35.8 | 87.1 | 69.6 | ||
Net income attributable to limited partners | 1.2 | 73 | 31.5 | 161.6 | ||
Net income attributable to Targa Resources Partners LP | $ 45.8 | $ 108.8 | $ 118.6 | $ 231.2 | ||
Net income per limited partner unit - basic (in dollars per share) | $ 0.01 | $ 0.64 | $ 0.20 | $ 1.43 | ||
Net income per limited partner unit - diluted (in dollars per share) | $ 0.01 | $ 0.64 | $ 0.20 | $ 1.42 | ||
Weighted average limited partner units outstanding - basic (in shares) | 181.9 | 114.2 | 159.7 | 113.3 | ||
Weighted average limited partner units outstanding - diluted (in shares) | [2] | 182.6 | 114.9 | 160.1 | 113.9 | |
[1] | Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015, including the amortization of a basis difference resulting from acquisition date fair value accounting. | |||||
[2] | For the three and six months ended June 30, 2015, approximately 173,125 units and 180,413 units were excluded from the computation of diluted earnings per unit because the inclusion of such units would have been anti-dilutive. |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) [Abstract] | ||||
Net income | $ 53.3 | $ 120.9 | $ 131.1 | $ 252.2 |
Commodity hedging contracts: | ||||
Change in fair value | (8.7) | (6.8) | 16.5 | (18.6) |
Settlements reclassified to revenues | (16.3) | 4.5 | (24.4) | 10.8 |
Interest rate swaps: | ||||
Settlements reclassified to interest expense, net | 0 | 1.1 | 0 | 2.4 |
Other comprehensive income (loss) | (25) | (1.2) | (7.9) | (5.4) |
Comprehensive income (loss) | 28.3 | 119.7 | 123.2 | 246.8 |
Less: Comprehensive income attributable to noncontrolling interests | 7.5 | 12.1 | 12.5 | 21 |
Comprehensive income attributable to Targa Resources Partners LP | $ 20.8 | $ 107.6 | $ 110.7 | $ 225.8 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY (Unaudited) - USD ($) $ in Millions | Limited Partners Common [Member] | General Partner [Member] | Receivables From Unit Issuances [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Treasury Units [Member] | Non-controlling Interests [Member] | Total |
Balance at Dec. 31, 2013 | $ 2,001.9 | $ 62 | $ 0 | $ (6.1) | $ 0 | $ 160.6 | $ 2,218.4 |
Balance (in units) at Dec. 31, 2013 | 111,263,000 | 2,271,000 | 0 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Compensation on equity grants | $ 4.9 | $ 0 | 0 | 0 | $ 0 | 0 | 4.9 |
Compensation on equity grants (in units) | 215,000 | 0 | 0 | ||||
Accrual of distribution equivalent rights | $ (1.4) | $ 0 | 0 | 0 | $ 0 | 0 | (1.4) |
Equity offerings | $ 163 | $ 0 | 0 | 0 | $ 0 | 0 | 163 |
Equity offerings (in units) | 3,025,000 | 0 | 0 | ||||
Contributions from Targa Resources Corp. | $ 3.7 | (0.3) | 0 | $ 0 | 0 | 3.4 | |
Contributions from Targa Resources Corp. (in units) | 66,000 | 0 | |||||
Distributions to noncontrolling interests | $ 0 | $ 0 | 0 | 0 | $ 0 | (17.2) | (17.2) |
Other comprehensive income (loss) | 0 | 0 | 0 | (5.4) | 0 | 0 | (5.4) |
Net income | 161.6 | 69.6 | 0 | 0 | 0 | 21 | 252.2 |
Distributions | (171.2) | (65.9) | 0 | 0 | 0 | 0 | (237.1) |
Balance at Jun. 30, 2014 | $ 2,158.8 | $ 69.4 | (0.3) | (11.5) | $ 0 | 164.4 | 2,380.8 |
Balance (in units) at Jun. 30, 2014 | 114,503,000 | 2,337,000 | 0 | ||||
Balance at Dec. 31, 2014 | $ 2,384.1 | $ 78.6 | (1) | 60.3 | $ (4.8) | 171.2 | 2,688.4 |
Balance (in units) at Dec. 31, 2014 | 118,586,000 | 2,420,000 | 67,000 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Compensation on equity grants | $ 8.9 | $ 0 | 0 | 0 | $ 0 | 0 | 8.9 |
Compensation on equity grants (in units) | 0 | 0 | 0 | ||||
Accrual of distribution equivalent rights | $ (0.7) | $ 0 | 0 | 0 | $ 0 | 0 | (0.7) |
Issuance of common units under compensation program | $ 0 | $ 0 | 0 | 0 | $ 0 | 0 | 0 |
Issuance of common units under compensation program (in units) | 134,000 | 0 | 0 | ||||
Units tendered for tax withholding obligations | $ 0 | $ 0 | 0 | 0 | $ (2.1) | 0 | (2.1) |
Units tendered for tax withholding obligations (in units) | (50,000) | 0 | 50,000 | ||||
Equity offerings | $ 293.4 | $ 0 | 0 | 0 | $ 0 | 0 | 293.4 |
Equity offerings (in units) | 6,813,000 | 0 | 0 | ||||
Issuance of units for acquisition | $ 2,583.1 | $ 0 | 0 | 0 | $ 0 | 113.4 | 2,696.5 |
Issuance of units for acquisition (in units) | 58,614,000 | 0 | 0 | ||||
Contributions from Targa Resources Corp. | $ 0 | $ 58.6 | 0.1 | 0 | $ 0 | 0 | 58.7 |
Contributions from Targa Resources Corp. (in units) | 0 | 1,337,000 | 0 | ||||
Distributions to noncontrolling interests | $ 0 | $ 0 | 0 | 0 | $ 0 | (5.6) | (5.6) |
Contribution from noncontrolling interests | 0 | 0 | 0 | 0 | 0 | 5.9 | 5.9 |
Other comprehensive income (loss) | 0 | 0 | 0 | (7.9) | 0 | 0 | (7.9) |
Net income | 31.5 | 87.1 | 0 | 0 | 0 | 12.5 | 131.1 |
Distributions | (245) | (86.7) | 0 | 0 | 0 | 0 | (331.7) |
Targa contribution - Special General Partner Interest (see Note 2) | 0 | 1,612.4 | 0 | 0 | 0 | 0 | 1,612.4 |
Balance at Jun. 30, 2015 | $ 5,055.3 | $ 1,750 | $ (0.9) | $ 52.4 | $ (6.9) | $ 297.4 | $ 7,147.3 |
Balance (in units) at Jun. 30, 2015 | 184,098,000 | 3,757,000 | 117,000 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | ||
Cash flows from operating activities | |||
Net income | $ 131.1 | $ 252.2 | |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Amortization in interest expense | 6 | 6.7 | |
Compensation on equity grants | 8.9 | 4.9 | |
Depreciation and amortization expense | 282.5 | 165.3 | |
Accretion of asset retirement obligations | 2.6 | 2.2 | |
Deferred income tax expense (benefit) | 0.3 | 0.7 | |
Equity earnings of unconsolidated affiliates | (0.5) | [1] | (9.1) |
Distributions received from unconsolidated affiliates | 6.9 | 9.1 | |
Risk management activities | 31.5 | (0.7) | |
(Gain) loss on sale or disposition of assets | (0.2) | (1.2) | |
Changes in operating assets and liabilities, net of business acquisitions: | |||
Receivables and other assets | 146.5 | (23) | |
Inventory | 58.1 | (18.1) | |
Accounts payable and other liabilities | (151.4) | 67.8 | |
Net cash provided by operating activities | 522.3 | 456.8 | |
Cash flows from investing activities | |||
Outlays for property, plant and equipment | (436.2) | (419.6) | |
Business acquisition, net of cash acquired | (828.7) | 0 | |
Return of capital from unconsolidated affiliate | 0.1 | 3.6 | |
Other, net | (1.3) | 2.3 | |
Net cash used in investing activities | (1,266.1) | (413.7) | |
Cash flows from financing activities | |||
Proceeds from borrowings under credit facility | 1,343 | 950 | |
Repayments of credit facility | (465) | (850) | |
Borrowings from accounts receivable securitization facility | 253.4 | 67.8 | |
Repayments of accounts receivable securitization facility | (312) | (113.2) | |
Proceeds from issuance of senior notes | 1,100 | 0 | |
Redemption of APL senior notes | (1,168.8) | 0 | |
Costs in connection with financing arrangements | (14.6) | (1.7) | |
Proceeds from sale of common units | 295.8 | 168.1 | |
Repurchase of common units under compensation plans | (2.1) | 0 | |
Contributions received from General Partner | 58.7 | 0 | |
Contributions received from noncontrolling interests | 5.9 | 0 | |
Distributions paid to unitholders | (331.7) | (237.1) | |
Distributions paid to noncontrolling interests | (5.6) | (17.2) | |
Net cash provided by (used in) financing activities | 757 | (33.3) | |
Net change in cash and cash equivalents | 13.2 | 9.8 | |
Cash and cash equivalents, beginning of period | 72.3 | 57.5 | |
Cash and cash equivalents, end of period | $ 85.5 | $ 67.3 | |
[1] | Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015, including the amortization of a basis difference resulting from acquisition date fair value accounting. |
Organization and Operations
Organization and Operations | 6 Months Ended |
Jun. 30, 2015 | |
Organization and Operations [Abstract] | |
Organization and Operations | Note 1 — Organization and Operations Our Organization Targa Resources Partners LP is a publicly traded Delaware limited partnership formed in October 2006 by Targa. Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange under the symbol “NGLS.” 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. Targa Resources GP LLC is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa. As of June 30, 2015, Targa owned a 10.7% interest in us in the form of 3,757,093 general partner units and 16,309,594 common units. In addition, Targa Resources GP LLC also owns our incentive distribution rights (“IDRs”), which entitle it to receive increasing cash distributions up to 48% of distributable cash for a quarter, exclusive of amounts reallocated to common unit-holders under the IDR Giveback Amendment (see Note 11-Partnership Units and Related Matters). In connection with the Atlas mergers (see Note 4 – Business Acquisitions), our partnership agreement was amended to provide for the issuance of a special general partner interest (“the Special GP Interest”) representing a capital account credit equal to the consideration paid by Targa for and resulting tax basis in the Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL (“APL GP”) acquired in the ATLS merger (see Note 4 – Business Acquisitions). 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 . Allocation of costs 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 centralized general and administrative services. 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 18-Segment Information for certain financial information for our business segments. |
Basis of Presentation
Basis of Presentation | 6 Months Ended |
Jun. 30, 2015 | |
Basis of Presentation [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. The February 27, 2015 Atlas mergers involved two separate legal transactions involving different groups of unitholders. 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 1, 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. The unaudited consolidated financial statements for the three and six months ended June 30, 2015 and 2014 include all adjustments that we believe are necessary for a fair presentation of the results for interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation. Our financial results for the three and six months ended June 30, 2015 |
Significant Accounting Policies
Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2015 | |
Significant 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 of the Notes to Consolidated Financial Statements in our Annual Report. We have updated our policies during the six months ended June 30, 2015 to include our accounting policy for goodwill related to the Atlas mergers. Goodwill results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Impairment testing for goodwill is performed at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (also known as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available, and segment management regularly reviews the operating results of that component. We evaluate goodwill for impairment at least annually, as of November 30 th Recent Accounting Pronouncements In February 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 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 July 2015, the FASB issued ASU 2015-11, Inventory (Topic 303): Simplifying the Measurement of Inventory. Topic 303 currently requires inventory to be measured at the lower of cost or market, where market could be replacement cost, net realizable value or net realizable value less a normal profit margin. The amendments in this update require that all inventory, excluding inventory that is measured using the last-in, first-out method or the retail inventory method, be measured at the lower of cost or net realizable value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments are effective for us in 2017, with early adoption permitted, and should be applied prospectively. We anticipate adopting the amendments on January 1, 2017, which will not have a material effect on our consolidated financial statements or results of operations. |
Business Acquisitions
Business Acquisitions | 6 Months Ended |
Jun. 30, 2015 | |
Business Acquisitions [Abstract] | |
Business Acquisitions | Note 4 –Business Acquisitions 2015 Acquisition Atlas Mergers On February 27, 2015, (i) 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 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, our 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 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. 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”). 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 add TPL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing operations. In total, 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 Considerations, 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. While these were two separate legal transactions involving different groups of unitholders, 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. 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 (the “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. Pro forma Impact of Atlas Mergers on Consolidated Statements of Operations The acquired business contributed revenues of $616.8 million and net income of $17.8 million to us for the period from February 27, 2015 to June 30, 2015, and is reported in our Field Gathering and Processing segment. The following summarized unaudited pro forma consolidated statement of operations information for the six months ended June 30, 2015 and June 30, 2014 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. Pro Forma Results for the Six Months Ended June 30, 2015 June 30, 2014 Revenues $ 3,667.8 $ 5,647.6 Net income 124.2 267.1 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 our preliminary estimate of 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 our preliminary estimate of 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 APL businesses sold during the periods: (1) the May 2014 sale of APL’s 20% interest in West Texas LPG Pipeline Limited Partnership and (2) the February 2015 transfer to Atlas Resource Partners, L.P. of 100% of APL’s interest in gas gathering assets located in the Appalachian Basin of Tennessee. · Exclude $14.3 million of acquisition-related costs incurred in 2015 from pro forma net income for the six months ended June 30, 2015. Pro forma net income for the six months ended June 30, 2014 was adjusted to include these charges. · Conform to our accounting policy, we also adjusted TPL’s revenues to report plant sales of Y-grade at contractual net-back values rather than grossed up for transportation and fractionation deduction factors. 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 Value of Consideration Transferred by Targa for ATLS: Cash, 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, 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. Targa also received $7.3 million in April 2015 as part of the Atlas mergers, representing the one-time cash payment from us for the APL common units owned by ATLS. (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. As of February 27, 2015, our preliminary fair value determination related to the Atlas mergers was as follows. The excess of the purchase price over the estimated fair value of net assets acquired was approximately $557.9 million, which was recorded as goodwill. This determination is based on our preliminary valuation and is subject to revisions pending the completion of the valuation and other adjustments. Preliminary fair value determination: February 27, 2015 Trade and other current receivables, net $ 181.1 Other current assets 25.1 Assets from risk management activities 102.1 Property, plant and equipment 4,693.2 Investments in unconsolidated affiliates 214.2 Intangible assets 1,204.0 Other long-term assets 6.6 Current liabilities (255.1 ) Long-term debt (1,573.3 ) Deferred income tax liabilities, net (8.6 ) Other long-term liabilities (9.1 ) Total identifiable net assets 4,580.2 Noncontrolling interest in subsidiaries (113.4 ) Current liabilities retained by Targa (0.5 ) Goodwill 557.9 $ 5,024.2 Our valuation of the acquired assets and liabilities is ongoing and may result in future measurement period adjustments to these preliminary fair values. The fair values of property, plant and equipment, investments in unconsolidated affiliates, intangible assets representing the GP interest, IDRs, customer contracts and customer relationships, deferred income taxes related to APL Arkoma, Inc., a taxable subsidiary acquired, and noncontrolling interest, which is calculated as a proportionate share of the fair value of the acquired joint ventures’ net assets, are preliminary pending completion of final valuations. As a result, goodwill is also preliminary, as it has been recorded as the excess of the purchase price over the estimated fair value of net assets acquired. During the three months ended June 30, 2015, we recorded measurement period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. As a result, the statement of operations for the three months ended March 31, 2015 has been retrospectively adjusted for the impact of measurement period adjustments to property, plant and equipment, intangible assets, and investment 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 three months ended March 31, 2015. The preliminary valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 14 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation. The preliminary determination of goodwill of $557.9 million 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 attribution of the goodwill to reporting units for the purpose of required future impairment assessments will be completed in conjunction with our finalization of the fair value determination. 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. See Note 10-Debt Obligations for additional disclosures regarding related financing activities associated with the Atlas mergers. 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 a decrease in the acquisition date fair value from $6.0 million to $4.2 million. Any future changes 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”). 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 future compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award. |
