Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 17, 2016 | Jun. 30, 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 | ||
Entity Public Float | $ 6,669 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Limited Partner Interest [Member] | |||
Entity Information [Line Items] | |||
Entity Common Stock, Shares Outstanding | 184,899,602 | ||
General Partner Units [Member] | |||
Entity Information [Line Items] | |||
Entity Common Stock, Shares Outstanding | 3,773,461 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | |
Current assets: | |||
Cash and cash equivalents | $ 135.4 | $ 72.3 | |
Trade receivables, net of allowances of $0.1 and $0.0 million at December 31, 2015 and December 31, 2014 | 514.8 | 566.8 | |
Inventories | 141 | 168.9 | |
Assets from risk management activities | 92.2 | 44.4 | |
Other current assets | 10 | 3.8 | |
Total current assets | 893.4 | 856.2 | |
Property, plant and equipment | 11,928.2 | 6,514.3 | |
Accumulated depreciation | (2,225.6) | (1,689.7) | |
Property, plant and equipment, net | 9,702.6 | 4,824.6 | |
Intangible assets, net | 1,810.1 | 591.9 | |
Goodwill | 417 | [1] | 0 |
Long-term assets from risk management activities | 34.9 | 15.8 | |
Investments in unconsolidated affiliates | 258.9 | 50.2 | |
Other long-term assets | 48.1 | 38.5 | |
Total assets | 13,165 | [2] | 6,377.2 |
Current liabilities: | |||
Accounts payable and accrued liabilities | 635.8 | 592.7 | |
Accounts payable to Targa Resources Corp. | 30 | 53.2 | |
Liabilities from risk management activities | 5.2 | 5.2 | |
Accounts receivable securitization facility | 219.3 | 182.8 | |
Total current liabilities | 890.3 | 833.9 | |
Long-term debt | 5,164 | 2,783.4 | |
Long-term liabilities from risk management activities | 2.4 | 0 | |
Deferred income taxes, net | 27.2 | 13.7 | |
Other long-term liabilities | $ 178.2 | $ 57.8 | |
Contingencies (see Note 17) | |||
Owners' equity | |||
Series A preferred limited partners (5,000,000 units issued and 5,000,000 outstanding as of December 31, 2015) | $ 120.6 | $ 0 | |
Common limited partners (185,083,420 and 118,652,798 units issued and 184,870,693 and 118,586,056 outstanding as of December 31, 2015 and December 31, 2014) | 4,550.4 | 2,384.1 | |
General partner ( 3,772,871 and 2,420,124 units issued and 3,772,871 and 2,420,124 outstanding as of December 31, 2015 and December 31, 2014) | 1,735.3 | 78.6 | |
Receivables from unit issuances | 0 | (1) | |
Accumulated other comprehensive income (loss) | 86.8 | 60.3 | |
Treasury units at cost (212,727 units as of December 31, 2015, and 66,742 as of December 31, 2014) | (10.3) | (4.8) | |
Partners' Capital | 6,482.8 | 2,517.2 | |
Noncontrolling interests in subsidiaries | 420.1 | 171.2 | |
Total owners' equity | 6,902.9 | 2,688.4 | |
Total liabilities and owners' equity | $ 13,165 | $ 6,377.2 | |
[1] | Total assets include goodwill. Goodwill has been attributed to our Field Gathering and Processing segment - See Note 4 - Business Acquisitions. | ||
[2] | Corporate assets at the Segment level primarily include investments in unconsolidated subsidiaries and debt issuance cost associated with our debt obligations |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets: | ||
Trade receivables, allowances | $ 0.1 | $ 0 |
Owners' equity | ||
Common limited partners units issued (in units) | 185,083,420 | 118,652,798 |
Common limited partners units outstanding (in units) | 184,870,693 | 118,586,056 |
General partner units issued (in units) | 3,772,871 | 2,420,124 |
General partner units outstanding (in units) | 3,772,871 | 2,420,124 |
Treasury units (in units) | 212,727 | 66,742 |
Series A Preferred Limited Partner Units [Member] | ||
Owners' equity | ||
Series A preferred limited partners units issued (in units) | 5,000,000 | 0 |
Series A preferred limited partners units outstanding (in units) | 5,000,000 | 0 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Revenues: | ||||
Sales of commodities | $ 5,465.4 | $ 7,595.2 | $ 5,728.2 | |
Fees from midstream services | 1,193.2 | 1,021.3 | 586.7 | |
Total revenues | 6,658.6 | 8,616.5 | 6,314.9 | |
Costs and expenses: | ||||
Product purchases | 4,873 | 7,046.9 | 5,137.2 | |
Operating expenses | 504.6 | 433 | 376.2 | |
Depreciation and amortization expenses | 677.1 | 346.5 | 271.6 | |
General and administrative expenses | 153.6 | 139.8 | 143.1 | |
Provisional goodwill impairment | 290 | 0 | 0 | |
Other operating (income) expense | (7.1) | (3) | 9.6 | |
Income from operations | 167.4 | 653.3 | 377.2 | |
Other income (expense): | ||||
Interest expense, net | (207.8) | (143.8) | (131) | |
Equity earnings (loss) | (2.5) | 18 | 14.8 | |
Gain (loss) from financing activities (see Note 9 - Debt Obligations) | 2.8 | (12.4) | (14.7) | |
Other | (18.6) | (5.2) | 15.2 | |
Income (loss) before income taxes | (58.7) | 509.9 | 261.5 | |
Income tax (expense) benefit: | ||||
Current | (0.8) | (3.2) | (2) | |
Deferred | 0.2 | (1.6) | (0.9) | |
Total income tax benefit (expense) | (0.6) | (4.8) | (2.9) | |
Net income (loss) | (59.3) | 505.1 | 258.6 | |
Less: Net income (loss) attributable to noncontrolling interests | (31.9) | 37.4 | 25.1 | |
Net income (loss) attributable to Targa Resources Partners LP | (27.4) | 467.7 | 233.5 | |
Net income attributable to preferred limited partners | 2.4 | 0 | 0 | |
Net income attributable to general partner | 167.7 | 148.7 | 107.5 | |
Net income (loss) attributable to common limited partners | (197.5) | 319 | 126 | |
Net income (loss) attributable to Targa Resources Partners LP | $ (27.4) | $ 467.7 | $ 233.5 | |
Net income (loss) per common limited partner unit - basic (in dollars per share) | $ (1.15) | $ 2.78 | $ 1.19 | |
Net income (loss) per common limited partner unit - diluted (in dollars per share) | $ (1.15) | $ 2.77 | $ 1.19 | |
Weighted average units outstanding - basic (in shares) | 172.3 | 114.7 | 105.5 | |
Weighted average limited partner units outstanding - diluted (in shares) | [1] | 172.3 | 115.1 | 105.7 |
[1] | For the year ended December 31, 2015 and 2014, approximately 697,989 and 168,495 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract] | |||
Net income (loss) | $ (59.3) | $ 505.1 | $ 258.6 |
Commodity hedging contracts: | |||
Change in fair value | 81.3 | 59.8 | (5.8) |
Settlements reclassified to revenues | (54.8) | 4.2 | (21.2) |
Interest rate swaps: | |||
Settlements reclassified to interest expense, net | 0 | 2.4 | 6.1 |
Other comprehensive income (loss) | 26.5 | 66.4 | (20.9) |
Comprehensive income (loss) | (32.8) | 571.5 | 237.7 |
Less: Comprehensive income attributable to noncontrolling interests | (31.9) | 37.4 | 25.1 |
Comprehensive income attributable to Targa Resources Partners LP | $ (0.9) | $ 534.1 | $ 212.6 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY - USD ($) $ in Millions | Receivables from Unit Issuances [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Treasury Units [Member] | Non-controlling Interests [Member] | Total | Limited Partner Preferred [Member] | Limited Partners Common [Member] | General Partner [Member] |
Balance at Dec. 31, 2012 | $ 0 | $ 14.8 | $ 0 | $ 150.5 | $ 1,860.1 | $ 0 | $ 1,649.5 | $ 45.3 |
Balance (in units) at Dec. 31, 2012 | 0 | 0 | 100,096,000 | 2,043,000 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Compensation on equity grants | 0 | 0 | $ 0 | 0 | 6 | $ 0 | $ 6 | $ 0 |
Compensation on equity grants (in units) | 0 | 0 | 0 | |||||
Distribution equivalent rights | 0 | 0 | $ 0 | 0 | (1.7) | $ 0 | $ (1.7) | 0 |
Issuance of common units under compensation program | 0 | 0 | $ 0 | 0 | 0 | $ 0 | $ 0 | $ 0 |
Issuance of common units under compensation program (in units) | 0 | 0 | 13,000 | 0 | ||||
Equity offerings | 0 | 0 | $ 0 | 0 | 517.8 | $ 0 | $ 517.8 | $ 0 |
Equity offerings (in units) | 0 | 0 | 11,154,000 | 0 | ||||
Contributions from Targa Resources Corp. | 0 | 0 | $ 0 | 0 | 10.8 | $ 0 | $ 0 | $ 10.8 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 0 | 228,000 | ||||
Distributions to noncontrolling interests | 0 | 0 | $ 0 | (19.3) | (19.3) | $ 0 | $ 0 | $ 0 |
Contribution from noncontrolling interests | 0 | 0 | 0 | 4.3 | 4.3 | 0 | 0 | 0 |
Other comprehensive income (loss) | 0 | (20.9) | 0 | 0 | (20.9) | 0 | 0 | 0 |
Net income (loss) | 0 | 0 | 0 | 25.1 | 258.6 | 0 | 126 | 107.5 |
Distributions | 0 | 0 | 0 | 0 | (397.3) | 0 | (295.7) | (101.6) |
Balance at Dec. 31, 2013 | 0 | (6.1) | $ 0 | 160.6 | 2,218.4 | $ 0 | $ 2,001.9 | $ 62 |
Balance (in units) at Dec. 31, 2013 | 0 | 0 | 111,263,000 | 2,271,000 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Compensation on equity grants | 0 | 0 | $ 0 | 0 | 9.2 | $ 0 | $ 9.2 | $ 0 |
Compensation on equity grants (in units) | 0 | 0 | 0 | 0 | ||||
Distribution equivalent rights | 0 | 0 | $ 0 | 0 | (1.4) | $ 0 | $ (1.4) | $ 0 |
Issuance of common units under compensation program | 0 | 0 | $ 0 | 0 | 0 | $ 0 | $ 0 | $ 0 |
Issuance of common units under compensation program (in units) | 0 | 0 | 215,000 | 0 | ||||
Units tendered for tax withholding obligations | 0 | 0 | $ (4.8) | 0 | (4.8) | $ 0 | $ 0 | $ 0 |
Units tendered for tax withholding obligations (in units) | 67,000 | 0 | (67,000) | 0 | ||||
Equity offerings | 0 | 0 | $ 0 | 0 | 408.4 | $ 0 | $ 408.4 | $ 0 |
Equity offerings (in units) | 0 | 0 | 7,175,000 | 0 | ||||
Contributions from Targa Resources Corp. | (1) | 0 | $ 0 | 0 | 7.7 | $ 0 | $ 0 | $ 8.7 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 0 | 149,000 | ||||
Distributions to noncontrolling interests | 0 | 0 | $ 0 | (26.8) | (26.8) | $ 0 | $ 0 | $ 0 |
Other comprehensive income (loss) | 0 | 66.4 | 0 | 0 | 66.4 | 0 | 0 | 0 |
Net income (loss) | 0 | 0 | 0 | 37.4 | 505.1 | 0 | 319 | 148.7 |
Distributions | 0 | 0 | 0 | 0 | (493.8) | 0 | (353) | (140.8) |
Balance at Dec. 31, 2014 | (1) | 60.3 | $ (4.8) | 171.2 | 2,688.4 | $ 0 | $ 2,384.1 | $ 78.6 |
Balance (in units) at Dec. 31, 2014 | 67,000 | 0 | 118,586,000 | 2,420,000 | ||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Compensation on equity grants | 0 | 0 | $ 0 | 0 | 16.6 | $ 0 | $ 16.6 | $ 0 |
Compensation on equity grants (in units) | 0 | 0 | 0 | 0 | ||||
Distribution equivalent rights | 0 | 0 | $ 0 | 0 | (1.6) | $ 0 | $ (1.6) | $ 0 |
Issuance of common units under compensation program | 0 | 0 | $ 0 | 0 | 0 | $ 0 | $ 0 | $ 0 |
Issuance of common units under compensation program (in units) | 0 | 0 | 439,000 | 0 | ||||
Units tendered for tax withholding obligations | 0 | 0 | $ (5.5) | 0 | (5.5) | $ 0 | $ 0 | $ 0 |
Units tendered for tax withholding obligations (in units) | 145,000 | 0 | (145,000) | 0 | ||||
Equity offerings | 0 | 0 | $ 0 | 0 | 436 | $ 120.6 | $ 315.4 | $ 0 |
Equity offerings (in units) | 0 | 5,000,000 | 7,377,000 | 0 | ||||
Acquisition of APL | 0 | 0 | $ 0 | 216.8 | 2,799.8 | $ 0 | $ 2,583 | $ 0 |
Acquisition of APL (in units) | 0 | 0 | 58,614,000 | 0 | ||||
Contributions from Targa Resources Corp. | 1 | 0 | $ 0 | 0 | 60.1 | $ 0 | $ 0 | $ 59.1 |
Contributions from Targa Resources Corp. (in units) | 0 | 0 | 0 | 1,353,000 | ||||
Distributions to noncontrolling interests | 0 | 0 | $ 0 | (14.4) | (14.4) | $ 0 | $ 0 | $ 0 |
Contribution from noncontrolling interests | 0 | 0 | 0 | 78.4 | 78.4 | 0 | 0 | 0 |
Other comprehensive income (loss) | 0 | 26.5 | 0 | 0 | 26.5 | 0 | 0 | 0 |
Net income (loss) | 0 | 0 | 0 | (31.9) | (59.3) | 2.4 | (197.5) | 167.7 |
Distributions | 0 | 0 | 0 | 0 | (733.6) | (1.5) | (549.6) | (182.5) |
Distributions payable to preferred unit holders | 0 | 0 | 0 | 0 | (0.9) | (0.9) | 0 | 0 |
Targa contribution - Special General Partner Interest | 0 | 0 | 0 | 0 | 1,612.4 | 0 | 0 | 1,612.4 |
Balance at Dec. 31, 2015 | $ 0 | $ 86.8 | $ (10.3) | $ 420.1 | $ 6,902.9 | $ 120.6 | $ 4,550.4 | $ 1,735.3 |
Balance (in units) at Dec. 31, 2015 | 212,000 | 5,000,000 | 184,871,000 | 3,773,000 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash flows from operating activities | |||
Net income (loss) | $ (59.3) | $ 505.1 | $ 258.6 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Amortization in interest expense | 12.6 | 11.2 | 15.5 |
Compensation on equity grants | 16.6 | 9.2 | 6 |
Depreciation and amortization expense | 677.1 | 346.5 | 271.6 |
Provisional goodwill impairment | 290 | 0 | 0 |
Accretion of asset retirement obligations | 5.3 | 4.4 | 3.9 |
Change in redemption value of other long term liabilities | (30.6) | 0 | 0 |
Deferred income tax expense (benefit) | (0.2) | 1.6 | 0.9 |
Equity (earnings) loss of unconsolidated affiliates | 2.5 | (18) | (14.8) |
Distributions received from unconsolidated affiliates | 13.8 | 18 | 12 |
Risk management activities | 71.1 | 4.7 | (0.5) |
(Gain) loss on sale or disposition of assets | (8) | (4.8) | 3.9 |
(Gain) loss from financing activities | (2.8) | 12.4 | 14.7 |
Changes in operating assets and liabilities, net of business acquisitions: | |||
Receivables and other assets | 236.1 | 94.5 | (145.8) |
Inventory | 41.4 | (35.9) | (84.5) |
Accounts payable and other liabilities | (181.7) | (110.4) | 69.9 |
Net cash provided by operating activities | 1,083.9 | 838.5 | 411.4 |
Cash flows from investing activities | |||
Outlays for property, plant and equipment | (817.2) | (762.2) | (1,013.6) |
Business acquisition, net of cash acquired | (828.7) | 0 | 0 |
Investment in unconsolidated affiliates | (11.7) | 0 | 0 |
Return of capital from unconsolidated affiliates | 1.2 | 5.7 | 0 |
Other, net | 2.5 | 5.1 | (12.7) |
Net cash used in investing activities | (1,653.9) | (751.4) | (1,026.3) |
Cash flows from financing activities | |||
Proceeds from borrowings under credit facility | 1,996 | 1,600 | 1,613 |
Repayments of credit facility | (1,716) | (1,995) | (1,838) |
Borrowings from accounts receivable securitization facility | 391.6 | 381.9 | 373.3 |
Repayments of accounts receivable securitization facility | (355.1) | (478.8) | (93.6) |
Proceeds from issuance of senior notes | 1,700 | 800 | 625 |
Redemption of senior notes | (14.3) | (259.8) | (183.2) |
Redemption of APL senior notes | (1,168.8) | 0 | 0 |
Costs incurred in connection with financing arrangements | (26.1) | (14) | (15.3) |
Proceeds from sale of common and preferred units | 443.6 | 412.7 | 524.7 |
Repurchase of common units under compensation plans | (5.5) | (4.8) | 0 |
Contributions received from General Partner | 60.1 | 7.7 | 10.8 |
Contributions received from noncontrolling interests | 78.4 | 0 | 4.3 |
Distributions paid to unit holders | (733.6) | (493.8) | (397.3) |
Payments of distribution equivalent rights | (2.8) | (1.6) | 0 |
Distributions paid to noncontrolling interests | (14.4) | (26.8) | (19.3) |
Net cash provided by (used in) financing activities | 633.1 | (72.3) | 604.4 |
Net change in cash and cash equivalents | 63.1 | 14.8 | (10.5) |
Cash and cash equivalents, beginning of period | 72.3 | 57.5 | 68 |
Cash and cash equivalents, end of period | $ 135.4 | $ 72.3 | $ 57.5 |
Organization and Operations
Organization and Operations | 12 Months Ended |
Dec. 31, 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 (“NYSE”) under the symbol “NGLS.” In this Annual 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 December 31, 2015, Targa owned a 10.6% interest in us in the form of 3,772,871 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 GP and the right to receive distributions in liquidation. In connection with our issuance of 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) in October 2015, our Partnership Agreement was amended and restated for the purpose of defining the preferences, rights, powers and duties of holders of our Preferred Units (see Note 11 – Partnership Units and Related Matters). Our preferred units are listed on the NYSE under the symbol “NGLS PRA.” TRC/TRP Merger On February 17, 2016, TRC completed the previously announced transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement”), dated November 2, 2015, by and among us, our general partner, TRC and Spartan Merger Sub LLC, a subsidiary of TRC (“Merger Sub”) pursuant to which TRC acquired indirectly all of our outstanding common units that TRC and its subsidiaries did not already own. Upon the terms and conditions set forth in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP (the “TRC/TRP Merger”), with TRP continuing as the surviving entity and as a subsidiary of TRC. At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by TRC or its subsidiaries was converted into the right to receive 0.62 shares of common stock of TRC, par value $0.001 per share (“TRC shares”). No fractional TRC shares were issued in the TRC/TRP Merger, and TRP common unitholders instead received cash in lieu of fractional TRC shares. 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 23-Segment Information for certain financial information for our business segments. The employees supporting our operations are employed by Targa. Our financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa’s centralized general and administrative services. |
Basis of Presentation
Basis of Presentation | 12 Months Ended |
Dec. 31, 2015 | |
Basis of Presentation [Abstract] | |
Basis of Presentation | Note 2 — Basis of Presentation These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2015 and 2014, and the results of operations, comprehensive income, cash flows and changes in owners’ equity for the years ended December 31, 2015, 2014, and 2013. We have prepared our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany balances and transactions have been eliminated. Certain amounts in prior periods have been reclassified to conform to the current year presentation. The February 27, 2015 Atlas mergers involved two separate legal transactions involving different groups of equity holders. For GAAP reporting purposes, these two mergers are viewed as a single integrated transaction. As such, the financial effects of the Targa consideration related to the ATLS merger have been reflected in these financial statements. As described in Note 4 – Business Acquisitions, our Partnership Agreement was amended to provide for the issuance of the Special GP Interest in us equal to the tax basis of the APL GP Interests acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation. Impact of Errors On February 27, 2015, Targa completed the Atlas mergers (see Note 4 – Business Acquisitions). During the fourth quarter of 2015, we concluded that our review procedures over the development and application of inputs, assumptions, and calculations used in cash flow-based fair value measurements associated with business combinations did not operate as designed. This resulted in errors in the preliminary fair values of our purchase accounting previously reported in our interim quarterly filings during 2015. The correction of these items in the fourth quarter of 2015 resulted in an increase to intangible assets, goodwill and noncontrolling interests, and a decrease to property, plant and equipment in each period. We concluded that these errors errors balances well as effect of ordinary measurement period . Three Month Period As Reported Impact of Errors Other Measurement Period Adjustments (1) As If Adjusted March 31, 2015 Property, plant and equipment, net $ 9,832.9 $ (77.0 ) $ (248.8 ) $ 9,507.1 Intangible assets, net 1,602.4 114.5 204.1 1,921.0 Goodwill 628.5 48.5 30.0 707.0 Noncontrolling interests 480.7 86.2 (173.2 ) 393.7 Depreciation and amortization expenses 119.6 0.2 (0.2 ) 119.6 June 30, 2015 Property, plant, and equipment, net $ 9,684.3 $ (76.0 ) $ 1.0 $ 9,609.3 Intangible assets, net 1,735.6 113.1 35.4 1,884.1 Goodwill 557.9 48.5 100.6 707.0 Noncontrolling interests 297.4 86.2 17.2 400.8 Depreciation and amortization expenses 163.9 0.5 0.5 164.9 September 30, 2015 Property, plant, and equipment, net $ 9,750.2 $ (75.0 ) $ (8.6 ) $ 9,666.6 Intangible assets, net 1,695.7 111.6 39.8 1,847.1 Goodwill 551.4 48.5 107.1 707.0 Noncontrolling interests 309.6 86.2 17.3 413.1 Depreciation and amortization expenses 165.8 0.5 0.4 166.7 (1) Other Measurement Period Adjustments for Goodwill include the impact of all balance sheet adjustments not presented in this table Revision of Previously Reported Revenues and Product Purchases During the third quarter of 2014, we concluded that certain prior period buy-sell transactions related to the marketing of NGL products were incorrectly reported on a gross basis as Revenues and Product Purchases in previous Consolidated Statements of Operations. GAAP requires that such transactions that involve purchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another be reported as a single transaction on a combined net basis. We concluded that these misclassifications were not material to any of the periods affected. However, we have revised previously reported revenues and product purchases to correctly report NGL buy-sell transactions on a net basis. Accordingly, Revenues and Product Purchases reported in our Form 10-K filed on February 14, 2014 have been reduced by equal amounts as presented in the following table. There is no impact on previously reported net income, cash flows, financial position or other profitability measures. Year Ended December 31, 2013 As Reported: Revenues $ 6,556.2 Product Purchases 5,378.5 Effect of Revisions: Revenues (241.3 ) Product Purchases (241.3 ) As Revised: Revenues 6,314.9 Product Purchases 5,137.2 |
Significant Accounting Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Significant Accounting Policies [Abstract] | |
Significant Accounting Policies | Note 3 — Significant Accounting Policies Consolidation Policy Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests. We follow the equity method of accounting when we can not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. Cash and Cash Equivalents Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. Checks outstanding at the end of a period are reclassified to accounts payable, as we extinguish liabilities when the creditor receives our payment and we are relieved of our obligation (which for a check generally occurs when our bank honors that check). Comprehensive Income (Loss) Comprehensive income (loss) includes net income (loss) and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as hedges. Allowance for Doubtful Accounts Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required. Inventories Our inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of cost or net realizable value using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are classified as Property, Plant and Equipment. Inventories also include materials and supplies required for our Badlands expansion activities in North Dakota, which are valued using the specific identification method. Product Exchanges Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities. Gas Processing Imbalances Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs. Derivative Instruments We employ derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which under GAAP, are not accounted for as derivatives. As a result, the revenues and expenses associated with such contracts are recognized during the period when volumes are physically delivered or received. If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense. If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss resulting from the change in fair value on the derivative is recognized currently in earnings as a component of revenues. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the gain or loss related to the change in fair value to earnings in the current period. We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately. For balance sheet classification purposes, we analyze the fair values of the derivative contracts on a deal by deal basis and report the related fair value on a gross basis. Property, Plant and Equipment Property, plant and equipment are stated at acquisition value less accumulated depreciation. All of our property, plant and equipment purchased from Targa from 2007 to 2010 in drop-down transactions were stated at historical cost in the transactions recorded under common control accounting. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize increased depreciation expense equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of additional depreciation expense due to impairment. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations. Goodwill Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Goodwill must be assigned to reporting units for the purpose of impairment testing. A reporting unit is an operating segment or one level below an operating segment (also known as a component). Goodwill resulting from the Atlas merger has been attributed to our WestTX, SouthOK and SouthTX reporting units. Our annual goodwill impairment testing is performed as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not the fair value of these reporting units is less than their carrying amounts. This typically entails performing a two-step goodwill impairment test. However, we are permitted to first assess qualitative factors to determine the two-step goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or otherwise determine if that a two-step process goodwill impairment test is required, the first step involves comparing the fair value of the reporting unit to which goodwill has been attributed with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step is required and involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. The implied fair value of goodwill is determined by assigning the reporting unit’s fair value to its individual assets and liabilities. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as a reduction of goodwill on our Consolidated Balance Sheets and a goodwill impairment loss on our Consolidated Statements of Operations. Intangible Assets Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with businesses acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Amortization expense attributable to these assets is recorded in a manner that closely resembles the expected pattern in which we benefit from services provided to customers. Asset Retirement Obligations AROs AROs are legal obligations associated with the retirement of tangible long-lived assets that result from an asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The consolidated cost of the asset and the capitalized asset retirement obligation is depreciated using the straight-line method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing. Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows shall be recognized as an increase or a decrease in the carrying amount of the liability for an asset retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. Upon settlement, AROs will be extinguished by us at either the recorded amount or we will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost. Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issuance costs. Accounts Receivable Securitization Facility Proceeds from the sale or contribution of certain receivables under our Accounts Receivable Securitization Facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Such borrowings are reflected as long-term debt on our balance sheets to the extent that we have the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities on our Consolidated Statements of Cash Flows. Environmental Liabilities and Other Loss Contingencies Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Income Taxes We generally are not subject to federal income taxes. For federal income tax purposes, our earnings or losses are included in the tax returns of our separate partners. The taxable income or loss passed through to our partners may vary substantially from the net income or net loss we report in the Consolidated Statement of Income. As part of the APL Merger, we acquired TPL Arkoma, Inc. a corporate subsidiary subject to federal and state income tax. The Partnership’s corporate subsidiary accounts for income taxes under the asset and liability method and provides deferred income taxes for all significant temporary differences. As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes for our taxable corporate subsidiary. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheets. We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we establish a valuation allowance. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies. The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are generally not subject to federal and state income taxes at the Partnership level. We are also subject to the Texas margin tax, consisting generally of a 0.75% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas. See Note 18 for discussion of the Partnership’s federal and state income tax expense (benefits) of its taxable subsidiary as well as the Partnership’s net deferred income tax assets (liabilities). Noncontrolling Interests Third-party ownership in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of our Consolidated Balance Sheets. In the Consolidated Statements of Operations and consolidated statements of comprehensive income, noncontrolling interests reflects the attribution of results to third-party investors. Mandatorily Redeemable Preferred Interests Mandatorily redeemable preferred interests are included in other long term liabilities (or assets) on our Consolidated Balance Sheets. Mandatorily redeemable preferred interests with multiple or indeterminate redemption dates are reported at their estimated redemption value as of the reporting date. This point-in-time value does not represent the amount that ultimately would occur in the future when the interests are redeemed. Changes in the redemption value are recorded in interest expense, net on our Consolidated Statements of Operations. Revenue Recognition Our operating revenues are primarily derived from the following activities: · sales of natural gas, NGLs, condensate, crude oil and petroleum products; · services related to compressing, gathering, treating, and processing of natural gas; and · services related to NGL fractionation, terminaling and storage, transportation and treating. We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. For natural gas processing activities, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we retain the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on a percent-of-liquids basis or a fee basis, depending on market conditions. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above. We generally report sales revenues gross in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another are reported as a single transaction on a combined net basis. Unit-Based Compensation We award unit-based compensation to employees of Targa and to directors and non-management directors of our General Partner in the form of restricted common units and performance units. Compensation expense on restricted common units and performance unit awards that qualify as equity arrangements are measured by the fair value of the award as determined at the date of grant. Compensation expense on performance unit awards that qualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured subsequently at each reporting date through the settlement period. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. Earnings per Unit We account for earnings per unit (“EPU”) in accordance with Accounting Standards Codification (“ASC”) Topic 260 – Earnings per Share. Diluted EPU reflects the potential dilution that could occur if securities or other contracts to issue common units were exercised or converted into common units or resulted in the issuance of common units so long as it does not have an anti-dilutive effect on EPU. The dilutive effect is determined through the application of the treasury method. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic EPU. The common limited partners’ net income (loss) per unit is based on net income (loss) after net income attributable to Preferred Units, allocation to the general partner’s 2% interest and incentive distribution rights. Because our Partnership Agreement limits the quarterly distribution payable to holders of incentive distribution rights to a percentage of Available Cash, the incentive distribution rights do not receive an allocation of earnings in excess of the incentive distributions for the period. Use of Estimates When preparing financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets,(5) determining amounts to accrue for contingencies, guarantees and indemnifications and (6) estimating redemption value of mandatorily redeemable preferred interests. Actual results, therefore, could differ materially from estimated amounts. Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), The revenue recognition standard is effective for the annual period beginning December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retroactively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the amendment is adopted. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact on our revenue recognition practices. In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity (a consensus of the FASB Emerging Issues Task Force). In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 303): Simplifying the Measurement of Inventory. Topic 303 In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. |
Business Acquisitions
Business Acquisitions | 12 Months Ended |
Dec. 31, 2015 | |
Business Acquisitions [Abstract] | |
Business Acquisitions | Note 4 –Business Acquisitions 2015 Acquisition Atlas Mergers On February 27, 2015, Targa completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”), by and among (i) Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of Targa (“GP Merger Sub”), ATLS and Atlas Energy GP, LLC, a Delaware limited liability company and the general partner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the transactions contemplated by the Agreement and Plan of Merger (the “APL Merger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, the Partnership’s general partner, Trident MLP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of the Partnership (“MLP Merger Sub”), ATLS, APL and Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and the general partner of APL (“APL GP”). Pursuant to the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged (the “ATLS merger”) with and into ATLS, with ATLS continuing as the surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth in the APL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APL continuing as the surviving entity and as a subsidiary of the Partnership. While the Atlas mergers were two separate legal transactions, for GAAP reporting purposes, they are viewed as a single integrated transaction. 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.” While the Atlas mergers were two separate legal transactions, for GAAP reporting purposes, they are viewed as a single integrated transaction. As such, the financial effects of the ATLS Merger Consideration (as defined below) paid by Targa have been reflected in these financial statements. In addition, prior to the completion of the Atlas mergers, ATLS, pursuant to a separation and distribution agreement entered into by and among ATLS, ATLS GP and Atlas Energy Group, LLC, a Delaware limited liability company (“AEG”), on February 27, 2015, (i) transferred its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro rata distribution to the ATLS unitholders of AEG common units representing a 100% interest in AEG (collectively, the “Spin-Off” and, together with the Atlas mergers, the “Atlas Transactions”). On February 27, 2015, the Partnership Agreement was amended to provide for the issuance of a special general partner interest in the Partnership (the “Special GP Interest”) representing the contribution to the Partnership of the APL GP interest acquired in the ATLS merger totaling $1.6 billion. The Special GP Interest is not entitled to current distributions or allocations of net income or loss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right to distributions in liquidation. We acquired all of the outstanding units of APL for a total purchase price of approximately $5.3 billion (including $1.8 billion of acquired debt and all other assumed liabilities). Of the $1.8 billion of debt acquired and other liabilities assumed, approximately $1.2 billion of the acquired debt was tendered and settled upon the closing of the Atlas mergers via our January 2015 cash tender offers. These tender offers were in connection with, and conditioned upon, the consummation of the merger with APL. The merger with APL, however, was not conditioned on the consummation of the tender offers. On that same date, Targa acquired ATLS for a total purchase price of approximately $1.6 billion (including all assumed liabilities). Pursuant to the APL Merger Agreement, our general partner entered into an amendment to our Partnership Agreement, which we refer to as the IDR Giveback Amendment, in order to reduce aggregate distributions to TRC, as the holder of the Partnership’s IDRs by (a) $9,375,000 per quarter during the first four quarters following the APL merger, (b) $6,250,000 per quarter for the next four quarters, (c) $2,500,000 per quarter for the next four quarters and (d) $1,250,000 per quarter for the next four quarters, with the amount of such reductions to be distributed pro rata to the holders of our outstanding common units. TPL is a provider of natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in south Texas. The Atlas mergers add TPL’s Woodford/SCOOP, Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing operations. In total, TPL adds 2,053 MMcf/d of processing capacity and 12,220 miles of additional pipeline. The operating results of TPL are reported in our Field Gathering and Processing segment. The APL merger was a unit-for-unit transaction with an exchange ratio of 0.5846 of our common units (the “APL Unit Consideration”) and $1.26 in cash for each APL common unit (the “APL Cash Consideration” and, with the APL Unit Consideration, the “APL Merger Consideration”), a $128.0 million total cash payment, of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion of retained employees’ APL phantom awards. We issued 58,614,157 of our common units and awarded 629,231 replacement phantom unit awards with a combined value of approximately $2.6 billion as consideration for the APL merger (based on the $43.82 closing market price of a common unit on the NYSE on February 27, 2015). The cash component of the APL merger also included $701.4 million for the mandatory repayment and extinguishment at closing of the APL Senior Secured Revolving Credit Facility that was to mature in May 2017 (the “APL Revolver”), $28.8 million of payments related to change of control and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March 2015, Targa contributed $52.4 million to us to maintain its 2% general partner interest. In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the effective time of the APL merger. The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS Stock Consideration”), and $9.12 in cash for each ATLS common unit (the ATLS Cash Consideration” and, with the ATLS Stock Consideration, the “ATLS Merger Consideration”), (a $514.7 million total cash payment). Targa issued 10,126,532 of its common shares and awarded 81,740 replacement restricted stock units with a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSE on February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million of payments related to change of control and cash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for reimbursement of certain transaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vesting of a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date. ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Targa’s acquisition of ATLS resulted in Targa acquiring these common units (converted to 3,363,935 of our common units) valued at approximately $147.4 million (based on the $43.82 closing market price of our common units on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, which reduced the consolidated purchase price by approximately $154.7 million. All outstanding ATLS equity awards, whether vested or unvested, were adjusted in connection with the Spin-Off on the terms and conditions set forth in an Employee Matters Agreement entered into by ATLS, ATLS GP and AEG on February 27, 2015. Following the Spin-Off-related adjustment and at the effective time of the ATLS merger, each outstanding ATLS option and ATLS phantom unit award, whether vested or unvested, held by a person who became an employee of AEG became fully vested (to the extent not vested) and was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). Each outstanding vested ATLS option held by an employee of APL who became an employee of Targa in connection with the Atlas Transactions (a “Midstream Employee”) was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unit underlying the vested ATLS option, net of the applicable exercise price. Each outstanding unvested ATLS option and each outstanding ATLS phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the ATLS Cash Consideration in respect of each ATLS common unit underlying such ATLS option or phantom unit award and (2) a TRC restricted stock unit award with respect to a number of shares of TRC Common Stock equal to the product of the ATLS Stock Consideration multiplied by the number of ATLS common units underlying such ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). In connection with the APL merger, each outstanding APL phantom unit award held by an employee of AEG became fully vested and was cancelled and converted into the right to receive the APL Merger Consideration in respect of each APL common unit underlying the APL phantom unit award. Each outstanding APL phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the APL Cash Consideration in respect of each APL common unit underlying such APL phantom unit award and (2) a Partnership phantom unit award with respect to a number of our common units equal to the product of the APL Unit Consideration multiplied by the number of APL common units underlying such APL phantom unit award. The acquired business contributed revenues of $1,459.3 million and a net loss of $30.1 million to us for the period from February 27, 2015 to December 31, 2015, and is reported in our Field Gathering and Processing segment. In 2015, we incurred $19.2 million of acquisition-related costs. These expenses are included in other expense in our Consolidated Statements of Operations for the year ended December 31, 2015. Pro Forma Impact of Atlas Mergers on Consolidated Statements of Operations The following summarized unaudited pro forma Consolidated Statement of Operations information for the year ended December 31, 2015 and December 31, 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 these acquisitions as of January 1, 2014, or that the results that will be attained in the future. Pro Forma Results for the Year Ended December 31, 2015 December 31, 2014 Revenues $ 6,947.3 $ 11,449.3 Net income (loss) (62.2 ) 691.2 The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making adjustments to: · Reflect the change in amortization expense resulting from the difference between the historical balances of APL’s intangible assets, net, and the fair value of intangible assets acquired. · Reflect the change in depreciation expense resulting from the difference between the historical balances of APL’s property, plant and equipment, net, and the fair value of property, plant and equipment acquired. · Reflect the change in interest expense resulting from our financing activities directly related to the Atlas mergers as compared with APL’s historical interest expense. · Reflect the changes in stock-based compensation expense related to the fair value of the unvested portion of replacement Partnership Long Term Incentive Plan (“LTIP”) awards which were issued in connection with the acquisition to APL phantom unitholders who continue to provide service as Targa employees following the completion of the APL merger. · Remove the results of operations attributable to 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 $19.2 million of acquisition-related costs incurred in 2015 from pro forma net income for the year ended December 31, 2015. Pro forma net income for the year ended December 31, 2014 was adjusted to include these charges. · Conform to our accounting policy, we also adjusted APL’s revenues to report plant sales of Y-grade at contractual net 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 paid, net of cash acquired (1) $ 745.7 Common shares of TRC 1,008.5 Replacement restricted stock units awarded (3) 5.2 Less: value of APL common units owned by ATLS (147.4 ) Total $ 1,612.0 Fair Value of Consideration Transferred by Targa for APL: Cash paid, net of cash acquired (2) $ 828.7 Common units of TRP 2,568.5 Replacement phantom units awarded (3) 15.0 Total $ 3,412.2 Total fair value of consideration transferred $ 5,024.2 (1) Targa acquired $5.5 million of cash. (2) We acquired $35.3 million of cash. (3) The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. As of February 27, 2015, our fair value determination related to the Atlas mergers was as follows: Fair value determination: February 27, 2015 Trade and other current receivables, net $ 181.1 Other current assets 24.4 Assets from risk management activities 102.1 Property, plant and equipment 4,616.9 Investments in unconsolidated affiliates 214.5 Intangible assets 1,354.9 Other long-term assets 5.5 Current liabilities (258.8 ) Long-term debt (1,573.3 ) Deferred income tax liabilities, net (13.6 ) Other long-term liabilities (119.1 ) Total identifiable net assets 4,534.6 Noncontrolling interest in subsidiaries (216.9 ) Current liabilities retained by Targa (0.5 ) Goodwill 707.0 $ 5,024.2 During the three months ended June 30, 2015, we recorded measurement-period adjustments to our acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. As a result, the Consolidated Statement of Operations for the three months ended March 31, 2015 was retrospectively adjusted for the impact of measurement-period adjustments to property, plant and equipment, intangible assets, and 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 quarter ended March 31, 2015. During the three months ended September 30, 2015, we recorded additional measurement-period adjustments to our acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. In accordance with ASU 2015-16, we have recognized these measurement-period adjustments in the current reporting period, with the effect on the Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at February 27, 2015. During the three months ended September 30, 2015, the acquisition date fair value of property, plant and equipment increased by $9.9 million, investments in unconsolidated affiliates increased by $5.5 million, intangible assets decreased by $5.0 million, current liabilities increased by $2.4 million, other assets decreased by $1.0 million, and other current assets decreased by $0.6 million, which resulted in a decrease in goodwill of $6.4 million. These adjustments resulted in increased revenues of $0.6 million, a reduction of operating expenses of $1.9 million, depreciation and amortization expense of $0.1 million and equity losses of $0.1 million recorded in the three months ended September 30, 2015, which under the prior accounting standard would have been reflected in previous reporting periods. During the three months ended December 31, 2015, we recorded additional measurement-period adjustments to our acquisition date fair values due to the refinement of our valuation models, assumptions and inputs, as well as adjustments to previously reported preliminary fair values as a result of our review procedures over the development and application of inputs, assumptions and calculations used in cash-flow based fair value measurements associated with business combinations not operating as designed (see Note 2 – Basis of Presentation). We have recognized these adjustments in the current reporting period, with the effect on the Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if the acquisition had been completed at February 27, 2015. During the three months ended December 31, 2015, the acquisition date fair value of intangible assets increased $155.9 million, noncontrolling interest in subsidiaries increased $103.5 million, other long-term liabilities increased $110.1 million, property, plant and equipment decreased by $86.2 million, investments in unconsolidated affiliates decreased by $5.2 million, deferred tax liabilities increased by $5.0 million, current liabilities increased by $1.3 million, other assets decreased by $0.1 million and other current assets decreased by $0.1 million, which resulted in an increase in goodwill of $155.6 million. These adjustments resulted in The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 14 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation. The excess of the purchase price over the fair value of net assets acquired was approximately $707.0 million, which was recorded as goodwill, is attributable to the workforce of the acquired business and the expected synergies with us and Targa. The goodwill is expected to be amortizable for tax purposes. The fair value of assets acquired includes trade receivables of $178.1 million. The gross amount due under contracts is $178.1 million, all of which is expected to be collectible. The fair value of assets acquired includes receivables of $3.0 million reported in current receivables and $4.5 million reported in other long-term assets related to a contractual settlement with a counterparty. See Note 9 – Debt Obligations for additional disclosures regarding related financing activities associated with the Atlas mergers. Mandatorily Redeemable Preferred Interests Acquired other long-term liabilities include $109.3 million related to mandatorily redeemable preferred interests held by our partner in two joint ventures (see note 10 – Other Long-Term Liabilities). Contingent Consideration A liability arising from the contingent consideration for APL’s previous acquisition of a gas gathering system and related assets has been recognized at fair value. APL agreed to pay up to an additional $6.0 million if certain volumes are achieved on the acquired gathering system within a specified time period. The fair value of the remaining contingent payment is recorded within other long term liabilities on our Consolidated Balance Sheets. The range of the undiscounted amount that we could pay related to the remaining contingent payment is between $0.0 and $6.0 million. We finalized our acquisition analysis and modeling of this contingent liability during the three months ended June 30, 2015, which resulted in an acquisition date fair value of $4.2 million. Any future change in the fair value of this liability will be included in earnings. Replacement Phantom Units In connection with the Atlas mergers, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained unchanged from the existing APL awards, and will vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 33% per year over the original three year term. Each replacement phantom unit will entitle the grantee to one common unit on the vesting date and is an equity-settled award. The replacement phantom units include distribution equivalent rights (“DERs”). When we declare and pay cash distributions, the holders of replacement phantom units will be entitled within 60 days to receive cash payment of DERs in an amount equal to the cash distributions the holders would have received if they were the holders of record on the record date of the number of our common units related to the replacement phantom units. The fair value of the replacement phantom units was based on the closing price of our units at the close of trading on February 27, 2015. The fair value was allocated between the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award. Goodwill We recognized goodwill at a fair value of approximately $707.0 million associated with the Atlas mergers as of the acquisition date on February 27, 2015. Goodwill has been attributed to the WestTX, SouthTX and SouthOK reporting units in our Field Gathering and Processing segment. As a result, any level of decrease in the forecasted cash flows from the date of acquisition would likely result in the fair value of the reporting unit to fall below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill could be impaired. As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if we believe necessary based on events or changes in circumstances. As of February 29, 2016, the date these financial statements were issued, we had not completed our November 30, 2015 impairment assessment. Based on the results of our preliminary evaluation, we recorded a provisional goodwill impairment of $290.0 million during the fourth quarter of 2015. The provisional goodwill impairment is included in impairment expense in our Consolidated Statements of Operations for the year ended December 31, 2015, and reduces the carrying value of goodwill to $417.0 million as of December 31, 2015. The provisional goodwill impairment recorded reflects that goodwill impairment is probable; a provisional impairment amount can be reasonably estimated and recognizes the provisional amount in these financial statements as the best estimate of the impairment at the filing date of these financial statements. The impairment of goodwill is primarily due to the effects of lower commodity prices, and a higher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas. Our evaluation as of November 30, 2015 utilizes the income approach (a discounted cash flow analysis (“DCF”)) to estimate the fair values of our reporting units. The future cash flows for our reporting units is based on our estimates, at that time, of future revenues, income from operations and other factors, such as working capital and capital expenditures. We take into account current and expected industry and market conditions, commodity pricing and volumetric forecasts in the basins in which the reporting units operate. The discount rates used in our DCF analysis are based on a weighted average cost of capital determined from relevant market comparisons. The provisional goodwill impairment recognized is based on our progress in completing the goodwill impairment analysis. As of the filing date of these financial statements, we have (a) completed the calculations of estimated future cash flows based on commodity pricing, volumetric and capital spending forecasts; (b) determined that other long-lived assets in our reporting units that contain goodwill are not impaired; (c) determined an appropriate weighted average cost of capital based on relevant market comparisons, which is the basis of the discount rate used in our DCF analysis; (d) substantially completed the valuations of intangible assets; and (e) have made initial estimates of the fair values of tangible assets. We are in the process of finalizing the review of certain tangible assets and the mandatorily redeemable preferred interests' valuations, and the final outcome of these valuations could impact the implied fair value of goodwill in our reporting units and consequently the ultimate amount of impairment. Any material difference between the provisional amount of goodwill impairment and the final impairment will be recognized in our first quarter 2016 financial statements once final valuations are complete. Changes in the gross amounts of our goodwill and impairment loss for the year ended December 31, 2015 are as follows: December 31, 2015 WestTX SouthTX SouthOK Total Beginning of period $ - $ - $ - $ - Acquisition 364.5 160.3 182.2 707.0 Impairment (37.6 ) (70.2 ) (182.2 ) (290.0 ) Goodwill $ 326.9 $ 90.1 $ - $ 417.0 The sustained decrease and uncertain outlook in commodity prices have adversely impacted our customers and their future capital and operating plans. A continued or prolonged period of lower commodity prices could result in further deterioration of reporting unit fair values and potential further impairment charges. |
Inventories
Inventories | 12 Months Ended |
Dec. 31, 2015 | |
Inventories [Abstract] | |
Inventories | Note 5 — Inventories December 31, 2015 December 31, 2014 Commodities $ 128.3 $ 157.4 Materials and supplies 12.7 11.5 $ 141.0 $ 168.9 |
Property, Plant and Equipment a
Property, Plant and Equipment and Intangible Assets | 12 Months Ended |
Dec. 31, 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 Property, Plant and Equipment December 31, 2015 December 31, 2014 Estimated useful life Gathering systems $ 6,304.5 $ 2,588.6 5 to 20 Processing and fractionation facilities 2,988.5 1,884.1 5 to 25 Terminaling and storage facilities 1,115.0 1,038.9 5 to 25 Transportation assets 454.0 359.0 10 to 25 Other property, plant and equipment 220.9 149.1 3 to 25 Land 108.8 95.6 - Construction in progress 736.5 399.0 - Property, plant and equipment 11,928.2 6,514.3 Accumulated depreciation (2,225.6 ) (1,689.7 ) Property, plant and equipment, net $ 9,702.6 $ 4,824.6 Intangible assets $ 2,036.6 $ 681.8 20 Accumulated amortization (226.5 ) (89.9 ) Intangible assets, net $ 1,810.1 $ 591.9 For each of the years ended December 31, 2015, 2014, and 2013 depreciation expense for property, plant and equipment was $540.5 million, $285.0 million and $244.2 million. We recorded non-cash pre-tax impairment charges of $32.6 million in 2015 and $3.2 million in 2014 due to the impairment of certain gas processing facilities and associated gathering systems in the Coastal Gathering and Processing segment. The impairments are a result of reduced forecasted gas processing volumes due to market conditions and processing spreads in Louisiana in the fourth quarters of 2015 and 2014. We measured the impairment of property, plant and equipment using discounted estimated future cash flows representative of a Level 3 fair value measurement. These carrying value adjustments are included in depreciation and amortization expenses on our Consolidated Statements of Operations. Intangible Assets Intangible assets consist of customer contracts and customer relationships acquired in the Atlas mergers in 2015 and our Badlands business acquisition in 2012. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate. The fair values of intangible assets acquired in the Atlas mergers have been recorded at a fair value of $1,354.9 million and are being amortized over the 20 year life using a straight-line method. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation. December 31, 2015 2014 Beginning of period $ 591.9 $ 653.4 Additions from acquisition 1,354.9 - Amortization (136.7 ) (61.5 ) Intangible assets, net $ 1,810.1 $ 591.9 For each of the years ended December 31, 2015, 2014, and 2013 amortization expense for our intangible assets was $136.7 million, $61.5 million and $27.4 million. The estimated annual amortization expense for intangible assets is approximately $156.2 million, $149.4 million, $135.7 million, $124.7 million and $112.5 million for each of the years 2016 through 2020. As of December 31, 2015 the weighted average amortization period for our intangible assets was approximately 18.5 years. |
Investment in Unconsolidated Af
Investment in Unconsolidated Affiliate | 12 Months Ended |
Dec. 31, 2015 | |
Investment in Unconsolidated Affiliate [Abstract] | |
Investment in Unconsolidated Affiliate | Note 7 — Investments in Unconsolidated Affiliates Our unconsolidated investments consist of a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”) and three non-operated joint ventures in South Texas acquired in the Atlas merger in 2015: 75% interest in T2 LaSalle; 50% interest in T2 Eagle Ford; and 50% interest in T2 EF Co-Gen (together the “T2 Joint Ventures”). The T2 Joint Ventures were formed to provide services for the benefit of the joint interest owners. The T2 Joint Ventures have capacity lease agreements with the joint interest owners, which cover the costs of operations of the T2 Joint Ventures. The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements, but do afford us the significant influence required to employ the equity method of accounting. The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 Cogen Total December 31, 2012 $ 53.1 $ - $ - $ - $ 53.1 Equity earnings 14.8 - - - 14.8 Cash distributions (1) (12.0 ) - - - (12.0 ) December 31, 2013 55.9 - - - 55.9 Equity earnings 18.0 - - - 18.0 Cash distributions (1) (23.7 ) - - - (23.7 ) December 31, 2014 50.2 - - - 50.2 Fair value of T2 Joint Ventures acquired - 67.5 126.7 20.3 214.5 Equity earnings (loss) 13.8 (3.9 ) (9.4 ) (3.0 ) (2.5 ) Cash distributions (1) (14.5 ) - - (0.5 ) (15.0 ) Cash calls for expansion projects - - 6.5 5.2 11.7 December 31, 2015 $ 49.5 $ 63.6 $ 123.8 $ 22.0 $ 258.9 (1) Includes $1.2 million in distributions from GCF and T2 Joint Ventures in excess of our share of cumulative earnings for the year ended December 31, 2015. Includes $5.7 million in distributions from GCF in excess of our share of cumulative earnings for the year ended December 31, 2014. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows. The recorded value of the T2 Joint Ventures is based on fair values at the date of acquisition which results in an excess fair value of $39.9 million over the book value of our partner capital accounts. This basis difference is attributable to depreciable tangible assets and is being amortized over the estimated useful lives of the underlying assets of 20 years on a straight-line basis and is included as a component of equity earnings. See Note 4 – Business Acquisitions for further information regarding the fair value determinations related to the Atlas mergers. |
Accounts Payable and Accrued Li
Accounts Payable and Accrued Liabilities | 12 Months Ended |
Dec. 31, 2015 | |
Accounts Payable and Accrued Liabilities [Abstract] | |
Accounts Payable and Accrued Liabilities | Note 8 — Accounts Payable and Accrued Liabilities December 31, 2015 December 31, 2014 Commodities $ 385.3 $ 416.7 Other goods and services 141.3 108.9 Interest 80.3 37.3 Compensation and benefits 0.4 1.3 Income and other taxes 10.4 13.6 Other 18.1 14.9 $ 635.8 $ 592.7 As of December 31, 2015 and December 31, 2014, liabilities to creditors to whom we have issued checks that remain outstanding of $34.0 million and $13.3 million are included in accounts payable and accrued liabilities. |
Debt Obligations
Debt Obligations | 12 Months Ended |
Dec. 31, 2015 | |
Debt Obligations [Abstract] | |