Inventories
Inventories | 6 Months Ended |
Jun. 30, 2015 | |
Inventories [Abstract] | |
Inventories | Note 5 — Inventories June 30, 2015 December 31, 2014 Commodities $ 112.7 $ 157.4 Materials and supplies 12.1 11.5 $ 124.8 $ 168.9 |
Property, Plant and Equipment a
Property, Plant and Equipment and Intangible Assets | 6 Months Ended |
Jun. 30, 2015 | |
Property, Plant and Equipment and Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | Note 6 — Property, Plant and Equipment and Intangible Assets June 30, 2015 December 31, 2014 Estimated useful life Gathering systems $ 6,052.6 $ 2,588.6 5 to 40 Processing and fractionation facilities 2,976.1 1,884.1 5 to 40 Terminaling and storage facilities 1,090.0 1,038.9 5 to 25 Transportation assets 438.7 359.0 10 to 25 Other property, plant and equipment 209.8 149.1 3 to 40 Land 102.6 95.6 - Construction in progress 725.4 399.0 - Property, plant and equipment 11,595.2 6,514.3 Accumulated depreciation (1,910.9 ) (1,689.7 ) Property, plant and equipment, net $ 9,684.3 $ 4,824.6 Intangible assets $ 1,885.6 $ 681.8 20 Accumulated amortization (150.0 ) (89.9 ) Intangible assets, net $ 1,735.6 $ 591.9 Intangible assets consist of customer contracts and customer relationships acquired in the Atlas mergers and our Badlands business acquisition. 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 preliminary value of $1,204.0 million pending completion of final valuations. For the purpose of our preparing the accompanying financial statements (which includes four months of amortization of these intangible assets) we have amortized these intangible assets over a 20 year life using a straight-line method. The amortization method and lives for the Atlas mergers intangible assets will be reviewed and possibly revised as we finalize the valuations over the upcoming months. 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. The estimated annual amortization expense for intangible assets, including the preliminary Atlas valuation and straight-line treatment is approximately $130.1 million, $148.3 million, $141.5 million, $127.8 million and $116.8 million for each of the years 2015 through 2019. |
Asset Retirement Obligations
Asset Retirement Obligations | 6 Months Ended |
Jun. 30, 2015 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | Note 7 — 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: Six Months Ended June 30, 2015 Beginning of period $ 56.8 Preliminary fair value of ARO acquired with the APL merger 4.0 Change in cash flow estimate 3.8 Accretion expense 2.6 End of period $ 67.2 |
Investments in Unconsolidated A
Investments in Unconsolidated Affiliates | 6 Months Ended |
Jun. 30, 2015 | |
Investments in Unconsolidated Affiliates [Abstract] | |
Investments in Unconsolidated Affiliates | Note 8 — Investments in Unconsolidated Affiliates Our unconsolidated investments consisted of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and . The following table shows the activity related to our investments in unconsolidated affiliates: Six Months Ended June 30, 2015 Beginning of period $ 50.2 Preliminary fair value of T2 Joint Ventures acquired 214.2 Equity earnings (1) 0.5 Cash distributions (2) (7.0 ) Cash calls for expansion projects 0.1 End of period $ 258.0 (1) Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015, including the amortization of a basis difference resulting from acquisition date fair value accounting. (2) Includes $0.1 million distributions received in excess of our share of cumulative earnings for the six months ended June 30, 2015. 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 investment is based on preliminary fair values at the date of acquisition which results in an excess fair value of $39.6 million over the book value of our partner capital accounts. This basis difference is attributable to depreciable tangible assets and is being amortized over the preliminary 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 preliminary fair value determinations related to the Atlas mergers. |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 6 Months Ended |
Jun. 30, 2015 | |
Accounts Payable and Accrued Liabilities [Abstract] | |
Accounts Payable and Accrued Liabilities | Note 9 — June 30, 2015 December 31, 2014 Commodities $ 402.5 $ 416.7 Other goods and services 105.9 108.9 Interest 63.3 37.3 Compensation and benefits 1.8 1.3 Income and other taxes 31.6 13.6 Other 47.6 14.9 $ 652.7 $ 592.7 |
Debt Obligations
Debt Obligations | 6 Months Ended |
Jun. 30, 2015 | |
Debt Obligations [Abstract] | |
Debt Obligations | Note 10 — Debt Obligations June 30, 2015 December 31, 2014 Current: Accounts receivable securitization facility, due December 2015 $ 124.2 $ 182.8 Long-term: Senior secured revolving credit facility, variable rate, due October 2017 (1) 878.0 - Senior unsecured notes, 5% fixed rate, due January 2018 1,100.0 - Senior unsecured notes, 6 ⅞ 483.6 483.6 Unamortized discount (23.8 ) (25.2 ) Senior unsecured notes, 6 ⅝ 342.1 - Unamortized premium 5.4 - Senior unsecured notes, 6 ⅜ 300.0 300.0 Senior unsecured notes, 5 ¼ 600.0 600.0 Senior unsecured notes, 4¼% fixed rate, due November 2023 625.0 625.0 Senior unsecured notes, 4 ⅛ 800.0 800.0 Senior unsecured notes, 6 ⅝ 13.1 - Unamortized premium 0.2 - Senior unsecured notes, 4¾% fixed rate, due November 2021 (3) 6.5 - Senior unsecured notes, 5⅞% fixed rate, due August 2023 (3) 48.1 - Unamortized premium 0.6 - Total long-term debt 5,178.8 2,783.4 Total debt $ 5,303.0 $ 2,966.2 Letters of credit outstanding $ 20.5 $ 44.1 (1) As of , availability under our $1.6 billion senior secured revolving credit facility was $701.5 million. (2) In May 2015, we exchanged the TRP 6⅝% Senior Notes with the same economic terms to the holders of the 2020 APL Notes (as defined below) who validly tendered such notes for exchange to us. (3) Senior unsecured notes issued by APL entities and acquired in the Atlas mergers. While we consolidate the debt acquired in the Atlas mergers, we do not guarantee the acquired debt of APL. The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the six months ended Range of Interest Rates Incurred Weighted Average Interest Rate Incurred Senior secured revolving credit facility 1.9% - 4.3 % 2.0 % Accounts receivable securitization facility 0.9 % 0.9 % Compliance with Debt Covenants As of June 30, 2015, we were in compliance with the covenants contained in our various debt agreements. Financing Activities Revolving Credit Agreement In February 2015, we entered into the First Amendment, Waiver and Incremental Commitment Agreement (the “First Amendment”) that amended our Second Amended and Restated Credit Agreement (the “Original Agreement”). The First Amendment increased available commitments to $1.6 billion from $1.2 billion while retaining our ability to request up to an additional $300.0 million in commitment increases. In addition, the First Amendment amends certain provisions of the Original Agreement and designates each of APL and its subsidiaries as an “Unrestricted Subsidiary.” We used proceeds from borrowings under the credit facility to fund some of the cash components of the APL merger, including $701.4 million for the repayments of the APL Revolver and $28.8 million related to change of control payments. Senior Unsecured Notes In January 2015, we issued $1. ender Offers . The otes are unsecured senior obligations that have substantially the same terms and covenants as our other senior notes. April 2015 Shelf In April 2015, we filed with the SEC a universal shelf registration statement that allows us to issue up to an aggregate of $1.0 billion of debt or equity securities (the "April 2015 Shelf"). The April 2015 Shelf expires in April 2018. APL Merger Financing Activities APL Senior Notes Tender Offers In January 2015, we commenced cash tender offers for any and all of the outstanding fixed rate senior notes to be acquired in the APL merger, referred to as the APL Notes Tender Offers, which totaled $1.55 billion. The results of the APL Notes Tender Offers were: Senior Notes Outstanding Note Balance Amount Tendered Premium Paid Accrued Interest Paid Total Tender Offer payments % Tendered Note Balance after Tender Offers ($ amounts in millions) 6⅝% due 2020 $ 500.0 $ 140.1 $ 2.1 $ 3.7 $ 145.9 28.02 % $ 359.9 4¾% due 2021 400.0 393.5 5.9 5.3 404.7 98.38 % 6.5 5⅞% due 2023 650.0 601.9 8.7 2.6 613.2 92.60 % 48.1 Total $ 1,550.0 $ 1,135.5 $ 16.7 $ 11.6 $ 1,163.8 $ 414.5 In connection with the APL Notes Tender Offers, on February 27, 2015, the supplemental indentures governing the 4¾% Senior Notes due 2021 (the “2021 APL Notes”) and the 5⅞% Senior Notes due 2023 (the “2023 APL Notes”) of TPL and Targa Pipeline Finance Corporation (formerly known as Atlas Pipeline Finance Corporation) (together, the “APL Issuers”), became operative. These supplemental indentures eliminated substantially all of the restrictive covenants and certain events of default applicable to the 2021 APL Notes and the 2023 APL Notes that were not accepted for payment. Not having achieved the minimum tender condition on the 6⅝% Senior Notes due 2020 of the APL Issuers (the “2020 APL Notes”), we made a change of control offer, referred to as the Change of Control Offer, for any and all of the 2020 APL Notes in advance of, and conditioned upon, the consummation of the APL merger. In March 2015, holders representing $4.8 million of the outstanding 2020 APL Notes tendered their notes requiring a payment of $5.0 million, which included the change of control premium and accrued interest. Payments made under the APL Notes Tender Offers and Change of Control Offer totaling $1,168.8 million are presented as financing activities in the Consolidated Statements of Cash Flows. Exchange Offer and Consent Solicitation On April 13, 2015, we and Targa Resources Partners Finance Corporation (collectively, the “Partnership Issuers”) commenced an offer to exchange (the “Exchange Offer”) any and all of the outstanding 2020 APL Notes, for an equal amount of new unsecured 6⅝% Senior Notes due 2020 issued by the Partnership Issuers (the “6⅝% Notes” or the “TRP 6⅝% Notes”). On April 27, 2015, we had received tenders and consents from holders of approximately 96.3% of the total outstanding 2020 APL Notes. As a result, the minimum tender condition to the Exchange Offer and related consent solicitation was satisfied, and the APL Issuers entered into a supplemental indenture which eliminated substantially all of the restrictive covenants and certain events of default applicable to the 2020 APL Notes. In May 2015, upon the closing of the Exchange Offer, we issued $342.1 million aggregate principal amount of the TRP 6⅝% Notes to holders of the 2020 APL Notes which were validly tendered for exchange. The related $5.6 million premium, resulting from acquisition date fair value accounting, will be amortized as an adjustment to interest expense over the remaining term of the TRP 6⅝% Notes. |
Partnership Units and Related M
Partnership Units and Related Matters | 6 Months Ended |
Jun. 30, 2015 | |
Partnership Units and Related Matters [Abstract] | |
Partnership Units and Related Matters | Note 11 — Partnership Units and Related Matters Issuances of Common Units As part of the Atlas merger, we issued 58,614,157 common units to former APL unitholders as consideration for the APL merger, of which 3,363,935 common units represented ATLS’s common unit ownership in APL and were issued to Targa. In May 2014, we entered into an additional Equity Distribution Agreement under a shelf registration statement filed in July 2013 (the “May 2014 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregate of $400.0 million of our common units. During the six months ended June 30, 2015, we issued 3,590,826 common units under the May 2014 EDA, receiving total net proceeds of $153.0 million (net of commissions up to 1% of gross proceeds to our sales agents). Targa contributed $3.1 million to us to maintain its 2% general partner interest. In May 2015, we entered into an additional Equity Distribution Agreement under a shelf registration statement filed in April 2015 (the “May 2015 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregate of $1.0 billion of our common units. During the six months ended June 30, 2015, we issued 3,222,981 common units under the May 2015 EDA, receiving total net proceeds of $140.5 million (net of commissions up to 0.75% of gross proceeds to our sales agents). Targa contributed $2.9 million to us to maintain its 2% general partner interest, of which $0.9 million was received in July 2015. Subsequent Event During July 2015, we issued 563,573 common units under the May 2015 EDA, receiving net proceeds of $22.6 million. Targa contributed $0.5 million to us to maintain its 2% general partner interest. As of July 31, 2015, approximately $835.6 million of the aggregate offering amount remained available for sale pursuant to the May 2015 EDA. Distributions We must distribute all of our available cash, as defined in the Partnership Agreement, and as determined by the general partner, to unitholders of record within 45 days after the end of each quarter. Distributions Limited Partners General Partner Three Months Ended Date Paid or to be Paid Common Incentive Distribution Rights 2% Total Distributions per Limited Partner Unit (In millions, except per unit amounts) June 30, 2015 August 15, 2015 $ 152.5 $ 43.9 (1) $ 4.0 $ 200.4 $ 0.8250 March 31, 2015 May 14, 2015 148.3 41.7 (1) 3.9 193.9 0.8200 December 31, 2014 February 13, 2015 96.3 38.4 2.7 137.4 0.8100 (1) Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDR’s of $9.375 million were allocated to common unitholders in the first and second quarter of 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and will result in reallocation of IDR payments to common unitholders at the following amounts: $9.375 million per quarter for 2015, $6.25 million per quarter for 2016, $2.5 million per quarter for 2017 and $1.25 million per quarter for 2018. |
Earnings per Limited Partner Un
Earnings per Limited Partner Unit | 6 Months Ended |
Jun. 30, 2015 | |
Earnings per Limited Partner Unit [Abstract] | |
Earnings per Limited Partner Unit | Note 12 — Earnings per Limited Partner Unit The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per limited partner unit: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Net income $ 53.3 $ 120.9 $ 131.1 $ 252.2 Less: Net income attributable to noncontrolling interests 7.5 12.1 12.5 21.0 Net income attributable to Targa Resources Partners LP $ 45.8 $ 108.8 $ 118.6 $ 231.2 Net income attributable to general partner $ 44.6 $ 35.8 $ 87.1 $ 69.6 Net income attributable to limited partners 1.2 73.0 31.5 161.6 Net income attributable to Targa Resources Partners LP $ 45.8 $ 108.8 $ 118.6 $ 231.2 Weighted average units outstanding - basic 181.9 114.2 159.7 113.3 Net income available per limited partner unit - basic $ 0.01 $ 0.64 $ 0.20 $ 1.43 Weighted average units outstanding 181.9 114.2 159.7 113.3 Dilutive effect of unvested stock awards 0.7 0.7 0.4 0.6 Weighted average units outstanding - diluted (1) 182.6 114.9 160.1 113.9 Net income available per limited partner unit - diluted $ 0.01 $ 0.64 $ 0.20 $ 1.42 (1) For the three and six months ended June 30, 2015, approximately 173,125 units and 180,413 units were excluded from the computation of diluted earnings per unit because the inclusion of such units would have been anti-dilutive. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments and Hedging Activities [Abstract] | |