Debt Obligations | Note 9 — Debt Obligations December 31, 2015 December 31, 2014 Current: Accounts receivable securitization facility, due December 2016 $ 219.3 $ 182.8 Long-term: Senior secured revolving credit facility, variable rate, due October 2017 (1) 280.0 - Senior unsecured notes, 5% fixed rate, due January 2018 1,100.0 - Senior unsecured notes, 4⅛% fixed rate, due November 2019 800.0 800.0 Senior unsecured notes, 6⅝% fixed rate, due October 2020 (2) 342.1 - Unamortized premium 5.0 - Senior unsecured notes, 6⅞% fixed rate, due February 2021 483.6 483.6 Unamortized discount (22.1 ) (25.2 ) Senior unsecured notes, 6⅜% fixed rate, due August 2022 300.0 300.0 Senior unsecured notes, 5¼% fixed rate, due May 2023 583.7 600.0 Senior unsecured notes, 4¼% fixed rate, due November 2023 623.5 625.0 Senior unsecured notes, 6¾% fixed rate, due March 2024 600.0 - Senior unsecured APL notes, 6⅝% fixed rate, due October 2020 (2)(3) 12.9 - Unamortized premium 0.2 - Senior unsecured APL notes, 4¾% fixed rate, due November 2021 (3) 6.5 - Senior unsecured APL notes, 5⅞% fixed rate, due August 2023 (3) 48.1 - Unamortized premium 0.5 - Total long-term debt 5,164.0 2,783.4 Total debt $ 5,383.3 $ 2,966.2 Irrevocable standby letters of credit outstanding $ 12.9 $ 44.1 (1) As of December 31, 2015, availability under our $1.6 billion senior secured revolving credit facility was $1,307.1 million. (2) In May 2015, we exchanged the TRP 6⅝% Senior Notes with the same economic terms to the holders of the 6⅝% APL Notes that validly tendered such notes for exchange to us. (3) While we consolidate the debt acquired in the Atlas mergers, APL debt is not guaranteed by us. The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2015, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2016 2017 2018 2019 2020 After 2020 Senior secured revolving credit facility $ 280.0 $ - $ 280.0 $ - $ $ - $ - Senior unsecured notes 4,900.4 - - 1,100.0 800.0 355.0 2,645.4 Accounts receivable securitization facility 219.3 219.3 - - - - - Total $ 5,399.7 $ 219.3 $ 280.0 $ 1,100.0 $ 800.0 $ 355.0 $ 2,645.4 The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2015: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred Senior secured revolving credit facility 1.9% - 4.8% 2.2% Accounts receivable securitization facility 0.9% - 1.2% 0.9% Compliance with Debt Covenants As of December 31, 2015, we were in compliance with the covenants contained in our various debt agreements. Revolving Credit Agreement In October 2012, we entered into a Second Amended and Restated Credit Agreement that amended and replaced our variable rate Senior Secured Credit Facility due July 2015 to provide a variable rate Senior Secured Credit Facility due October 3, 2017 (the “Original Agreement”). The Original Agreement had an available commitment of $1.2 billion and allowed us to request up to an additional $300.0 million in commitment increases. In February 2015, we entered into the First Amendment, Waiver and Incremental Commitment Agreement (the “First Amendment”) that amended 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 amended certain provisions of the existing TRP Revolver and designated each of TPL 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. The TRP Revolver bears interest, at our option, either at the base rate or the Eurodollar rate. The base rate is equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin ranging from 0.75% to 1.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA). The Eurodollar rate is equal to LIBOR rate plus an applicable margin ranging from 1.75% to 2.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA). We are required to pay a commitment fee equal to an applicable rate ranging from 0.3% to 0.5% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA) times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable rate ranging from 1.75% to 2.75% (dependent on our ratio of consolidated funded indebtedness to consolidated adjusted EBITDA). The TRP Revolver is collateralized by a majority of our assets. Borrowings are guaranteed by our restricted subsidiaries. The TRP Revolver restricts our ability to make distributions of available cash to unitholders if a default or an event of default (as defined in the TRP Revolver) exists or would result from such distribution. The TRP Revolver requires us to maintain a ratio of consolidated funded indebtedness to consolidated adjusted EBITDA of no more than 5.50 to 1.00. The TRP Revolver also requires us to maintain a ratio of consolidated EBITDA to consolidated interest expense of no less than 2.25 to 1.00. In addition, the TRP Revolver contains various covenants that may limit, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates (in each case, subject to our right to incur indebtedness or grant liens in connection with, and convey accounts receivable as part of, a permitted receivables financing). Senior Unsecured Notes In May 2013, we privately placed $625.0 million in aggregate principal amount of 4¼% Notes. The 4¼% Notes resulted in approximately $618.1 million of net proceeds, which were used to reduce borrowings under the TRP Revolver and for general partnership purposes. In June 2013, we paid $106.4 million plus accrued interest, which included a premium of $6.4 million, to redeem $100.0 million of the outstanding 6⅜% Notes. The redemption resulted in a $7.4 million loss on debt redemption, including the write-off of $1.0 million of unamortized debt issuance costs. In July 2013, we paid $76.8 million plus accrued interest, which included a premium of $4.1 million, per the terms of the note agreement to redeem the outstanding balance of the 11¼% Notes. The redemption resulted in a $7.4 million loss on debt redemption in the third quarter 2013, including the write-off of $1.0 million of unamortized debt issuance costs. In October 2014, we privately placed $800.0 million in aggregate principal amount of 4⅛% Senior Notes due 2019 (the “4⅛% Notes”). The 4⅛% Notes resulted in approximately $790.8 million of net proceeds, which were used to reduce borrowings under the TRP Revolver and Securitization Facility and for general partnership purposes. In November 2014, we redeemed the outstanding 7⅞% Notes at a price of 103.938% plus accrued interest through the redemption date. The redemption resulted in a $12.4 million loss on redemption for the year ended 2014, consisting of premiums paid of $9.9 million and a non-cash loss to write-off $2.5 million of unamortized debt issuance costs. In January 2015, we and Targa Resources Partners Finance Corporation (collectively, the “Partnership Issuers”) issued $1.1 billion in aggregate principal amount of 5% Senior Notes due 2018 (the “5% Notes”). The 5% Notes resulted in approximately $1,089.8 million of net proceeds after costs, which were used with borrowings under our senior secured credit facility to fund the APL Notes Tender Offers and the Change of Control Offer (each as defined below). The 5% Notes are unsecured senior obligations that have substantially the same terms and covenants as our other senior notes. In September 2015, the Partnership Issuers issued $600 million in aggregate principal amount of 6¾% Senior Notes due 2024 (the “6¾% Notes”). The 6¾% Notes resulted in approximately $595.0 million of net proceeds after costs, which were used to reduce borrowings under our senior secured credit facility and for general partnership purposes. The 6¾% Notes are unsecured senior obligations that have substantially the same terms and covenants as our other senior notes. Debt Repurchases In December 2015, we repurchased on the open market a portion of outstanding Senior Notes as follows: • 5¼% Notes due 2023 (the “5¼% Notes”) paying $13.0 million plus accrued interest to repurchase $16.3 million of the outstanding balance of the 5¼% Notes. • 4¼% Notes due 2023 (the “4¼% Notes”) paying $1.2 million plus accrued interest to repurchase $1.5 million of the outstanding balance of the 4¼% Notes. • 6⅝% APL Notes due 2020 (the “6⅝% Notes”) paying $0.1 million plus accrued interest to repurchase $0.1 million of the outstanding balance of the 6⅝% Notes. The December 2015 Senior note repurchases resulted in a $3.6 million gain on debt repurchases and a write-off of $0.1 million in related deferred debt issuance costs. 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 secured 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, 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, the Partnership Issuers 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. We recognized $0.7 million of costs associated with the Exchange Offer, reflected as a Loss from financing activities on our Consolidated Statements of Operations. Debt Repurchases Summary The following table summarizes the debt repurchases that are included in our Consolidated Statements of Operations: 2015 2014 2013 Premium over face value paid upon redemption: 6⅜ Notes $ - $ - $ 6.4 7⅞ Notes - 9.9 - 11¼ Notes - - 4.1 Recognition of unamortized discount: 11¼ Notes - - 2.2 Gain on repurchase of debt: 5¼ Notes (3.3 ) - - 4¼ Notes (0.3 ) - - Loss from financing with Exchange Offer: 6⅝ Notes 0.7 - - Write-off of deferred debt issuance costs: 5¼ Notes 0.1 - - 6⅜ Notes - - 1.0 7⅞ Notes - 2.5 - 11¼ Notes - - 1.0 (Gain) loss from financing activities $ (2.8 ) $ 12.4 $ 14.7 Selected terms of the senior unsecured notes outstanding as of December 31, 2015 were as follows: Note Issue Issue Date Per Annum Interest Rate Due Date Dates Interest Paid "6⅞% Notes" February 2011 6⅞% February 1, 2021 February & August 1 st "6⅜% Notes" January 2012 6⅜% August 1, 2022 February & August 1 st "5¼% Notes" Oct / Dec 2012 5¼% May 1, 2023 May & November 1 st "4¼% Notes" May 2013 4¼% November 15, 2023 May & November 15 th "4⅛% Notes" October 2014 4⅛% November 15, 2019 May & November 15 th "5% Notes" January 2015 5% January 15, 2018 January & July 15 th "6⅝% Notes" May 2015 6⅝% October 1, 2020 February & October 1 st "6¾% Notes" September 2015 6¾% March 15, 2024 March & September 15 th "APL 6⅝% Notes" Sept 2012 (1) 6⅝% October 1, 2020 April & October 1 st "APL 4¾% Notes" May 2013 (1) 4¾% November 15, 2021 May & November 15 th "APL 5⅞% Notes" February 2013 (1) 5⅞% August 1, 2023 February & August 1 st (1) Issue dates for APL Notes are original dates of issuance. These notes were acquired in the APL Merger. See Note 4 – Business Acquisitions. All issues of unsecured senior notes are obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under the TRP Revolver. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by us and our restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the TRP Revolver, which is secured by substantially all of our assets and our Securitization Facility, which is secured by accounts receivable pledged under the Securitization Facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears. Our senior unsecured notes and associated indenture agreements restrict our ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the notes are rated investment grade by either Moody’s Investors Service, Inc. (“Moody’s)” or Standard & Poor’s Corporation (“S&P”) (or rated investment grade by both Moody’s and S&P for the 6⅞% Notes) and no Default or Event of Default (each as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and we will cease to be subject to such covenants. We may redeem up to 35% of the aggregate principal amount of Notes (other than with respect to the 5% Notes) at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 180 days for the 6¾% Notes, 6⅜% Notes, 5¼% Notes, 4¼ % Notes and 4⅛% Notes of the date of the closing of such equity offering. Note Issue Any Date Prior To Price 4¼% Notes May 15, 2016 104.250 % 6¾% Notes September 15, 2018 106.750 % 4⅛% Notes November 15, 2017 104.125 % We may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed. 6⅞% Notes 6⅜% Notes 5¼% Notes 4¼% Notes Redemption Date: February 1 Redemption Date: February 1 Redemption Date: November 1 Redemption Date: May 15 Year Price Year Price Year Price Year Price 2016 103.438 % 2017 103.188 % 2017 102.625 % 2018 102.125 % 2017 102.292 % 2018 102.125 % 2018 101.750 % 2019 101.417 % 2018 101.146 % 2019 101.063 % 2019 100.875 % 2020 100.708 % 2019 and thereafter 100 % 2020 and thereafter 100 % 2020 and thereafter 100 % 2021 and thereafter 100 % 6⅝% Notes 6¾% Notes 4⅛% Notes APL 6⅝% Notes Redemption Date: October 1 Redemption Date: September 15 Redemption Date: November 15 Redemption Date: October 1 Year Price Year Price Year Price Year Price 2016 103.313 % 2019 103.375 % 2016 102.063 % 2016 103.313 % 2017 101.656 % 2020 101.688 % 2017 101.031 % 2017 101.656 % 2018 and thereafter 100.000 % 2021 and thereafter 100.000 % 2018 and thereafter 100 % 2018 and thereafter 100 % APL 4¾% Notes APL 5⅞% Notes Redemption Date: May 15 Redemption Date: February 1 Year Price Year Price 2016 103.563 % 2018 102.938 % 2017 102.375 % 2019 101.958 % 2018 101.188 % 2020 100.979 % 2019 and thereafter 100 % 2021 and thereafter 100 % Accounts Receivable Securitization Facility The Securitization Facility provides up to $225.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 9, 2016. Under the Securitization Facility, subsidiaries sell or contribute qualifying receivables, without recourse, to TRLLC. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to a third-party financial institution. Sold receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of TLMT, TMS, TGM or us. Any excess receivables are eligible to satisfy the claims of creditors of the selling subsidiaries or us. Any excess receivables are eligible to satisfy the creditor claims. As of December 31, 2015, total funding under the Securitization Facility was $219.3 million. April 2013 Shelf In April 2013, we filed with the SEC a universal shelf registration statement (the “April 2013 Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The April 2013 Shelf expires in April 2016. There was no activity under the April 2013 Shelf during the years ended December 31, 2015 and 2014. July 2013 Shelf In July 2013, we filed with the SEC a universal shelf registration statement that allows us to issue up to an aggregate of $800.0 million of debt or equity securities (the “July 2013 Shelf”). The July 2013 Shelf expires in August 2016. See Note 11 – Partnership Units and Related Matters for equity issuances under the July 2013 Shelf. 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. Subsequent Events As of February 18, 2016, we repurchased on the open market a portion of outstanding Senior Notes as follows: · 5¼% Senior Notes due 2023 (the “5¼% Notes”) paying 16.7 million plus accrued interest to repurchase $20.5 million of the outstanding balance of the 5¼% Notes. · 4¼% Senior Notes due 2023 (the “4¼% Notes”) paying $17.0 million plus accrued interest to repurchase $22.9 million of the outstanding balance of the 4¼% Notes. · 6⅞% Senior Notes due 2021 (the “6⅞% Notes”) paying $4.3 million plus accrued interest to repurchase $5.0 million of the outstanding balance of the 6⅞% Notes. · 6⅝% Senior Notes due 2020 (the “6⅝% Notes”) paying $15.3 million plus accrued interest to repurchase $17.4 million of the outstanding balance of the 6⅝% Notes. · 6⅜% Senior Notes due 2022 (the “6⅜% Notes”) paying $7.6 million plus accrued interest to repurchase $9.5 million of the outstanding balance of the 6⅜% Notes. · 6¾% Senior Notes due 2024 (the “6¾% Notes”) paying $2.4 million plus accrued interest to repurchase $3.0 million of the outstanding balance of the 6¾% Notes. · 5% Senior Notes due 2018 (the “5% Notes”) paying $1.5 million plus accrued interest to repurchase $1.9 million of the outstanding balance of the 5% Notes. · 4⅛% Senior Notes due 2019 (the “4⅛%Notes”) paying $11.9 million plus accrued interest to repurchase $16.4 million of the outstanding balance of the 4⅛% Notes. We paid a total of $0.2 million in fees and $1.4 million in accrued interest for the repurchase of these Senior Notes. |
Other Long-term Liabilities
Other Long-term Liabilities | 12 Months Ended |
Dec. 31, 2015 | |
Other Long-term Liabilities [Abstract] | |
Other Long-term Liabilities | Note 10 — Other Long-term Liabilities Other long-term liabilities are comprised of the following obligations. December 31, 2015 2014 Asset retirement obligations $ 69.9 $ 56.8 Mandatorily redeemable preferred interests 82.9 - Deferred revenue and other 25.4 1.0 Total long-term liabilities $ 178.2 $ 57.8 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: 2015 2014 2013 Beginning of period $ 56.8 $ 50.5 $ 45.2 Fair value of ARO acquired with the APL merger 4.0 - - Change in cash flow estimate 3.8 2.1 1.4 Accretion expense 5.3 4.4 3.9 Retirement of ARO - (0.2 ) - End of period $ 69.9 $ 56.8 $ 50.5 Mandatorily Redeemable Preferred Interests Our consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering and processing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holds preferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037. The joint ventures, collectively, hold $1.9 billion face value in notes receivable from our partner, which are due July 2042. The interest rate payable under the notes receivable is a variable LIBOR-based rate. For the period ending on December 31, 2015, interest earned on the notes receivable of $8.9 million, exclusive of the priority return payable to our partner, is reflected within Interest expense, net on our Consolidated Statements of Operations. We have accounted for the notes receivable at fair value. Upon redemption: (i) the distributable value of our partner’s interest in each joint venture is required to be adjusted by mutual agreement or under a valuation procedure outlined in each joint venture agreement based, among other things, on changes in the market value of the joint venture’s assets allocable to our partner (including the value of the notes receivable); and (ii) the parties are obligated to set off the value of the notes receivable from our partner against the value of our partner’s interest in the applicable joint venture. For reporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. Our estimate was not derived using the explicit valuation procedures required under the joint venture agreements which, at the earliest, would be required in 2022 and, as such, the actual value of our partner’s allocable share of each joint venture’s assets may differ from our estimate. The aggregate fair values of the notes receivable and the estimated redemption values of our partner’s interest in the joint ventures as of the reporting date are presented on the Consolidated Balance Sheets on a net basis as Other long-term liabilities of $82.9 million as of December 31, 2015. Aggregate changes in the fair values of the notes receivable and the estimated redemption value of the mandatorily redeemable preferred interests in the WestTX and WestOK joint ventures resulted in income of $30.6 million within interest expense, net on the Consolidated Statement of Operations for the year ended December 31, 2015. The following table shows the changes in long-term liabilities attributable to mandatorily redeemable preferred interests: Liability attributable to mandatorily redeemable preferred interests Balance at December 31, 2014 $ - Acquired mandatorily redeemable preferred interests 109.3 Change in estimated redemption value (30.6 ) Income attributable to mandatorily redeemable preferred interests 2.8 Other activity, net 1.4 Balance at December 31, 2015 $ 82.9 Deferred Revenue and Other Deferred revenue and other includes consideration received in a 2015 amendment to a gas gathering and processing agreement which requires future performance by Targa. The consideration paid for the contract amendment will require future performance by Targa which has resulted in the deferred revenue. The deferred revenue will be recognized on a straight-line basis through the end of the agreement’s term in 2030. As of December 31, 2015, the balance of deferred revenue is $21.1 million. For the year ended December 31, 2015, we recognized approximately $1.4 million of revenue for this transaction. See Note 21 – Supplemental Cash Flow Information. |
Partnership Units and Related M
Partnership Units and Related Matters | 12 Months Ended |
Dec. 31, 2015 | |
Partnership Units and Related Matters [Abstract] | |
Partnership Units and Related Matters | Note 11 — Partnership Units and Related Matters Public Offerings of Common Units In July 2012, we filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $300.0 million of debt or equity securities (the “2012 Shelf”). The 2012 Shelf expired in August 2015. In August 2012, we entered into an Equity Distribution Agreement (the “2012 EDA”) with Citigroup Global Markets Inc. (“Citigroup”) pursuant to which we may sell, at our option, up to an aggregate of $100.0 million of our common units through Citigroup, as sales agent, under the 2012 Shelf. During the year ended December 31, 2013, we issued 2,420,046 common units under the 2012 EDA, receiving net proceeds of $94.8 million. Targa contributed $2.0 In March 2013, we entered into a second Equity Distribution Agreement under the 2012 Shelf (the “March 2013 EDA”) with Citigroup, Deutsche Bank Securities Inc. (“Deutsche Bank”), Raymond James & Associates, Inc. (“Raymond James”) and UBS Securities LLC (“UBS”), as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $200.0 million of our common units. During the year ended December 31, 2013 we issued 4,204,751 common units receiving net proceeds of $197.5 million. Targa contributed $4.1 million to maintain its 2% general partner interest. In August 2013, we entered into an Equity Distribution Agreement under the July 2013 Shelf (the “August 2013 EDA”) with Citigroup, Deutsche Bank, Morgan Stanley & Co. LLC (“Morgan Stanley”), Raymond James, RBC Capital Markets, LLC (“RBC”), UBS and Wells Fargo Securities, LLC (“Wells Fargo”), as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $400.0 million of our common units. During the year ended 2013, we issued 4,259,641 common units under the August 2013 EDA, receiving net proceeds of $225.6 million. Targa contributed $4.7 million to us to maintain its 2% general partner interest. In May 2014, we entered into an additional equity distribution agreement under our July 2013 Shelf (the “May 2014 EDA”), with Barclays Capital Inc., Citigroup, Deutsche Bank, Jefferies LLC, Morgan Stanley, Raymond James, RBC, UBS and Wells Fargo, as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $400 million of our common units. During the year ended 2014, pursuant to the August 2013 EDA and the May 2014 EDA, we issued a total of 7,175,096 common units representing total net proceeds of $408.4 million, (net of commissions up to 1% of gross proceeds to our sales agent), which were used to reduce borrowings under the TRP Revolver and for general partnership purposes. Targa contributed $8.4 million to us to maintain its 2% general partner interest. In May 2015, we entered into an additional Equity Distribution Agreement under the April 2015 Shelf (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. As of December 31, 2015,, we issued 7,377,380 common units under our EDAs, receiving net proceeds of $316.1 million. As of December 31, 2015, approximately $4.2 million of capacity and $835.6 million of capacity remain under the May 2014 and May 2015 EDAs. As of December 31, 2015, Targa contributed $6.5 million to us to maintain its 2% general partner interest. Pursuant to the TRC/TRP Merger Agreement, TRC has agreed to cause the TRP common units to be delisted from the NYSE and deregistered under the Exchange Act. As a result of the completion of the TRC/TRP Merger, the TRP common units are no longer publicly traded. 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. Targa contributed $52.4 million to us to maintain its 2% general partner interest. Issuance of Preferred Units In October 2015, under our automatic shelf registration statement filed in April 2013 and amended by a post-effective amendment filed in October 2015 (the “April 2013 Shelf”), we completed an offering of 4,400,000 Preferred Units at a price of $25.00 per unit. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 600,000 Preferred Units at a price of $25.00 per unit. We received net proceeds after costs of approximately $121.1 million. We used the net proceeds from this offering to reduce borrowings under our senior secured credit facility and for general partnership purposes. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.” Distributions on the Preferred Units are cumulative from the date of original issue and are payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of our general partner. Distributions on the Preferred Units will be payable out of amounts legally available therefor from at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on the Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. The Preferred Units will, with respect to anticipated monthly distributions, rank: · senior to our common units and to each other class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is not expressly made senior to or pari passu with the Preferred Units as to the payment of distributions; · pari passu with any class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is not expressly made senior or subordinated to the Preferred Units as to the payment of distributions; · junior to all of our existing and future indebtedness (including (i) indebtedness outstanding under our senior secured credit facility, (ii) our 5% Notes, our 4⅛% Notes, our 6⅝% Notes, our 6⅞% Senior Notes due 2021, our 6⅜% Senior Notes due 2022, our 5¼% Senior Notes due 2023, our 4¼% Senior Notes due 2023 and our 6¾% Notes and (iii) indebtedness outstanding under our Securitization Facility and other liabilities with respect to assets available to satisfy claims against us; and · junior to each other class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units that is expressly made senior to the Preferred Units as to the payment of distributions. At any time on or after November 1, 2020, we may redeem the Preferred Units, in whole or in part, from any source of funds legally available for such purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. In addition, we (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in our Partnership Agreement. If we do not (or a third party with our prior written consent does not) exercise this option, then the holders of the Preferred Units have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in our partnership agreement. If we exercise (or a third party with our prior written consent exercises) our redemption rights relating to any Preferred Units, the holders of those Preferred Units will not have the conversion right described above with respect to the Preferred Units called for redemption. Holders of Preferred Units have no voting rights except for certain exceptions set forth in our Partnership Agreement. As of December 31, 2015, we have paid $1.5 million in distributions to our preferred unitholders. Distributions In accordance with the Partnership Agreement, we must distribute all of our available cash, as determined by the general partner, to common unitholders of record within 45 days after the end of each quarter. The following table details the distributions declared and/or paid by us during the periods presented. As a result of the TRC/TRP Merger, which was completed on February 17, 2016, Targa owns all of our outstanding common units. Distributions Three Months Ended Date Paid Limited Partners General Partner Distributions per Limited Partner Unit Common Incentive Distribution Rights 2 % Total (In millions, except per unit amounts) December 31, 2015 February 9, 2016 $ 152.5 $ 43.9 (1 ) $ 4.0 $ 200.4 $ 0.8250 September 30, 2015 November 13, 2015 152.5 43.9 (1 ) 4.0 200.4 0.8250 June 30, 2015 August 14, 2015 152.5 43.9 (1 ) 4.0 200.4 0.8250 March 31, 2015 May 15, 2015 148.3 41.7 (1 ) 3.9 193.9 0.8200 2014 December 31, 2014 February 13, 2015 96.3 38.4 2.7 137.4 0.8100 September 30, 2014 November 14, 2014 92.3 36.0 2.6 130.9 0.7975 June 30, 2014 August 14, 2014 89.5 33.7 2.5 125.7 0.7800 March 31, 2014 May 15, 2014 87.2 31.7 2.4 121.3 0.7625 2013 December 31, 2013 February 14, 2014 84.0 29.5 2.3 115.8 0.7475 September 30, 2013 November 14, 2013 79.4 26.9 2.2 108.5 0.7325 June 30, 2013 August 14, 2013 75.8 24.6 2.0 102.4 0.7150 March 31, 2013 May 15, 2013 71.7 22.1 1.9 95.7 0.6975 (1) Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDRs of $9.375 million were allocated to common unitholders in each of the quarters for 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and resulted in reallocation of IDR payments to common unitholders in the following amounts: $9.375 million per quarter for 2015. The IDR Giveback will result in reallocation of IDR payments to common unitholders of $6.25 million in the first quarter of 2016. |
Earnings per Limited Partner Un
Earnings per Limited Partner Unit | 12 Months Ended |
Dec. 31, 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 (loss) and weighted average shares outstanding used in computing basic and diluted net income (loss) per limited partner unit: 2015 2014 2013 Net income (loss) $ (59.3 ) $ 505.1 $ 258.6 Less: Net income attributable to noncontrolling interests (31.9 ) 37.4 25.1 Net income (loss) attributable to Targa Resources Partners LP $ (27.4 ) $ 467.7 $ 233.5 Net income attributable to preferred limited partners $ 2.4 $ - $ - Net income attributable to general partner 167.7 148.7 107.5 Net income (loss) attributable to limited partners (197.5 ) 319.0 126.0 Net income (loss) attributable to Targa Resources Partners LP $ (27.4 ) $ 467.7 $ 233.5 Weighted average units outstanding - basic 172.3 114.7 105.5 Net income (loss) available per limited partner unit - basic $ (1.15 ) $ 2.78 $ 1.19 Weighted average units outstanding 172.3 114.7 105.5 Dilutive effect of unvested stock awards - 0.4 0.2 Weighted average units outstanding - diluted (1) 172.3 115.1 105.7 Net income (loss) available per limited partner unit - diluted $ (1.15 ) $ 2.77 $ 1.19 (1) For the year ended December 31, 2015 and 2014, approximately 697,989 and 168,495 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activities | 12 Months Ended |
Dec. 31, 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 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 $67.9 million related to these novated contracts were received during the year ended December 31, 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 were settled in December 2015, which resulted in a $2.2 million gain on cash settlement for the year ended December 31, 2015. Additionally, for the year ended December 31, 2015, we recorded $0.9 million of ineffectiveness gains related to otherwise qualifying APL derivatives, primarily natural gas swaps. At December 31, 2015, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2016 2017 2018 Natural Gas Swaps MMBtu/d 83,264 23,082 - Natural Gas Basis Swaps MMBtu/d 48,962 18,082 - Natural Gas Collars MMBtu/d 22,900 22,900 9,486 NGL Swaps Bbl/d 4,473 1,078 208 NGL Futures Bbl/d 1,956 - - NGL Options/Collars Bbl/d 920 920 32 Condensate Swaps Bbl/d 1,502 500 - Condensate Options/Collars Bbl/d 790 790 101 We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and 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 within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of December 31, 2015 Fair Value as of December 31, 2014 Balance Sheet Location Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 92.1 $ 2.1 $ 44.4 $ - Long-term 34.9 2.4 15.8 - Total derivatives designated as hedging instruments $ 127.0 $ 4.5 $ 60.2 $ - Derivatives not designated as hedging instruments Commodity contracts Current $ 0.1 $ 3.1 $ - $ 5.2 Total derivatives not designated as hedging instruments $ 0.1 $ 3.1 $ - $ 5.2 Total current position $ 92.2 $ 5.2 $ 44.4 $ 5.2 Total long-term position 34.9 2.4 15.8 - Total derivatives $ 127.1 $ 7.6 $ 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 December 31, 2015 Asset Position Liability Position Asset Position Liability Position Current position Counterparties with offsetting position $ 86.9 $ 5.2 $ 81.7 $ - Counterparties without offsetting position - assets 5.3 - 5.3 - Counterparties without offsetting position - liabilities - - - - 92.2 5.2 87.0 - Long-term position Counterparties with offsetting position 34.2 2.4 31.8 - Counterparties without offsetting position - assets 0.7 - 0.7 - Counterparties without offsetting position - liabilities - - - - 34.9 2.4 32.5 - Total derivatives Counterparties with offsetting position 121.1 7.6 113.5 - Counterparties without offsetting position - assets 6.0 - 6.0 - Counterparties without offsetting position - liabilities - - - - $ 127.1 $ 7.6 $ 119.5 $ - 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. Some of our hedges are futures contracts executed through a counterparty that clears the hedges through an exchange. The payment obligations on these futures are settled daily. The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a net asset of $119.5 million as of December 31, 2015. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that are cleared through an exchange are settled daily and do not require any credit adjustment. The following tables reflect amounts recorded in Other Comprehensive Income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated: Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Derivatives in Cash Flow Hedging Relationships 2015 2014 2013 Commodity contracts $ 81.3 $ 59.8 $ (5.8 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2015 2014 2013 Interest expense, net $ - $ (2.4 ) $ (6.1 ) Revenues 54.8 (4.2 ) 21.2 $ 54.8 $ (6.6 ) $ 15.1 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 2015 2014 2013 Commodity contracts Revenue $ (5.7 ) $ (5.5 ) $ (0.1 ) The following table shows the deferred gains (losses) included in accumulated OCI, which will be reclassified into earnings through the end of 2018 as of the balance sheet date: December 31, 2015 December 31, 2014 Commodity hedges (1) $ 86.7 $ 60.3 (1) Includes deferred net gains of $52.1 million as of December 31, 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 | 12 Months Ended |