Derivative Instruments and Hedging Activities | Note 13 — Derivative Instruments and Hedging Activities Commodity Hedges 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 Field Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in our Field Gathering and Processing segment and the LOU business unit in our Coastal 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 New York Mercantile Exchange (“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 the Partnership and included in the acquisition date fair value of assets acquired. Derivative settlements of $23.1 million and $31.5 million related to these novated contracts were received during the three and six months ended June 30, 2015 and were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired, with no effect on results of operations. The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Certain novated APL crude options with a fair value of $7.7 million as of the acquisition date did not fall within the “highly effective” correlation range required to qualify as a hedging instrument for accounting purposes. These non-qualifying hedges resulted in $1.3 million and $0.2 million of mark-to-market losses for the three and six months ended June 30, 2015. These crude oil options expired during 2015. Additionally, for the three and six months ended June 30, 2015, we recorded $0.2 million of ineffectiveness losses and $0.9 million of ineffectiveness gains related to otherwise qualifying APL derivatives, primarily natural gas swaps. At June 30, 2015, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2015 2016 2017 2018 Natural Gas Swaps MMBtu/d 134,141 68,205 23,082 - Natural Gas Basis Swaps MMBtu/d 55,734 18,853 9,041 - Natural Gas Collars MMBtu/d - 7,500 7,500 1,849 NGL Swaps Bbl/d 5,015 2,254 658 - NGL Options/Collars Bbl/d 1,083 920 920 32 Condensate Swaps Bbl/d 1,826 1,082 500 - Condensate Options/Collars Bbl/d 1,605 790 790 101 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 we 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. 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 June 30, 2015 Fair Value as of December 31, 2014 Balance Sheet Location Derivative Derivative Derivative Derivative Derivatives designated as hedging instruments Commodity contracts Current $ 87.3 $ 1.9 $ 44.4 $ - Long-term 40.3 5.3 15.8 - Total derivatives designated as hedging instruments $ 127.6 $ 7.2 $ 60.2 $ - Derivatives not designated as hedging instruments Commodity contracts Current $ 4.5 $ - $ - $ 5.2 Total derivatives not designated as hedging instruments $ 4.5 $ - $ - $ 5.2 Total current position $ 91.8 $ 1.9 $ 44.4 $ 5.2 Total long-term position 40.3 5.3 15.8 - Total derivatives $ 132.1 $ 7.2 $ 60.2 $ 5.2 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 Asset Liability Asset Liability June 30, 2015 Position Position Position Position Current position Counterparties with offsetting position $ 77.2 $ 1.9 $ 75.3 $ - Counterparties without offsetting position - assets 14.6 - 14.6 - Counterparties without offsetting position - liabilities - - - - 91.8 1.9 89.9 - Long-term position Counterparties with offsetting position 33.8 5.3 28.5 - Counterparties without offsetting position - assets 6.5 - 6.5 - Counterparties without offsetting position - liabilities - - - - 40.3 5.3 35.0 - Total derivatives Counterparties with offsetting position 111.0 7.2 103.8 - Counterparties without offsetting position - assets 21.1 - 21.1 - Counterparties without offsetting position - liabilities - - - - $ 132.1 $ 7.2 $ 124.9 $ - December 31, 2014 Current position Counterparties with offsetting position $ 35.5 $ 4.4 $ 31.1 $ - Counterparties without offsetting position - assets 8.9 - 8.9 - Counterparties without offsetting position - liabilities - 0.8 - 0.8 44.4 5.2 40.0 0.8 Long-term position Counterparties with offsetting position - - - - Counterparties without offsetting position - assets 15.8 - 15.8 - Counterparties without offsetting position - liabilities - - - - 15.8 - 15.8 - Total derivatives Counterparties with offsetting position 35.5 4.4 31.1 - Counterparties without offsetting position - assets 24.7 - 24.7 - Counterparties without offsetting position - liabilities - 0.8 - 0.8 $ 60.2 $ 5.2 $ 55.8 $ 0.8 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. 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 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 Hedging Relationships Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Commodity contracts $ (8.7 ) $ (6.8 ) $ 16.5 $ (18.6 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended June 30, Six Months Ended June 30, Location of Gain (Loss) 2015 2014 2015 2014 Interest expense, net $ - $ (1.1 ) $ - $ (2.4 ) Revenues 16.3 (4.5 ) 24.4 (10.8 ) $ 16.3 $ (5.6 ) $ 24.4 $ (13.2 ) Our consolidated earnings are also affected by our 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. Gain (Loss) Recognized in Income on Derivatives Derivatives Not Designated as Hedging Instruments Location of Gain Recognized in Income on Derivatives Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Commodity contracts Revenue $ (4.0 ) $ (0.1 ) $ 3.2 $ (0.3 ) 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 year-end valuations: June 30, 2015 December 31, 2014 Commodity hedges (1) $ 52.4 $ 60.3 (1) Includes deferred net gains of $36.1 million as of June 30, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months. See Note 14 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities. |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | Note 14 — Fair Value Measurements Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value in our Consolidated Balance Sheets. Other financial instruments are reported at historical cost or amortized cost in our Consolidated Balance Sheets. The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments. Fair Value of Derivative Financial Instruments Our derivative instruments consist of financially settled commodity swaps and option contracts and fixed-price 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 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 June 30, 2015, a net asset position of $124.9 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 $92.5 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 $154.6 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 our accounts receivable securitization facility (the “Securitization Facility”) · Senior unsecured notes are based on quoted market prices derived from trades of the debt. 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: June 30, 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) $ 132.1 $ 132.1 $ - $ 129.0 $ 3.1 Liabilities from commodity derivative contracts (1) 7.2 7.2 - 4.8 2.4 TPL contingent consideration (2) 4.2 4.2 - - 4.2 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 85.5 85.5 - - - Senior secured revolving credit facility 878.0 878.0 - 878.0 - Senior unsecured notes 4,300.8 4,360.8 - 4,360.8 - Accounts receivable securitization facility 124.2 124.2 - 124.2 - (1) The fair value of our derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 - Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes . (2) See Note 4 – Business Acquisitions. Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets We reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable 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 natural gas 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 June 30, 2015, we had 29 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. T he following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts (Asset)/Liability Contingent Liability Balance, December 31, 2014 $ (1.7 ) $ - TPL contingent consideration (see Note 4-Business Acquisitions) - 4.2 New Level 3 instruments (0.7 ) - Transfers out of Level 3 1.7 - Balance, June 30, 2015 $ (0.7 ) $ 4.2 For the six months ended June 30, 2015, the Partnership transferred $1.7 million in derivative liabilities out of Level 3 and into Level 2. These 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 | 6 Months Ended |
Jun. 30, 2015 | |
Related Party Transactions - Targa [Abstract] | |
Related Party Transactions - Targa | Note 15 — Related Party Transactions - 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. The Partnership Agreement between Targa and us, with Targa as the general partner of the Partnership, 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 June 30, Six Months Ended June 30, 2015 2014 2015 2014 Targa billings of payroll and related costs included in operating expense $ 42.0 $ 31.6 $ 77.0 $ 61.5 Targa allocation of general and administrative expense 40.6 23.2 79.0 46.0 Cash distributions to Targa based on unit ownership 59.0 44.0 110.4 85.5 Cash contributions from Targa to maintain its 2% general partner ownership 5.1 1.0 58.7 3.4 |
Contingencies
Contingencies | 6 Months Ended |
Jun. 30, 2015 | |
Contingencies [Abstract] | |
Contingencies | Note 16 - Contingencies Legal Proceedings Targa Shareholder Litigation On January 28, 2015, a public shareholder of Targa (the “TRC Plaintiff”) filed a putative class action and derivative lawsuit against Targa (as a nominal defendant), its directors at the time of the ATLS merger (the “TRC Director Defendants”), and ATLS (together with Targa and the TRC Director Defendants, the “TRC Lawsuit Defendants”). This lawsuit was styled Inspired Investors v. Joe Bob Perkins, et al. The TRC Plaintiff alleged a variety of causes of action challenging the ATLS merger and the disclosures related to the ATLS merger. Generally, the TRC Plaintiff alleged that the TRC Director Defendants breached their fiduciary duties. The TRC Plaintiff further alleged that the registration statement filed on January 22, 2015 failed to disclose allegedly material details concerning (i) Wells Fargo Securities, LLC’s and the TRC Director Defendants’ supposed conflicts of interest with respect to the ATLS merger, (ii) Targa’s financial projections, (iii) the background of the ATLS merger, and (iv) Wells Fargo Securities, LLC’s analysis of the ATLS merger. The TRC Plaintiff also alleged that Targa overpaid to acquire ATLS. Based on these allegations, the TRC Plaintiff sought to enjoin the TRC Lawsuit Defendants from proceeding with or consummating the ATLS merger. The TRC Plaintiff also sought rescission, damages, and attorneys’ fees. On February 25, 2015, the Harris County trial court denied the TRC Plaintiff’s request for a preliminary injunction. The ATLS merger occurred on February 27, 2015. The TRC Plaintiff voluntarily filed a joint motion to dismiss the TRC Lawsuit on June 4, 2015. The Harris County trial court dismissed the TRC Lawsuit with prejudice on June 9, 2015. 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 Me rger Sub (the “APL Lawsuit Defendants”). These lawsuits are styled (a) Michael Evnin v. Atlas Pipeline Partners, L.P., et al ., in the Court of Common Pleas for Allegheny County, Pennsylvania; (b) William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., in the District Court of Tulsa County, Oklahoma (the “Tulsa Lawsuit”); (c) Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al ., in the Court of Common Pleas for Allegheny County, Pennsylvania; (d) Mike Welborn v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; and (e) Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania, though the Tulsa Lawsuit has since been voluntarily dismissed. The Evnin, Greenthal, Welborn and Feldbaum lawsuits have been consolidated as In re Atlas Pipeline Partners, L.P. Unitholder Litigation , Case No. GD-14-019245, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated APL Lawsuit”). In October and November 2014, two public unitholders of ATLS (the “ATLS Plaintiffs” and, together with the APL Plaintiffs, the “Atlas Lawsuit Plaintiffs”) filed putative class action lawsuits against ATLS, ATLS GP, its managers, Targa and GP Merger Sub (the “ATLS Lawsuit Defendants” and, together with the APL Lawsuit Defendants, the “Atlas Lawsuit Defendants”). These lawsuits are styled (a) Rick Kane v. Atlas Energy, L.P., et al. , in the Court of Common Pleas for Allegheny County, Pennsylvania and (b) Jeffrey Ayers v. Atlas Energy, L.P., et al. , in the Court of Common Pleas for Allegheny County, Pennsylvania (the “ATLS Lawsuits”). The ATLS Lawsuits have been consolidated as In re Atlas Energy, L.P. Unitholder Litigation , Case No. GD-14-019658, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated ATLS Lawsuit” and, together with the Consolidated APL Lawsuit, the “Consolidated Atlas Lawsuits”), though the Kane lawsuit has since been voluntarily dismissed. 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 The parties to the Consolidated Atlas Lawsuits are finalizing settlement agreements and expect to seek court approval of the settlements. 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 | 6 Months Ended |
Jun. 30, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Note 17 — Supplemental Cash Flow Information Six Months Ended June 30, 2015 2014 Cash: Interest paid, net of capitalized interest (1) $ 91.3 $ 61.4 Income taxes paid, net of refunds 4.1 2.0 Non-cash Investing and Financing balance sheet movements: Debt additions and retirements related to exchange of TRP 6⅝% Notes for APL 6⅝% Notes 342.1 - Deadstock commodity inventories transferred to property, plant and equipment 0.5 15.9 Reductions in Owner's Equity related to accrued distributions on unvested equity awards under share compensation arrangements 0.7 1.4 Receivables from equity issuances (0.1 ) 0.3 Impact of capital expenditure accruals on property, plant and equipment (52.9 ) (30.1 ) Transfers from materials and supplies inventory to property, plant and equipment 1.6 1.4 Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate 3.8 2.1 Non-cash balance sheet movements related to business acquisition: (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 $5.5 million and $11.5 million for the six months ended June 30, 2015 and 2014. |
Segment Information
Segment Information | 6 Months Ended |
Jun. 30, 2015 | |
Segment Information [Abstract] | |
Segment Information | Note 18 — Segment Information We report our operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution. The operating margin results of our commodity derivative activities are reported in Other. Our Gathering and Processing division 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 Field 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; and the Williston Basin in North Dakota. The Coastal Gathering and Processing segment's assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico Our Logistics and Marketing division is also referred to as our Downstream Business. Our Downstream Business 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, refined petroleum products and crude oil. It also includes certain natural gas supply and marketing activities in support of our other operations, including services to LPG exporters, as well as transporting natural gas and NGLs. Our Logistics Assets segment is involved in transporting, storing, and fractionating mixed NGLs; storing, terminaling, and transporting finished NGLs, including services for the LPG export market; and storing and terminaling refined petroleum products. These assets 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 and Lake Charles, Louisiana. Our Marketing and Distribution segment covers activities required to distribute and market raw and finished NGLs and all natural gas marketing activities. It includes (1) marketing our own NGL production and purchasing NGL products for resale in selected United States markets; (2) providing LPG balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end-users; (4) providing propane, butane and services to LPG exporters; and (5) marketing natural gas available to us from our Gathering and Processing division and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets. Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin and mark-to-market gain/losses related to derivative contracts that were not designated as cash-flow hedges. Eliminations of inter-segment transactions are reflected in the corporate and eliminations column. We are reviewing our segment disclosures as a result of the merger and integration efforts related to the Atlas mergers. Our reportable segment information is shown in the following tables: Three Months Ended June 30, 2015 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 434.1 $ 52.6 $ 30.8 $ 861.5 $ 17.1 $ - $ 1,396.1 Fees from midstream services 106.2 7.4 89.6 100.1 - - 303.3 540.3 60.0 120.4 961.6 17.1 - 1,699.4 Intersegment revenues Sales of commodities 212.8 57.7 2.0 68.6 - (341.1 ) - Fees from midstream services 1.9 - 63.1 5.4 - (70.4 ) - 214.7 57.7 65.1 74.0 - (411.5 ) - Revenues $ 755.0 $ 117.7 $ 185.5 $ 1,035.6 $ 17.1 $ (411.5 ) $ 1,699.4 Operating margin $ 138.2 $ 6.5 $ 112.7 $ 51.0 $ 17.1 $ - $ 325.5 Other financial information: Total assets (1) $ 10,116.7 $ 350.0 $ 1,831.2 $ 475.0 $ 132.2 $ 332.5 $ 13,237.6 Goodwill (2) $ 557.9 $ - $ - $ - $ - $ - $ 557.9 Capital expenditures $ 142.7 $ 4.8 $ 74.4 $ 5.9 $ $ 1.3 $ 229.1 Business acquisition $ 5,024.2 $ - $ - $ - $ - $ - $ 5,024.2 (1) Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our debt obligations. (2) Total assets include goodwill. Three Months Ended June 30, 2014 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 62.9 $ 89.7 $ 28.9 $ 1,581.7 $ (4.0 ) $ - $ 1,759.2 Fees from midstream services 43.1 10.5 72.7 115.1 - - 241.4 106.0 100.2 101.6 1,696.8 (4.0 ) - 2,000.6 Intersegment revenues Sales of commodities 381.9 163.4 0.8 137.0 - (683.1 ) - Fees from midstream services 1.1 - 72.3 7.6 - (81.0 ) - 383.0 163.4 73.1 144.6 - (764.1 ) - Revenues $ 489.0 $ 263.6 $ 174.7 $ 1,841.4 $ (4.0 ) $ (764.1 ) $ 2,000.6 Operating margin $ 97.7 $ 21.8 $ 108.6 $ 53.3 $ (4.0 ) $ - $ 277.4 Other financial information: Total assets $ 3,338.6 $ 377.0 $ 1,606.0 $ 799.4 $ 3.5 $ 115.5 $ 6,240.0 Capital expenditures $ 128.4 $ 3.1 $ 67.5 $ 15.5 $ - $ 1.0 $ 215.5 Six Months Ended June 30, 2015 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 602.0 $ 105.3 $ 58.1 $ 1,994.1 $ 38.8 $ - $ 2,798.3 Fees from midstream services 169.5 16.1 177.4 217.8 - - 580.8 771.5 121.4 235.5 2,211.9 38.8 - 3,379.1 Intersegment revenues Sales of commodities 428.2 120.4 3.2 147.1 - (698.9 ) - Fees from midstream services 3.8 - 135.6 9.9 - (149.3 ) - 432.0 120.4 138.8 157.0 - (848.2 ) - Revenues $ 1,203.5 $ 241.8 $ 374.3 $ 2,368.9 $ 38.8 $ (848.2 ) $ 3,379.1 Operating margin $ 217.3 $ 14.1 $ 238.1 $ 117.3 $ 38.8 $ - $ 625.6 Other financial information: Total assets (1) $ 10,116.7 $ 350.0 $ 1,831.2 $ 475.0 $ 132.2 $ 332.5 $ 13,237.6 Goodwill (2) $ 557.9 $ - $ - $ - $ - $ - $ 557.9 Capital expenditures $ 235.6 $ 6.0 $ 132.1 $ 8.9 $ - $ 2.3 $ 384.9 Business acquisition $ 5,024.2 $ - $ - $ - $ - $ - $ 5,024.2 (1) Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our debt obligations. (2) Total assets include goodwill. Six Months Ended June 30, 2014 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 108.7 $ 190.2 $ 49.9 $ 3,505.4 $ (10.1 ) $ - $ 3,844.1 Fees from midstream services 83.9 18.2 140.8 208.3 - - 451.2 192.6 208.4 190.7 3,713.7 (10.1 ) - 4,295.3 Intersegment revenues Sales of commodities 782.2 340.4 1.4 267.5 - (1,391.5 ) - Fees from midstream services 2.1 - 138.6 15.4 - (156.1 ) - 784.3 340.4 140.0 282.9 - (1,547.6 ) - Revenues $ 976.9 $ 548.8 $ 330.7 $ 3,996.6 $ (10.1 ) $ (1,547.6 ) $ 4,295.3 Operating margin $ 191.7 $ 47.8 $ 205.4 $ 117.9 $ (10.1 ) $ - $ 552.7 Other financial information: Total assets $ 3,338.6 $ 377.0 $ 1,606.0 $ 799.4 $ 3.5 $ 115.5 $ 6,240.0 Capital expenditures $ 227.3 $ 7.4 $ 136.1 $ 18.6 $ - $ 1.5 $ 390.9 The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Sales of commodities Natural gas $ 443.5 $ 358.1 $ 750.9 $ 750.4 NGL 854.1 1,335.5 1,884.6 2,986.4 Condensate 51.3 41.8 72.8 70.1 Petroleum products 30.1 28.2 56.5 48.3 Derivative activities 17.1 (4.4 ) 33.5 (11.1 ) 1,396.1 1,759.2 2,798.3 3,844.1 Fees from midstream services Fractionating and treating 54.7 51.7 104.5 98.2 Storage, terminaling, transportation and export 121.6 125.9 257.7 227.1 Gathering and processing 105.7 48.0 174.1 90.6 Other 21.3 15.8 44.5 35.3 303.3 241.4 580.8 451.2 Total revenues $ 1,699.4 $ 2,000.6 $ 3,379.1 $ 4,295.3 The following table shows a reconciliation of operating margin to net income for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Reconciliation of operating margin to net income: Operating margin $ 325.5 $ 277.4 $ 625.6 $ 552.7 Depreciation and amortization expense (163.9 ) (85.8 ) (282.5 ) (165.3 ) General and administrative expense (46.8 ) (39.1 ) (87.1 ) (74.8 ) Interest expense, net (62.2 ) (34.9 ) (113.1 ) (68.1 ) Other 0.4 4.6 (11.0 ) 10.1 Income tax (expense)/benefit 0.3 (1.3 ) (0.8 ) (2.4 ) Net income $ 53.3 $ 120.9 $ 131.1 $ 252.2 |
Significant Accounting Polici26
Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2015 | |
Significant Accounting Policies [Abstract] | |
Accounting Policy Updates | Accounting Policy Updates The accounting policies that we follow are set forth in Note 3 of the Notes to Consolidated Financial Statements in our Annual Report. We have updated our policies during the six months ended June 30, 2015 to include our accounting policy for goodwill related to the Atlas mergers. |
Goodwill and Intangible Assets | Goodwill results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Impairment testing for goodwill is performed at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (also known as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available, and segment management regularly reviews the operating results of that component. We evaluate goodwill for impairment at least annually, as of November 30 th |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In February 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 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 July 2015, the FASB issued ASU 2015-11, Inventory (Topic 303): Simplifying the Measurement of Inventory. Topic 303 currently requires inventory to be measured at the lower of cost or market, where market could be replacement cost, net realizable value or net realizable value less a normal profit margin. The amendments in this update require that all inventory, excluding inventory that is measured using the last-in, first-out method or the retail inventory method, be measured at the lower of cost or net realizable value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments are effective for us in 2017, with early adoption permitted, and should be applied prospectively. We anticipate adopting the amendments on January 1, 2017, which will not have a material effect on our consolidated financial statements or results of operations. |
Business Acquisitions (Tables)
Business Acquisitions (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Business Acquisitions [Abstract] | |
Pro Forma Consolidated Results of Operations | The following summarized unaudited pro forma consolidated statement of operations information for the six months ended June 30, 2015 and June 30, 2014 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. Pro Forma Results for the Six Months Ended June 30, 2015 June 30, 2014 Revenues $ 3,667.8 $ 5,647.6 Net income 124.2 267.1 |
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 Value of Consideration Transferred by Targa for ATLS: Cash, 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, 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. Targa also received $7.3 million in April 2015 as part of the Atlas mergers, representing the one-time cash payment from us for the APL common units owned by ATLS. (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. |
Preliminary Fair Value Determination Related to the Atlas Mergers | As of February 27, 2015, our preliminary fair value determination related to the Atlas mergers was as follows. The excess of the purchase price over the estimated fair value of net assets acquired was approximately $557.9 million, which was recorded as goodwill. This determination is based on our preliminary valuation and is subject to revisions pending the completion of the valuation and other adjustments. Preliminary fair value determination: February 27, 2015 Trade and other current receivables, net $ 181.1 Other current assets 25.1 Assets from risk management activities 102.1 Property, plant and equipment 4,693.2 Investments in unconsolidated affiliates 214.2 Intangible assets 1,204.0 Other long-term assets 6.6 Current liabilities (255.1 ) Long-term debt (1,573.3 ) Deferred income tax liabilities, net (8.6 ) Other long-term liabilities (9.1 ) Total identifiable net assets 4,580.2 Noncontrolling interest in subsidiaries (113.4 ) Current liabilities retained by Targa (0.5 ) Goodwill 557.9 $ 5,024.2 |
Inventories (Tables)
Inventories (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Inventories [Abstract] | |
Components of Inventories | June 30, 2015 December 31, 2014 Commodities $ 112.7 $ 157.4 Materials and supplies 12.1 11.5 $ 124.8 $ 168.9 |
Property, Plant and Equipment29
Property, Plant and Equipment and Intangible Assets (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Property, Plant and Equipment and Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | June 30, 2015 December 31, 2014 Estimated useful life Gathering systems $ 6,052.6 $ 2,588.6 5 to 40 Processing and fractionation facilities 2,976.1 1,884.1 5 to 40 Terminaling and storage facilities 1,090.0 1,038.9 5 to 25 Transportation assets 438.7 359.0 10 to 25 Other property, plant and equipment 209.8 149.1 3 to 40 Land 102.6 95.6 - Construction in progress 725.4 399.0 - Property, plant and equipment 11,595.2 6,514.3 Accumulated depreciation (1,910.9 ) (1,689.7 ) Property, plant and equipment, net $ 9,684.3 $ 4,824.6 Intangible assets $ 1,885.6 $ 681.8 20 Accumulated amortization (150.0 ) (89.9 ) Intangible assets, net $ 1,735.6 $ 591.9 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Asset Retirement Obligations [Abstract] | |
Changes in 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: Six Months Ended June 30, 2015 Beginning of period $ 56.8 Preliminary fair value of ARO acquired with the APL merger 4.0 Change in cash flow estimate 3.8 Accretion expense 2.6 End of period $ 67.2 |
Investments in Unconsolidated31
Investments in Unconsolidated Affiliates (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Investments in Unconsolidated Affiliates [Abstract] | |
Activity Related to Investment in Unconsolidated Affiliate | The following table shows the activity related to our investments in unconsolidated affiliates: Six Months Ended June 30, 2015 Beginning of period $ 50.2 Preliminary fair value of T2 Joint Ventures acquired 214.2 Equity earnings (1) 0.5 Cash distributions (2) (7.0 ) Cash calls for expansion projects 0.1 End of period $ 258.0 (1) Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015, including the amortization of a basis difference resulting from acquisition date fair value accounting. (2) Includes $0.1 million distributions received in excess of our share of cumulative earnings for the six months ended June 30, 2015. 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 32
Accounts Payable and Accrued Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Accounts Payable and Accrued Liabilities [Abstract] | |
Schedule of Accounts Payable and Accrued Liabilities | June 30, 2015 December 31, 2014 Commodities $ 402.5 $ 416.7 Other goods and services 105.9 108.9 Interest 63.3 37.3 Compensation and benefits 1.8 1.3 Income and other taxes 31.6 13.6 Other 47.6 14.9 $ 652.7 $ 592.7 |
Debt Obligations (Tables)
Debt Obligations (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Debt Obligations [Abstract] | |
Schedule of Outstanding Debt | June 30, 2015 December 31, 2014 Current: Accounts receivable securitization facility, due December 2015 $ 124.2 $ 182.8 Long-term: Senior secured revolving credit facility, variable rate, due October 2017 (1) 878.0 - Senior unsecured notes, 5% fixed rate, due January 2018 1,100.0 - Senior unsecured notes, 6 ⅞ 483.6 483.6 Unamortized discount (23.8 ) (25.2 ) Senior unsecured notes, 6 ⅝ 342.1 - Unamortized premium 5.4 - Senior unsecured notes, 6 ⅜ 300.0 300.0 Senior unsecured notes, 5 ¼ 600.0 600.0 Senior unsecured notes, 4¼% fixed rate, due November 2023 625.0 625.0 Senior unsecured notes, 4 ⅛ 800.0 800.0 Senior unsecured notes, 6 ⅝ 13.1 - Unamortized premium 0.2 - Senior unsecured notes, 4¾% fixed rate, due November 2021 (3) 6.5 - Senior unsecured notes, 5⅞% fixed rate, due August 2023 (3) 48.1 - Unamortized premium 0.6 - Total long-term debt 5,178.8 2,783.4 Total debt $ 5,303.0 $ 2,966.2 Letters of credit outstanding $ 20.5 $ 44.1 (1) As of , availability under our $1.6 billion senior secured revolving credit facility was $701.5 million. (2) In May 2015, we exchanged the TRP 6⅝% Senior Notes with the same economic terms to the holders of the 2020 APL Notes (as defined below) who validly tendered such notes for exchange to us. (3) Senior unsecured notes issued by APL entities and acquired in the Atlas mergers. While we consolidate the debt acquired in the Atlas mergers, we do not guarantee the acquired debt of APL. |
Interest Rates Incurred on Variable-Rate Debt Obligations | The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the six months ended Range of Interest Rates Incurred Weighted Average Interest Rate Incurred Senior secured revolving credit facility 1.9% - 4.3 % 2.0 % Accounts receivable securitization facility 0.9 % 0.9 % |
Summary of Results of Tender Offers | The results of the APL Notes Tender Offers were: Senior Notes Outstanding Note Balance Amount Tendered Premium Paid Accrued Interest Paid Total Tender Offer payments % Tendered Note Balance after Tender Offers ($ amounts in millions) 6⅝% due 2020 $ 500.0 $ 140.1 $ 2.1 $ 3.7 $ 145.9 28.02 % $ 359.9 4¾% due 2021 400.0 393.5 5.9 5.3 404.7 98.38 % 6.5 5⅞% due 2023 650.0 601.9 8.7 2.6 613.2 92.60 % 48.1 Total $ 1,550.0 $ 1,135.5 $ 16.7 $ 11.6 $ 1,163.8 $ 414.5 |
Partnership Units and Related34
Partnership Units and Related Matters (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Partnership Units and Related Matters [Abstract] | |
Schedule of Distributions | The following table details the distributions declared and/or paid by us for the six months ended June 30, 2015: Distributions Limited Partners General Partner Three Months Ended Date Paid or to be Paid Common Incentive Distribution Rights 2% Total Distributions per Limited Partner Unit (In millions, except per unit amounts) June 30, 2015 August 15, 2015 $ 152.5 $ 43.9 (1) $ 4.0 $ 200.4 $ 0.8250 March 31, 2015 May 14, 2015 148.3 41.7 (1) 3.9 193.9 0.8200 December 31, 2014 February 13, 2015 96.3 38.4 2.7 137.4 0.8100 (1) Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDR’s of $9.375 million were allocated to common unitholders in the first and second quarter of 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and will result in reallocation of IDR payments to common unitholders at the following amounts: $9.375 million per quarter for 2015, $6.25 million per quarter for 2016, $2.5 million per quarter for 2017 and $1.25 million per quarter for 2018. |
Earnings per Limited Partner 35
Earnings per Limited Partner Unit (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Earnings per Limited Partner Unit [Abstract] | |
Computation of Basic and Diluted Net Income per Limited Partner | The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per limited partner unit: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Net income $ 53.3 $ 120.9 $ 131.1 $ 252.2 Less: Net income attributable to noncontrolling interests 7.5 12.1 12.5 21.0 Net income attributable to Targa Resources Partners LP $ 45.8 $ 108.8 $ 118.6 $ 231.2 Net income attributable to general partner $ 44.6 $ 35.8 $ 87.1 $ 69.6 Net income attributable to limited partners 1.2 73.0 31.5 161.6 Net income attributable to Targa Resources Partners LP $ 45.8 $ 108.8 $ 118.6 $ 231.2 Weighted average units outstanding - basic 181.9 114.2 159.7 113.3 Net income available per limited partner unit - basic $ 0.01 $ 0.64 $ 0.20 $ 1.43 Weighted average units outstanding 181.9 114.2 159.7 113.3 Dilutive effect of unvested stock awards 0.7 0.7 0.4 0.6 Weighted average units outstanding - diluted (1) 182.6 114.9 160.1 113.9 Net income available per limited partner unit - diluted $ 0.01 $ 0.64 $ 0.20 $ 1.42 (1) For the three and six months ended June 30, 2015, approximately 173,125 units and 180,413 units were excluded from the computation of diluted earnings per unit because the inclusion of such units would have been anti-dilutive. |
Derivative Instruments and He36
Derivative Instruments and Hedging Activities (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments and Hedging Activities [Abstract] | |
Notional Volume of Commodity Hedges | At June 30, 2015, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2015 2016 2017 2018 Natural Gas Swaps MMBtu/d 134,141 68,205 23,082 - Natural Gas Basis Swaps MMBtu/d 55,734 18,853 9,041 - Natural Gas Collars MMBtu/d - 7,500 7,500 1,849 NGL Swaps Bbl/d 5,015 2,254 658 - NGL Options/Collars Bbl/d 1,083 920 920 32 Condensate Swaps Bbl/d 1,826 1,082 500 - Condensate Options/Collars Bbl/d 1,605 790 790 101 |
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 June 30, 2015 Fair Value as of December 31, 2014 Balance Sheet Location Derivative Derivative Derivative Derivative Derivatives designated as hedging instruments Commodity contracts Current $ 87.3 $ 1.9 $ 44.4 $ - Long-term 40.3 5.3 15.8 - Total derivatives designated as hedging instruments $ 127.6 $ 7.2 $ 60.2 $ - Derivatives not designated as hedging instruments Commodity contracts Current $ 4.5 $ - $ - $ 5.2 Total derivatives not designated as hedging instruments $ 4.5 $ - $ - $ 5.2 Total current position $ 91.8 $ 1.9 $ 44.4 $ 5.2 Total long-term position 40.3 5.3 15.8 - Total derivatives $ 132.1 $ 7.2 $ 60.2 $ 5.2 |
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 Asset Liability Asset Liability June 30, 2015 Position Position Position Position Current position Counterparties with offsetting position $ 77.2 $ 1.9 $ 75.3 $ - Counterparties without offsetting position - assets 14.6 - 14.6 - Counterparties without offsetting position - liabilities - - - - 91.8 1.9 89.9 - Long-term position Counterparties with offsetting position 33.8 5.3 28.5 - Counterparties without offsetting position - assets 6.5 - 6.5 - Counterparties without offsetting position - liabilities - - - - 40.3 5.3 35.0 - Total derivatives Counterparties with offsetting position 111.0 7.2 103.8 - Counterparties without offsetting position - assets 21.1 - 21.1 - Counterparties without offsetting position - liabilities - - - - $ 132.1 $ 7.2 $ 124.9 $ - December 31, 2014 Current position Counterparties with offsetting position $ 35.5 $ 4.4 $ 31.1 $ - Counterparties without offsetting position - assets 8.9 - 8.9 - Counterparties without offsetting position - liabilities - 0.8 - 0.8 44.4 5.2 40.0 0.8 Long-term position Counterparties with offsetting position - - - - Counterparties without offsetting position - assets 15.8 - 15.8 - Counterparties without offsetting position - liabilities - - - - 15.8 - 15.8 - Total derivatives Counterparties with offsetting position 35.5 4.4 31.1 - Counterparties without offsetting position - assets 24.7 - 24.7 - Counterparties without offsetting position - liabilities - 0.8 - 0.8 $ 60.2 $ 5.2 $ 55.8 $ 0.8 |