Dec. 31, 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, futures, option contracts and fixed-price forward commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and 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 December 31, 2015, a net asset position of $119.5 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 $99.8 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 $138.1 million, ignoring an adjustment for counterparty credit risk. Fair Value of Other Financial Instruments Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows: • The senior secured revolving credit facility (the “TRP Revolver”) and the Securitization Facility • Senior unsecured notes are based on quoted market prices derived from trades of the debt. We have a contingent consideration liability for APL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value (see Note 4 – Business Acquisitions). Fair Value Hierarchy We categorize the inputs to the fair value measurements of financial assets and liabilities using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value: • Level 1 – observable inputs such as quoted prices in active markets; • Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid for the relevant settlement periods; and • Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions. The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments: December 31, 2015 Carrying Value Fair Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 127.1 $ 127.1 $ - $ 123.1 4.0 Liabilities from commodity derivative contracts (1) 7.6 7.6 0.3 7.0 0.3 TPL contingent consideration (2) 3.0 3.0 - - 3.0 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 135.4 135.4 - - - Senior secured revolving credit facility 280.0 280.0 - 280.0 - Senior unsecured notes 4,884.0 4,192.0 - 4,192.0 - Accounts receivable securitization facility 219.3 219.3 - 219.3 - December 31, 2014 Carrying Value Fair Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts $ 60.2 $ 60.2 $ - $ 58.4 $ 1.8 Liabilities from commodity derivative contracts 5.2 5.2 - 5.1 0.1 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 72.3 72.3 - - - Senior secured revolving credit facility - - - - - Senior unsecured notes 2,783.4 2,731.5 - 2,731.5 - Accounts receivable securitization facility 182.8 182.8 182.8 - - (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 December 31, 2015, we had 14 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are the forward natural gas curves, for which a significant portion of the derivative’s term is beyond available forward pricing. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial. The fair value of the contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures. These probability-based inputs are not observable; the entire valuation of the contingent consideration is categorized in Level 3. Changes in the fair value of this liability are included in Other Income on the Consolidated Statements of Operations. The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts (Asset)/Liability Contingent Liability Balance, December 31, 2012 $ 0.6 $ 15.3 Settlements included in Revenue (1.3 ) - Change in valuation of contingent liability included in Other Income - (15.3 ) Balance, December 31, 2013 (0.7 ) - Settlements included in Revenue (0.2 ) - Unrealized losses included in OCI (1.1 ) - Transfers out of Level 3 0.3 - Balance, December 31, 2014 (1.7 ) - TPL contingent consideration fair value at acquisition date (see Note 4-Business Acquisitions) - 4.2 Change in fair value of TPL contingent consideration included in Other Income - (1.2 ) New Level 3 instruments (3.7 ) - Transfers out of Level 3 1.7 - Balance, December 31, 2015 $ (3.7 ) $ 3.0 For the year ended December 31, 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
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 15 — Related Party Transactions Relationship with Targa We do not have any employees. Targa provides operational, general and administrative and other services to us associated with our existing assets and assets acquired from third parties. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Our Partnership Agreement governs the reimbursement of costs incurred by Targa on behalf of us. Targa charges us for all the direct costs of the employees assigned to our operations, as well as all general and administrative support costs other than (1) costs attributable to Targa’s status as a separate reporting company and (2) costs of Targa providing management and support services to certain unaffiliated spun-off entities. We generally reimburse Targa monthly for cost allocations to the extent that Targa has made a cash outlay. The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable. 2015 2014 2013 Targa billings of payroll and related costs included in operating expense $ 153.8 $ 124.9 $ 109.7 Targa allocation of general and administrative expense 136.2 129.4 134.3 Cash distributions to Targa based on IDR and unit ownership 233.4 180.7 138.2 Cash contributions from Targa to maintain its 2% general partner ownership 60.1 7.7 10.8 Transactions with Unconsolidated Affiliates For the years ended December 31, 2015, 2014 and 2013, transactions with GCF included in revenues were $0.5 million, $0.8 million and $0.4 million. For the same periods, transactions with GCF included in costs and expenses were $5.8 million, $7.6 million and $6.3 million. The Partnership is subject to paying a deficiency fee in instances where the Partnership does not deliver its minimum volume requirements as outlined in the Partnership and fractionation agreements with GCF. For the year ended December 31, 2015, capacity lease fees paid to T2 Eagle Ford and T2 LaSalle included in operating expenses were $2.8 million and $1.1 million, respectively. These fees are billed to the Partnership based on its portion of the cost to operate each respective joint venture. As of December 31, 2015, the Partnership had a $1.8 million payable to T2 Eagle Ford for capital project cash calls and accrued lease capacity fees. |
Commitments (Leases)
Commitments (Leases) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments (Leases) [Abstract] | |
Commitments (Leases) | Note 16 — Commitments (Leases) Future lease obligations are presented below in aggregate and for each of the next five fiscal years. In Aggregate 2016 2017 2018 2019 2020 Operating leases (1) $ 42.1 $ 16.0 $ 10.8 $ 8.8 $ 3.7 $ 2.8 Land site lease and right-of-way (2) 11.0 2.4 2.3 2.2 2.1 2.0 $ 53.1 $ 18.4 $ 13.1 $ 11.0 $ 5.8 $ 4.8 (1) Includes minimum payments on lease obligations for office space, railcars and tractors. (2) Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual. Total expenses incurred under the above lease obligations were: 2015 2014 2013 Operating leases (1) $ 40.4 $ 24.4 $ 23.3 Land site lease and right-of-way 4.2 4.1 3.6 (1) Includes short-term leases for items such as compressors and equipment. |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Contingencies [Abstract] | |
Contingencies | Note 17 - Contingencies Legal Proceedings Litigation related to TRC/TRP Merger On December 16, 2015, two purported unitholders of TRP (the “State Court Plaintiffs”) filed a putative class action and derivative lawsuit challenging the TRC/TRP Merger against TRC, TRP (as a nominal defendant), TRP GP, the members of the board of our general partner (the “TRP GP Board”) and Merger Sub (collectively, the “State Court Defendants”). This lawsuit is styled Leslie Blumberg et al. v. TRC Resources Corp., et al. The State Court Plaintiffs allege several causes of action challenging the TRC/TRP Merger. Generally, the State On December 16, 2015, two purported unitholders of TRP (the “State Court Plaintiffs”) filed a putative class action and derivative lawsuit challenging the TRC/TRP Merger against TRC, TRP (as a nominal defendant), TRP GP, the members of the board of our general partner (the “TRP GP Board”) and Merger Sub (collectively, the “State Court Defendants”). This lawsuit is styled Leslie Blumberg et al. v. TRC Resources Corp., et al. The State Court Plaintiffs allege several causes of action challenging the TRC/TRP Merger. Generally, the State Court Plaintiffs allege that (i) the members of the TRP GP Board breached express and/or implied duties under the TRP partnership agreement and (ii) TRC, our general partner, and Merger Sub aided and abetted in these alleged breaches of duties. The State Court Plaintiffs further allege, in general, that (a) the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair and (e) the TRP GP Board has conflicts of interest due to TRC’s control of our general partner. Based on these allegations, the State Court Plaintiffs sought to enjoin the State Court Defendants from proceeding with or consummating the TRC/TRP Merger unless and until the TRP GP Board adopted and implemented processes to obtain the best possible terms for TRP common unitholders. The State Court Plaintiffs now seek to have the TRC/TRP Merger rescinded. The date to answer or otherwise respond to the State Court Lawsuit is currently set for February 29, 2016. On January 6 and 19, 2016, two additional purported unitholders of TRP (the “Federal Court Plaintiffs”) filed two putative class action lawsuits challenging the disclosures made in connection with the TRC/TRP Merger against TRP and the members of the TRP GP Board (the “Federal Court Defendants”). These lawsuits have been consolidated as In re Targa Resources Partners, L.P. Securities Litigation The Federal Court Plaintiffs allege that (i) the Federal Court Defendants have violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and (ii) the members of the TRP GP Board have violated Section 20(a) of the Exchange Act. The Federal Court Plaintiffs allege, in general, that the preliminary and definitive joint proxy statements/prospectuses filed in connection with the TRC/TRP Merger fail, among other things, to disclose allegedly material information concerning (i) the TRP GP Conflicts Committee’s financial advisor’s and TRC’s financial advisor’s analyses in connection with the TRC/TRP Merger, (ii) certain TRC and TRP projections, and (iii) the events leading up to the TRC/TRP Merger. The Federal Court Plaintiffs further allege, in general, that (a) the premium offered to TRP’s unitholders was inadequate, (b) the TRC/TRP Merger did not include a collar to protect TRP unitholders from decreases in TRC’s stock price, (c) the TRP GP Board agreed to contractual terms that allegedly may have dissuaded other potential acquirers from seeking to acquire TRP (including the “no-solicitation,” “matching rights,” and “termination fee” provisions), (d) the process leading up to the TRC/TRP Merger was unfair and (e) the TRP GP Board has conflicts of interest due to TRC’s control of the general partner. Based on these allegations, the Federal Court Plaintiffs sought to enjoin the Federal Court Defendants from proceeding with or consummating the TRC/TRP Merger unless and until the Federal Court Defendants disclosed the allegedly omitted information summarized above. The Federal Court Plaintiffs now seek to have the TRC/TRP Merger rescinded. The Federal Court Plaintiffs also seek damages and attorneys’ fees. One of the Federal Court Plaintiffs sought a Temporary Restraining Order (“TRO”) to prevent the Federal Court Defendants from proceeding with the TRC/TRP vote and/or merger. On January 29, 2016, this Plaintiff was denied his request for a TRO. The date for the Federal Court Defendants to answer, move to dismiss, or otherwise respond to the Federal Court Lawsuits has not yet been set. Neither the State Court Defendants nor the Federal Court Defendants (collectively, the “Defendants”) can predict the outcome of these or any other lawsuits that might be filed subsequent to the date of the filing of this report, nor can Defendants predict the amount of time and expense that will be required to resolve such litigation. Defendants believe these lawsuits are without merit and intend to defend vigorously against these lawsuits and any other actions challenging the TRC/TRP Merger. Targa Litigation related to Atlas Mergers On January 28, 2015, a public shareholder of TRC (the “TRC Plaintiff”) filed a putative class action and derivative lawsuit against TRC (as a nominal defendant), its directors at the time of the ATLS Merger (the “TRC Director Defendants”), and ATLS (together with TRC 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 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) TRC’s financial projections, (iii) the background of the ATLS Merger, and (iv) Wells Fargo Securities, LLC’s analysis of the ATLS Merger. Based on these allegations, the TRC Plaintiff sought to enjoin the TRC Lawsuit Defendants from proceeding with or consummating the ATLS Merger unless and until TRC disclosed the allegedly material omitted details. The TRC Plaintiff also sought to have the ATLS Merger rescinded, recissory damages, and attorneys’ fees. On June 9, 2015, the Court dismissed the TRC Lawsuit with prejudice. Atlas Unitholder Litigation Between October and December 2014, five public unitholders of APL (the “APL Plaintiffs”) filed putative class action lawsuits against APL, ATLS, APL GP, its managers, Targa, the Partnership, the general partner and MLP Merger Sub (the “APL Lawsuit Defendants”). These lawsuits were styled (a) Michael Evnin v. Atlas Pipeline Partners, L.P., et al ., 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 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 were 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 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, which ATLS and APL did on February 11, 2015. The Atlas Lawsuit Defendants agreed to make such supplemental disclosures solely to avoid the uncertainty, risk, burden, and expense inherent in litigation and deny that any supplemental disclosure was or is required under any applicable rule, statute, regulation or law. On January 21, 2016, the Court granted final approval of the settlements in the Consolidated Atlas Lawsuits and dismissed the Consolidated Atlas Lawsuits with prejudice. Environmental Proceedings On August 22, 2014 and September 9, 2014, the Texas Commission on Environmental Quality (“TCEQ”) issued Notices of Enforcement (“NOEs”) to Targa Midstream Services LLC for alleged violations of air emissions regulations at the Mont Belvieu Fractionator relating to the operations of two regenerative thermal oxidizers during 2013 and 2014 and an unrelated discrete emissions event that occurred on May 29, 2014. On May 26, 2015, we signed an Agreed Order resolving all alleged violations stated in the NOEs. The Executive Director of the TCEQ signed the Agreed Order on September 11, 2015, and the TCEQ Commissioners approved the Agreed Order during their November 4, 2015 meeting. Pursuant to the Agreed Order, we (1) paid an administrative penalty in the amount of $115,644; and (2) paid $115,643 to fund certain supplemental environmental projects. Under the Agreed Order, we must comply with certain ordering provisions, including a requirement to install a flare gas recovery unit at the Mont Belvieu Fractionator within one year of the effective date of the Agreed Order. On June 18, 2015, the New Mexico Environment Department’s Air Quality Bureau issued a Notice of Violation to Targa Midstream Services LLC for alleged violations of air emissions regulations related to emissions events that occurred at the Monument Gas Plant between June 2014 and December 2014. The Monument Gas Plant is operated by us and owned by Versado Gas Processors, L.L.C., which is a joint venture in which we own a 63% interest. We are in discussions with the New Mexico Environment Department to resolve the alleged violations. We anticipate that this matter could result in a monetary sanction in excess of $100,000 but less than $300,000. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. |
Income Tax
Income Tax | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax [Abstract] | |
Income Tax | Note 18 – Income Tax 2015 2014 2013 Provision for Income Taxes: Current expense $ 0.8 $ 3.2 $ 2.0 Deferred expense (benefit) (0.2 ) 1.6 0.9 Total income tax expense (benefit) $ 0.6 $ 4.8 $ 2.9 The Partnership is subject to the Texas margin tax, consisting generally of a 0.75% tax on the amounts by which total revenues exceed cost of goods sold, as apportioned to Texas. As part of the APL merger in 2015, the Partnership acquired TPL Arkoma, Inc., a corporate subsidiary subject to federal and state income tax. The Partnership’s corporate subsidiary accounts for income taxes under the asset and liability method and provides deferred income taxes for all significant temporary differences. Our deferred income tax assets and liabilities at December 31, 2015 consist of differences related to the timing of recognition of certain types of costs as follows: Year Ended December 31, 2015 2014 Deferred tax assets: Net operating loss carryforwards $ 19.8 $ - Deferred tax liabilities: Property, plant, and equipment (47.0 ) (13.7 ) Net deferred tax asset/(liability) $ (27.2 ) $ (13.7 ) As of December 31, 2015, TPL Arkoma, Inc. had net operating loss carry forwards for federal income tax purposes of approximately $51.3 million, which expire at various dates from 2029 to 2035. Management of the General Partner believes it more likely than not that the deferred tax asset will be fully utilized. |
Significant Risks and Uncertain
Significant Risks and Uncertainties | 12 Months Ended |
Dec. 31, 2015 | |
Significant Risks and Uncertainties [Abstract] | |
Significant Risks and Uncertainties | Note 19 — Significant Risks and Uncertainties Nature of Operations in Midstream Energy Industry We operate in the midstream energy industry. Our business activities include gathering, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products and changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. Our profitability could be impacted by a decline in the volume of crude oil, natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration and development activities, or otherwise, could result in a decline in the volume of crude oil, natural gas, NGLs and condensate handled by our facilities. A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position. The principal market risks are exposure to changes in commodity prices, as well as changes in interest rates. Commodity Price Risk A majority of the revenues from the gathering and processing business are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes as payment for services. The prices of natural gas and NGLs are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. In an effort to reduce the variability of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated with a significant portion of our expected natural gas, NGL equity volumes and condensate equity volumes through 2018 by entering into financially settled derivative transactions. Historically, these transactions have included both swaps and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We hedge a higher percentage of our expected equity volumes in the earlier future periods. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGLs and pays the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. To reduce the volatility of our cash flows, we have entered into derivative financial instruments related to a portion of our equity volumes to manage the purchase and sales prices of commodities. We also monitor NGL inventory levels with a view to mitigating losses related to downward price exposure. Interest Rate Risk We are exposed to changes in interest rates, primarily as a result of our variable rate borrowings under our TRP Revolver and Securitization Facility. Counterparty Risk – Credit and Concentration Derivative Counterparty Risk Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties. We have master netting provisions in the International Swap Dealers Association agreements with all of our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties, and would reduce our maximum loss due to counterparty credit risk by $7.6 million as of December 31, 2015. The range of losses attributable to our individual counterparties would be between $0.4 million and $38.9 million, depending on the counterparty in default. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value, representing expected future receipts, at the reporting date. At such times, these outstanding instruments expose us to losses in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. Customer Credit Risk We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met. The following table summarizes the activity affecting our allowance for bad debts: 2015 2014 2013 Balance at beginning of year $ - $ 0.9 $ 0.7 Additions 0.1 - 0.2 Deductions (0.9 ) - Balance at end of year $ 0.1 $ - $ 0.9 Significant Commercial Relationship During the years ended December 31, 2015, 2014 and 2013, we did not have any commercial relationships that exceeded 10% of consolidated revenues. During the year ended December 31, 2015, ONEOK Hydrocarbon L.P. accounted for 12% of our consolidated purchases with a supplier. During the years ended December 31, 2014 and 2013, we did not have any suppliers that exceeded 10% of our consolidated product purchases. Casualty or Other Risks Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverage which is customary for the nature and scope of our operations. The majority of the insurance costs described above is allocated to us by Targa through the Partnership Agreement described in Note 15 – Related Party Transactions Management believes that Targa has adequate insurance coverage, although insurance may not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles may change overtime, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Targa may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations. Furthermore, even when a business interruption event is covered, it could affect interperiod results as we would not recognize the contingent gain until realized in a period following the incident. |
Other Operating (Income) Expens
Other Operating (Income) Expense | 12 Months Ended |
Dec. 31, 2015 | |
Other Operating (Income) Expense [Abstract] | |
Other Operating (Income) Expense | Note 20 — Other Operating (Income) Expense 2015 2014 2013 Loss (gain) on sale or disposal of assets $ (8.0 ) $ (4.8 ) $ 3.9 Casualty (gain) loss (0.2 ) 0.1 4.3 Miscellaneous business tax 0.5 0.4 0.7 Other 0.6 1.3 0.7 $ (7.1 ) $ (3.0 ) $ 9.6 |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | Note 21 — Supplemental Cash Flow Information 2015 2014 2013 Cash: Interest paid, net of capitalized interest (1) $ 193.1 $ 131.0 $ 119.1 Income taxes paid, net of refunds 3.4 2.7 2.3 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment 1.2 14.8 30.4 Impact of capital expenditure accruals on property, plant and equipment 43.8 19.0 (0.4 ) Transfers from materials and supplies inventory to property, plant and equipment 3.7 4.6 20.5 Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate 3.8 2.1 1.4 Property, plant and equipment in consideration of contract amendment (2) 22.6 - - Non-cash financing activities: Debt additions and retirements related to exchange of TRP 6⅝% Notes for APL 6⅝% Notes 342.1 - - Reductions in Owner's Equity related to accrued distributions on unvested equity awards under share compensation arrangements 1.6 1.4 1.7 Receivables from equity issuances - 1.0 - Accrued distributions of preferred unit 0.9 - - Non-cash balance sheet movements related to business acquisition: (See Note 4) 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 $13.2 million, $16.1 million and $28.0 million for 2015, 2014 and 2013. (2) We measured the estimated fair value of the assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. |
Compensation Plans
Compensation Plans | 12 Months Ended |
Dec. 31, 2015 | |
Compensation Plans [Abstract] | |
Compensation Plans | Note 22 — Compensation Plans We recognize compensation expenses related to awards under our long-term incentive plan and expenses allocated to us under Targa’s incentive plan. The components of each plan are shown as below: Partnership Long-Term Incentive Plan Performance Units - Equity-settled Phantom Units - Equity -settled Phantom Units Replacement Phantom Units Director Grants Allocated compensation cost related to: TRC Long-Term Incentive Plan Cash-settled Performance Units 2010 TRC Stock Incentive Plan Restricted Stock Awards Restricted Stock Units - Equity- settled Restricted Stock Units Replacement Restricted Stock Units Targa 401(k) Plan Long-Term Incentive Plans Performance Units In 2007, both Targa and we adopted Long-Term Incentive Plans (each, an “LTIP”) for employees, consultants, directors and non-employee directors of Targa and its affiliates who perform services for Targa or its affiliates. The performance units granted under these plans are linked to the performance of our common units. Targa’s LTIP (the “TRC LTIP”) provides for the grant of cash-settled performance units only, but our LTIP (“TRP LTIP”) provides for, among other things, the grant of both cash-settled and equity-settled performance units. Performance unit awards granted under either LTIP may also include distribution equivalent rights (“DERs”). The TRP LTIPs are administered by the board of directors of our general partner, while the TRC LTIP is administered by the compensation committee (the “Committee”) of the Targa Board of Directors. Total units authorized under the TRP LTIP are 1,680,000. Each performance unit will entitle the grantee to the value of our common unit on the vesting date multiplied by a stipulated vesting percentage determined from our ranking in a defined peer group. Currently, the performance period for most awards is three years, except for certain awards granted in December 2013, which provide for two, three or four-year vesting periods. The grantee will receive the vested unit value in cash or common units depending on the terms of the grant. The grantee may also be entitled to the value of any DERs based on the notional distributions accumulated during the vesting period times the vesting percentage. DERs are paid for both cash-settled and equity-settled performance units. Compensation cost for equity-settled performance units is recognized as an expense over the performance period based on fair value at the grant date. Fair value is calculated using a simulated unit price that incorporates peer ranking. DERs associated with equity-settled performance units are accrued over the performance period as a reduction of owners’ equity. Compensation expense for cash-settled performance units and any related DERs will ultimately be equal to the cash paid to the grantee upon vesting. However, throughout the performance period we must record an accrued expense based on an estimate of that future pay-out. Targa and we use a Monte Carlo simulation model and historical volatility assumption to estimate accruals throughout the vesting period. Equity-Settled Performance Units The following table summarizes activities of our equity-settled performance units for the years ended December 31, 2015, 2014 and 2013. Number of units Weighted Average Grant-Date Fair Value Outstanding at December 31, 2012 307,620 $ 38.40 Granted 244,578 46.54 Outstanding at December 31, 2013 552,198 42.01 Granted 168,495 57.19 Vested (137,170 ) 34.02 Forfeited (6,120 ) 49.39 Outstanding at December 31, 2014 577,403 48.26 Granted 277,242 34.48 Vested (178,900 ) 41.92 Outstanding at December 31, 2015 675,745 44.29 Equity – Settled Phantom units In 2015, we granted phantom units under our LTIP to various employees of Targa. These phantom units are denominated with respect to our common units, but are not otherwise linked to the performance of our common units. Their vesting periods vary from one year to five years. The DERs of the phantom units are accumulated to be paid in cash at vesting date. Phantom Units In 2015 we issued 25,162 phantom units with the weighted average grant date fair value of $36.87. As of December 31, 2015, there are no forfeited phantom units. Replacement Phantom Units In connection with the APL merger, we awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreements to those APL employees who became Targa employees upon closing of the acquisition. The vesting dates and terms remained unchanged from the original APL awards, and will vest either 25% per year over the original four year term or 33% per year over the original three year term. The DERs of the replacement phantom units are paid in cash within 60 days of the payment of distributions (see Note 4 - Business Acquisitions.) The following table summarize the activities of the awards for the year ended 2015. Number of units Weighted Average Grant-Date Fair Value Outstanding at December 31, 2014 - $ - Granted 629,231 43.82 Vested (224,021 ) 43.82 Forfeited (49,852 ) 43.82 Outstanding at December 31, 2015 355,358 $ 43.82 Subsequent Event – Director Grants Starting in 2012, the common units granted to our non-management directors vest immediately at the grant date. The following table summarizes the activities of the common unit-based awards granted to our Directors for the years ended December 31, 2015, 2014 and 2013 (in units and dollars): Number of units Weighted Average Grant-Date Fair Value Outstanding at December 31, 2012 4,500 $ 23.51 Granted 12,780 39.33 Vested (17,280 ) 35.21 Outstanding at December 31, 2013 - - Granted 8,740 50.29 Vested (8,740 ) 50.29 Outstanding at December 31, 2014 - - Granted 10,565 44.67 Vested (10,565 ) 44.67 Outstanding at December 31, 2015 - - Subsequent Event – TRC LTIP - Cash-settled Performance Units The following table summarizes the cash-settled performance units for the year ended 2015 awarded under the TRC LTIP (in units and dollars): Program Year 2012 Awards 2013 Awards 2014 Awards 2015 Awards Total Units outstanding January 1, 2015 138,460 142,110 122,360 - 402,930 Granted - - - 198,280 198,280 Vested and paid (138,460 ) - - - (138,460 ) Forfeited - (2,410 ) (2,460 ) (5,890 ) (10,760 ) Units outstanding December 31, 2015 - 139,700 119,900 192,390 451,990 Calculated fair market value as of December 31, 2015 $ 622,496 $ 359,684 $ 1,662,913 $ 2,645,093 Current liability $ 511,247 $ - $ - $ 511,247 Long-term liability - 172,926 229,460 402,386 Liability as of December 31, 2015 $ 511,247 $ 172,926 $ 229,460 $ 913,633 To be recognized in future periods $ 111,249 $ 186,758 $ 1,433,453 $ 1,731,460 Vesting date June 2016 June 2017 June 2018 The remaining weighted average recognition period for the unrecognized compensation cost is approximately 2.3 years. 