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 Hedging Relationships Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Commodity contracts $ (8.7 ) $ (6.8 ) $ 16.5 $ (18.6 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Three Months Ended June 30, Six Months Ended June 30, Location of Gain (Loss) 2015 2014 2015 2014 Interest expense, net $ - $ (1.1 ) $ - $ (2.4 ) Revenues 16.3 (4.5 ) 24.4 (10.8 ) $ 16.3 $ (5.6 ) $ 24.4 $ (13.2 ) |
Gain (Loss) Recognized in Income on Derivatives | Gain (Loss) Recognized in Income on Derivatives Derivatives Not Designated as Hedging Instruments Location of Gain Recognized in Income on Derivatives Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Commodity contracts Revenue $ (4.0 ) $ (0.1 ) $ 3.2 $ (0.3 ) |
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 year-end valuations: June 30, 2015 December 31, 2014 Commodity hedges (1) $ 52.4 $ 60.3 (1) Includes deferred net gains of $36.1 million as of June 30, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Measurements [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: June 30, 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) $ 132.1 $ 132.1 $ - $ 129.0 $ 3.1 Liabilities from commodity derivative contracts (1) 7.2 7.2 - 4.8 2.4 TPL contingent consideration (2) 4.2 4.2 - - 4.2 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 85.5 85.5 - - - Senior secured revolving credit facility 878.0 878.0 - 878.0 - Senior unsecured notes 4,300.8 4,360.8 - 4,360.8 - Accounts receivable securitization facility 124.2 124.2 - 124.2 - (1) The fair value of our derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 - Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes . (2) See Note 4 – Business Acquisitions. |
Reconciliation of the Changes in Fair Value of Financial Instruments Classified As Level 3 | T he following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts (Asset)/Liability Contingent Liability Balance, December 31, 2014 $ (1.7 ) $ - TPL contingent consideration (see Note 4-Business Acquisitions) - 4.2 New Level 3 instruments (0.7 ) - Transfers out of Level 3 1.7 - Balance, June 30, 2015 $ (0.7 ) $ 4.2 |
Related Party Transactions - 38
Related Party Transactions - Targa (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Related Party Transactions - Targa [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 June 30, Six Months Ended June 30, 2015 2014 2015 2014 Targa billings of payroll and related costs included in operating expense $ 42.0 $ 31.6 $ 77.0 $ 61.5 Targa allocation of general and administrative expense 40.6 23.2 79.0 46.0 Cash distributions to Targa based on unit ownership 59.0 44.0 110.4 85.5 Cash contributions from Targa to maintain its 2% general partner ownership 5.1 1.0 58.7 3.4 |
Supplemental Cash Flow Inform39
Supplemental Cash Flow Information (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Note 17 — Supplemental Cash Flow Information Six Months Ended June 30, 2015 2014 Cash: Interest paid, net of capitalized interest (1) $ 91.3 $ 61.4 Income taxes paid, net of refunds 4.1 2.0 Non-cash Investing and Financing balance sheet movements: Debt additions and retirements related to exchange of TRP 6⅝% Notes for APL 6⅝% Notes 342.1 - Deadstock commodity inventories transferred to property, plant and equipment 0.5 15.9 Reductions in Owner's Equity related to accrued distributions on unvested equity awards under share compensation arrangements 0.7 1.4 Receivables from equity issuances (0.1 ) 0.3 Impact of capital expenditure accruals on property, plant and equipment (52.9 ) (30.1 ) Transfers from materials and supplies inventory to property, plant and equipment 1.6 1.4 Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate 3.8 2.1 Non-cash balance sheet movements related to business acquisition: (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 $5.5 million and $11.5 million for the six months ended June 30, 2015 and 2014. |
Segment Information (Tables)
Segment Information (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Segment Information [Abstract] | |
Information by Segment | Our reportable segment information is shown in the following tables: Three Months Ended June 30, 2015 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 434.1 $ 52.6 $ 30.8 $ 861.5 $ 17.1 $ - $ 1,396.1 Fees from midstream services 106.2 7.4 89.6 100.1 - - 303.3 540.3 60.0 120.4 961.6 17.1 - 1,699.4 Intersegment revenues Sales of commodities 212.8 57.7 2.0 68.6 - (341.1 ) - Fees from midstream services 1.9 - 63.1 5.4 - (70.4 ) - 214.7 57.7 65.1 74.0 - (411.5 ) - Revenues $ 755.0 $ 117.7 $ 185.5 $ 1,035.6 $ 17.1 $ (411.5 ) $ 1,699.4 Operating margin $ 138.2 $ 6.5 $ 112.7 $ 51.0 $ 17.1 $ - $ 325.5 Other financial information: Total assets (1) $ 10,116.7 $ 350.0 $ 1,831.2 $ 475.0 $ 132.2 $ 332.5 $ 13,237.6 Goodwill (2) $ 557.9 $ - $ - $ - $ - $ - $ 557.9 Capital expenditures $ 142.7 $ 4.8 $ 74.4 $ 5.9 $ $ 1.3 $ 229.1 Business acquisition $ 5,024.2 $ - $ - $ - $ - $ - $ 5,024.2 (1) Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our debt obligations. (2) Total assets include goodwill. Three Months Ended June 30, 2014 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 62.9 $ 89.7 $ 28.9 $ 1,581.7 $ (4.0 ) $ - $ 1,759.2 Fees from midstream services 43.1 10.5 72.7 115.1 - - 241.4 106.0 100.2 101.6 1,696.8 (4.0 ) - 2,000.6 Intersegment revenues Sales of commodities 381.9 163.4 0.8 137.0 - (683.1 ) - Fees from midstream services 1.1 - 72.3 7.6 - (81.0 ) - 383.0 163.4 73.1 144.6 - (764.1 ) - Revenues $ 489.0 $ 263.6 $ 174.7 $ 1,841.4 $ (4.0 ) $ (764.1 ) $ 2,000.6 Operating margin $ 97.7 $ 21.8 $ 108.6 $ 53.3 $ (4.0 ) $ - $ 277.4 Other financial information: Total assets $ 3,338.6 $ 377.0 $ 1,606.0 $ 799.4 $ 3.5 $ 115.5 $ 6,240.0 Capital expenditures $ 128.4 $ 3.1 $ 67.5 $ 15.5 $ - $ 1.0 $ 215.5 Six Months Ended June 30, 2015 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 602.0 $ 105.3 $ 58.1 $ 1,994.1 $ 38.8 $ - $ 2,798.3 Fees from midstream services 169.5 16.1 177.4 217.8 - - 580.8 771.5 121.4 235.5 2,211.9 38.8 - 3,379.1 Intersegment revenues Sales of commodities 428.2 120.4 3.2 147.1 - (698.9 ) - Fees from midstream services 3.8 - 135.6 9.9 - (149.3 ) - 432.0 120.4 138.8 157.0 - (848.2 ) - Revenues $ 1,203.5 $ 241.8 $ 374.3 $ 2,368.9 $ 38.8 $ (848.2 ) $ 3,379.1 Operating margin $ 217.3 $ 14.1 $ 238.1 $ 117.3 $ 38.8 $ - $ 625.6 Other financial information: Total assets (1) $ 10,116.7 $ 350.0 $ 1,831.2 $ 475.0 $ 132.2 $ 332.5 $ 13,237.6 Goodwill (2) $ 557.9 $ - $ - $ - $ - $ - $ 557.9 Capital expenditures $ 235.6 $ 6.0 $ 132.1 $ 8.9 $ - $ 2.3 $ 384.9 Business acquisition $ 5,024.2 $ - $ - $ - $ - $ - $ 5,024.2 (1) Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our debt obligations. (2) Total assets include goodwill. Six Months Ended June 30, 2014 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 108.7 $ 190.2 $ 49.9 $ 3,505.4 $ (10.1 ) $ - $ 3,844.1 Fees from midstream services 83.9 18.2 140.8 208.3 - - 451.2 192.6 208.4 190.7 3,713.7 (10.1 ) - 4,295.3 Intersegment revenues Sales of commodities 782.2 340.4 1.4 267.5 - (1,391.5 ) - Fees from midstream services 2.1 - 138.6 15.4 - (156.1 ) - 784.3 340.4 140.0 282.9 - (1,547.6 ) - Revenues $ 976.9 $ 548.8 $ 330.7 $ 3,996.6 $ (10.1 ) $ (1,547.6 ) $ 4,295.3 Operating margin $ 191.7 $ 47.8 $ 205.4 $ 117.9 $ (10.1 ) $ - $ 552.7 Other financial information: Total assets $ 3,338.6 $ 377.0 $ 1,606.0 $ 799.4 $ 3.5 $ 115.5 $ 6,240.0 Capital expenditures $ 227.3 $ 7.4 $ 136.1 $ 18.6 $ - $ 1.5 $ 390.9 |
Revenues by Product and Service | The following table shows our consolidated revenues by product and service for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Sales of commodities Natural gas $ 443.5 $ 358.1 $ 750.9 $ 750.4 NGL 854.1 1,335.5 1,884.6 2,986.4 Condensate 51.3 41.8 72.8 70.1 Petroleum products 30.1 28.2 56.5 48.3 Derivative activities 17.1 (4.4 ) 33.5 (11.1 ) 1,396.1 1,759.2 2,798.3 3,844.1 Fees from midstream services Fractionating and treating 54.7 51.7 104.5 98.2 Storage, terminaling, transportation and export 121.6 125.9 257.7 227.1 Gathering and processing 105.7 48.0 174.1 90.6 Other 21.3 15.8 44.5 35.3 303.3 241.4 580.8 451.2 Total revenues $ 1,699.4 $ 2,000.6 $ 3,379.1 $ 4,295.3 |
Reconciliation of Operating Margin to Net Income | The following table shows a reconciliation of operating margin to net income for the periods presented: Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Reconciliation of operating margin to net income: Operating margin $ 325.5 $ 277.4 $ 625.6 $ 552.7 Depreciation and amortization expense (163.9 ) (85.8 ) (282.5 ) (165.3 ) General and administrative expense (46.8 ) (39.1 ) (87.1 ) (74.8 ) Interest expense, net (62.2 ) (34.9 ) (113.1 ) (68.1 ) Other 0.4 4.6 (11.0 ) 10.1 Income tax (expense)/benefit 0.3 (1.3 ) (0.8 ) (2.4 ) Net income $ 53.3 $ 120.9 $ 131.1 $ 252.2 |
Organization and Operations (De
Organization and Operations (Details) - shares | 6 Months Ended | |
Jun. 30, 2015 | Dec. 31, 2014 | |
Organization and Operations [Abstract] | ||
General partner interest (in hundredths) | 2.00% | |
Ownership interest by parent (in hundredths) | 10.70% | |
General partner units outstanding (in units) | 3,757,093 | 2,420,124 |
Common units held by related party (in units) | 16,309,594 | |
Increasing cash distributions as percentage of distributable cash for a quarter (in hundredths) | 48.00% |
Basis of Presentation (Details)
Basis of Presentation (Details) - Feb. 27, 2015 $ in Billions | USD ($)Transaction |
Business Acquisition [Line Items] | |
Number of separate legal transactions involved in mergers | 2 |
Atlas Energy [Member] | |
Business Acquisition [Line Items] | |
Total general partner interest acquired | $ | $ 1.6 |
Significant Accounting Polici43
Significant Accounting Policies (Details) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Significant Accounting Policies [Abstract] | ||
Unamortized debt issuance costs | $ 37.2 | $ 29.9 |
Business Acquisitions (Details)
Business Acquisitions (Details) | Feb. 27, 2015USD ($)Transaction$ / sharesshares | Mar. 31, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Jun. 30, 2015USD ($)MMcf / dQuartermi | Jun. 30, 2014USD ($) |
Business Acquisition [Line Items] | ||||||
Contribution made by Targa to general partner's interest | $ 58,700,000 | $ 0 | ||||
Percentage of general partner's interest maintained (in hundredths) | 2.00% | |||||
Acquisition-related expenses | $ 14,300,000 | |||||
Number of separate legal transactions involved in mergers | Transaction | 2 | |||||
Targa Pipeline Partners LP [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Processing capacity (in MMcf/D) | MMcf / d | 2,053 | |||||
Length of additional pipelines (in miles) | mi | 12,220 | |||||
Atlas Pipeline Partners [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Purchase consideration | $ 5,300,000,000 | |||||
Debt and all other assumed liabilities included purchase consideration | 1,800,000,000 | |||||
Payments for notes tendered and settled upon closing of merger | $ 1,200,000,000 | |||||
Reduction in incentive distribution | $ 9,375,000 | $ 9,375,000 | ||||
Number of successive quarters, annual distribution is paid | Quarter | 4 | |||||
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 (in hundredths) | 8.25% | |||||
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 (in hundredths) | 2.00% | |||||
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] | Change Of Control Payments [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payments related to acquisition | $ 28,800,000 | |||||
Atlas Pipeline Partners [Member] | Common Units [Member] | Atlas Energy [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Common units owned by parent prior to closing (in units) | shares | 5,754,253 | |||||
Atlas Pipeline Partners [Member] | Revolving Credit Facility [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payments related to acquisition | $ 701,400,000 | |||||
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 Energy [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Purchase consideration | $ 1,600,000,000 | |||||
Atlas Energy [Member] | Targa Resources Corp [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Percentage of interest in common units (in hundredths) | 100.00% | |||||
Purchase consideration | $ 1,600,000,000 | |||||
Distribution of common units/shares for each common unit (in shares) | shares | 0.1809 | |||||
Cash payment (in dollars per common unit) | $ / shares | $ 9.12 | |||||
Cash payments related to acquisition | $ 514,700,000 | |||||
Common units acquired | $ 1,000,000,000 | |||||
Closing market price of common share (in dollars per share) | $ / shares | $ 99.58 | |||||
Common units par value (in dollars per share) | $ / shares | $ 0.001 | |||||
Acquisition-related expenses | $ 11,000,000 | |||||
Reduction in purchase price | (154,700,000) | |||||
Atlas Energy [Member] | Targa Resources Corp [Member] | Common Unit Holders [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payments related to acquisition | $ 7,300,000 | |||||
Atlas Energy [Member] | Restricted Stock Units (RSUs) [Member] | Targa Resources Corp [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Total distribution of common shares (in shares) | shares | 81,740 | |||||
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] | Change Of Control Payments [Member] | Targa Resources Corp [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payments related to acquisition | 149,200,000 | |||||
Atlas Energy [Member] | Equity Award Settlements [Member] | Targa Resources Corp [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Cash payments related to acquisition | $ 88,000,000 | |||||
Atlas Energy [Member] | Common Units [Member] | Targa Pipeline Partners LP [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Total distribution of common shares (in shares) | shares | 3,363,935 | |||||
Atlas Energy [Member] | Common Units [Member] | Targa Resources Corp [Member] | ||||||
Business Acquisition [Line Items] | ||||||
Total distribution of common shares (in shares) | shares | 10,126,532 | |||||
Common units acquired | $ 147,400,000 |
Business Acquisitions, Pro form
Business Acquisitions, Pro forma Impact of Atlas Mergers on Consolidated Statements of Operations (Details) - USD ($) $ in Millions | 4 Months Ended | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2015 | Jun. 30, 2014 | |
Business Acquisition [Line Items] | |||
Revenues from acquired business | $ 616.8 | ||
Net income from acquired business | $ 17.8 | ||
Acquisition-related expenses | $ 14.3 | ||
Pro forma consolidated results of operations [Abstract] | |||
Revenues | 3,667.8 | $ 5,647.6 | |
Net income | $ 124.2 | $ 267.1 | |
West Texas LPG Pipeline Limited Partnership [Member] | |||
Pro forma consolidated results of operations [Abstract] | |||
Percentage of equity interest sold (in hundredths) | 20.00% | ||
Atlas Resource Partners, LP [Member] | |||
Pro forma consolidated results of operations [Abstract] | |||
Percentage of equity interest sold (in hundredths) | 100.00% |
Business Acquisitions, Fair Val
Business Acquisitions, Fair Value of Consideration Transferred (Details) - USD ($) $ in Millions | Feb. 27, 2015 | Jun. 30, 2015 | Jun. 30, 2014 | |
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Cash paid, net of cash acquired | $ 828.7 | $ 0 | ||
Total fair value of consideration transferred | $ 5,024.2 | $ 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 | |||
Atlas Pipeline Partners [Member] | Common Unit Holders [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Cash payments related to acquisition | 128 | |||
Atlas Pipeline Partners [Member] | Phantom Unit Awards [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Common shares | [2] | 15 | ||
Atlas Pipeline Partners [Member] | Common Stock [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Common shares | 2,568.5 | |||
Atlas Energy [Member] | Targa Resources Corp [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 | |||
Cash payments related to acquisition | 514.7 | |||
Atlas Energy [Member] | Targa Resources Corp [Member] | Common Unit Holders [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Cash payments related to acquisition | 7.3 | |||
Atlas Energy [Member] | Restricted Stock Units (RSUs) [Member] | Targa Resources Corp [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Common shares | [2] | 5.2 | ||
Atlas Energy [Member] | Common Units [Member] | Targa Resources Corp [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Less: value of APL common units owned by ATLS | (147.4) | |||