2010 TRC Stock Incentive Plan In December 2010, Targa adopted the Targa Resources Corp. 2010 Stock Incentive Plan (“TRC Plan”) for employees, consultants and non-employee directors of the Company. The TRC Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as incentive options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock awards (“Phantom Stock Awards”), (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards (collectively referred to a “Awards”). Restricted Stock Awards – Total shares of Targa common stock authorized under this plan are 5,000,000. Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends, and paid in cash when the award vests. The following table summarizes the restricted stock awards in shares and in dollars for the years indicated: Number of shares Weighted-average Grant-Date Fair Value Outstanding at December 31, 2012 711,030 $ 25.95 Granted (1) 30,623 57.59 Forfeited (2,740 ) 27.28 Vested (2) (534,940 ) 22.00 Outstanding at December 31, 2013 203,973 41.05 Forfeited (1,980 ) 42.82 Vested (82,800 ) 33.37 Outstanding at December 31, 2014 119,193 46.35 Vested (88,570 ) 42.46 Outstanding at December 31, 2015 30,623 57.59 (1) These awards will cliff vest at the end of three years. (2) Awards vested in 2013 were 60% of the awards issued in conjunction with the Targa IPO, net of forfeitures. 40% of the awards vested prior to 2013. Equity-Settled Restricted Stock Units Restricted Stock Units (“RSUs”) Awards – Number of shares Weighted-average Grant-Date Fair Value Outstanding at December 31, 2012 - $ - Granted 55,790 69.90 Forfeited (240 ) 67.07 Outstanding at December 31, 2013 55,550 69.92 Granted 54,357 112.89 Forfeited (1,440 ) 75.81 Vested (100 ) 67.07 Outstanding at December 31, 2014 108,367 91.41 Granted 140,477 83.54 Forfeited (2,530 ) 86.73 Vested (2,220 ) 81.56 Outstanding at December 31, 2015 244,094 87.02 RSU –Replacement Restricted Stock Units In connection with the ATLS merger, we awarded RSUs in accordance with and as required by the Atlas Merger Agreements to those APL employees that who became Targa employees upon closing of the acquisition (“Replacement RSUs”). The vesting dates and terms remained unchanged from the existing ATLS awards, and will vest either 25% per year over the original four year term or 25% after the third year of the original term and 75% after the fourth year of the original term. The dividends of the replacement awards are paid in cash within 60 days of the payment of common stock dividends (see Note 4 – Business Acquisitions for details). The following table summarizes the awards in shares and in dollars for the years indicated. Number of units Weighted Average Grant-Date Fair Value Outstanding at December 31, 2014 - $ - Granted 81,740 99.58 Vested (41,539 ) 99.58 Forfeited (1,556 ) 99.58 Outstanding at December 31, 2015 38,645 $ 99.58 Subsequent Events In January 2016, the Committee made restricted stock units awards of 440,163 shares to executive management and employees under the TRC Plan for the 2016 compensation cycle that will cliff vest in three years from the grant date. On January 15, 2016, 29,123 shares of the restricted stock units granted in January 2013 vested, and Targa repurchased 6,861 shares at $17.04 per share to satisfy the employee’s minimum statutory tax withholdings on the vested awards. The repurchased shares are recorded by Targa in treasury stock at cost. The following table summarizes the compensation expenses under the various compensation plans recognized for the years indicated: 2015 2014 2013 TRP LTIP - Equity-Settled Performance Units $ 9.5 $ 8.8 $ 5.5 TRP LTIP - Equity-Settled Phantom units - Replacement Phantom Units 6.4 - - TRP LTIP - Equity-Settled Phantom units - Phantom Units 0.2 - - Director Grants 0.5 0.4 0.5 Allocated from Targa: TRC LTIP - Cash-Settled Performance Units (2.2 ) 11.0 21.9 2010 TRC Stock Incentive Plan - Restricted Stock 1.1 2.2 6.3 2010 TRC Stock Incentive Plan - Equity-Settled Restricted Stock Units: RSUs 5.4 2.5 0.4 2010 TRC Stock Incentive Plan - Equity-Settled Restricted Stock Units: Replacement RSUs 1.3 - - The table below summarizes the unrecognized compensation expenses and the approximate remaining weighted average vesting periods related to our various share-based compensation plans as of December 31, 2015: Unrecognized Compensation Expense Weighted Average Remaining Vesting Period (In millions) (In years) TRP LTIP Equity-Settled Performance Units $ 13.3 1.9 TRP LTIP Equity-Settled Phantom units - Replacement Phantom Units 5.8 1.3 TRP LTIP Equity-Settled Phantom units - Phantom Units 0.8 3.3 2010 TRC Stock Incentive Plan - Restricted Stock 0.0 0.1 2010 TRC Stock Incentive Plan - Equity-Settled Restricted Stock Units: RSUs 13.1 2.3 2010 TRC Stock Incentive Plan - Equity-Settled Restricted Stock Units: Replacement RSUs 1.5 1.4 The total fair value of share-based awards on the dates they vested are as follows: 2015 2014 2013 TRP LTIP Equity-Settled Performance units $ 7.9 $ 10.0 $ - TRP LTIP Accrued DERs settled for Equity - Settled Performance units 1.7 1.6 - TRP LTIP Replacement Phantom Units 8.8 - - Accrued DERs settled for Phantom units - TRP LTIP Replacement Phantom Units 1.1 - - Director Grants 0.5 0.4 0.7 TRC LTIP Cash-Settled performance units 7.8 14.7 25.2 2010 TRC Stock Incentive Plan - Restricted Stock (1) 7.3 7.1 42.2 Accrued dividends settled 0.2 0.5 2.4 2010 TRC Stock Incentive Plan - Equity-Settled Restricted Stock Units: Replacement RSUs 3.8 - - (1) Targa recognized $1.1 million, $1.0 million and $1.6 million in tax benefits associated with the vesting of the restricted stock for 2015, 2014 and 2013. Targa 401(k) Plan Targa has a 401(k) plan whereby it matches 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan). Targa also contributes an amount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at its sole discretion. All Targa contributions are made 100% in cash. Targa made contributions to the 401(k) plan totaling $13.8 million, $10.5 million and $9.6 million during 2015, 2014 and 2013. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Segment Information | Note 23 — Segment Information We aggregate our reporting segments into 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 merger. Our reportable segment information is shown in the following tables: Year Ended December 31, 2015 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 1,283.0 $ 202.4 $ 104.4 $ 3,791.4 $ 84.2 $ - $ 5,465.4 Fees from midstream services 394.3 32.8 330.2 435.9 - - 1,193.2 1,677.3 235.2 434.6 4,227.3 84.2 - 6,658.6 Intersegment revenues Sales of commodities 894.0 232.3 9.1 290.6 - (1,426.0 ) - Fees from midstream services 8.7 - 264.2 19.5 - (292.4 ) - 902.7 232.3 273.3 310.1 - (1,718.4 ) - Revenues $ 2,580.0 $ 467.5 $ 707.9 $ 4,537.4 $ 84.2 $ (1,718.4 ) $ 6,658.6 Operating margin $ 484.8 $ 30.3 $ 439.5 $ 242.2 $ 84.2 $ - $ 1,281.0 Other financial information: Total assets (1) $ 9,892.3 $ 290.2 $ 1,912.2 $ 605.5 $ 127.1 $ 337.7 $ 13,165.0 Goodwill (2) $ 417.0 $ - $ - $ - $ - $ - $ 417.0 Capital expenditures $ 481.5 $ 14.8 $ 257.6 $ 14.4 $ - $ 8.9 $ 777.2 Business acquisition $ 5,024.2 $ - $ - $ - $ - $ - $ 5,024.2 (1) Corporate assets at the Segment level primarily include investments in unconsolidated subsidiaries and debt issuance cost associated with our debt obligations. (2) Total assets include goodwill. Goodwill has been attributed to our Field Gathering and Processing segment – See Note 4 – Business Acquisitions. Year Ended December 31, 2014 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 197.4 $ 355.0 $ 99.1 $ 6,951.7 $ (8.0 ) $ - $ 7,595.2 Fees from midstream services 190.3 34.4 293.6 503.0 - - 1,021.3 387.7 389.4 392.7 7,454.7 (8.0 ) - 8,616.5 Intersegment revenues Sales of commodities 1,491.2 577.6 4.4 486.7 - (2,559.9 ) - Fees from midstream services 5.2 - 308.3 30.1 - (343.6 ) - 1,496.4 577.6 312.7 516.8 - (2,903.5 ) - Revenues $ 1,884.1 $ 967.0 $ 705.4 $ 7,971.5 $ (8.0 ) $ (2,903.5 ) $ 8,616.5 Operating margin $ 372.3 $ 77.6 $ 445.1 $ 249.6 $ (8.0 ) $ - $ 1,136.6 Other financial information: Total assets $ 3,409.0 $ 367.2 $ 1,717.3 $ 708.5 $ 60.2 $ 115.0 $ 6,377.2 Capital expenditures $ 423.1 $ 14.0 $ 274.4 $ 30.2 $ - $ 6.1 $ 747.8 Year Ended December 31, 2013 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 188.8 $ 305.0 $ 140.5 $ 5,072.4 $ 21.4 $ 0.1 $ 5,728.2 Fees from midstream services 113.9 33.6 216.0 223.3 - (0.1 ) 586.7 302.7 338.6 356.5 5,295.7 21.4 - 6,314.9 Intersegment revenues Sales of commodities 1,218.9 642.2 3.9 478.6 - (2,343.6 ) - Fees from midstream services 3.4 1.0 176.5 29.8 - (210.7 ) - 1,222.3 643.2 180.4 508.4 - (2,554.3 ) - Revenues $ 1,525.0 $ 981.8 $ 536.9 $ 5,804.1 $ 21.4 $ (2,554.3 ) $ 6,314.9 Operating margin $ 270.5 $ 85.4 $ 282.3 $ 141.9 $ 21.4 $ - $ 801.5 Other financial information: Total assets $ 3,200.7 $ 383.8 $ 1,503.6 $ 756.1 $ 5.1 $ 122.1 $ 5,971.4 Capital expenditures $ 557.8 $ 20.6 $ 444.7 $ 6.3 $ - $ 5.1 $ 1,034.5 The following table shows our consolidated revenues by product and service for the periods presented: 2015 2014 2013 Sales of commodities Natural gas $ 1,594.5 $ 1,414.1 $ 1,225.0 NGL 3,558.7 5,960.1 4,224.0 Condensate 142.4 134.3 121.8 Petroleum products 101.6 96.3 136.0 Derivative activities 68.2 (9.6 ) 21.4 5,465.4 7,595.2 5,728.2 Fees from midstream services Fractionating and treating 209.0 208.9 133.9 Storage, terminaling, transportation and export 506.2 548.1 280.3 Gathering and processing 393.7 196.9 114.1 Other 84.3 67.4 58.4 1,193.2 1,021.3 586.7 Total revenues $ 6,658.6 $ 8,616.5 $ 6,314.9 The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: 2015 2014 2013 Reconciliation of operating margin to net income (loss): Operating margin $ 1,281.0 $ 1,136.6 $ 801.5 Depreciation and amortization expense (677.1 ) (346.5 ) (271.6 ) General and administrative expense (153.6 ) (139.8 ) (143.1 ) Provisional goodwill impairment (290.0 ) - - Interest expense, net (207.8 ) (143.8 ) (131.0 ) Other, net (11.2 ) 3.4 5.7 Income tax expense (0.6 ) (4.8 ) (2.9 ) Net income (loss) $ (59.3 ) $ 505.1 $ 258.6 |
Selected Quarterly Financial Da
Selected Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Selected Quarterly Financial Data (Unaudited) [Abstract] | |
Selected Quarterly Financial Data (Unaudited) | Note 24 — Selected Quarterly Financial Data (Unaudited) Our results of operations by quarter for the years ended December 31, 2015 and 2014 were as follows: First Quarter Second Quarter Third Quarter Fourth Quarter Total (In millions, except per unit amounts) 2015 Revenues $ 1,679.7 $ 1,699.4 $ 1,632.1 $ 1,647.4 $ 6,658.6 Gross margin 411.4 462.3 459.7 452.2 1,785.6 Operating income (loss) 141.0 114.8 117.3 (205.7 ) (1)(2) 167.4 Net income (loss) 77.8 53.3 53.3 (243.7 ) (59.3 ) Net income attributable to limited partners (loss) 30.3 1.2 3.6 (232.6 ) (197.5 ) Net income (loss) per limited partner unit - basic $ 0.21 $ 0.01 $ 0.02 $ (1.26 ) $ (1.15 ) - diluted $ 0.21 $ 0.01 $ 0.02 $ (1.26 ) $ (1.15 ) 2014 Revenues $ 2,294.7 $ 2,000.6 $ 2,288.3 $ 2,032.9 $ 8,616.5 Gross margin 379.6 384.0 407.8 398.2 1,569.6 Operating income 160.6 152.9 171.4 168.4 (1) 653.3 Net income 131.3 120.9 138.2 114.7 505.1 Net income attributable to limited partners 88.6 73.0 89.7 67.7 319.0 Net income per limited partner unit - basic $ 0.79 $ 0.64 $ 0.78 $ 0.58 $ 2.78 - diluted $ 0.78 $ 0.64 $ 0.78 $ 0.58 $ 2.77 (1) Included $32.6 million in the fourth quarter of 2015 and $3.2 million in the fourth quarter of 2014 losses due to the impairments. See Note 6 – Property, Plant and Equipment and Intangible Assets. (2) Included a provisional goodwill impairment of $290.0 million in the fourth quarter of 2015. See Note 4 –Business Acquisitions. |
Significant Accounting Polici32
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Significant Accounting Policies [Abstract] | |
Consolidation Policy | Consolidation Policy Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests. We follow the equity method of accounting when we can not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. Checks outstanding at the end of a period are reclassified to accounts payable, as we extinguish liabilities when the creditor receives our payment and we are relieved of our obligation (which for a check generally occurs when our bank honors that check). |
Comprehensive Income (Loss) | Comprehensive Income (Loss) Comprehensive income (loss) includes net income (loss) and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that are designated as hedges. |
Allowance for Doubtful Accounts | Allowance for Doubtful Accounts Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required. |
Inventories | Inventories Our inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of cost or net realizable value using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are classified as Property, Plant and Equipment. Inventories also include materials and supplies required for our Badlands expansion activities in North Dakota, which are valued using the specific identification method. |
Product Exchanges | Product Exchanges Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. The exchange differential is recorded as either accounts receivable or accrued liabilities. |
Gas Processing Imbalances | Gas Processing Imbalances Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs. |
Derivative Instruments | Derivative Instruments We employ derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which under GAAP, are not accounted for as derivatives. As a result, the revenues and expenses associated with such contracts are recognized during the period when volumes are physically delivered or received. If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense. If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss resulting from the change in fair value on the derivative is recognized currently in earnings as a component of revenues. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the gain or loss related to the change in fair value to earnings in the current period. We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately. For balance sheet classification purposes, we analyze the fair values of the derivative contracts on a deal by deal basis and report the related fair value on a gross basis. |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment are stated at acquisition value less accumulated depreciation. All of our property, plant and equipment purchased from Targa from 2007 to 2010 in drop-down transactions were stated at historical cost in the transactions recorded under common control accounting. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize increased depreciation expense equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of additional depreciation expense due to impairment. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations. |
Goodwill | Goodwill Goodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Goodwill must be assigned to reporting units for the purpose of impairment testing. A reporting unit is an operating segment or one level below an operating segment (also known as a component). Goodwill resulting from the Atlas merger has been attributed to our WestTX, SouthOK and SouthTX reporting units. Our annual goodwill impairment testing is performed as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not the fair value of these reporting units is less than their carrying amounts. This typically entails performing a two-step goodwill impairment test. However, we are permitted to first assess qualitative factors to determine the two-step goodwill impairment test is necessary. If we choose to bypass this qualitative assessment or otherwise determine if that a two-step process goodwill impairment test is required, the first step involves comparing the fair value of the reporting unit to which goodwill has been attributed with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step is required and involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. The implied fair value of goodwill is determined by assigning the reporting unit’s fair value to its individual assets and liabilities. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as a reduction of goodwill on our Consolidated Balance Sheets and a goodwill impairment loss on our Consolidated Statements of Operations. |
Intangible Assets | Intangible Assets Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with businesses acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Amortization expense attributable to these assets is recorded in a manner that closely resembles the expected pattern in which we benefit from services provided to customers. |
Asset Retirement Obligations ("AROs") | Asset Retirement Obligations AROs AROs are legal obligations associated with the retirement of tangible long-lived assets that result from an asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The consolidated cost of the asset and the capitalized asset retirement obligation is depreciated using the straight-line method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing. Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows shall be recognized as an increase or a decrease in the carrying amount of the liability for an asset retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. Upon settlement, AROs will be extinguished by us at either the recorded amount or we will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost. |
Debt Issue Costs | Debt Issuance Costs Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issuance costs. |
Accounts Receivable Securitization Facility | Accounts Receivable Securitization Facility Proceeds from the sale or contribution of certain receivables under our Accounts Receivable Securitization Facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Such borrowings are reflected as long-term debt on our balance sheets to the extent that we have the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities on our Consolidated Statements of Cash Flows. |
Environmental Liabilities and Other Loss Contingencies | Environmental Liabilities and Other Loss Contingencies Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. |
Income Taxes | Income Taxes We generally are not subject to federal income taxes. For federal income tax purposes, our earnings or losses are included in the tax returns of our separate partners. The taxable income or loss passed through to our partners may vary substantially from the net income or net loss we report in the Consolidated Statement of Income. As part of the APL Merger, we acquired TPL Arkoma, Inc. a corporate subsidiary subject to federal and state income tax. The Partnership’s corporate subsidiary accounts for income taxes under the asset and liability method and provides deferred income taxes for all significant temporary differences. As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes for our taxable corporate subsidiary. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheets. We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we establish a valuation allowance. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies. The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are generally not subject to federal and state income taxes at the Partnership level. We are also subject to the Texas margin tax, consisting generally of a 0.75% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas. See Note 18 for discussion of the Partnership’s federal and state income tax expense (benefits) of its taxable subsidiary as well as the Partnership’s net deferred income tax assets (liabilities). |
Noncontrolling Interests | Noncontrolling Interests Third-party ownership in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of our Consolidated Balance Sheets. In the Consolidated Statements of Operations and consolidated statements of comprehensive income, noncontrolling interests reflects the attribution of results to third-party investors. |
Mandatorily Redeemable Preferred Interests | Mandatorily Redeemable Preferred Interests Mandatorily redeemable preferred interests are included in other long term liabilities (or assets) on our Consolidated Balance Sheets. Mandatorily redeemable preferred interests with multiple or indeterminate redemption dates are reported at their estimated redemption value as of the reporting date. This point-in-time value does not represent the amount that ultimately would occur in the future when the interests are redeemed. Changes in the redemption value are recorded in interest expense, net on our Consolidated Statements of Operations. |
Revenue Recognition | Revenue Recognition Our operating revenues are primarily derived from the following activities: · sales of natural gas, NGLs, condensate, crude oil and petroleum products; · services related to compressing, gathering, treating, and processing of natural gas; and · services related to NGL fractionation, terminaling and storage, transportation and treating. We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured. For natural gas processing activities, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we retain the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on a percent-of-liquids basis or a fee basis, depending on market conditions. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above. We generally report sales revenues gross in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another are reported as a single transaction on a combined net basis. |
Unit-Based Compensation | Unit-Based Compensation We award unit-based compensation to employees of Targa and to directors and non-management directors of our General Partner in the form of restricted common units and performance units. Compensation expense on restricted common units and performance unit awards that qualify as equity arrangements are measured by the fair value of the award as determined at the date of grant. Compensation expense on performance unit awards that qualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured subsequently at each reporting date through the settlement period. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. |
Earnings per Unit | Earnings per Unit We account for earnings per unit (“EPU”) in accordance with Accounting Standards Codification (“ASC”) Topic 260 – Earnings per Share. Diluted EPU reflects the potential dilution that could occur if securities or other contracts to issue common units were exercised or converted into common units or resulted in the issuance of common units so long as it does not have an anti-dilutive effect on EPU. The dilutive effect is determined through the application of the treasury method. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic EPU. The common limited partners’ net income (loss) per unit is based on net income (loss) after net income attributable to Preferred Units, allocation to the general partner’s 2% interest and incentive distribution rights. Because our Partnership Agreement limits the quarterly distribution payable to holders of incentive distribution rights to a percentage of Available Cash, the incentive distribution rights do not receive an allocation of earnings in excess of the incentive distributions for the period. |
Use of Estimates | Use of Estimates When preparing financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets,(5) determining amounts to accrue for contingencies, guarantees and indemnifications and (6) estimating redemption value of mandatorily redeemable preferred interests. Actual results, therefore, could differ materially from estimated amounts. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), The revenue recognition standard is effective for the annual period beginning December 15, 2017, and for annual and interim periods thereafter. Earlier adoption is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We must retroactively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restating each prior period presented or (2) presenting a cumulative effect adjustment in the period the amendment is adopted. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact on our revenue recognition practices. In November 2014, the FASB issued ASU 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity (a consensus of the FASB Emerging Issues Task Force). In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 303): Simplifying the Measurement of Inventory. Topic 303 In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments. In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) . The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. |
Basis of Presentation (Tables)
Basis of Presentation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Basis of Presentation [Abstract] | |
Revision of Previously Reported Preliminary Fair Values for Purchase Accounting | The following table presents for each period the impact of these errors balances well as effect of ordinary measurement period . Three Month Period As Reported Impact of Errors Other Measurement Period Adjustments (1) As If Adjusted March 31, 2015 Property, plant and equipment, net $ 9,832.9 $ (77.0 ) $ (248.8 ) $ 9,507.1 Intangible assets, net 1,602.4 114.5 204.1 1,921.0 Goodwill 628.5 48.5 30.0 707.0 Noncontrolling interests 480.7 86.2 (173.2 ) 393.7 Depreciation and amortization expenses 119.6 0.2 (0.2 ) 119.6 June 30, 2015 Property, plant, and equipment, net $ 9,684.3 $ (76.0 ) $ 1.0 $ 9,609.3 Intangible assets, net 1,735.6 113.1 35.4 1,884.1 Goodwill 557.9 48.5 100.6 707.0 Noncontrolling interests 297.4 86.2 17.2 400.8 Depreciation and amortization expenses 163.9 0.5 0.5 164.9 September 30, 2015 Property, plant, and equipment, net $ 9,750.2 $ (75.0 ) $ (8.6 ) $ 9,666.6 Intangible assets, net 1,695.7 111.6 39.8 1,847.1 Goodwill 551.4 48.5 107.1 707.0 Noncontrolling interests 309.6 86.2 17.3 413.1 Depreciation and amortization expenses 165.8 0.5 0.4 166.7 (1) Other Measurement Period Adjustments for Goodwill include the impact of all balance sheet adjustments not presented in this table |
Revision of Previously Reported Revenues and Product Purchases | Accordingly, Revenues and Product Purchases reported in our Form 10-K filed on February 14, 2014 have been reduced by equal amounts as presented in the following table. There is no impact on previously reported net income, cash flows, financial position or other profitability measures. Year Ended December 31, 2013 As Reported: Revenues $ 6,556.2 Product Purchases 5,378.5 Effect of Revisions: Revenues (241.3 ) Product Purchases (241.3 ) As Revised: Revenues 6,314.9 Product Purchases 5,137.2 |
Business Acquisitions (Tables)
Business Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Acquisitions [Abstract] | |
Pro Forma Consolidated Results of Operations | The following summarized unaudited pro forma Consolidated Statement of Operations information for the year ended December 31, 2015 and December 31, 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 these acquisitions as of January 1, 2014, or that the results that will be attained in the future. Pro Forma Results for the Year Ended December 31, 2015 December 31, 2014 Revenues $ 6,947.3 $ 11,449.3 Net income (loss) (62.2 ) 691.2 |
Consideration Transferred to Acquire ATLS and APL | The following table summarizes the consideration transferred to acquire ATLS and APL, which are viewed together as a single integrated transaction for GAAP reporting purposes: Fair Value of Consideration Transferred by Targa for ATLS: Cash paid, net of cash acquired (1) $ 745.7 Common shares of TRC 1,008.5 Replacement restricted stock units awarded (3) 5.2 Less: value of APL common units owned by ATLS (147.4 ) Total $ 1,612.0 Fair Value of Consideration Transferred by Targa for APL: Cash paid, net of cash acquired (2) $ 828.7 Common units of TRP 2,568.5 Replacement phantom units awarded (3) 15.0 Total $ 3,412.2 Total fair value of consideration transferred $ 5,024.2 (1) Targa acquired $5.5 million of cash. (2) We acquired $35.3 million of cash. (3) The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. |
Fair Value Determination Related to the Atlas Mergers | As of February 27, 2015, our fair value determination related to the Atlas mergers was as follows: Fair value determination: February 27, 2015 Trade and other current receivables, net $ 181.1 Other current assets 24.4 Assets from risk management activities 102.1 Property, plant and equipment 4,616.9 Investments in unconsolidated affiliates 214.5 Intangible assets 1,354.9 Other long-term assets 5.5 Current liabilities (258.8 ) Long-term debt (1,573.3 ) Deferred income tax liabilities, net (13.6 ) Other long-term liabilities (119.1 ) Total identifiable net assets 4,534.6 Noncontrolling interest in subsidiaries (216.9 ) Current liabilities retained by Targa (0.5 ) Goodwill 707.0 $ 5,024.2 |
Changes in Gross Amounts of Goodwill and Impairment Loss | Changes in the gross amounts of our goodwill and impairment loss for the year ended December 31, 2015 are as follows: December 31, 2015 WestTX SouthTX SouthOK Total Beginning of period $ - $ - $ - $ - Acquisition 364.5 160.3 182.2 707.0 Impairment (37.6 ) (70.2 ) (182.2 ) (290.0 ) Goodwill $ 326.9 $ 90.1 $ - $ 417.0 |
Inventories (Tables)
Inventories (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Inventories [Abstract] | |
Components of Inventories | December 31, 2015 December 31, 2014 Commodities $ 128.3 $ 157.4 Materials and supplies 12.7 11.5 $ 141.0 $ 168.9 |
Property, Plant and Equipment36
Property, Plant and Equipment and Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment and Intangible Assets [Abstract] | |
Property, Plant and Equipment and Intangible Assets | Property, Plant and Equipment December 31, 2015 December 31, 2014 Estimated useful life Gathering systems $ 6,304.5 $ 2,588.6 5 to 20 Processing and fractionation facilities 2,988.5 1,884.1 5 to 25 Terminaling and storage facilities 1,115.0 1,038.9 5 to 25 Transportation assets 454.0 359.0 10 to 25 Other property, plant and equipment 220.9 149.1 3 to 25 Land 108.8 95.6 - Construction in progress 736.5 399.0 - Property, plant and equipment 11,928.2 6,514.3 Accumulated depreciation (2,225.6 ) (1,689.7 ) Property, plant and equipment, net $ 9,702.6 $ 4,824.6 Intangible assets $ 2,036.6 $ 681.8 20 Accumulated amortization (226.5 ) (89.9 ) Intangible assets, net $ 1,810.1 $ 591.9 |
Schedule of Intangible Assets | The fair values of intangible assets acquired in the Atlas mergers have been recorded at a fair value of $1,354.9 million and are being amortized over the 20 year life using a straight-line method. Amortization expense attributable to our intangible assets related to the Badlands acquisition is recorded using a method that closely reflects the cash flow pattern underlying their intangible asset valuation. December 31, 2015 2014 Beginning of period $ 591.9 $ 653.4 Additions from acquisition 1,354.9 - Amortization (136.7 ) (61.5 ) Intangible assets, net $ 1,810.1 $ 591.9 |
Investment in Unconsolidated 37
Investment in Unconsolidated Affiliate (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Investment in Unconsolidated Affiliate [Abstract] | |
Activity Related to Partnership's Investment in Unconsolidated Affiliate | The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 Cogen Total December 31, 2012 $ 53.1 $ - $ - $ - $ 53.1 Equity earnings 14.8 - - - 14.8 Cash distributions (1) (12.0 ) - - - (12.0 ) December 31, 2013 55.9 - - - 55.9 Equity earnings 18.0 - - - 18.0 Cash distributions (1) (23.7 ) - - - (23.7 ) December 31, 2014 50.2 - - - 50.2 Fair value of T2 Joint Ventures acquired - 67.5 126.7 20.3 214.5 Equity earnings (loss) 13.8 (3.9 ) (9.4 ) (3.0 ) (2.5 ) Cash distributions (1) (14.5 ) - - (0.5 ) (15.0 ) Cash calls for expansion projects - - 6.5 5.2 11.7 December 31, 2015 $ 49.5 $ 63.6 $ 123.8 $ 22.0 $ 258.9 (1) Includes $1.2 million in distributions from GCF and T2 Joint Ventures in excess of our share of cumulative earnings for the year ended December 31, 2015. Includes $5.7 million in distributions from GCF in excess of our share of cumulative earnings for the year ended December 31, 2014. 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 38
Accounts Payable and Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounts Payable and Accrued Liabilities [Abstract] | |
Schedule of Accounts Payable and Accrued Liabilities | December 31, 2015 December 31, 2014 Commodities $ 385.3 $ 416.7 Other goods and services 141.3 108.9 Interest 80.3 37.3 Compensation and benefits 0.4 1.3 Income and other taxes 10.4 13.6 Other 18.1 14.9 $ 635.8 $ 592.7 |
Debt Obligations (Tables)
Debt Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Obligations [Abstract] | |
Schedule of Outstanding Debt | December 31, 2015 December 31, 2014 Current: Accounts receivable securitization facility, due December 2016 $ 219.3 $ 182.8 Long-term: Senior secured revolving credit facility, variable rate, due October 2017 (1) 280.0 - Senior unsecured notes, 5% fixed rate, due January 2018 1,100.0 - Senior unsecured notes, 4⅛% fixed rate, due November 2019 800.0 800.0 Senior unsecured notes, 6⅝% fixed rate, due October 2020 (2) 342.1 - Unamortized premium 5.0 - Senior unsecured notes, 6⅞% fixed rate, due February 2021 483.6 483.6 Unamortized discount (22.1 ) (25.2 ) Senior unsecured notes, 6⅜% fixed rate, due August 2022 300.0 300.0 Senior unsecured notes, 5¼% fixed rate, due May 2023 583.7 600.0 Senior unsecured notes, 4¼% fixed rate, due November 2023 623.5 625.0 Senior unsecured notes, 6¾% fixed rate, due March 2024 600.0 - Senior unsecured APL notes, 6⅝% fixed rate, due October 2020 (2)(3) 12.9 - Unamortized premium 0.2 - Senior unsecured APL notes, 4¾% fixed rate, due November 2021 (3) 6.5 - Senior unsecured APL notes, 5⅞% fixed rate, due August 2023 (3) 48.1 - Unamortized premium 0.5 - Total long-term debt 5,164.0 2,783.4 Total debt $ 5,383.3 $ 2,966.2 Irrevocable standby letters of credit outstanding $ 12.9 $ 44.1 (1) As of December 31, 2015, availability under our $1.6 billion senior secured revolving credit facility was $1,307.1 million. (2) In May 2015, we exchanged the TRP 6⅝% Senior Notes with the same economic terms to the holders of the 6⅝% APL Notes that validly tendered such notes for exchange to us. (3) While we consolidate the debt acquired in the Atlas mergers, APL debt is not guaranteed by us. |
Schedule of Contractually Scheduled Maturities of Debt Obligations Outstanding | The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2015, for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2016 2017 2018 2019 2020 After 2020 Senior secured revolving credit facility $ 280.0 $ - $ 280.0 $ - $ $ - $ - Senior unsecured notes 4,900.4 - - 1,100.0 800.0 355.0 2,645.4 Accounts receivable securitization facility 219.3 219.3 - - - - - Total $ 5,399.7 $ 219.3 $ 280.0 $ 1,100.0 $ 800.0 $ 355.0 $ 2,645.4 |
Interest Rates Incurred on Variable-Rate Debt Obligations | The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2015: Range of Interest Rates Incurred Weighted Average Interest Rate Incurred Senior secured revolving credit facility 1.9% - 4.8% 2.2% Accounts receivable securitization facility 0.9% - 1.2% 0.9% |
Schedule of Debt Re-acquisitions and 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 The following table summarizes the debt repurchases that are included in our Consolidated Statements of Operations: 2015 2014 2013 Premium over face value paid upon redemption: 6⅜ Notes $ - $ - $ 6.4 7⅞ Notes - 9.9 - 11¼ Notes - - 4.1 Recognition of unamortized discount: 11¼ Notes - - 2.2 Gain on repurchase of debt: 5¼ Notes (3.3 ) - - 4¼ Notes (0.3 ) - - Loss from financing with Exchange Offer: 6⅝ Notes 0.7 - - Write-off of deferred debt issuance costs: 5¼ Notes 0.1 - - 6⅜ Notes - - 1.0 7⅞ Notes - 2.5 - 11¼ Notes - - 1.0 (Gain) loss from financing activities $ (2.8 ) $ 12.4 $ 14.7 |
Schedule of Terms of Senior Unsecured Notes Outstanding | Selected terms of the senior unsecured notes outstanding as of December 31, 2015 were as follows: Note Issue Issue Date Per Annum Interest Rate Due Date Dates Interest Paid "6⅞% Notes" February 2011 6⅞% February 1, 2021 February & August 1 st "6⅜% Notes" January 2012 6⅜% August 1, 2022 February & August 1 st "5¼% Notes" Oct / Dec 2012 5¼% May 1, 2023 May & November 1 st "4¼% Notes" May 2013 4¼% November 15, 2023 May & November 15 th "4⅛% Notes" October 2014 4⅛% November 15, 2019 May & November 15 th "5% Notes" January 2015 5% January 15, 2018 January & July 15 th "6⅝% Notes" May 2015 6⅝% October 1, 2020 February & October 1 st "6¾% Notes" September 2015 6¾% March 15, 2024 March & September 15 th "APL 6⅝% Notes" Sept 2012 (1) 6⅝% October 1, 2020 April & October 1 st "APL 4¾% Notes" May 2013 (1) 4¾% November 15, 2021 May & November 15 th "APL 5⅞% Notes" February 2013 (1) 5⅞% August 1, 2023 February & August 1 st (1) Issue dates for APL Notes are original dates of issuance. These notes were acquired in the APL Merger. See Note 4 – Business Acquisitions. |
Schedule of Redemption Prices for Issued Debt | We may redeem up to 35% of the aggregate principal amount of Notes (other than with respect to the 5% Notes) at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 180 days for the 6¾% Notes, 6⅜% Notes, 5¼% Notes, 4¼ % Notes and 4⅛% Notes of the date of the closing of such equity offering. Note Issue Any Date Prior To Price 4¼% Notes May 15, 2016 104.250 % 6¾% Notes September 15, 2018 106.750 % 4⅛% Notes November 15, 2017 104.125 % We may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed. 6⅞% Notes 6⅜% Notes 5¼% Notes 4¼% Notes Redemption Date: February 1 Redemption Date: February 1 Redemption Date: November 1 Redemption Date: May 15 Year Price Year Price Year Price Year Price 2016 103.438 % 2017 103.188 % 2017 102.625 % 2018 102.125 % 2017 102.292 % 2018 102.125 % 2018 101.750 % 2019 101.417 % 2018 101.146 % 2019 101.063 % 2019 100.875 % 2020 100.708 % 2019 and thereafter 100 % 2020 and thereafter 100 % 2020 and thereafter 100 % 2021 and thereafter 100 % 6⅝% Notes 6¾% Notes 4⅛% Notes APL 6⅝% Notes Redemption Date: October 1 Redemption Date: September 15 Redemption Date: November 15 Redemption Date: October 1 Year Price Year Price Year Price Year Price 2016 103.313 % 2019 103.375 % 2016 102.063 % 2016 103.313 % 2017 101.656 % 2020 101.688 % 2017 101.031 % 2017 101.656 % 2018 and thereafter 100.000 % 2021 and thereafter 100.000 % 2018 and thereafter 100 % 2018 and thereafter 100 % APL 4¾% Notes APL 5⅞% Notes Redemption Date: May 15 Redemption Date: February 1 Year Price Year Price 2016 103.563 % 2018 102.938 % 2017 102.375 % 2019 101.958 % 2018 101.188 % 2020 100.979 % 2019 and thereafter 100 % 2021 and thereafter 100 % |
Other Long-term Liabilities (Ta
Other Long-term Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Other Long-term Liabilities [Abstract] | |
Other Long-term Liabilities | Other long-term liabilities are comprised of the following obligations. December 31, 2015 2014 Asset retirement obligations $ 69.9 $ 56.8 Mandatorily redeemable preferred interests 82.9 - Deferred revenue and other 25.4 1.0 Total long-term liabilities $ 178.2 $ 57.8 |
Changes in Aggregate Asset Retirement Obligations | The changes in our ARO are as follows: 2015 2014 2013 Beginning of period $ 56.8 $ 50.5 $ 45.2 Fair value of ARO acquired with the APL merger 4.0 - - Change in cash flow estimate 3.8 2.1 1.4 Accretion expense 5.3 4.4 3.9 Retirement of ARO - (0.2 ) - End of period $ 69.9 $ 56.8 $ 50.5 |
Schedule of Changes in Long-term Liability Attributable to Mandatorily Redeemable Preferred Interests | The following table shows the changes in long-term liabilities attributable to mandatorily redeemable preferred interests: Liability attributable to mandatorily redeemable preferred interests Balance at December 31, 2014 $ - Acquired mandatorily redeemable preferred interests 109.3 Change in estimated redemption value (30.6 ) Income attributable to mandatorily redeemable preferred interests 2.8 Other activity, net 1.4 Balance at December 31, 2015 $ 82.9 |
Partnership Units and Related41
Partnership Units and Related Matters (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Partnership Units and Related Matters [Abstract] | |
Schedule of Distributions | The following table details the distributions declared and/or paid by us during the periods presented. As a result of the TRC/TRP Merger, which was completed on February 17, 2016, Targa owns all of our outstanding common units. Distributions Three Months Ended Date Paid Limited Partners General Partner Distributions per Limited Partner Unit Common Incentive Distribution Rights 2 % Total (In millions, except per unit amounts) December 31, 2015 February 9, 2016 $ 152.5 $ 43.9 (1 ) $ 4.0 $ 200.4 $ 0.8250 September 30, 2015 November 13, 2015 152.5 43.9 (1 ) 4.0 200.4 0.8250 June 30, 2015 August 14, 2015 152.5 43.9 (1 ) 4.0 200.4 0.8250 March 31, 2015 May 15, 2015 148.3 41.7 (1 ) 3.9 193.9 0.8200 2014 December 31, 2014 February 13, 2015 96.3 38.4 2.7 137.4 0.8100 September 30, 2014 November 14, 2014 92.3 36.0 2.6 130.9 0.7975 June 30, 2014 August 14, 2014 89.5 33.7 2.5 125.7 0.7800 March 31, 2014 May 15, 2014 87.2 31.7 2.4 121.3 0.7625 2013 December 31, 2013 February 14, 2014 84.0 29.5 2.3 115.8 0.7475 September 30, 2013 November 14, 2013 79.4 26.9 2.2 108.5 0.7325 June 30, 2013 August 14, 2013 75.8 24.6 2.0 102.4 0.7150 March 31, 2013 May 15, 2013 71.7 22.1 1.9 95.7 0.6975 (1) Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDRs of $9.375 million were allocated to common unitholders in each of the quarters for 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and resulted in reallocation of IDR payments to common unitholders in the following amounts: $9.375 million per quarter for 2015. The IDR Giveback will result in reallocation of IDR payments to common unitholders of $6.25 million in the first quarter of 2016. |
Earnings per Limited Partner 42
Earnings per Limited Partner Unit (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings per Limited Partner Unit [Abstract] | |
Computation of Basic and Diluted Net Income (Loss) Per Limited Partner | The following table sets forth a reconciliation of net income (loss) and weighted average shares outstanding used in computing basic and diluted net income (loss) per limited partner unit: 2015 2014 2013 Net income (loss) $ (59.3 ) $ 505.1 $ 258.6 Less: Net income attributable to noncontrolling interests (31.9 ) 37.4 25.1 Net income (loss) attributable to Targa Resources Partners LP $ (27.4 ) $ 467.7 $ 233.5 Net income attributable to preferred limited partners $ 2.4 $ - $ - Net income attributable to general partner 167.7 148.7 107.5 Net income (loss) attributable to limited partners (197.5 ) 319.0 126.0 Net income (loss) attributable to Targa Resources Partners LP $ (27.4 ) $ 467.7 $ 233.5 Weighted average units outstanding - basic 172.3 114.7 105.5 Net income (loss) available per limited partner unit - basic $ (1.15 ) $ 2.78 $ 1.19 Weighted average units outstanding 172.3 114.7 105.5 Dilutive effect of unvested stock awards - 0.4 0.2 Weighted average units outstanding - diluted (1) 172.3 115.1 105.7 Net income (loss) available per limited partner unit - diluted $ (1.15 ) $ 2.77 $ 1.19 (1) For the year ended December 31, 2015 and 2014, approximately 697,989 and 168,495 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. |
Derivative Instruments and He43
Derivative Instruments and Hedging Activities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities [Abstract] | |
Notional Volume of Commodity Hedges | At December 31, 2015, the notional volumes of our commodity derivative contracts were: Commodity Instrument Unit 2016 2017 2018 Natural Gas Swaps MMBtu/d 83,264 23,082 - Natural Gas Basis Swaps MMBtu/d 48,962 18,082 - Natural Gas Collars MMBtu/d 22,900 22,900 9,486 NGL Swaps Bbl/d 4,473 1,078 208 NGL Futures Bbl/d 1,956 - - NGL Options/Collars Bbl/d 920 920 32 Condensate Swaps Bbl/d 1,502 500 - Condensate Options/Collars Bbl/d 790 790 101 |
Fair Values of Derivative Instruments | The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of December 31, 2015 Fair Value as of December 31, 2014 Balance Sheet Location Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivatives designated as hedging instruments Commodity contracts Current $ 92.1 $ 2.1 $ 44.4 $ - Long-term 34.9 2.4 15.8 - Total derivatives designated as hedging instruments $ 127.0 $ 4.5 $ 60.2 $ - Derivatives not designated as hedging instruments Commodity contracts Current $ 0.1 $ 3.1 $ - $ 5.2 Total derivatives not designated as hedging instruments $ 0.1 $ 3.1 $ - $ 5.2 Total current position $ 92.2 $ 5.2 $ 44.4 $ 5.2 Total long-term position 34.9 2.4 15.8 - Total derivatives $ 127.1 $ 7.6 $ 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 December 31, 2015 Asset Position Liability Position Asset Position Liability Position Current position Counterparties with offsetting position $ 86.9 $ 5.2 $ 81.7 $ - Counterparties without offsetting position - assets 5.3 - 5.3 - Counterparties without offsetting position - liabilities - - - - 92.2 5.2 87.0 - Long-term position Counterparties with offsetting position 34.2 2.4 31.8 - Counterparties without offsetting position - assets 0.7 - 0.7 - Counterparties without offsetting position - liabilities - - - - 34.9 2.4 32.5 - Total derivatives Counterparties with offsetting position 121.1 7.6 113.5 - Counterparties without offsetting position - assets 6.0 - 6.0 - Counterparties without offsetting position - liabilities - - - - $ 127.1 $ 7.6 $ 119.5 $ - 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 2015 2014 2013 Commodity contracts $ 81.3 $ 59.8 $ (5.8 ) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2015 2014 2013 Interest expense, net $ - $ (2.4 ) $ (6.1 ) Revenues 54.8 (4.2 ) 21.2 $ 54.8 $ (6.6 ) $ 15.1 |
Gain (Loss) Recognized in Income on Derivatives | The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. Gain (Loss) Recognized in Income on Derivatives Derivatives Not Designated as Hedging Instruments Location of Gain Recognized in Income on Derivatives 2015 2014 2013 Commodity contracts Revenue $ (5.7 ) $ (5.5 ) $ (0.1 ) |
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 as of the balance sheet date: December 31, 2015 December 31, 2014 Commodity hedges (1) $ 86.7 $ 60.3 (1) Includes deferred net gains of $52.1 million as of December 31, 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) | 12 Months Ended |
Dec. 31, 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: December 31, 2015 Carrying Value Fair Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $ 127.1 $ 127.1 $ - $ 123.1 4.0 Liabilities from commodity derivative contracts (1) 7.6 7.6 0.3 7.0 0.3 TPL contingent consideration (2) 3.0 3.0 - - 3.0 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 135.4 135.4 - - - Senior secured revolving credit facility 280.0 280.0 - 280.0 - Senior unsecured notes 4,884.0 4,192.0 - 4,192.0 - Accounts receivable securitization facility 219.3 219.3 - 219.3 - December 31, 2014 Carrying Value Fair Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts $ 60.2 $ 60.2 $ - $ 58.4 $ 1.8 Liabilities from commodity derivative contracts 5.2 5.2 - 5.1 0.1 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 72.3 72.3 - - - Senior secured revolving credit facility - - - - - Senior unsecured notes 2,783.4 2,731.5 - 2,731.5 - Accounts receivable securitization facility 182.8 182.8 182.8 - - (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 Changes in Fair Value of Financial Instruments Classified as Level 3 | The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts (Asset)/Liability Contingent Liability Balance, December 31, 2012 $ 0.6 $ 15.3 Settlements included in Revenue (1.3 ) - Change in valuation of contingent liability included in Other Income - (15.3 ) Balance, December 31, 2013 (0.7 ) - Settlements included in Revenue (0.2 ) - Unrealized losses included in OCI (1.1 ) - Transfers out of Level 3 0.3 - Balance, December 31, 2014 (1.7 ) - TPL contingent consideration fair value at acquisition date (see Note 4-Business Acquisitions) - 4.2 Change in fair value of TPL contingent consideration included in Other Income - (1.2 ) New Level 3 instruments (3.7 ) - Transfers out of Level 3 1.7 - Balance, December 31, 2015 $ (3.7 ) $ 3.0 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Summary of Transactions with Affiliates | The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable. 2015 2014 2013 Targa billings of payroll and related costs included in operating expense $ 153.8 $ 124.9 $ 109.7 Targa allocation of general and administrative expense 136.2 129.4 134.3 Cash distributions to Targa based on IDR and unit ownership 233.4 180.7 138.2 Cash contributions from Targa to maintain its 2% general partner ownership 60.1 7.7 10.8 |
Commitments (Leases) (Tables)
Commitments (Leases) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments (Leases) [Abstract] | |
Future Lease Obligations for Next Five Fiscal Years | Future lease obligations are presented below in aggregate and for each of the next five fiscal years. In Aggregate 2016 2017 2018 2019 2020 Operating leases (1) $ 42.1 $ 16.0 $ 10.8 $ 8.8 $ 3.7 $ 2.8 Land site lease and right-of-way (2) 11.0 2.4 2.3 2.2 2.1 2.0 $ 53.1 $ 18.4 $ 13.1 $ 11.0 $ 5.8 $ 4.8 (1) Includes minimum payments on lease obligations for office space, railcars and tractors. (2) Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual. |
Total Expenses on Lease Obligations | Total expenses incurred under the above lease obligations were: 2015 2014 2013 Operating leases (1) $ 40.4 $ 24.4 $ 23.3 Land site lease and right-of-way 4.2 4.1 3.6 (1) Includes short-term leases for items such as compressors and equipment. |
Income Tax (Tables)
Income Tax (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax [Abstract] | |
Provision for Income Taxes | 2015 2014 2013 Provision for Income Taxes: Current expense $ 0.8 $ 3.2 $ 2.0 Deferred expense (benefit) (0.2 ) 1.6 0.9 Total income tax expense (benefit) $ 0.6 $ 4.8 $ 2.9 |
Deferred Tax Assets and Liabilities | Our deferred income tax assets and liabilities at December 31, 2015 consist of differences related to the timing of recognition of certain types of costs as follows: Year Ended December 31, 2015 2014 Deferred tax assets: Net operating loss carryforwards $ 19.8 $ - Deferred tax liabilities: Property, plant, and equipment (47.0 ) (13.7 ) Net deferred tax asset/(liability) $ (27.2 ) $ (13.7 ) |
Significant Risks and Uncerta48
Significant Risks and Uncertainties (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Significant Risks and Uncertainties [Abstract] | |
Activity Affecting Allowance for Bad Debts | The following table summarizes the activity affecting our allowance for bad debts: 2015 2014 2013 Balance at beginning of year $ - $ 0.9 $ 0.7 Additions 0.1 - 0.2 Deductions (0.9 ) - Balance at end of year $ 0.1 $ - $ 0.9 |
Other Operating (Income) Expe49
Other Operating (Income) Expense (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Other Operating (Income) Expense [Abstract] | |
Other Operating (Income) Expense | 2015 2014 2013 Loss (gain) on sale or disposal of assets $ (8.0 ) $ (4.8 ) $ 3.9 Casualty (gain) loss (0.2 ) 0.1 4.3 Miscellaneous business tax 0.5 0.4 0.7 Other 0.6 1.3 0.7 $ (7.1 ) $ (3.0 ) $ 9.6 |
Supplemental Cash Flow Inform50
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Cash Flow Information | 2015 2014 2013 Cash: Interest paid, net of capitalized interest (1) $ 193.1 $ 131.0 $ 119.1 Income taxes paid, net of refunds 3.4 2.7 2.3 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment 1.2 14.8 30.4 Impact of capital expenditure accruals on property, plant and equipment 43.8 19.0 (0.4 ) Transfers from materials and supplies inventory to property, plant and equipment 3.7 4.6 20.5 Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate 3.8 2.1 1.4 Property, plant and equipment in consideration of contract amendment (2) 22.6 - - Non-cash financing activities: Debt additions and retirements related to exchange of TRP 6⅝% Notes for APL 6⅝% Notes 342.1 - - Reductions in Owner's Equity related to accrued distributions on unvested equity awards under share compensation arrangements 1.6 1.4 1.7 Receivables from equity issuances - 1.0 - Accrued distributions of preferred unit 0.9 - - Non-cash balance sheet movements related to business acquisition: (See Note 4) 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 $13.2 million, $16.1 million and $28.0 million for 2015, 2014 and 2013. (2) We measured the estimated fair value of the assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. |
Compensation Plans (Tables)
Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Activity of the Common Unit-Based Awards Granted to the Partnership's Directors | The following table summarizes the activities of the common unit-based awards granted to our Directors for the years ended December 31, 2015, 2014 and 2013 (in units and dollars): Number of units Weighted Average Grant-Date Fair Value Outstanding at December 31, 2012 4,500 $ 23.51 Granted 12,780 39.33 Vested (17,280 ) 35.21 Outstanding at December 31, 2013 - - Granted 8,740 50.29 Vested (8,740 ) 50.29 Outstanding at December 31, 2014 - - Granted 10,565 44.67 Vested (10,565 ) 44.67 Outstanding at December 31, 2015 - - |
Summary of Compensation Expenses under Various Compensation Plans | The following table summarizes the compensation expenses under the various compensation plans recognized for the years indicated: 2015 2014 2013 TRP LTIP - Equity-Settled Performance Units $ 9.5 $ 8.8 $ 5.5 TRP LTIP - Equity-Settled Phantom units - Replacement Phantom Units 6.4 - - TRP LTIP - Equity-Settled Phantom units - Phantom Units 0.2 - - Director Grants 0.5 0.4 0.5 Allocated from Targa: TRC LTIP - Cash-Settled Performance Units (2.2 ) 11.0 21.9 2010 TRC Stock Incentive Plan - Restricted Stock 1.1 2.2 6.3 2010 TRC Stock Incentive Plan - Equity-Settled Restricted Stock Units: RSUs 5.4 2.5 0.4 2010 TRC Stock Incentive Plan - Equity-Settled Restricted Stock Units: Replacement RSUs 1.3 - - |
Summary of Unrecognized Compensation Expenses and Approximate Remaining Weighted Average Vesting Periods | The table below summarizes the unrecognized compensation expenses and the approximate remaining weighted average vesting periods related to our various share-based compensation plans as of December 31, 2015: Unrecognized Compensation Expense Weighted Average Remaining Vesting Period (In millions) (In years) TRP LTIP Equity-Settled Performance Units $ 13.3 1.9 TRP LTIP Equity-Settled Phantom units - Replacement Phantom Units 5.8 1.3 TRP LTIP Equity-Settled Phantom units - Phantom Units 0.8 3.3 2010 TRC Stock Incentive Plan - Restricted Stock 0.0 0.1 2010 TRC Stock Incentive Plan - Equity-Settled Restricted Stock Units: RSUs 13.1 2.3 2010 TRC Stock Incentive Plan - Equity-Settled Restricted Stock Units: Replacement RSUs 1.5 1.4 |
Fair Values of Share-Based Awards on the Dates They Vested | The total fair value of share-based awards on the dates they vested are as follows: 2015 2014 2013 TRP LTIP Equity-Settled Performance units $ 7.9 $ 10.0 $ - TRP LTIP Accrued DERs settled for Equity - Settled Performance units 1.7 1.6 - TRP LTIP Replacement Phantom Units 8.8 - - Accrued DERs settled for Phantom units - TRP LTIP Replacement Phantom Units 1.1 - - Director Grants 0.5 0.4 0.7 TRC LTIP Cash-Settled performance units 7.8 14.7 25.2 2010 TRC Stock Incentive Plan - Restricted Stock (1) 7.3 7.1 42.2 Accrued dividends settled 0.2 0.5 2.4 2010 TRC Stock Incentive Plan - Equity-Settled Restricted Stock Units: Replacement RSUs 3.8 - - (1) Targa recognized $1.1 million, $1.0 million and $1.6 million in tax benefits associated with the vesting of the restricted stock for 2015, 2014 and 2013. |
Equity-Settled Performance Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of Performance Units | The following table summarizes activities of our equity-settled performance units for the years ended December 31, 2015, 2014 and 2013. Number of units Weighted Average Grant-Date Fair Value Outstanding at December 31, 2012 307,620 $ 38.40 Granted 244,578 46.54 Outstanding at December 31, 2013 552,198 42.01 Granted 168,495 57.19 Vested (137,170 ) 34.02 Forfeited (6,120 ) 49.39 Outstanding at December 31, 2014 577,403 48.26 Granted 277,242 34.48 Vested (178,900 ) 41.92 Outstanding at December 31, 2015 675,745 44.29 |
Replacement Phantom Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of Performance Units | The following table summarize the activities of the awards for the year ended 2015. Number of units Weighted Average Grant-Date Fair Value Outstanding at December 31, 2014 - $ - Granted 629,231 43.82 Vested (224,021 ) 43.82 Forfeited (49,852 ) 43.82 Outstanding at December 31, 2015 355,358 $ 43.82 |
Cash-Settled Performance Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of Performance Units | The following table summarizes the cash-settled performance units for the year ended 2015 awarded under the TRC LTIP (in units and dollars): Program Year 2012 Awards 2013 Awards 2014 Awards 2015 Awards Total Units outstanding January 1, 2015 138,460 142,110 122,360 - 402,930 Granted - - - 198,280 198,280 Vested and paid (138,460 ) - - - (138,460 ) Forfeited - (2,410 ) (2,460 ) (5,890 ) (10,760 ) Units outstanding December 31, 2015 - 139,700 119,900 192,390 451,990 Calculated fair market value as of December 31, 2015 $ 622,496 $ 359,684 $ 1,662,913 $ 2,645,093 Current liability $ 511,247 $ - $ - $ 511,247 Long-term liability - 172,926 229,460 402,386 Liability as of December 31, 2015 $ 511,247 $ 172,926 $ 229,460 $ 913,633 To be recognized in future periods $ 111,249 $ 186,758 $ 1,433,453 $ 1,731,460 Vesting date June 2016 June 2017 June 2018 |
Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of Restricted Stock Units Awards | The following table summarizes the restricted stock awards in shares and in dollars for the years indicated: Number of shares Weighted-average Grant-Date Fair Value Outstanding at December 31, 2012 711,030 $ 25.95 Granted (1) 30,623 57.59 Forfeited (2,740 ) 27.28 Vested (2) (534,940 ) 22.00 Outstanding at December 31, 2013 203,973 41.05 Forfeited (1,980 ) 42.82 Vested (82,800 ) 33.37 Outstanding at December 31, 2014 119,193 46.35 Vested (88,570 ) 42.46 Outstanding at December 31, 2015 30,623 57.59 (1) These awards will cliff vest at the end of three years. (2) Awards vested in 2013 were 60% of the awards issued in conjunction with the Targa IPO, net of forfeitures. 40% of the awards vested prior to 2013. |
Restricted Stock Units (RSUs) [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of Restricted Stock Units Awards | The following table summarizes the regular RSUs Targa granted to the management of the general partner in shares and in dollars for the years indicated. Number of shares Weighted-average Grant-Date Fair Value Outstanding at December 31, 2012 - $ - Granted 55,790 69.90 Forfeited (240 ) 67.07 Outstanding at December 31, 2013 55,550 69.92 Granted 54,357 112.89 Forfeited (1,440 ) 75.81 Vested (100 ) 67.07 Outstanding at December 31, 2014 108,367 91.41 Granted 140,477 83.54 Forfeited (2,530 ) 86.73 Vested (2,220 ) 81.56 Outstanding at December 31, 2015 244,094 87.02 |
Replacement Restricted Stock Units (RSUs) [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of Restricted Stock Units Awards | The following table summarizes the awards in shares and in dollars for the years indicated. Number of units Weighted Average Grant-Date Fair Value Outstanding at December 31, 2014 - $ - Granted 81,740 99.58 Vested (41,539 ) 99.58 Forfeited (1,556 ) 99.58 Outstanding at December 31, 2015 38,645 $ 99.58 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Information by Segment | Our reportable segment information is shown in the following tables: Year Ended December 31, 2015 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 1,283.0 $ 202.4 $ 104.4 $ 3,791.4 $ 84.2 $ - $ 5,465.4 Fees from midstream services 394.3 32.8 330.2 435.9 - - 1,193.2 1,677.3 235.2 434.6 4,227.3 84.2 - 6,658.6 Intersegment revenues Sales of commodities 894.0 232.3 9.1 290.6 - (1,426.0 ) - Fees from midstream services 8.7 - 264.2 19.5 - (292.4 ) - 902.7 232.3 273.3 310.1 - (1,718.4 ) - Revenues $ 2,580.0 $ 467.5 $ 707.9 $ 4,537.4 $ 84.2 $ (1,718.4 ) $ 6,658.6 Operating margin $ 484.8 $ 30.3 $ 439.5 $ 242.2 $ 84.2 $ - $ 1,281.0 Other financial information: Total assets (1) $ 9,892.3 $ 290.2 $ 1,912.2 $ 605.5 $ 127.1 $ 337.7 $ 13,165.0 Goodwill (2) $ 417.0 $ - $ - $ - $ - $ - $ 417.0 Capital expenditures $ 481.5 $ 14.8 $ 257.6 $ 14.4 $ - $ 8.9 $ 777.2 Business acquisition $ 5,024.2 $ - $ - $ - $ - $ - $ 5,024.2 (1) Corporate assets at the Segment level primarily include investments in unconsolidated subsidiaries and debt issuance cost associated with our debt obligations. (2) Total assets include goodwill. Goodwill has been attributed to our Field Gathering and Processing segment – See Note 4 – Business Acquisitions. Year Ended December 31, 2014 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 197.4 $ 355.0 $ 99.1 $ 6,951.7 $ (8.0 ) $ - $ 7,595.2 Fees from midstream services 190.3 34.4 293.6 503.0 - - 1,021.3 387.7 389.4 392.7 7,454.7 (8.0 ) - 8,616.5 Intersegment revenues Sales of commodities 1,491.2 577.6 4.4 486.7 - (2,559.9 ) - Fees from midstream services 5.2 - 308.3 30.1 - (343.6 ) - 1,496.4 577.6 312.7 516.8 - (2,903.5 ) - Revenues $ 1,884.1 $ 967.0 $ 705.4 $ 7,971.5 $ (8.0 ) $ (2,903.5 ) $ 8,616.5 Operating margin $ 372.3 $ 77.6 $ 445.1 $ 249.6 $ (8.0 ) $ - $ 1,136.6 Other financial information: Total assets $ 3,409.0 $ 367.2 $ 1,717.3 $ 708.5 $ 60.2 $ 115.0 $ 6,377.2 Capital expenditures $ 423.1 $ 14.0 $ 274.4 $ 30.2 $ - $ 6.1 $ 747.8 Year Ended December 31, 2013 Field Gathering and Processing Coastal Gathering and Processing Logistics Assets Marketing and Distribution Other Corporate and Eliminations Total Revenues Sales of commodities $ 188.8 $ 305.0 $ 140.5 $ 5,072.4 $ 21.4 $ 0.1 $ 5,728.2 Fees from midstream services 113.9 33.6 216.0 223.3 - (0.1 ) 586.7 302.7 338.6 356.5 5,295.7 21.4 - 6,314.9 Intersegment revenues Sales of commodities 1,218.9 642.2 3.9 478.6 - (2,343.6 ) - Fees from midstream services 3.4 1.0 176.5 29.8 - (210.7 ) - 1,222.3 643.2 180.4 508.4 - (2,554.3 ) - Revenues $ 1,525.0 $ 981.8 $ 536.9 $ 5,804.1 $ 21.4 $ (2,554.3 ) $ 6,314.9 Operating margin $ 270.5 $ 85.4 $ 282.3 $ 141.9 $ 21.4 $ - $ 801.5 Other financial information: Total assets $ 3,200.7 $ 383.8 $ 1,503.6 $ 756.1 $ 5.1 $ 122.1 $ 5,971.4 Capital expenditures $ 557.8 $ 20.6 $ 444.7 $ 6.3 $ - $ 5.1 $ 1,034.5 |