Atlas Energy [Member] | Common Stock [Member] | Targa Resources Corp [Member] | ||||
Fair Value of Consideration Transferred by Targa [Abstract] | ||||
Common shares | 1,008.5 | |||
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. Targa also received $7.3 million in April 2015 as part of the Atlas mergers, representing the one-time cash payment from us for the APL common units owned by ATLS. |
Business Acquisitions, Prelimin
Business Acquisitions, Preliminary Fair Value Determination (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||||||
Jun. 30, 2015 | Mar. 31, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Feb. 27, 2015 | Dec. 31, 2014 | |||
Preliminary fair value determination [Abstract] | |||||||||
Trade and other current receivables, net | $ 181.1 | ||||||||
Other current assets | 25.1 | ||||||||
Assets from risk management activities | 102.1 | ||||||||
Property, plant and equipment | 4,693.2 | ||||||||
Investments in unconsolidated affiliates | 214.2 | ||||||||
Intangible assets | $ 1,204 | $ 1,204 | 1,204 | ||||||
Other long-term assets | 6.6 | ||||||||
Current liabilities | (255.1) | ||||||||
Long-term debt | (1,573.3) | ||||||||
Deferred income tax liabilities, net | (8.6) | ||||||||
Other long-term liabilities | (9.1) | ||||||||
Total identifiable net assets | 4,580.2 | ||||||||
Noncontrolling interest in subsidiaries | (113.4) | ||||||||
Current liabilities retained by Targa | (0.5) | ||||||||
Goodwill | 557.9 | [1] | 557.9 | [1] | 557.9 | $ 0 | |||
Total fair value of consideration transferred | 5,024.2 | 5,024.2 | 5,024.2 | ||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||
Depreciation and amortization expense | (163.9) | $ (85.8) | (282.5) | $ (165.3) | |||||
Equity earnings | $ (1.5) | $ 4.2 | $ 0.5 | [2] | $ 9.1 | ||||
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] | Restatement Adjustment [Member] | |||||||||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||||||||
Depreciation and amortization expense | $ (1) | ||||||||
Equity earnings | $ 0.3 | ||||||||
[1] | Total assets include goodwill. | ||||||||
[2] | Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015, including the amortization of a basis difference resulting from acquisition date fair value accounting. |
Business Acquisitions, Continge
Business Acquisitions, Contingent Consideration and Replacement Phantom Units (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2015 | Feb. 27, 2015 | |
Phantom Unit Awards [Member] | ||
Business Acquisition [Line Items] | ||
Number of common units called by replacement equity unit (in shares) | 1 | |
Dividend payment period | 60 days | |
Phantom Unit Awards [Member] | Vesting Term One [Member] | ||
Business Acquisition [Line Items] | ||
Vesting percentage original term (in hundredths) | 25.00% | |
Vesting period of original term | 4 years | |
Phantom Unit Awards [Member] | Vesting Term Two [Member] | ||
Business Acquisition [Line Items] | ||
Vesting percentage original term (in hundredths) | 33.00% | |
Vesting period of original term | 3 years | |
Atlas Pipeline Partners [Member] | ||
Business Acquisition [Line Items] | ||
Contingent consideration additional amount | $ 6 | |
Contingent liability acquisition date fair value | 4.2 | $ 6 |
Contingent consideration liability lower range | 0 | |
Contingent consideration liability higher range | $ 6 |
Inventories (Details)
Inventories (Details) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Components of inventory [Abstract] | ||
Commodities | $ 112.7 | $ 157.4 |
Materials and supplies | 12.1 | 11.5 |
Total inventory | $ 124.8 | $ 168.9 |
Property, Plant and Equipment50
Property, Plant and Equipment and Intangible Assets (Details) - USD ($) $ in Millions | 6 Months Ended | ||
Jun. 30, 2015 | Feb. 27, 2015 | Dec. 31, 2014 | |
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | $ 11,595.2 | $ 6,514.3 | |
Accumulated depreciation | (1,910.9) | (1,689.7) | |
Property, plant and equipment, net | 9,684.3 | 4,824.6 | |
Finite-lived intangible assets, net [Abstract] | |||
Intangible assets | 1,885.6 | 681.8 | |
Accumulated amortization | (150) | (89.9) | |
Intangible assets, net | $ 1,735.6 | 591.9 | |
Estimated useful lives | 20 years | ||
Provisional value of intangible assets acquired | $ 1,204 | $ 1,204 | |
Amortization period of acquired intangible assets used for preparing financial statements | 4 months | ||
Estimated annual amortization expense for intangible assets [Abstract] | |||
2,015 | $ 130.1 | ||
2,016 | 148.3 | ||
2,017 | 141.5 | ||
2,018 | 127.8 | ||
2,019 | 116.8 | ||
Gathering Systems [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | $ 6,052.6 | 2,588.6 | |
Gathering Systems [Member] | Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful lives | 5 years | ||
Gathering Systems [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful lives | 40 years | ||
Processing and Fractionation Facilities [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | $ 2,976.1 | 1,884.1 | |
Processing and Fractionation Facilities [Member] | Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful lives | 5 years | ||
Processing and Fractionation Facilities [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful lives | 40 years | ||
Terminaling and Storage Facilities [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | $ 1,090 | 1,038.9 | |
Terminaling and Storage Facilities [Member] | Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful lives | 5 years | ||
Terminaling and Storage Facilities [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful lives | 25 years | ||
Transportation Assets [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | $ 438.7 | 359 | |
Transportation Assets [Member] | Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful lives | 10 years | ||
Transportation Assets [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful lives | 25 years | ||
Other Property, Plant and Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | $ 209.8 | 149.1 | |
Other Property, Plant and Equipment [Member] | Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful lives | 3 years | ||
Other Property, Plant and Equipment [Member] | Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful lives | 40 years | ||
Land [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | $ 102.6 | 95.6 | |
Construction in Progress [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment | $ 725.4 | $ 399 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Changes in asset retirement obligations [Roll Forward] | ||
Beginning of period | $ 56.8 | |
Preliminary fair value of ARO acquired with the APL merger | 4 | |
Change in cash flow estimate | 3.8 | $ 2.1 |
Accretion expense | 2.6 | $ 2.2 |
End of period | $ 67.2 |
Investments in Unconsolidated52
Investments in Unconsolidated Affiliates (Details) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2015USD ($)JointVenture | Jun. 30, 2014USD ($) | Jun. 30, 2015USD ($)JointVenture | Jun. 30, 2014USD ($) | |||
Schedule of Equity Method Investments [Line Items] | ||||||
Number of non-operated joint ventures acquired in Atlas mergers | JointVenture | 3 | 3 | ||||
Beginning of period | $ 50.2 | |||||
Preliminary fair value of T2 Joint Ventures acquired | 214.2 | |||||
Equity earnings | $ (1.5) | $ 4.2 | 0.5 | [1] | $ 9.1 | |
Cash distributions | [2] | (7) | ||||
Cash calls for expansion projects | 0.1 | |||||
End of period | 258 | 258 | ||||
Return of capital from unconsolidated affiliate | 0.1 | $ 3.6 | ||||
Basis difference on preliminary fair values | $ 39.6 | $ 39.6 | ||||
Preliminary estimated useful lives of the underlying assets | 20 years | |||||
Gulf Coast Fractionators LP. [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Ownership interest (in hundredths) | 38.80% | 38.80% | ||||
T2 La Salle [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Ownership interest (in hundredths) | 75.00% | 75.00% | ||||
T2 Eagle Ford [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Ownership interest (in hundredths) | 50.00% | 50.00% | ||||
T2 EF Co-Gen [Member] | ||||||
Schedule of Equity Method Investments [Line Items] | ||||||
Ownership interest (in hundredths) | 50.00% | 50.00% | ||||
[1] | Includes equity earnings of acquired investments since the date of acquisition of February 27, 2015, including the amortization of a basis difference resulting from acquisition date fair value accounting. | |||||
[2] | Includes $0.1 million distributions received in excess of our share of cumulative earnings for the six months ended June 30, 2015. Such excess distributions are considered a return of capital and are disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows. |
Accounts Payable and Accrued 53
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Components of accounts payable and accrued liabilities [Abstract] | ||
Commodities | $ 402.5 | $ 416.7 |
Other goods and services | 105.9 | 108.9 |
Interest | 63.3 | 37.3 |
Compensation and benefits | 1.8 | 1.3 |
Income and other taxes | 31.6 | 13.6 |
Other | 47.6 | 14.9 |
Total accounts payable and accrued liabilities | $ 652.7 | $ 592.7 |
Debt Obligations (Details)
Debt Obligations (Details) - USD ($) $ in Millions | 6 Months Ended | ||
Jun. 30, 2015 | Dec. 31, 2014 | ||
Long-term [Abstract] | |||
Long-term debt | $ 5,178.8 | $ 2,783.4 | |
Total Debt | 5,303 | 2,966.2 | |
Letters of credit outstanding | $ 20.5 | 44.1 | |
Senior Secured Credit Facility [Member] | |||
Range of interest rates and weighted average interest rate [Abstract] | |||
Range of interest rates incurred, minimum (in hundredths) | 1.90% | ||
Range of interest rates incurred, maximum (in hundredths) | 4.30% | ||
Weighted Average Interest Rate Incurred (in hundredths) | 2.00% | ||
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2017 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [1] | $ 878 | 0 |
Maturity Date | Oct. 31, 2017 | ||
Maximum borrowing capacity | $ 1,600 | ||
Remaining borrowing capacity | 701.5 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 1,100 | 0 | |
Interest rate on fixed rate debt (in hundredths) | 5.00% | ||
Maturity Date | Jan. 31, 2018 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 483.6 | 483.6 | |
Unamortized discount | $ (23.8) | (25.2) | |
Interest rate on fixed rate debt (in hundredths) | 6.875% | ||
Maturity Date | Feb. 28, 2021 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due August 2020 [Member] | Targa Pipeline Partners LP [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [2] | $ 342.1 | 0 |
Unamortized premium | $ 5.4 | 0 | |
Interest rate on fixed rate debt (in hundredths) | 6.625% | ||
Maturity Date | Aug. 31, 2020 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 300 | 300 | |
Interest rate on fixed rate debt (in hundredths) | 6.375% | ||
Maturity Date | Aug. 31, 2022 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 600 | 600 | |
Interest rate on fixed rate debt (in hundredths) | 5.25% | ||
Maturity Date | May 31, 2023 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 625 | 625 | |
Interest rate on fixed rate debt (in hundredths) | 4.25% | ||
Maturity Date | Nov. 30, 2023 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% notes due November 2019 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 800 | 800 | |
Interest rate on fixed rate debt (in hundredths) | 4.125% | ||
Maturity Date | Nov. 30, 2019 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Targa Pipeline Partners LP [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [2],[3] | $ 13.1 | 0 |
Unamortized premium | $ 0.2 | 0 | |
Interest rate on fixed rate debt (in hundredths) | 6.625% | ||
Maturity Date | Oct. 31, 2020 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | Targa Pipeline Partners LP [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [3] | $ 6.5 | 0 |
Interest rate on fixed rate debt (in hundredths) | 4.75% | ||
Maturity Date | Nov. 30, 2021 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | Targa Pipeline Partners LP [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [3] | $ 48.1 | 0 |
Unamortized premium | $ 0.6 | 0 | |
Interest rate on fixed rate debt (in hundredths) | 5.875% | ||
Maturity Date | Aug. 31, 2023 | ||
Accounts Receivable Securitization Facility [Member] | |||
Range of interest rates and weighted average interest rate [Abstract] | |||
Range of Interest Rates Incurred (in hundredths) | 0.90% | ||
Weighted Average Interest Rate Incurred (in hundredths) | 0.90% | ||
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility due December 2015 [Member] | |||
Debt Instrument [Line Items] | |||
Current debt | [1] | $ 124.2 | $ 182.8 |
Long-term [Abstract] | |||
Maturity Date | Dec. 31, 2015 | ||
[1] | As of June 30, 2015, availability under our $1.6 billion senior secured revolving credit facility was $701.5 million. | ||
[2] | In May 2015, we exchanged the TRP 6.625% Senior Notes with the same economic terms to the holders of the 2020 APL Notes (as defined below) who validly tendered such notes for exchange to us. | ||
[3] | Senior unsecured notes issued by APL entities and acquired in the Atlas mergers. While we consolidate the debt acquired in the Atlas mergers, we do not guarantee the acquired debt of APL. |
Debt Obligations, Financing Act
Debt Obligations, Financing Activities (Details) - USD ($) $ in Millions | 1 Months Ended | 6 Months Ended | |||
Feb. 28, 2015 | Jan. 31, 2015 | Jun. 30, 2015 | Jun. 30, 2014 | Apr. 30, 2015 | |
Debt Instrument [Line Items] | |||||
Net proceeds from issuance of senior notes | $ 1,100 | $ 0 | |||
Atlas Pipeline Partners [Member] | |||||
Debt Instrument [Line Items] | |||||
Cash payment related to change of control payments | $ 28.8 | ||||
Shelf Offering April 2015 [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate amount of debt or equity securities allowed under shelf agreement | $ 1,000 | ||||
Revolving Credit Facility [Member] | Atlas Pipeline Partners [Member] | |||||
Debt Instrument [Line Items] | |||||
Cash payments related to acquisition | 701.4 | ||||
Revolving Credit Facility [Member] | First Amendment [Member] | TRC Senior Secured Revolving Credit Facility due 2017 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maximum borrowing capacity | 1,600 | ||||
Additional commitment increase available upon request | $ 300 | ||||
Revolving Credit Facility [Member] | Original Agreement [Member] | TRC Senior Secured Revolving Credit Facility due 2017 [Member] | |||||
Debt Instrument [Line Items] | |||||
Maximum borrowing capacity | $ 1,200 | ||||
Additional commitment increase available upon request | 300 | ||||
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Aggregate principal amount | 1,100 | ||||
Net proceeds from issuance of senior notes | $ 1,089.8 |
Debt Obligations, APL Senior No
Debt Obligations, APL Senior Notes Tender Offers (Details) - USD ($) $ in Millions | Feb. 27, 2015 | Mar. 31, 2015 | Feb. 27, 2015 |
Atlas Pipeline Partners [Member] | |||
Results of tender offers [Abstract] | |||
Amount Tendered | $ 1,200 | ||
APL Senior Notes Tender Offers [Member] | |||
Results of tender offers [Abstract] | |||
Outstanding Note Balance | $ 1,550 | ||
Amount Tendered | 1,135.5 | ||
Premium Paid | 16.7 | ||
Accrued Interest Paid | 11.6 | ||
Total Tender Offer payments | 1,163.8 | ||
Note Balance after Tender Offers | 414.5 | 414.5 | |
APL Senior Notes Tender Offers [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||
Results of tender offers [Abstract] | |||
Outstanding Note Balance | 500 | ||
Amount Tendered | 140.1 | ||
Premium Paid | 2.1 | ||
Accrued Interest Paid | 3.7 | ||
Total Tender Offer payments | $ 145.9 | ||
Tendered percentage (in hundredths) | 28.02% | ||
Note Balance after Tender Offers | 359.9 | $ 359.9 | |
APL Senior Notes Tender Offers [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | |||
Results of tender offers [Abstract] | |||
Outstanding Note Balance | 400 | ||
Amount Tendered | 393.5 | ||
Premium Paid | 5.9 | ||
Accrued Interest Paid | 5.3 | ||
Total Tender Offer payments | $ 404.7 | ||
Tendered percentage (in hundredths) | 98.38% | ||
Note Balance after Tender Offers | 6.5 | $ 6.5 | |
APL Senior Notes Tender Offers [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | |||
Results of tender offers [Abstract] | |||
Outstanding Note Balance | 650 | ||
Amount Tendered | 601.9 | ||
Premium Paid | 8.7 | ||
Accrued Interest Paid | 2.6 | ||
Total Tender Offer payments | $ 613.2 | ||
Tendered percentage (in hundredths) | 92.60% | ||
Note Balance after Tender Offers | $ 48.1 | $ 48.1 | |
APL Senior Notes with Offers Tendered [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Atlas Pipeline Partners [Member] | |||
Results of tender offers [Abstract] | |||
Total Tender Offer payments | $ 5 |
Debt Obligations, Debt Redempti
Debt Obligations, Debt Redemption (Details) - USD ($) $ in Millions | 1 Months Ended | 2 Months Ended | 6 Months Ended | ||
Mar. 31, 2015 | Jan. 31, 2015 | Feb. 27, 2015 | Jun. 30, 2015 | Jun. 30, 2014 | |
Results of tender offers [Abstract] | |||||
Repayment of debt | $ 1,168.8 | $ 0 | |||
APL Senior Notes Tender Offers [Member] | |||||
Results of tender offers [Abstract] | |||||
Total tender offer payments | $ 1,163.8 | ||||