Revenues by Product and Service | The following table shows our consolidated revenues by product and service for the periods presented: 2015 2014 2013 Sales of commodities Natural gas $ 1,594.5 $ 1,414.1 $ 1,225.0 NGL 3,558.7 5,960.1 4,224.0 Condensate 142.4 134.3 121.8 Petroleum products 101.6 96.3 136.0 Derivative activities 68.2 (9.6 ) 21.4 5,465.4 7,595.2 5,728.2 Fees from midstream services Fractionating and treating 209.0 208.9 133.9 Storage, terminaling, transportation and export 506.2 548.1 280.3 Gathering and processing 393.7 196.9 114.1 Other 84.3 67.4 58.4 1,193.2 1,021.3 586.7 Total revenues $ 6,658.6 $ 8,616.5 $ 6,314.9 |
Reconciliation of Operating Margin to Net Income (Loss) | The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: 2015 2014 2013 Reconciliation of operating margin to net income (loss): Operating margin $ 1,281.0 $ 1,136.6 $ 801.5 Depreciation and amortization expense (677.1 ) (346.5 ) (271.6 ) General and administrative expense (153.6 ) (139.8 ) (143.1 ) Provisional goodwill impairment (290.0 ) - - Interest expense, net (207.8 ) (143.8 ) (131.0 ) Other, net (11.2 ) 3.4 5.7 Income tax expense (0.6 ) (4.8 ) (2.9 ) Net income (loss) $ (59.3 ) $ 505.1 $ 258.6 |
Selected Quarterly Financial 53
Selected Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Selected Quarterly Financial Data (Unaudited) [Abstract] | |
Results of Operations by Quarter | Our results of operations by quarter for the years ended December 31, 2015 and 2014 were as follows: First Quarter Second Quarter Third Quarter Fourth Quarter Total (In millions, except per unit amounts) 2015 Revenues $ 1,679.7 $ 1,699.4 $ 1,632.1 $ 1,647.4 $ 6,658.6 Gross margin 411.4 462.3 459.7 452.2 1,785.6 Operating income (loss) 141.0 114.8 117.3 (205.7 ) (1)(2) 167.4 Net income (loss) 77.8 53.3 53.3 (243.7 ) (59.3 ) Net income attributable to limited partners (loss) 30.3 1.2 3.6 (232.6 ) (197.5 ) Net income (loss) per limited partner unit - basic $ 0.21 $ 0.01 $ 0.02 $ (1.26 ) $ (1.15 ) - diluted $ 0.21 $ 0.01 $ 0.02 $ (1.26 ) $ (1.15 ) 2014 Revenues $ 2,294.7 $ 2,000.6 $ 2,288.3 $ 2,032.9 $ 8,616.5 Gross margin 379.6 384.0 407.8 398.2 1,569.6 Operating income 160.6 152.9 171.4 168.4 (1) 653.3 Net income 131.3 120.9 138.2 114.7 505.1 Net income attributable to limited partners 88.6 73.0 89.7 67.7 319.0 Net income per limited partner unit - basic $ 0.79 $ 0.64 $ 0.78 $ 0.58 $ 2.78 - diluted $ 0.78 $ 0.64 $ 0.78 $ 0.58 $ 2.77 (1) Included $32.6 million in the fourth quarter of 2015 and $3.2 million in the fourth quarter of 2014 losses due to the impairments. See Note 6 – Property, Plant and Equipment and Intangible Assets. (2) Included a provisional goodwill impairment of $290.0 million in the fourth quarter of 2015. See Note 4 –Business Acquisitions. |
Organization and Operations (De
Organization and Operations (Details) | Feb. 17, 2016$ / shares | Dec. 31, 2015shares | Dec. 31, 2014shares |
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||
General partner interest | 2.00% | 2.00% | |
Ownership interest by related party and subsidiaries | 10.60% | ||
General partner units outstanding (in units) | 3,772,871 | 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 | 48.00% | ||
Series A Cumulative Redeemable Perpetual Preferred Units [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||
Preferred units issued (in units) | 5,000,000 | 0 | |
Preferred units dividend percentage | 9.00% | ||
Subsequent Event [Member] | |||
Subsidiary of Limited Liability Company or Limited Partnership [Line Items] | |||
Conversion ratio in stock-for-unit transaction | 0.62 | ||
Common stock, par value (in dollars per share) | $ / shares | $ 0.001 |
Basis of Presentation (Details)
Basis of Presentation (Details) $ in Millions | Feb. 27, 2015USD ($)Transaction | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |||
Business Acquisition [Line Items] | |||||||||||||||
Number of legal transactions involved in mergers | Transaction | 2 | ||||||||||||||
Revision Of Previously Reported Preliminary Fair Values For Purchase Accounting [Abstract] | |||||||||||||||
Property, plant and equipment, net | $ 9,702.6 | $ 9,666.6 | $ 9,609.3 | $ 9,507.1 | $ 4,824.6 | $ 9,702.6 | $ 4,824.6 | ||||||||
Intangible assets, net | 1,810.1 | 1,847.1 | 1,884.1 | 1,921 | 591.9 | 1,810.1 | 591.9 | $ 653.4 | |||||||
Goodwill | $ 707 | 417 | [1] | 707 | 707 | 707 | 0 | 417 | [1] | 0 | |||||
Noncontrolling interests | 413.1 | 400.8 | 393.7 | ||||||||||||
Depreciation and amortization expenses | 166.7 | 164.9 | 119.6 | 677.1 | 346.5 | 271.6 | |||||||||
Revision of Previously Reported Revenues and Product Purchases [Abstract] | |||||||||||||||
Revenues | $ 1,647.4 | 1,632.1 | 1,699.4 | 1,679.7 | $ 2,032.9 | $ 2,288.3 | $ 2,000.6 | $ 2,294.7 | 6,658.6 | 8,616.5 | 6,314.9 | ||||
Product Purchases | $ 4,873 | $ 7,046.9 | 5,137.2 | ||||||||||||
As Reported [Member] | |||||||||||||||
Revision Of Previously Reported Preliminary Fair Values For Purchase Accounting [Abstract] | |||||||||||||||
Property, plant and equipment, net | 9,750.2 | 9,684.3 | 9,832.9 | ||||||||||||
Intangible assets, net | 1,695.7 | 1,735.6 | 1,602.4 | ||||||||||||
Goodwill | 551.4 | 557.9 | 628.5 | ||||||||||||
Noncontrolling interests | 309.6 | 297.4 | 480.7 | ||||||||||||
Depreciation and amortization expenses | 165.8 | 163.9 | 119.6 | ||||||||||||
Revision of Previously Reported Revenues and Product Purchases [Abstract] | |||||||||||||||
Revenues | 6,556.2 | ||||||||||||||
Product Purchases | 5,378.5 | ||||||||||||||
Impact of Errors [Member] | |||||||||||||||
Revision Of Previously Reported Preliminary Fair Values For Purchase Accounting [Abstract] | |||||||||||||||
Property, plant and equipment, net | (75) | (76) | (77) | ||||||||||||
Intangible assets, net | 111.6 | 113.1 | 114.5 | ||||||||||||
Goodwill | 48.5 | 48.5 | 48.5 | ||||||||||||
Noncontrolling interests | 86.2 | 86.2 | 86.2 | ||||||||||||
Depreciation and amortization expenses | 0.5 | 0.5 | 0.2 | ||||||||||||
Other Measurement Period Adjustments [Member] | |||||||||||||||
Revision Of Previously Reported Preliminary Fair Values For Purchase Accounting [Abstract] | |||||||||||||||
Property, plant and equipment, net | [2] | (8.6) | 1 | (248.8) | |||||||||||
Intangible assets, net | [2] | 39.8 | 35.4 | 204.1 | |||||||||||
Goodwill | [2] | 107.1 | 100.6 | 30 | |||||||||||
Noncontrolling interests | [2] | 17.3 | 17.2 | (173.2) | |||||||||||
Depreciation and amortization expenses | [2] | $ 0.4 | $ 0.5 | $ (0.2) | |||||||||||
Effect of Revisions [Member] | |||||||||||||||
Revision of Previously Reported Revenues and Product Purchases [Abstract] | |||||||||||||||
Revenues | (241.3) | ||||||||||||||
Product Purchases | $ (241.3) | ||||||||||||||
Atlas Energy [Member] | |||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||
Total general partner interest acquired | $ 1,600 | ||||||||||||||
[1] | Total assets include goodwill. Goodwill has been attributed to our Field Gathering and Processing segment - See Note 4 - Business Acquisitions. | ||||||||||||||
[2] | Other Measurement Period Adjustments for Goodwill include the impact of all balance sheet adjustments not presented in this table |
Significant Accounting Polici56
Significant Accounting Policies (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Income Taxes [Abstract] | ||
Margin tax rate | 0.75% | |
Earnings per Unit [Abstract] | ||
General partner's interest and incentive distribution rights | 2.00% | |
Term Loans And Notes [Member] | Accounting Standards Update 2015-03 [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Unamortized debt issuance costs | $ 38.3 | $ 29.9 |
Revolving Credit Facility [Member] | Accounting Standards Update 2015-15 [Member] | ||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||
Unamortized debt issuance costs | $ 5.9 | $ 7.4 |
Business Acquisitions (Details)
Business Acquisitions (Details) | Feb. 27, 2015USD ($)Transaction$ / sharesshares | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2015USD ($)Quartershares | Dec. 31, 2014MMcf / dmishares |
Business Acquisition [Line Items] | |||||||||
Number of separate legal transactions involved in mergers | Transaction | 2 | ||||||||
Total distribution of common shares (in shares) | shares | 7,377,380 | 7,175,096 | |||||||
Percentage of general partner's interest maintained | 2.00% | 2.00% | |||||||
Acquisition-related expenses | $ 19,200,000 | ||||||||
Revenues from acquired business | $ 1,459,300,000 | ||||||||
Net income (loss) from acquired business | $ (30,100,000) | ||||||||
Targa Pipeline Partners LP [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Processing capacity | MMcf / d | 2,053 | ||||||||
Length of additional pipelines | mi | 12,220 | ||||||||
Phantom Unit Awards [Member] | Atlas Energy [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Cash payment related to one-time cash payments and cash settlements of equity awards | $ 4,500,000 | ||||||||
Common Units [Member] | Targa Resources Corp [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Percentage of general partner's interest maintained | 2.00% | ||||||||
Atlas Pipeline Partners [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Purchase consideration | 5,300,000,000 | ||||||||
Acquired debt and all other assumed liabilities included purchase consideration | 1,800,000,000 | ||||||||
Payments for notes tendered and settled upon closing of merger | $ 1,200,000,000 | ||||||||
Reduction in incentive distribution | $ 9,375,000 | $ 9,375,000 | $ 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 | 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 | 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] | |||||||||
Business Acquisition [Line Items] | |||||||||
Total distribution of common shares (in shares) | shares | 58,614,157 | ||||||||
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 | ||||||||
Cash payment related to one-time cash payments and cash settlements of equity awards | $ 7,300,000 | ||||||||
Atlas Energy [Member] | Targa Resources Corp [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Percentage of interest in common units | 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] | 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] | 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 | 3,363,935 | |||||||
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 | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Pro forma consolidated results of operations [Abstract] | ||
Revenues | $ 6,947.3 | $ 11,449.3 |
Net income (loss) | (62.2) | $ 691.2 |
Acquisition-related costs | $ 19.2 | |
West Texas LPG Pipeline Limited Partnership [Member] | ||
Pro forma consolidated results of operations [Abstract] | ||
Percentage of equity interest sold | 20.00% | |
Atlas Resource Partners, LP [Member] | ||
Pro forma consolidated results of operations [Abstract] | ||
Percentage of equity interest sold | 100.00% |
Business Acquisitions, Fair Val
Business Acquisitions, Fair Value of Consideration Transferred (Details) - USD ($) $ in Millions | Feb. 27, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Cash paid, net of cash acquired | $ 828.7 | $ 0 | $ 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] | Phantom Unit Awards [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Common shares of TRC | [2] | 15 | |||
Atlas Pipeline Partners [Member] | Common Units [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Common shares of TRC | 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 | ||||
Atlas Energy [Member] | Replacement Restricted Stock Units RSUs [Member] | Targa Resources Corp [Member] | |||||
Fair Value of Consideration Transferred by Targa [Abstract] | |||||
Common shares of TRC | [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 of TRC | $ 1,008.5 | ||||
[1] | We acquired $35.3 million of cash. | ||||
[2] | The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent the allocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combination service period will be recognized over the remaining service period of the award. | ||||
[3] | Targa acquired $5.5 million of cash. |
Business Acquisitions, Fair V60
Business Acquisitions, Fair Value Determination (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Feb. 27, 2015 | |||
Fair value determination [Abstract] | ||||||||||||||
Trade and other current receivables, net | $ 181.1 | |||||||||||||
Other current assets | 24.4 | |||||||||||||
Assets from risk management activities | 102.1 | |||||||||||||
Property, plant and equipment | 4,616.9 | |||||||||||||
Investments in unconsolidated affiliates | 214.5 | |||||||||||||
Intangible assets | 1,354.9 | |||||||||||||
Other long-term assets | 5.5 | |||||||||||||
Current liabilities | (258.8) | |||||||||||||
Long-term debt | (1,573.3) | |||||||||||||
Deferred income tax liabilities, net | (13.6) | |||||||||||||
Other long-term liabilities | (119.1) | |||||||||||||
Total identifiable net assets | 4,534.6 | |||||||||||||
Noncontrolling interest in subsidiaries | (216.9) | |||||||||||||
Current liabilities retained by Targa | (0.5) | |||||||||||||
Goodwill | $ 417 | [1] | $ 707 | $ 707 | $ 707 | $ 0 | $ 417 | [1] | $ 0 | 707 | ||||
Total fair value of consideration transferred | 5,024.2 | 5,024.2 | 5,024.2 | |||||||||||
Measurement-period adjustments to preliminary acquisition date fair values [Abstract] | ||||||||||||||
Revenues | 1,647.4 | 1,632.1 | 1,699.4 | 1,679.7 | $ 2,032.9 | $ 2,288.3 | $ 2,000.6 | $ 2,294.7 | 6,658.6 | 8,616.5 | $ 6,314.9 | |||
Operating expenses | 504.6 | 433 | 376.2 | |||||||||||
Depreciation and amortization expense | 166.7 | $ 164.9 | 119.6 | 677.1 | 346.5 | 271.6 | ||||||||
Equity earnings (loss) | (2.5) | 18 | 14.8 | |||||||||||
General and administrative expense | $ 153.6 | $ 139.8 | $ 143.1 | |||||||||||
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] | ||||||||||||||
Measurement-period adjustments to preliminary acquisition date fair values [Abstract] | ||||||||||||||
Depreciation and amortization expense | (1) | |||||||||||||
Equity earnings (loss) | $ 0.3 | |||||||||||||
Accounting Standards Update 2015-16 [Member] | Measurement Period Adjustments [Member] | ||||||||||||||
Measurement-period adjustments to preliminary acquisition date fair values [Abstract] | ||||||||||||||
Intangible assets | 155.9 | (5) | ||||||||||||
Noncontrolling interest in subsidiaries | 103.5 | |||||||||||||
Other long-term liabilities | 110.1 | |||||||||||||
Property, plant and equipment | (86.2) | 9.9 | ||||||||||||
Investments in unconsolidated affiliates | (5.2) | 5.5 | ||||||||||||
Deferred tax liabilities | 5 | |||||||||||||
Current liabilities | 1.3 | 2.4 | ||||||||||||
Other long-term assets | (0.1) | (1) | ||||||||||||
Other current assets | (0.1) | (0.6) | ||||||||||||
Goodwill | 155.6 | (6.4) | ||||||||||||
Revenues | 0.6 | |||||||||||||
Operating expenses | (1.9) | |||||||||||||
Depreciation and amortization expense | 2 | (0.1) | ||||||||||||
Interest Expense | (26.2) | |||||||||||||
Equity earnings (loss) | (0.2) | $ (0.1) | ||||||||||||
General and administrative expense | $ (0.4) | |||||||||||||
[1] | Total assets include goodwill. Goodwill has been attributed to our Field Gathering and Processing segment - See Note 4 - Business Acquisitions. |
Business Acquisitions, Continge
Business Acquisitions, Contingent Consideration and Replacement Phantom Units (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Jun. 30, 2015 | |
Replacement Phantom Units [Member] | ||
Business Acquisition [Line Items] | ||
Number of common units called by replacement equity unit (in shares) | 1 | |
Dividend payment period | 60 days | |
Replacement Phantom Units [Member] | Vesting Term One [Member] | ||
Business Acquisition [Line Items] | ||
Vesting percentage original term | 25.00% | |
Vesting period of original term | 4 years | |
Replacement Phantom Units [Member] | Vesting Term Two [Member] | ||
Business Acquisition [Line Items] | ||
Vesting percentage original term | 33.00% | |
Vesting period of original term | 3 years | |
Atlas Pipeline Partners [Member] | ||
Business Acquisition [Line Items] | ||
Contingent consideration additional amount | $ 6 | |
Contingent liability acquisition date fair value | $ 4.2 | |
Contingent consideration liability lower range | 0 | |
Contingent consideration liability higher range | $ 6 |
Business Acquisitions, Mandator
Business Acquisitions, Mandatorily Redeemable Preferred Interests (Details) - Mandatorily Redeemable Noncontrolling Interests [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($)JointVenture | |
Redeemable Noncontrolling Interest [Line Items] | |
Number of joint ventures | JointVenture | 2 |
Acquired other long-term liabilities | $ | $ 109.3 |
Business Acquisitions, Goodwill
Business Acquisitions, Goodwill (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Dec. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Goodwill [Roll Forward] | ||||||
Beginning of period | $ 707 | $ 0 | ||||
Acquisition | 707 | |||||
Impairment | (290) | (290) | $ 0 | $ 0 | ||
Goodwill | 417 | [1] | 417 | [1] | 0 | |
WestTX [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Beginning of period | 0 | |||||
Acquisition | 364.5 | |||||
Impairment | (37.6) | |||||
Goodwill | 326.9 | 326.9 | 0 | |||
SouthTX [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Beginning of period | 0 | |||||
Acquisition | 160.3 | |||||
Impairment | (70.2) | |||||
Goodwill | 90.1 | 90.1 | 0 | |||
SouthOK [Member] | ||||||
Goodwill [Roll Forward] | ||||||
Beginning of period | 0 | |||||
Acquisition | 182.2 | |||||
Impairment | (182.2) | |||||
Goodwill | $ 0 | $ 0 | $ 0 | |||
[1] | Total assets include goodwill. Goodwill has been attributed to our Field Gathering and Processing segment - See Note 4 - Business Acquisitions. |
Inventories (Details)
Inventories (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Inventories [Abstract] | ||
Commodities | $ 128.3 | $ 157.4 |
Materials and supplies | 12.7 | 11.5 |
Total inventories | $ 141 | $ 168.9 |
Property, Plant and Equipment65
Property, Plant and Equipment and Intangible Assets, Property, Plant and Equipment (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | |
Property, Plant and Equipment [Line Items] | ||||||||
Property, plant and equipment | $ 11,928.2 | $ 6,514.3 | $ 11,928.2 | $ 6,514.3 | ||||
Accumulated depreciation | (2,225.6) | (1,689.7) | (2,225.6) | (1,689.7) | ||||
Property, plant and equipment, net | 9,702.6 | 4,824.6 | 9,702.6 | 4,824.6 | $ 9,666.6 | $ 9,609.3 | $ 9,507.1 | |
Intangible assets | 2,036.6 | 681.8 | 2,036.6 | 681.8 | ||||
Accumulated amortization | (226.5) | (89.9) | (226.5) | (89.9) | ||||
Intangible assets, net | 1,810.1 | 591.9 | $ 1,810.1 | 591.9 | $ 653.4 | $ 1,847.1 | $ 1,884.1 | $ 1,921 |
Estimated useful life | 20 years | |||||||
Depreciation expenses for property, plant and equipment | $ 540.5 | 285 | $ 244.2 | |||||
Non-cash pre-tax impairment charges | 32.6 | 3.2 | 32.6 | 3.2 | ||||
Gathering Systems [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Property, plant and equipment | 6,304.5 | 2,588.6 | $ 6,304.5 | 2,588.6 | ||||
Gathering Systems [Member] | Minimum [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Estimated useful life | 5 years | |||||||
Gathering Systems [Member] | Maximum [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Estimated useful life | 20 years | |||||||
Processing and Fractionation Facilities [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Property, plant and equipment | 2,988.5 | 1,884.1 | $ 2,988.5 | 1,884.1 | ||||
Processing and Fractionation Facilities [Member] | Minimum [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Estimated useful life | 5 years | |||||||
Processing and Fractionation Facilities [Member] | Maximum [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Estimated useful life | 25 years | |||||||
Terminaling and Storage Facilities [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Property, plant and equipment | 1,115 | 1,038.9 | $ 1,115 | 1,038.9 | ||||
Terminaling and Storage Facilities [Member] | Minimum [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Estimated useful life | 5 years | |||||||
Terminaling and Storage Facilities [Member] | Maximum [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Estimated useful life | 25 years | |||||||
Transportation Assets [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Property, plant and equipment | 454 | 359 | $ 454 | 359 | ||||
Transportation Assets [Member] | Minimum [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Estimated useful life | 10 years | |||||||
Transportation Assets [Member] | Maximum [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Estimated useful life | 25 years | |||||||
Other Property, Plant and Equipment [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Property, plant and equipment | 220.9 | 149.1 | $ 220.9 | 149.1 | ||||
Other Property, Plant and Equipment [Member] | Minimum [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Estimated useful life | 3 years | |||||||
Other Property, Plant and Equipment [Member] | Maximum [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Estimated useful life | 25 years | |||||||
Land [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Property, plant and equipment | 108.8 | 95.6 | $ 108.8 | 95.6 | ||||
Construction in Progress [Member] | ||||||||
Property, Plant and Equipment [Line Items] | ||||||||
Property, plant and equipment | $ 736.5 | $ 399 | $ 736.5 | $ 399 |
Property, Plant and Equipment66
Property, Plant and Equipment and Intangible Assets, Intangible Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property, Plant and Equipment and Intangible Assets [Abstract] | |||
Estimated useful life | 20 years | ||
Intangible Assets, net [Roll Forward] | |||
Beginning of period | $ 591.9 | $ 653.4 | |
Additions from acquisition | 1,354.9 | 0 | |
Amortization | (136.7) | (61.5) | $ (27.4) |
Intangible assets, net | 1,810.1 | $ 591.9 | $ 653.4 |
Estimated amortization expense for intangible assets [Abstract] | |||
2,016 | 156.2 | ||
2,017 | 149.4 | ||
2,018 | 135.7 | ||
2,019 | 124.7 | ||
2,020 | $ 112.5 | ||
Weighted average amortization period, intangible assets | 18 years 6 months |
Investment in Unconsolidated 67
Investment in Unconsolidated Affiliate (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015USD ($)JointVenture | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | ||
Schedule of Equity Method Investments [Line Items] | ||||
Beginning of period | $ 50.2 | $ 55.9 | $ 53.1 | |
Fair value of T2 Joint Ventures acquired | 214.5 | |||
Equity earnings (loss) | (2.5) | 18 | 14.8 | |
Cash distributions | [1] | (15) | (23.7) | (12) |
Cash calls for expansion projects | 11.7 | |||
End of period | 258.9 | 50.2 | 55.9 | |
Return of capital from unconsolidated affiliate | $ 1.2 | 5.7 | 0 | |
Gulf Coast Fractionators LP [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Ownership interest | 38.80% | |||
Beginning of period | $ 50.2 | 55.9 | 53.1 | |
Fair value of T2 Joint Ventures acquired | 0 | |||
Equity earnings (loss) | 13.8 | 18 | 14.8 | |
Cash distributions | [1] | (14.5) | (23.7) | (12) |
Cash calls for expansion projects | 0 | |||
End of period | $ 49.5 | 50.2 | 55.9 | |
Return of capital from unconsolidated affiliate | 5.7 | |||
T2 Joint Ventures [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Number of non-operated joint ventures acquired in Atlas mergers | JointVenture | 3 | |||
Basis difference on preliminary fair values | $ 39.9 | |||
Preliminary estimated useful lives of the underlying assets | 20 years | |||
T2 La Salle [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Ownership interest | 75.00% | |||
Beginning of period | $ 0 | 0 | 0 | |
Fair value of T2 Joint Ventures acquired | 67.5 | |||
Equity earnings (loss) | (3.9) | 0 | 0 | |
Cash distributions | [1] | 0 | 0 | 0 |
Cash calls for expansion projects | 0 | |||
End of period | $ 63.6 | 0 | 0 | |
T2 Eagle Ford [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Ownership interest | 50.00% | |||
Beginning of period | $ 0 | 0 | 0 | |
Fair value of T2 Joint Ventures acquired | 126.7 | |||
Equity earnings (loss) | (9.4) | 0 | 0 | |
Cash distributions | [1] | 0 | 0 | 0 |
Cash calls for expansion projects | 6.5 | |||
End of period | $ 123.8 | 0 | 0 | |
T2 EF Co-Gen [Member] | ||||
Schedule of Equity Method Investments [Line Items] | ||||
Ownership interest | 50.00% | |||
Beginning of period | $ 0 | 0 | 0 | |
Fair value of T2 Joint Ventures acquired | 20.3 | |||
Equity earnings (loss) | (3) | 0 | 0 | |
Cash distributions | [1] | (0.5) | 0 | 0 |
Cash calls for expansion projects | 5.2 | |||
End of period | $ 22 | $ 0 | $ 0 | |
[1] | Includes $1.2 million in distributions from GCF and T2 Joint Ventures in excess of our share of cumulative earnings for the year ended December 31, 2015. Includes $5.7 million in distributions from GCF in excess of our share of cumulative earnings for the year ended December 31, 2014. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows. |
Accounts Payable and Accrued 68
Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Components of accounts payable and accrued liabilities [Abstract] | ||
Commodities | $ 385.3 | $ 416.7 |
Other goods and services | 141.3 | 108.9 |
Interest | 80.3 | 37.3 |
Compensation and benefits | 0.4 | 1.3 |
Income and other taxes | 10.4 | 13.6 |
Other | 18.1 | 14.9 |
Accounts payable and accrued liabilities | 635.8 | 592.7 |
Outstanding checks | $ 34 | $ 13.3 |
Debt Obligations (Details)
Debt Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Long-term [Abstract] | |||
Long-term debt | $ 5,164 | $ 2,783.4 | |
Total debt | 5,383.3 | 2,966.2 | |
Irrevocable standby letters of credit outstanding | $ 12.9 | 44.1 | |
Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||
Long-term [Abstract] | |||
Interest rate on fixed rate debt | 6.625% | ||
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | |||
Long-term [Abstract] | |||
Maturity date | Nov. 15, 2023 | ||
Interest rate on fixed rate debt | 4.25% | ||
Atlas Pipeline Partners, L.P. Acquisition [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||
Long-term [Abstract] | |||
Interest rate on fixed rate debt | 6.625% | ||
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility, Variable Rate, due October 2017 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [1] | $ 280 | 0 |
Maturity date | [1] | Oct. 3, 2017 | |
Maximum borrowing capacity | $ 1,600 | ||
Remaining borrowing capacity | 1,307.1 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 1,100 | 0 | |
Maturity date | Jan. 15, 2018 | ||
Interest rate on fixed rate debt | 5.00% | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [2] | $ 342.1 | 0 |
Unamortized premium | $ 5 | 0 | |
Maturity date | [2] | Oct. 1, 2020 | |
Interest rate on fixed rate debt | [2] | 6.63% | |
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 | $ (22.1) | (25.2) | |
Maturity date | Feb. 1, 2021 | ||
Interest rate on fixed rate debt | 6.875% | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 300 | 300 | |
Maturity date | Aug. 1, 2022 | ||
Interest rate on fixed rate debt | 6.375% | ||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 583.7 | 600 | |
Maturity date | May 1, 2023 | ||
Interest rate on fixed rate debt | 5.25% | ||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | |||
Long-term [Abstract] | |||
Unamortized discount | $ 623.5 | 625 | |
Maturity date | Nov. 15, 2023 | ||
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 600 | 0 | |
Maturity date | Mar. 15, 2024 | ||
Interest rate on fixed rate debt | 6.75% | ||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | $ 800 | 800 | |
Maturity date | Nov. 15, 2019 | ||
Interest rate on fixed rate debt | 4.13% | ||
Senior Unsecured Notes [Member] | Atlas Pipeline Partners, L.P. Acquisition [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [2],[3] | $ 12.9 | 0 |
Unamortized premium | $ 0.2 | 0 | |
Maturity date | [2],[3] | Oct. 1, 2020 | |
Interest rate on fixed rate debt | [2],[3] | 6.625% | |
Senior Unsecured Notes [Member] | Atlas Pipeline Partners, L.P. Acquisition [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [3] | $ 6.5 | 0 |
Maturity date | [3] | Nov. 15, 2021 | |
Interest rate on fixed rate debt | [3] | 4.75% | |
Senior Unsecured Notes [Member] | Atlas Pipeline Partners, L.P. Acquisition [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | |||
Long-term [Abstract] | |||
Long-term debt | [3] | $ 48.1 | 0 |
Unamortized premium | $ 0.5 | 0 | |
Maturity date | [3] | Aug. 1, 2023 | |
Interest rate on fixed rate debt | [3] | 5.875% | |
Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility Due December 2016 [Member] | |||
Debt Instrument [Line Items] | |||
Current debt | $ 219.3 | $ 182.8 | |
Long-term [Abstract] | |||
Maturity date | Dec. 31, 2016 | ||
[1] | As of December 31, 2015, availability under our $1.6 billion senior secured revolving credit facility was $1,307.1 million. | ||
[2] | In May 2015, we exchanged the TRP 6.625% Senior Notes with the same economic terms to the holders of the 6.625% APL Notes that validly tendered such notes for exchange to us. | ||
[3] | While we consolidate the debt acquired in the Atlas mergers, APL debt is not guaranteed by us. |
Debt Obligations, Contractually
Debt Obligations, Contractually Scheduled Maturities of Debt Obligations (Details) $ in Millions | Dec. 31, 2015USD ($) |
Scheduled maturities of debt [Abstract] | |
Total | $ 5,399.7 |
2,016 | 219.3 |
2,017 | 280 |
2,018 | 1,100 |
2,019 | 800 |
2,020 | 355 |
After 2,020 | 2,645.4 |
Revolving Credit Facility [Member] | |
Scheduled maturities of debt [Abstract] | |
Total | 280 |
2,016 | 0 |
2,017 | 280 |
2,018 | 0 |
2,019 | 0 |
2,020 | 0 |
After 2,020 | 0 |
Senior Unsecured Notes [Member] | |
Scheduled maturities of debt [Abstract] | |
Total | 4,900.4 |
2,016 | 0 |
2,017 | 0 |
2,018 | 1,100 |
2,019 | 800 |
2,020 | 355 |
After 2,020 | 2,645.4 |
Accounts Receivable Securitization Facility [Member] | |
Scheduled maturities of debt [Abstract] | |
Total | 219.3 |
2,016 | 219.3 |
2,017 | 0 |
2,018 | 0 |
2,019 | 0 |
2,020 | 0 |
After 2,020 | $ 0 |
Debt Obligations, Interest Rate
Debt Obligations, Interest Rates on Variable-Rate Debt Obligations (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Revolving Credit Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred, minimum | 1.90% |
Range of interest rates incurred, maximum | 4.80% |
Weighted average interest rate incurred | 2.20% |
Accounts Receivable Securitization Facility [Member] | |
Range of interest rates and weighted average interest rate [Abstract] | |
Range of interest rates incurred, minimum | 0.90% |
Range of interest rates incurred, maximum | 1.20% |
Weighted average interest rate incurred | 0.90% |
Debt Obligations, Revolving Cre
Debt Obligations, Revolving Credit Agreement (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |
Feb. 28, 2015 | Dec. 31, 2015 | Oct. 31, 2012 | |
Atlas Pipeline Partners [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Cash payments related to change of control payments | $ 28.8 | ||
TRP Revolver [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Maturity date | Oct. 3, 2017 | ||
Maximum consolidated leverage ratio | 5.50 | ||
Minimum ratio of consolidated EBITDA to consolidated interest expense | 2.25 | ||
TRP Revolver [Member] | Minimum [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Commitment fee percentage | 0.30% | ||
TRP Revolver [Member] | Maximum [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Commitment fee percentage | 0.50% | ||
TRP Revolver [Member] | Federal Funds Rate [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Basis spread on variable rate | 0.50% | ||
TRP Revolver [Member] | Base Rate [Member] | Minimum [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Basis spread on variable rate | 0.75% | ||
TRP Revolver [Member] | Base Rate [Member] | Maximum [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Basis spread on variable rate | 1.75% | ||