APL Senior Notes Tender Offers [Member] | Atlas Pipeline Partners [Member] | |||||
Results of tender offers [Abstract] | |||||
Repayment of debt | $ 1,168.8 | ||||
APL Senior Notes Tender Offers [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||||
Results of tender offers [Abstract] | |||||
Total tender offer payments | $ 145.9 | ||||
APL Senior Notes with Offers Tendered [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Atlas Pipeline Partners [Member] | |||||
Results of tender offers [Abstract] | |||||
Repayment of debt | $ 4.8 | ||||
Total tender offer payments | $ 5 |
Debt Obligations, Exchange Offe
Debt Obligations, Exchange Offer and Consent Solicitation and TRP Note Guarantees (Details) - Senior Unsecured 6 5/8% Notes due October 2020 [Member] - Atlas Pipeline Partners [Member] - USD ($) $ in Millions | Apr. 27, 2015 | May. 31, 2015 |
Debt Instrument [Line Items] | ||
Tendered percentage (in hundredths) | 96.30% | |
Aggregate principal amount outstanding | $ 342.1 | |
Unamortized premium | $ 5.6 |
Partnership Units and Related59
Partnership Units and Related Matters, Issuances of Common Units (Details) - USD ($) $ in Millions | Feb. 27, 2015 | Jul. 31, 2015 | Mar. 31, 2015 | Jun. 30, 2015 | Jun. 30, 2014 |
Partnership Equity [Abstract] | |||||
Amount contributed to maintain general partner ownership percentage | $ 58.7 | $ 0 | |||
General partner ownership interest (in hundredths) | 2.00% | ||||
Atlas Energy [Member] | Targa Pipeline Partners LP [Member] | Common Units [Member] | |||||
Partnership Equity [Abstract] | |||||
Number of common units included in public offerings (in shares) | 3,363,935 | ||||
Atlas Energy [Member] | Targa Resources Corp [Member] | Common Units [Member] | |||||
Partnership Equity [Abstract] | |||||
Number of common units included in public offerings (in shares) | 10,126,532 | ||||
Atlas Pipeline Partners [Member] | Common Unit Holders [Member] | |||||
Partnership Equity [Abstract] | |||||
Number of common units included in public offerings (in shares) | 58,614,157 | ||||
Atlas Pipeline Partners [Member] | Targa Resources Corp [Member] | |||||
Partnership Equity [Abstract] | |||||
Amount contributed to maintain general partner ownership percentage | $ 52.4 | ||||
General partner ownership interest (in hundredths) | 2.00% | ||||
May 2014 EDA [Member] | |||||
Partnership Equity [Abstract] | |||||
Number of common units included in public offerings (in shares) | 3,590,826 | ||||
Dollar amount of Common Units able to sell from Equity Distribution Agreement | $ 400 | ||||
Net proceeds from public offering | $ 153 | ||||
Commissions to sales agents, maximum (in hundredths) | 1.00% | ||||
Amount contributed to maintain general partner ownership percentage | $ 3.1 | ||||
General partner ownership interest (in hundredths) | 2.00% | ||||
May 2015 EDA [Member] | |||||
Partnership Equity [Abstract] | |||||
Number of common units included in public offerings (in shares) | 3,222,981 | ||||
Dollar amount of Common Units able to sell from Equity Distribution Agreement | $ 1,000 | ||||
Net proceeds from public offering | $ 140.5 | ||||
Commissions to sales agents, maximum (in hundredths) | 0.75% | ||||
Amount contributed to maintain general partner ownership percentage | $ 2.9 | ||||
General partner ownership interest (in hundredths) | 2.00% | ||||
May 2015 EDA [Member] | Subsequent Event [Member] | |||||
Partnership Equity [Abstract] | |||||
Number of common units included in public offerings (in shares) | 563,573 | ||||
Proceeds from public offering, net of commissions | $ 22.6 | ||||
Amount contributed to maintain general partner ownership percentage | 0.5 | ||||
Amount contributed subsequent to the reporting period to maintain general partner ownership percentage related to the reporting period | $ 0.9 | ||||
General partner ownership interest (in hundredths) | 2.00% | ||||
Amount which remain available under the shelf agreement | $ 835.6 |
Partnership Units and Related60
Partnership Units and Related Matters, Distributions (Details) - USD ($) | 3 Months Ended | 6 Months Ended | |||||
Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |||
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 [Abstract] | |||||||
Total distributions to general and limited partners | $ 331,700,000 | $ 237,100,000 | |||||
Distributions Declared [Member] | |||||||
Distributions declared and/or paid [Abstract] | |||||||
Date Paid or to be paid | Aug. 15, 2015 | ||||||
Distribution to limited partners common | $ 152,500,000 | ||||||
Distributions to general partners (Incentive distribution rights) | [1] | 43,900,000 | |||||
Distributions to general partners (2%) | 4,000,000 | ||||||
Total distributions to general and limited partners | $ 200,400,000 | ||||||
Distributions per limited partner per unit (in dollars per unit) | $ 0.8250 | ||||||
Distributions Paid [Member] | |||||||
Distributions declared and/or paid [Abstract] | |||||||
Date Paid or to be paid | May 14, 2015 | Feb. 13, 2015 | |||||
Distributions to limited partners Common | $ 148,300,000 | $ 96,300,000 | |||||
Distributions to general partners (Incentive distribution rights) | 41,700,000 | [1] | 38,400,000 | ||||
Distributions to general partners (2%) | 3,900,000 | 2,700,000 | |||||
Total distributions to general and limited partners | $ 193,900,000 | $ 137,400,000 | |||||
Distributions per limited partner per unit (in dollars per unit) | $ 0.8200 | $ 0.8100 | |||||
Atlas Pipeline Partners [Member] | |||||||
Distributions declared and/or paid [Abstract] | |||||||
Reduction in incentive distribution | $ 9,375,000 | $ 9,375,000 | |||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 1 [Member] | |||||||
Distributions declared and/or paid [Abstract] | |||||||
Reduction in incentive distribution | 9,375,000 | ||||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 2 [Member] | |||||||
Distributions declared and/or paid [Abstract] | |||||||
Reduction in incentive distribution | 6,250,000 | ||||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 3 [Member] | |||||||
Distributions declared and/or paid [Abstract] | |||||||
Reduction in incentive distribution | 2,500,000 | ||||||
Atlas Pipeline Partners [Member] | Distribution Rights Year 4 [Member] | |||||||
Distributions declared and/or paid [Abstract] | |||||||
Reduction in incentive distribution | $ 1,250,000 | ||||||
[1] | Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDR's of $9.375 million were allocated to common unitholders in the first and second quarter of 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and will result in reallocation of IDR payments to common unitholders at the following amounts: $9.375 million per quarter for 2015, $6.25 million per quarter for 2016, $2.5 million per quarter for 2017 and $1.25 million per quarter for 2018. |
Earnings per Limited Partner 61
Earnings per Limited Partner Unit (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Earnings per Limited Partner Unit [Abstract] | |||||
Net income | $ 53.3 | $ 120.9 | $ 131.1 | $ 252.2 | |
Less: Net income attributable to noncontrolling interests | 7.5 | 12.1 | 12.5 | 21 | |
Net income attributable to Targa Resources Partners LP | 45.8 | 108.8 | 118.6 | 231.2 | |
Net income attributable to general partner | 44.6 | 35.8 | 87.1 | 69.6 | |
Net income attributable to limited partners | 1.2 | 73 | 31.5 | 161.6 | |
Net income attributable to Targa Resources Partners LP | $ 45.8 | $ 108.8 | $ 118.6 | $ 231.2 | |
Weighted average units outstanding - basic (in shares) | 181,900,000 | 114,200,000 | 159,700,000 | 113,300,000 | |
Net income available per limited partner unit - basic (in dollars per share) | $ 0.01 | $ 0.64 | $ 0.20 | $ 1.43 | |
Weighted average units outstanding (in shares) | 181,900,000 | 114,200,000 | 159,700,000 | 113,300,000 | |
Dilutive effect of unvested stock awards (in shares) | 700,000 | 700,000 | 400,000 | 600,000 | |
Weighted average units outstanding - diluted (in shares) | [1] | 182,600,000 | 114,900,000 | 160,100,000 | 113,900,000 |
Net income available per limited partner unit - diluted (in dollars per share) | $ 0.01 | $ 0.64 | $ 0.20 | $ 1.42 | |
Shares excluded from computation of diluted earnings (in shares) | 173,125 | 180,413 | |||
[1] | For the three and six months ended June 30, 2015, approximately 173,125 units and 180,413 units were excluded from the computation of diluted earnings per unit because the inclusion of such units would have been anti-dilutive. |
Derivative Instruments and He62
Derivative Instruments and Hedging Activities (Details) $ in Millions | 3 Months Ended | 6 Months Ended | |
Jun. 30, 2015USD ($) | Jun. 30, 2015USD ($)MMBTUbbl | Feb. 27, 2015USD ($) | |
Derivative [Line Items] | |||
Fair value of derivative assets | $ | $ 102.1 | ||
Atlas Pipeline Partners [Member] | |||
Derivative [Line Items] | |||
Fair value of derivative assets | $ | 102.1 | ||
Fair value of derivative contracts received as component of derivative contract settlement | $ | $ 23.1 | $ 31.5 | |
Ineffectiveness gains (losses) | $ | (0.2) | $ 0.9 | |
Swaps [Member] | Year 2015 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 134,141 | ||
Swaps [Member] | Year 2015 [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 5,015 | ||
Swaps [Member] | Year 2015 [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 1,826 | ||
Swaps [Member] | Year 2016 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 68,205 | ||
Swaps [Member] | Year 2016 [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 2,254 | ||
Swaps [Member] | Year 2016 [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 1,082 | ||
Swaps [Member] | Year 2017 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 23,082 | ||
Swaps [Member] | Year 2017 [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 658 | ||
Swaps [Member] | Year 2017 [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 500 | ||
Swaps [Member] | Year 2018 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 | ||
Swaps [Member] | Year 2018 [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 0 | ||
Swaps [Member] | Year 2018 [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 0 | ||
Basis Swaps [Member] | Year 2015 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 55,734 | ||
Basis Swaps [Member] | Year 2016 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 18,853 | ||
Basis Swaps [Member] | Year 2017 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 9,041 | ||
Basis Swaps [Member] | Year 2018 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 | ||
Collars [Member] | Year 2015 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 | ||
Collars [Member] | Year 2016 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 7,500 | ||
Collars [Member] | Year 2017 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 7,500 | ||
Collars [Member] | Year 2018 [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 1,849 | ||
Option/Collars [Member] | Year 2015 [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 1,083 | ||
Option/Collars [Member] | Year 2015 [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 1,605 | ||
Option/Collars [Member] | Year 2016 [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 920 | ||
Option/Collars [Member] | Year 2016 [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 790 | ||
Option/Collars [Member] | Year 2017 [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 920 | ||
Option/Collars [Member] | Year 2017 [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 790 | ||
Option/Collars [Member] | Year 2018 [Member] | NGL [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 32 | ||
Option/Collars [Member] | Year 2018 [Member] | Condensate [Member] | |||
Derivative [Line Items] | |||
Notional volumes of commodity hedges (in Bbl per day) | 101 | ||
Options [Member] | Crude Oil [Member] | Atlas Pipeline Partners [Member] | |||
Derivative [Line Items] | |||
Fair value of derivative assets | $ | $ 7.7 | ||
Mark-to-market losses | $ | $ 1.3 | $ 0.2 |
Derivative Instruments and He63
Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, By Derivative Contract Type (Details) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets | $ 132.1 | $ 60.2 |
Derivative liabilities | 7.2 | 5.2 |
Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 91.8 | 44.4 |
Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 40.3 | 15.8 |
Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 1.9 | 5.2 |
Long-term Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 5.3 | 0 |
Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 127.6 | 60.2 |
Derivative liabilities | 7.2 | 0 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 87.3 | 44.4 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 40.3 | 15.8 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 1.9 | 0 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 5.3 | 0 |
Not Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 4.5 | 0 |
Derivative liabilities | 0 | 5.2 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 4.5 | 0 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | $ 0 | $ 5.2 |
Derivative Instruments and He64
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Derivative Asset [Abstract] | ||
Pro forma net presentation, asset | $ 124.9 | |
Gross asset | 132.1 | $ 60.2 |
Pro forma net presentation, asset, total | 124.9 | 55.8 |
Counterparties with Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 111 | 35.5 |
Gross liability | 7.2 | 4.4 |
Pro forma net presentation, asset | 103.8 | 31.1 |
Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 21.1 | 24.7 |
Current Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 91.8 | 44.4 |
Pro forma net presentation, asset, current | 89.9 | 40 |
Current Position [Member] | Counterparties with Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 77.2 | 35.5 |
Gross liability | 1.9 | 4.4 |
Pro forma net presentation, asset | 75.3 | 31.1 |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 14.6 | 8.9 |
Long-term Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 40.3 | 15.8 |
Pro forma net presentation, asset, noncurrent | 35 | 15.8 |
Long-term Position [Member] | Counterparties with Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 33.8 | 0 |
Gross liability | 5.3 | 0 |
Pro forma net presentation, asset | 28.5 | 0 |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | $ 6.5 | $ 15.8 |
Derivative Instruments and He65
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Derivative Liability [Abstract] | ||
Gross liability | $ 7.2 | $ 5.2 |
Pro forma net presentation, liability, total | 0 | 0.8 |
Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 0 | 0.8 |
Current Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 1.9 | 5.2 |
Pro forma net presentation, liability, current | 0 | 0.8 |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 0 | 0.8 |
Long-term Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 5.3 | 0 |
Pro forma net presentation, liability, noncurrent | 0 | 0 |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | $ 0 | $ 0 |
Derivative Instruments and He66
Derivative Instruments and Hedging Activities, Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | ||
Cash Flow Hedging [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Gain (loss) reclassified from OCI into income (effective portion) | $ 16.3 | $ (5.6) | $ 24.4 | $ (13.2) | ||
Cash Flow Hedging [Member] | Interest Expense, Net [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Gain (loss) reclassified from OCI into income (effective portion) | 0 | (1.1) | 0 | (2.4) | ||
Cash Flow Hedging [Member] | Revenues [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Gain (loss) reclassified from OCI into income (effective portion) | 16.3 | (4.5) | 24.4 | (10.8) | ||
Cash Flow Hedging [Member] | Commodity Contracts [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Gain (loss) recognized in OCI on derivatives (effective portion) | (8.7) | (6.8) | 16.5 | (18.6) | ||
Deferred gains (losses) included in accumulated OCI | [1] | 52.4 | 52.4 | $ 60.3 | ||
Net gains on commodity hedges recorded in OCI that are expected to be reclassified to revenue within twelve months | 36.1 | 36.1 | ||||
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Revenues [Member] | ||||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||||
Gain (loss) recognized in income on derivatives | $ (4) | $ (0.1) | $ 3.2 | $ (0.3) | ||
[1] | Includes deferred net gains of $36.1 million as of June 30, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months. |
Fair Value Measurements (Detail
Fair Value Measurements (Details) $ in Millions | 6 Months Ended | ||
Jun. 30, 2015USD ($)Swap | Dec. 31, 2014USD ($) | ||
Fair Value Measurements [Abstract] | |||
Derivatives financial instruments, fair value, net | $ 124.9 | ||
Derivative fair value of net asset if commodity price increases by 10 percent | 92.5 | ||
Derivative fair value of net asset if commodity price decreases by 10 percent | $ 154.6 | ||
Number of natural gas basis swaps categorized as Level 3 | Swap | 29 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | $ 124.9 | $ 55.8 | |
Liability from commodity derivative contracts | 0 | $ 0.8 | |
Carrying Value [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 132.1 | |
Liability from commodity derivative contracts | [1] | 7.2 | |
TPL contingent consideration | [2] | 4.2 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 85.5 | ||
Carrying Value [Member] | Senior Secured Revolving Credit Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 878 | ||
Carrying Value [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 4,300.8 | ||
Carrying Value [Member] | Accounts Receivable Securitization Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 124.2 | ||
Fair Value [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 132.1 | |
Liability from commodity derivative contracts | [1] | 7.2 | |
TPL contingent consideration | [2] | 4.2 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 85.5 | ||
Fair Value [Member] | Senior Secured Revolving Credit Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 878 | ||
Fair Value [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 4,360.8 | ||
Fair Value [Member] | Accounts Receivable Securitization Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 124.2 | ||
Fair Value [Member] | Level 1 [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 0 | |
Liability from commodity derivative contracts | [1] | 0 | |
TPL contingent consideration | [2] | 0 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 0 | ||
Fair Value [Member] | Level 1 [Member] | Senior Secured Revolving Credit Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 0 | ||
Fair Value [Member] | Level 1 [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 0 | ||
Fair Value [Member] | Level 1 [Member] | Accounts Receivable Securitization Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 0 | ||
Fair Value [Member] | Level 2 [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 129 | |
Liability from commodity derivative contracts | [1] | 4.8 | |
TPL contingent consideration | [2] | 0 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 0 | ||
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 | 878 | ||
Fair Value [Member] | Level 2 [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 4,360.8 | ||
Fair Value [Member] | Level 2 [Member] | Accounts Receivable Securitization Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 124.2 | ||
Fair Value [Member] | Level 3 [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | |||
Assets from commodity derivative contracts | [1] | 3.1 | |
Liability from commodity derivative contracts | [1] | 2.4 | |
TPL contingent consideration | [2] | 4.2 | |
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Cash and cash equivalents | 0 | ||
Fair Value [Member] | Level 3 [Member] | Senior Secured Revolving Credit Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 0 | ||
Fair Value [Member] | Level 3 [Member] | Senior Unsecured Notes [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 0 | ||
Fair Value [Member] | Level 3 [Member] | Accounts Receivable Securitization Facility [Member] | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | |||
Long-term debt | 0 | ||
Contingent Liability [Member] | |||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |||
Balance, beginning of period | 0 | ||
TPL contingent consideration (see Note 4-Business Acquisitions) | 4.2 | ||
New Level 3 instrument | 0 | ||
Transfers out of Level 3 | 0 | ||
Balance, end of period | 4.2 | ||
Commodity Derivative Contracts Asset/(Liability) | |||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |||
Balance, beginning of period | (1.7) | ||
TPL contingent consideration (see Note 4-Business Acquisitions) | 0 | ||
New Level 3 instruments | (0.7) | ||
Transfers out of Level 3 | 1.7 | ||
Balance, end of period | $ (0.7) | ||
[1] | The fair value of our derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 13 - Derivative Instruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-term portions for Consolidated Balance Sheets classification purposes. | ||
[2] | See Note 4 - Business Acquisitions |
Related Party Transactions - 68
Related Party Transactions - Targa (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Summary of transactions with Targa [Abstract] | ||||
Cash contributions from Targa to maintain its 2% general partner ownership | $ 58.7 | $ 3.4 | ||
General partner interest (in hundredths) | 2.00% | |||
Targa Resources Corp. [Member] | ||||
Summary of transactions with Targa [Abstract] | ||||
Targa billings of payroll and related costs included in operating expense | $ 42 | $ 31.6 | $ 77 | 61.5 |
Targa allocation of general and administrative expense | 40.6 | 23.2 | 79 | 46 |
Cash distributions to Targa based on unit ownership | 59 | 44 | 110.4 | 85.5 |
Cash contributions from Targa to maintain its 2% general partner ownership | $ 5.1 | $ 1 | $ 58.7 | $ 3.4 |
General partner interest (in hundredths) | 2.00% |
Contingencies (Details)
Contingencies (Details) - Atlas Unitholder Litigation [Member] - Unitholder | 2 Months Ended | 3 Months Ended |
Nov. 30, 2014 | Dec. 31, 2014 | |
Atlas Pipeline Partners [Member] | ||
Loss Contingencies [Line Items] | ||
Number of public unitholders | 5 | |
Atlas Energy [Member] | ||
Loss Contingencies [Line Items] | ||
Number of public unitholders | 2 |
Supplemental Cash Flow Inform70
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | Feb. 27, 2015 | Jun. 30, 2015 | Jun. 30, 2014 | |
Cash [Abstract] | ||||
Interest paid, net of capitalized interest | [1] | $ 91.3 | $ 61.4 | |
Income taxes paid, net of refunds | 4.1 | 2 | ||
Non-cash Investing and Financing balance sheet movements [Abstract] | ||||
Debt additions and retirements related to exchange of TRP 6.625% Notes for APL 6.625% Notes | 342.1 | 0 | ||
Deadstock commodity inventories transferred to property, plant and equipment | 0.5 | 15.9 | ||
Reductions in Owner's Equity related to accrued distributions on unvested equity awards under share compensation arrangements | 0.7 | 1.4 | ||
Receivables from equity issuances | (0.1) | 0.3 | ||
Impact of capital expenditure accruals on property, plant and equipment | (52.9) | (30.1) | ||
Transfers from materials and supplies inventory to property, plant and equipment | 1.6 | 1.4 | ||
Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate | 3.8 | 2.1 | ||
Non-cash balance sheet movements related to business acquisition: (see Note 4 - Business Acquisitions) [Abstract] | ||||
Non-cash merger consideration - common units and replacement equity awards | 2,583.5 | 0 | ||
Special GP Interest | 1,612.4 | 0 | ||
Current liabilities retained by Targa | (0.4) | 0 | ||
Net non-cash balance sheet movements excluded from consolidated statements of cash flows | 4,195.5 | 0 | ||
Net cash merger consideration included in investing activities | 828.7 | 0 | ||
Total fair value of consideration transferred | 5,024.2 | 0 | ||
Interest capitalized on major projects | $ 5.5 | $ 11.5 | ||
Atlas Pipeline Partners [Member] | ||||
Non-cash balance sheet movements related to business acquisition: (see Note 4 - Business Acquisitions) [Abstract] | ||||
Net cash merger consideration included in investing activities | [2] | $ 828.7 | ||
Atlas Pipeline Partners [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest rate on fixed rate debt (in hundredths) | 6.625% | |||
Targa Resources Corp [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | ||||
Debt Instrument [Line Items] | ||||
Interest rate on fixed rate debt (in hundredths) | 6.625% | |||
[1] | Interest capitalized on major projects was $5.5 million and $11.5 million for the six months ended June 30, 2015 and 2014. | |||
[2] | We acquired $35.3 million of cash. |
Segment Information, Revenues a
Segment Information, Revenues and Operating Margin (Details) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015USD ($) | Jun. 30, 2014USD ($) | Jun. 30, 2015USD ($)DivisionSegment | Jun. 30, 2014USD ($) | |
Segment Reporting Information [Line Items] | ||||
Number of divisions | Division | 2 | |||
Sales of commodities | $ 1,396.1 | $ 1,759.2 | $ 2,798.3 | $ 3,844.1 |
Fees from midstream services | 303.3 | 241.4 | 580.8 | 451.2 |
Revenues | 1,699.4 | 2,000.6 | 3,379.1 | 4,295.3 |
Operating margin | 325.5 | 277.4 | $ 625.6 | 552.7 |
Gathering and Processing [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Number of reportable segments per division | Segment | 2 | |||
Field Gathering and Processing [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 755 | 489 | $ 1,203.5 | 976.9 |
Operating margin | 138.2 | 97.7 | 217.3 | 191.7 |
Coastal Gathering and Processing [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 117.7 | 263.6 | 241.8 | 548.8 |
Operating margin | 6.5 | 21.8 | $ 14.1 | 47.8 |
Logistics and Marketing [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Number of reportable segments per division | Segment | 2 | |||
Logistics Assets [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 185.5 | 174.7 | $ 374.3 | 330.7 |
Operating margin | 112.7 | 108.6 | 238.1 | 205.4 |
Marketing and Distribution [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 1,035.6 | 1,841.4 | 2,368.9 | 3,996.6 |
Operating margin | 51 | 53.3 | 117.3 | 117.9 |
Other Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 17.1 | (4) | 38.8 | (10.1) |
Operating margin | 17.1 | (4) | 38.8 | (10.1) |
Corporate And Elimination [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | (411.5) | (764.1) | (848.2) | (1,547.6) |
Operating margin | 0 | 0 | 0 | 0 |
Operating Segments [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 434.1 | 62.9 | 602 | 108.7 |
Fees from midstream services | 106.2 | 43.1 | 169.5 | 83.9 |
Revenues | 540.3 | 106 | 771.5 | 192.6 |
Operating Segments [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 52.6 | 89.7 | 105.3 | 190.2 |
Fees from midstream services | 7.4 | 10.5 | 16.1 | 18.2 |
Revenues | 60 | 100.2 | 121.4 | 208.4 |
Operating Segments [Member] | Logistics Assets [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 30.8 | 28.9 | 58.1 | 49.9 |
Fees from midstream services | 89.6 | 72.7 | 177.4 | 140.8 |
Revenues | 120.4 | 101.6 | 235.5 | 190.7 |
Operating Segments [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 861.5 | 1,581.7 | 1,994.1 | 3,505.4 |
Fees from midstream services | 100.1 | 115.1 | 217.8 | 208.3 |
Revenues | 961.6 | 1,696.8 | 2,211.9 | 3,713.7 |
Operating Segments [Member] | Other Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 17.1 | (4) | 38.8 | (10.1) |
Fees from midstream services | 0 | 0 | 0 | 0 |
Revenues | 17.1 | (4) | 38.8 | (10.1) |
Operating Segments [Member] | Corporate And Elimination [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 0 | 0 | 0 | 0 |
Fees from midstream services | 0 | 0 | 0 | 0 |
Revenues | 0 | 0 | 0 | 0 |
Intersegment Eliminations [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 0 | 0 | 0 | 0 |
Fees from midstream services | 0 | 0 | 0 | 0 |
Revenues | 0 | 0 | 0 | 0 |
Intersegment Eliminations [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 212.8 | 381.9 | 428.2 | 782.2 |
Fees from midstream services | 1.9 | 1.1 | 3.8 | 2.1 |
Revenues | 214.7 | 383 | 432 | 784.3 |
Intersegment Eliminations [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 57.7 | 163.4 | 120.4 | 340.4 |
Fees from midstream services | 0 | 0 | 0 | 0 |
Revenues | 57.7 | 163.4 | 120.4 | 340.4 |
Intersegment Eliminations [Member] | Logistics Assets [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 2 | 0.8 | 3.2 | 1.4 |
Fees from midstream services | 63.1 | 72.3 | 135.6 | 138.6 |
Revenues | 65.1 | 73.1 | 138.8 | 140 |
Intersegment Eliminations [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 68.6 | 137 | 147.1 | 267.5 |
Fees from midstream services | 5.4 | 7.6 | 9.9 | 15.4 |
Revenues | 74 | 144.6 | 157 | 282.9 |
Intersegment Eliminations [Member] | Other Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | 0 | 0 | 0 | 0 |
Fees from midstream services | 0 | 0 | 0 | 0 |
Revenues | 0 | 0 | 0 | 0 |
Intersegment Eliminations [Member] | Corporate And Elimination [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Sales of commodities | (341.1) | (683.1) | (698.9) | (1,391.5) |
Fees from midstream services | (70.4) | (81) | (149.3) | (156.1) |
Revenues | $ (411.5) | $ (764.1) | $ (848.2) | $ (1,547.6) |
Segment Information, Other Fina
Segment Information, Other Financial Information (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||||||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Feb. 27, 2015 | Dec. 31, 2014 | ||||
Other financial information [Abstract] | |||||||||
Total assets | $ 13,237.6 | [1] | $ 6,240 | $ 13,237.6 | [1] | $ 6,240 | $ 6,377.2 | ||
Goodwill | 557.9 | [2] | 557.9 | [2] | $ 557.9 | $ 0 | |||
Capital expenditures | 229.1 | 215.5 | 384.9 | 390.9 | |||||
Business acquisition | 5,024.2 | 5,024.2 | $ 5,024.2 | ||||||
Field Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 10,116.7 | [1] | 3,338.6 | 10,116.7 | [1] | 3,338.6 | |||
Coastal Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 350 | [1] | 377 | 350 | [1] | 377 | |||
Logistics Assets [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 1,831.2 | [1] | 1,606 | 1,831.2 | [1] | 1,606 | |||
Marketing and Distribution [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 475 | [1] | 799.4 | 475 | [1] | 799.4 | |||
Other Segment [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 132.2 | [1] | 3.5 | 132.2 | [1] | 3.5 | |||
Corporate And Elimination [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 332.5 | [1] | 115.5 | 332.5 | [1] | 115.5 | |||
Operating Segments [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Goodwill | [2] | 557.9 | 557.9 | ||||||
Capital expenditures | 142.7 | 128.4 | 235.6 | 227.3 | |||||
Business acquisition | 5,024.2 | 5,024.2 | |||||||
Operating Segments [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Goodwill | [2] | 0 | 0 | ||||||
Capital expenditures | 4.8 | 3.1 | 6 | 7.4 | |||||
Business acquisition | 0 | 0 | |||||||
Operating Segments [Member] | Logistics Assets [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Goodwill | [2] | 0 | 0 | ||||||
Capital expenditures | 74.4 | 67.5 | 132.1 | 136.1 | |||||
Business acquisition | 0 | 0 | |||||||
Operating Segments [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Goodwill | [2] | 0 | 0 | ||||||
Capital expenditures | 5.9 | 15.5 | 8.9 | 18.6 | |||||
Business acquisition | 0 | 0 | |||||||
Operating Segments [Member] | Other Segment [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Goodwill | [2] | 0 | 0 | ||||||
Capital expenditures | 0 | 0 | 0 | 0 | |||||
Business acquisition | 0 | 0 | |||||||
Operating Segments [Member] | Corporate And Elimination [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Goodwill | [2] | 0 | 0 | ||||||
Capital expenditures | 1.3 | $ 1 | 2.3 | $ 1.5 | |||||
Business acquisition | $ 0 | $ 0 | |||||||
[1] | Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with our debt obligations. | ||||||||
[2] | Total assets include goodwill. |
Segment Information, Revenues b
Segment Information, Revenues by Product and Service (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Revenue from External Customer [Line Items] | ||||
Sales of commodities | $ 1,396.1 | $ 1,759.2 | $ 2,798.3 | $ 3,844.1 |
Fees from midstream services | 303.3 | 241.4 | 580.8 | 451.2 |
Revenues | 1,699.4 | 2,000.6 | 3,379.1 | 4,295.3 |
Natural Gas [Member] | ||||
Revenue from External Customer [Line Items] | ||||
Sales of commodities | 443.5 | 358.1 | 750.9 | 750.4 |
NGL [Member] | ||||
Revenue from External Customer [Line Items] | ||||
Sales of commodities | 854.1 | 1,335.5 | 1,884.6 | 2,986.4 |
Condensate [Member] | ||||
Revenue from External Customer [Line Items] | ||||
Sales of commodities | 51.3 | 41.8 | 72.8 | 70.1 |
Petroleum Products [Member] | ||||
Revenue from External Customer [Line Items] | ||||
Sales of commodities | 30.1 | 28.2 | 56.5 | 48.3 |
Derivative Activities [Member] | ||||
Revenue from External Customer [Line Items] | ||||
Sales of commodities | 17.1 | (4.4) | 33.5 | (11.1) |
Fractionating and Treating [Member] | ||||
Revenue from External Customer [Line Items] | ||||
Fees from midstream services | 54.7 | 51.7 | 104.5 | 98.2 |
Storage, Terminaling, Transportation and Export [Member] | ||||
Revenue from External Customer [Line Items] | ||||
Fees from midstream services | 121.6 | 125.9 | 257.7 | 227.1 |
Gathering and Processing [Member] | ||||
Revenue from External Customer [Line Items] | ||||
Fees from midstream services | 105.7 | 48 | 174.1 | 90.6 |
Other [Member] | ||||
Revenue from External Customer [Line Items] | ||||
Fees from midstream services | $ 21.3 | $ 15.8 | $ 44.5 | $ 35.3 |
Segment Information, Reconcilia
Segment Information, Reconciliation of Operating Margin to Net Income (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Reconciliation of operating margin to net income [Abstract] | ||||
Operating margin | $ 325.5 | $ 277.4 | $ 625.6 | $ 552.7 |
Depreciation and amortization expense | (163.9) | (85.8) | (282.5) | (165.3) |
General and administrative expense | (46.8) | (39.1) | (87.1) | (74.8) |
Interest expense, net | (62.2) | (34.9) | (113.1) | (68.1) |
Other, net | 0.4 | 4.6 | (11) | 10.1 |
Total Income tax (expense)/benefit | 0.3 | (1.3) | (0.8) | (2.4) |
Net income | $ 53.3 | $ 120.9 | $ 131.1 | $ 252.2 |