TRP Revolver [Member] | Eurodollar [Member] | Minimum [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Basis spread on variable rate | 1.75% | ||
TRP Revolver [Member] | Eurodollar [Member] | Maximum [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Basis spread on variable rate | 2.75% | ||
TRP Revolver [Member] | London Interbank Offered Rate (LIBOR) [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Basis spread on variable rate | 1.00% | ||
Letters of Credit [Member] | TRP Revolver [Member] | Minimum [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Interest rate percentage | 1.75% | ||
Letters of Credit [Member] | TRP Revolver [Member] | Maximum [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Interest rate percentage | 2.75% | ||
Revolving Credit Facility [Member] | Atlas Pipeline Partners [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Cash payments related to acquisition | 701.4 | ||
Revolving Credit Facility [Member] | Original Agreement [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Maximum borrowing capacity | $ 1,200 | ||
Additional commitment increase available upon request | $ 300 | ||
Revolving Credit Facility [Member] | First Amendment [Member] | |||
Revolving Credit Agreement [Abstract] | |||
Maximum borrowing capacity | 1,600 | ||
Additional commitment increase available upon request | $ 300 |
Debt Obligations, Senior Unsecu
Debt Obligations, Senior Unsecured Notes (Details) - USD ($) $ in Millions | Jan. 31, 2015 | Sep. 30, 2015 | Nov. 30, 2014 | Oct. 31, 2014 | Jul. 31, 2013 | Jun. 30, 2013 | May. 31, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Payment for redemption of debt | $ 1,168.8 | $ 0 | $ 0 | |||||||
Senior Unsecured Notes [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Unamortized debt issue costs written off | 0.1 | |||||||||
Gain on repurchase of debt | 3.6 | |||||||||
Senior Unsecured Notes [Member] | Senior Unsecured 11 1/4% Notes due July 2017 [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Payment for redemption of debt | $ 76.8 | |||||||||
Premium paid on redemption of debt | 4.1 | |||||||||
Unamortized debt issue costs written off | 1 | |||||||||
Pretax gain (loss) on extinguishment of debt | $ (7.4) | |||||||||
Senior Unsecured Notes [Member] | Senior Unsecured 7 7/8% Notes due October 2018 [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Premium paid on redemption of debt | 9.9 | |||||||||
Redemption price, percentage of face value | 103.938% | |||||||||
Unamortized debt issue costs written off | 2.5 | |||||||||
Pretax gain (loss) on extinguishment of debt | $ (12.4) | |||||||||
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Payment for redemption of debt | $ 106.4 | |||||||||
Premium paid on redemption of debt | 6.4 | |||||||||
Unamortized debt issue costs written off | 1 | |||||||||
Face amount of notes redeemed | 100 | |||||||||
Pretax gain (loss) on extinguishment of debt | $ (7.4) | |||||||||
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Payment for redemption of debt | 13 | |||||||||
Face amount of notes redeemed | 16.3 | |||||||||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Aggregate principal amount issued | $ 625 | |||||||||
Net proceeds from private placement of notes | $ 618.1 | |||||||||
Payment for redemption of debt | $ 1.2 | |||||||||
Redemption price, percentage of face value | 104.25% | |||||||||
Face amount of notes redeemed | $ 1.5 | |||||||||
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Aggregate principal amount issued | $ 800 | |||||||||
Net proceeds from private placement of notes | $ 790.8 | |||||||||
Redemption price, percentage of face value | 104.125% | |||||||||
Senior Unsecured Notes [Member] | Senior Unsecured Notes Due March 2024 [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Redemption price, percentage of face value | 106.75% | |||||||||
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Atlas Pipeline Partners [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Payment for redemption of debt | $ 0.1 | |||||||||
Face amount of notes redeemed | $ 0.1 | |||||||||
Partnership Issuers [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Aggregate principal amount issued | $ 1,100 | |||||||||
Net proceeds from private placement of notes | $ 1,089.8 | |||||||||
Partnership Issuers [Member] | Senior Unsecured Notes [Member] | Senior Unsecured Notes Due March 2024 [Member] | ||||||||||
The Partnership's Senior Unsecured Notes [Abstract] | ||||||||||
Aggregate principal amount issued | $ 600 | |||||||||
Net proceeds from private placement of notes | $ 595 |
Debt Obligations, APL Senior No
Debt Obligations, APL Senior Notes Tender Offers (Details) - USD ($) $ in Millions | Apr. 27, 2015 | Feb. 27, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Results of tender offers [Abstract] | ||||||
Repayment of debt | $ 1,168.8 | $ 0 | $ 0 | |||
Atlas Pipeline Partners [Member] | ||||||
Results of tender offers [Abstract] | ||||||
Amount Tendered | $ 1,200 | |||||
Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Atlas Pipeline Partners [Member] | ||||||
Results of tender offers [Abstract] | ||||||
Tendered percentage | 96.30% | |||||
APL Senior Notes Tender Offers [Member] | Atlas Pipeline Partners [Member] | ||||||
Results of tender offers [Abstract] | ||||||
Repayment of debt | 1,168.8 | |||||
APL Senior Notes with Offers Tendered [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 | 1,550 | ||||
APL Senior Notes with Offers Tendered [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 | 28.02% | |||||
Note Balance after Tender Offers | $ 359.9 | 500 | ||||
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] | ||||||
Amount Tendered | $ 4.8 | |||||
Total Tender Offer payments | $ 5 | |||||
APL Senior Notes with Offers Tendered [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 | 98.38% | |||||
Note Balance after Tender Offers | $ 6.5 | 400 | ||||
APL Senior Notes with Offers Tendered [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 | 92.60% | |||||
Note Balance after Tender Offers | $ 48.1 | $ 650 |
Debt Obligations, Exchange Offe
Debt Obligations, Exchange Offer and Consent Solicitation (Details) - Senior Unsecured 6 5/8% Notes due October 2020 [Member] - Atlas Pipeline Partners [Member] - USD ($) $ in Millions | Apr. 27, 2015 | Dec. 31, 2015 | May. 31, 2015 |
Debt Instrument [Line Items] | |||
Tendered percentage | 96.30% | ||
Costs associated with exchange offer | $ 0.7 | ||
Partnership Issuers [Member] | |||
Debt Instrument [Line Items] | |||
Aggregate principal amount outstanding | $ 342.1 | ||
Unamortized premium | $ 5.6 |
Debt Obligations, Debt Repurcha
Debt Obligations, Debt Repurchases Summary (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Debt Repurchases Summary [Abstract] | |||
(Gain) loss from financing activities | $ (2.8) | $ 12.4 | $ 14.7 |
Senior Unsecured Notes [Member] | |||
Debt Repurchases Summary [Abstract] | |||
Gain (Loss) on repurchase of debt | (3.6) | ||
Write-off of deferred debt issue costs | 0.1 | ||
Senior Unsecured Notes [Member] | Notes 6 3/8% Notes [Member] | |||
Debt Repurchases Summary [Abstract] | |||
Premium over face value paid upon redemption | 0 | 0 | 6.4 |
Write-off of deferred debt issue costs | 0 | 0 | 1 |
Senior Unsecured Notes [Member] | Notes 7 7/8% Notes [Member] | |||
Debt Repurchases Summary [Abstract] | |||
Premium over face value paid upon redemption | 0 | 9.9 | 0 |
Write-off of deferred debt issue costs | 0 | 2.5 | 0 |
Senior Unsecured Notes [Member] | Notes 5 1/4 % Notes [Member] | |||
Debt Repurchases Summary [Abstract] | |||
Gain (Loss) on repurchase of debt | (3.3) | 0 | 0 |
Write-off of deferred debt issue costs | 0.1 | 0 | 0 |
Senior Unsecured Notes [Member] | Notes 4 1/4% Notes [Member] | |||
Debt Repurchases Summary [Abstract] | |||
Gain (Loss) on repurchase of debt | (0.3) | 0 | 0 |
Senior Unsecured Notes [Member] | Notes 11.1/4% Notes [Member] | |||
Debt Repurchases Summary [Abstract] | |||
Premium over face value paid upon redemption | 0 | 0 | 4.1 |
Recognition of unamortized discount | 0 | 0 | 2.2 |
Write-off of deferred debt issue costs | 0 | 0 | 1 |
Senior Unsecured Notes [Member] | Notes 6 5/8% Notes [Member] | |||
Debt Repurchases Summary [Abstract] | |||
Loss from financing with exchange offer | $ 0.7 | $ 0 | $ 0 |
Debt Obligations, Terms of Seni
Debt Obligations, Terms of Senior Unsecured Notes Outstanding (Details) | 12 Months Ended | |
Dec. 31, 2015 | ||
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Due date | Nov. 15, 2023 | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | Feb. 1, 2011 | |
Per annum interest rate | 6.875% | |
Due date | Feb. 1, 2021 | |
Dates interest paid | February & August 1st | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | Jan. 1, 2012 | |
Per annum interest rate | 6.375% | |
Due date | Aug. 1, 2022 | |
Dates interest paid | February & August 1st | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Per annum interest rate | 5.25% | |
Due date | May 1, 2023 | |
Dates interest paid | May & November 1st | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | Minimum [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | Oct. 1, 2012 | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member] | Maximum [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | Dec. 1, 2012 | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | May 1, 2013 | |
Per annum interest rate | 4.25% | |
Due date | Nov. 15, 2023 | |
Dates interest paid | May & November 15th | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% Notes due November 2019 [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | Oct. 1, 2014 | |
Per annum interest rate | 4.125% | |
Due date | Nov. 15, 2019 | |
Dates interest paid | May & November 15th | |
Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | Jan. 1, 2015 | |
Per annum interest rate | 5.00% | |
Due date | Jan. 15, 2018 | |
Dates interest paid | January & July 15th | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | May 1, 2015 | |
Per annum interest rate | 6.625% | |
Due date | Oct. 1, 2020 | [1] |
Dates interest paid | February & October 1st | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Atlas Pipeline Partners [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | Sep. 1, 2012 | [2] |
Per annum interest rate | 6.625% | |
Due date | Oct. 1, 2020 | [1],[3] |
Dates interest paid | April & October 1st | |
Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | Sep. 1, 2015 | |
Per annum interest rate | 6.75% | |
Due date | Mar. 15, 2024 | |
Dates interest paid | March & September 15th | |
Senior Unsecured Notes [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | Atlas Pipeline Partners [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | May 1, 2013 | [2] |
Per annum interest rate | 4.75% | |
Due date | Nov. 15, 2021 | [3] |
Dates interest paid | May & November 15th | |
Senior Unsecured Notes [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | Atlas Pipeline Partners [Member] | ||
Terms of the Senior Unsecured Notes Outstanding [Abstract] | ||
Issue date | Feb. 1, 2013 | [2] |
Per annum interest rate | 5.875% | |
Due date | Aug. 1, 2023 | [3] |
Dates interest paid | February & August 1st | |
[1] | In May 2015, we exchanged the TRP 6.625% Senior Notes with the same economic terms to the holders of the 6.625% APL Notes that validly tendered such notes for exchange to us. | |
[2] | Issue dates for APL Notes are original dates of issuance. These notes were acquired in the APL Merger. See Note 4 - Business Acquisitions. | |
[3] | While we consolidate the debt acquired in the Atlas mergers, APL debt is not guaranteed by us. |
Debt Obligations, Redemption Da
Debt Obligations, Redemption Dates and Prices (Details) - Senior Unsecured Notes [Member] | 12 Months Ended |
Dec. 31, 2015 | |
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2016 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 103.438% |
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2017 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 102.292% |
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2018 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 101.146% |
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | 2019 and Thereafter [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.00% |
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days |
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2017 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 103.188% |
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2018 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 102.125% |
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2019 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 101.063% |
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | 2020 and Thereafter [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.00% |
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days |
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2017 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 102.625% |
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2018 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 101.75% |
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2019 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.875% |
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | 2020 and Thereafter [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.00% |
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days |
Redemption Dates and Prices [Abstract] | |
Any Date Prior To | May 15, 2016 |
Price | 104.25% |
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2016 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 102.063% |
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2017 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 101.031% |
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2018 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 102.125% |
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2018 and Thereafter [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.00% |
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2019 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 101.417% |
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2020 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.708% |
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | 2021 and Thereafter [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.00% |
Senior Unsecured 6 3/4% Notes due March 2024 [Member] | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days |
Redemption Dates and Prices [Abstract] | |
Any Date Prior To | Sep. 15, 2018 |
Price | 106.75% |
Senior Unsecured 6 3/4% Notes due March 2024 [Member] | 2019 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 103.375% |
Senior Unsecured 6 3/4% Notes due March 2024 [Member] | 2020 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 101.688% |
Senior Unsecured 6 3/4% Notes due March 2024 [Member] | 2021 and Thereafter [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.00% |
Senior Unsecured 4 1/8% Notes due November 2019 [Member] | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Redemption condition, maximum number of days from date of closing of equity offerings | 180 days |
Redemption Dates and Prices [Abstract] | |
Any Date Prior To | Nov. 15, 2017 |
Price | 104.125% |
Senior Unsecured 6 5/8% Notes Due October 2020 [Member] | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Senior Unsecured 6 5/8% Notes Due October 2020 [Member] | 2016 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 103.313% |
Senior Unsecured 6 5/8% Notes Due October 2020 [Member] | 2017 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 101.656% |
Senior Unsecured 6 5/8% Notes Due October 2020 [Member] | 2018 and Thereafter [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.00% |
Atlas Pipeline Partners [Member] | Senior Unsecured 6 5/8% Notes Due October 2020 [Member] | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Atlas Pipeline Partners [Member] | Senior Unsecured 6 5/8% Notes Due October 2020 [Member] | 2016 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 103.313% |
Atlas Pipeline Partners [Member] | Senior Unsecured 6 5/8% Notes Due October 2020 [Member] | 2017 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 101.656% |
Atlas Pipeline Partners [Member] | Senior Unsecured 6 5/8% Notes Due October 2020 [Member] | 2018 and Thereafter [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.00% |
Atlas Pipeline Partners [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Atlas Pipeline Partners [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | 2016 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 103.563% |
Atlas Pipeline Partners [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | 2017 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 102.375% |
Atlas Pipeline Partners [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | 2018 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 101.188% |
Atlas Pipeline Partners [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member] | 2019 and Thereafter [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.00% |
Atlas Pipeline Partners [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | |
Debt Instrument [Line Items] | |
Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings | 35.00% |
Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption | 65.00% |
Atlas Pipeline Partners [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | 2018 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 102.938% |
Atlas Pipeline Partners [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | 2019 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 101.958% |
Atlas Pipeline Partners [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | 2020 [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.979% |
Atlas Pipeline Partners [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member] | 2021 and Thereafter [Member] | |
Redemption Dates and Prices [Abstract] | |
Price | 100.00% |
Debt Obligations, Accounts Rece
Debt Obligations, Accounts Receivable Securitization Facility and Shelf Registration Statements (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015USD ($)Subsidiary | Apr. 30, 2015USD ($) | Jul. 31, 2013USD ($) | |
Accounts Receivable Securitization Facility [Member] | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 225 | ||
Funding under securitization facility | $ 219.3 | ||
Number of consolidated subsidiaries selling or contributing receivables under Securitization Facility | Subsidiary | 3 | ||
July 2013 Shelf [Member] | |||
Debt Instrument [Line Items] | |||
Aggregate amount of debt or equity securities allowed under shelf agreement | $ 800 | ||
April 2015 Shelf [Member] | |||
Debt Instrument [Line Items] | |||
Aggregate amount of debt or equity securities allowed under shelf agreement | $ 1,000 |
Debt Obligations, Subsequent Ev
Debt Obligations, Subsequent Events (Details) - USD ($) $ in Millions | Feb. 18, 2016 | Jun. 30, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | $ 1,168.8 | $ 0 | $ 0 | ||
Senior Unsecured Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Fees paid on repurchase of debt | $ 0.2 | ||||
Accrued interest paid | 1.4 | ||||
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | Senior Unsecured Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | 13 | ||||
Face amount of notes redeemed | 16.3 | ||||
Senior Unsecured 5 1/4% Notes due May 2023 [Member] | Senior Unsecured Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | 16.7 | ||||
Face amount of notes redeemed | 20.5 | ||||
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | Senior Unsecured Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | 1.2 | ||||
Face amount of notes redeemed | $ 1.5 | ||||
Senior Unsecured 4 1/4% Notes due November 2023 [Member] | Senior Unsecured Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | 17 | ||||
Face amount of notes redeemed | 22.9 | ||||
Senior Unsecured 6 7/8% Notes due February 2021 [Member] | Senior Unsecured Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | 4.3 | ||||
Face amount of notes redeemed | 5 | ||||
Senior Unsecured 6 5/8% Notes due October 2020 [Member] | Senior Unsecured Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | 15.3 | ||||
Face amount of notes redeemed | 17.4 | ||||
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | Senior Unsecured Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | $ 106.4 | ||||
Face amount of notes redeemed | 100 | ||||
Fees paid on repurchase of debt | $ 6.4 | ||||
Senior Unsecured 6 3/8% Notes due August 2022 [Member] | Senior Unsecured Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | 7.6 | ||||
Face amount of notes redeemed | 9.5 | ||||
Senior Unsecured 6 3/4% Notes due March 2024 [Member] | Senior Unsecured Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | 2.4 | ||||
Face amount of notes redeemed | 3 | ||||
Senior Unsecured 5% Notes due January 2018 [Member] | Senior Unsecured Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | 1.5 | ||||
Face amount of notes redeemed | 1.9 | ||||
Senior Unsecured 4 1/8% notes due November 2019 [Member] | Senior Unsecured Notes [Member] | Subsequent Event [Member] | |||||
Debt Instrument [Line Items] | |||||
Payment for redemption of debt | 11.9 | ||||
Face amount of notes redeemed | $ 16.4 |
Other Long-term Liabilities (De
Other Long-term Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Other Long-term Liabilities [Abstract] | ||||
Asset retirement obligations | $ 69.9 | $ 56.8 | $ 50.5 | $ 45.2 |
Mandatorily redeemable preferred interests | 82.9 | 0 | ||
Deferred revenue and other | 25.4 | 1 | ||
Total long-term liabilities | $ 178.2 | $ 57.8 |
Other Long-term Liabilities, As
Other Long-term Liabilities, Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning of period | $ 56.8 | $ 50.5 | $ 45.2 |
Fair value of ARO acquired with the APL merger | 4 | 0 | 0 |
Change in cash flow estimate | 3.8 | 2.1 | 1.4 |
Accretion expense | 5.3 | 4.4 | 3.9 |
Retirement of ARO | 0 | (0.2) | 0 |
End of period | $ 69.9 | $ 56.8 | $ 50.5 |
Other Long-term Liabilities, Ma
Other Long-term Liabilities, Mandatorily Redeemable Preferred Interests (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015USD ($)JointVenture | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Beginning of period | $ 0 | ||
Change in estimated redemption value | (30.6) | $ 0 | $ 0 |
Income attributable to mandatorily redeemable preferred interests | (31.9) | 37.4 | $ 25.1 |
End of period | 82.9 | 0 | |
Mandatorily Redeemable Preferred Interests [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Beginning of period | 0 | ||
Acquired mandatorily redeemable preferred interests | 109.3 | ||
Change in estimated redemption value | (30.6) | ||
Income attributable to mandatorily redeemable preferred interests | 2.8 | ||
Other activity, net | 1.4 | ||
End of period | $ 82.9 | $ 0 | |
Number of joint ventures | JointVenture | 2 | ||
Interest earned on notes receivable, net | $ 8.9 | ||
Mandatorily Redeemable Preferred Interests [Member] | West OK [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Ownership interest | 100.00% | ||
Mandatorily Redeemable Preferred Interests [Member] | West TX [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Ownership interest | 72.80% | ||
Mandatorily Redeemable Preferred Interests [Member] | Joint Ventures [Member] | |||
Changes in long-term liabilities attributable to mandatorily redeemable preferred interests [Abstract] | |||
Number of joint ventures | JointVenture | 2 | ||
Notes receivable, face amount | $ 1,900 | ||
Notes receivable, due date | Jul. 31, 2042 |
Other Long-term Liabilities, De
Other Long-term Liabilities, Deferred Revenue and Other (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Deferred Revenue and Other [Abstract] | |
Deferred revenue related to oil and gas processing agreement | $ 21.1 |
Deferred revenue recognized related to gas gathering and processing agreement | $ 1.4 |
Partnership Units and Related85
Partnership Units and Related Matters, Public Offerings of Common Units (Details) - USD ($) $ / shares in Units, $ in Millions | Feb. 27, 2015 | Oct. 31, 2015 | May. 31, 2015 | Mar. 31, 2015 | May. 31, 2014 | Aug. 31, 2013 | Mar. 31, 2013 | Aug. 31, 2012 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jul. 31, 2012 |
Partnership Equity [Abstract] | ||||||||||||
Number of common units included in public offering (in shares) | 7,377,380 | 7,175,096 | ||||||||||
Net proceeds from sale of common units | $ 316.1 | $ 408.4 | ||||||||||
General partner contributed to maintain general partner ownership percentage | $ 6.5 | $ 8.4 | ||||||||||
Ownership interest in Partnership by general partner | 2.00% | 2.00% | ||||||||||
Commissions to sales agents, maximum | 1.00% | |||||||||||
Distribution to preferred unitholders | $ 1.5 | |||||||||||
Senior Notes 5% Due 2018 [Member] | Senior Unsecured Notes [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Interest rate of partnership indebtedness percentage | 5.00% | |||||||||||
Maturity date | Jan. 15, 2018 | |||||||||||
Senior Notes 4 1/8% [Member] | Senior Unsecured Notes [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Interest rate of partnership indebtedness percentage | 4.125% | |||||||||||
Senior Notes 6 5/8% due 2020 [Member] | Senior Unsecured Notes [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Interest rate of partnership indebtedness percentage | 6.625% | |||||||||||
Maturity date | Oct. 1, 2020 | |||||||||||
Senior Notes 6 7/8% due 2021 [Member] | Senior Unsecured Notes [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Interest rate of partnership indebtedness percentage | 6.875% | |||||||||||
Maturity date | Feb. 1, 2021 | |||||||||||
Senior Notes 6 3/8% due 2022 [Member] | Senior Unsecured Notes [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Interest rate of partnership indebtedness percentage | 6.375% | |||||||||||
Maturity date | Aug. 1, 2022 | |||||||||||
Senior Notes 5 1/4% due 2023 [Member] | Senior Unsecured Notes [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Interest rate of partnership indebtedness percentage | 5.25% | |||||||||||
Maturity date | May 1, 2023 | |||||||||||
Senior Notes 4 1/4% due 2023 [Member] | Senior Unsecured Notes [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Interest rate of partnership indebtedness percentage | 4.25% | |||||||||||
Maturity date | Nov. 15, 2023 | |||||||||||
Senior Notes 6 3/4% due 2024 [Member] | Senior Unsecured Notes [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Interest rate of partnership indebtedness percentage | 6.75% | |||||||||||
Maturity date | Mar. 15, 2024 | |||||||||||
Common Units [Member] | Targa Resources Corp [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
General partner contributed to maintain general partner ownership percentage | $ 52.4 | |||||||||||
Ownership interest in Partnership by general partner | 2.00% | |||||||||||
Series A Preferred Units [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Preferred unit, redemption price (in dollars per share) | $ 25 | |||||||||||
Series A Preferred Units due November 1, 2020 [Member] | LIBOR [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Percentage of variable interest rate for distribution on preferred units upon maturity | 7.71% | |||||||||||
Atlas Energy [Member] | Common Units [Member] | Targa Resources Corp [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Number of common units included in public offering (in shares) | 10,126,532 | 3,363,935 | ||||||||||
Atlas Pipeline Partners [Member] | Targa Resources Corp [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Ownership interest in Partnership by general partner | 2.00% | |||||||||||
Atlas Pipeline Partners [Member] | Common Units [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Number of common units included in public offering (in shares) | 58,614,157 | |||||||||||
July 2012 Shelf [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Aggregate amount of debt or equity securities allowed to be issued under the shelf agreement | $ 300 | |||||||||||
August 2012 EDA [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Number of common units included in public offering (in shares) | 2,420,046 | |||||||||||
Net proceeds from sale of common units | $ 94.8 | |||||||||||
General partner contributed to maintain general partner ownership percentage | $ 2 | |||||||||||
Ownership interest in Partnership by general partner | 2.00% | |||||||||||
Dollar amount of common units able to sell from Equity Distribution Agreement | $ 100 | |||||||||||
March 2013 EDA [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Number of common units included in public offering (in shares) | 4,204,751 | |||||||||||
Net proceeds from sale of common units | $ 197.5 | |||||||||||
General partner contributed to maintain general partner ownership percentage | $ 4.1 | |||||||||||
Ownership interest in Partnership by general partner | 2.00% | |||||||||||
Dollar amount of common units able to sell from Equity Distribution Agreement | $ 200 | |||||||||||
August 2013 EDA [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Number of common units included in public offering (in shares) | 4,259,641 | |||||||||||
Net proceeds from sale of common units | $ 225.6 | |||||||||||
General partner contributed to maintain general partner ownership percentage | $ 4.7 | |||||||||||
Ownership interest in Partnership by general partner | 2.00% | |||||||||||
Dollar amount of common units able to sell from Equity Distribution Agreement | $ 400 | |||||||||||
May 2014 EDA [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Dollar amount of common units able to sell from Equity Distribution Agreement | $ 400 | |||||||||||
Capacity remaining available under shelf agreement | $ 4.2 | |||||||||||
May 2015 EDA [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Dollar amount of common units able to sell from Equity Distribution Agreement | $ 1,000 | |||||||||||
Capacity remaining available under shelf agreement | $ 835.6 | |||||||||||
April 2013 Shelf [Member] | Series A Preferred Units [Member] | ||||||||||||
Partnership Equity [Abstract] | ||||||||||||
Number of preferred units included in offerings (in shares) | 4,400,000 | |||||||||||
Preferred unit, price per unit (in dollars per share) | $ 25 | |||||||||||
Number of additional preferred units sold in public offering (in shares) | 600,000 | |||||||||||
Net proceeds received after costs | $ 121.1 | |||||||||||
Preferred unit, dividend interest rate | 9.00% |
Partnership Units and Related86
Partnership Units and Related Matters, Distributions (Details) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2015USD ($)$ / shares | Sep. 30, 2015USD ($)$ / shares | Jun. 30, 2015USD ($)$ / shares | Mar. 31, 2015USD ($)$ / shares | Dec. 31, 2014USD ($)$ / shares | Sep. 30, 2014USD ($)$ / shares | Jun. 30, 2014USD ($)$ / shares | Mar. 31, 2014USD ($)$ / shares | Dec. 31, 2013USD ($)$ / shares | Sep. 30, 2013USD ($)$ / shares | Jun. 30, 2013USD ($)$ / shares | Mar. 31, 2013USD ($)$ / shares | Dec. 31, 2015USD ($)Distribution | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |||||
Partnership Equity [Abstract] | |||||||||||||||||||
Number of days from end of each quarter by when cash is distributed to unitholders | 45 days | ||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Total distributions to general and limited partners | $ 733,600 | $ 493,800 | $ 397,300 | ||||||||||||||||
Distributions Declared [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Date paid | Feb. 9, 2016 | ||||||||||||||||||
Distributions to limited partners common | $ 152,500 | ||||||||||||||||||
Distributions to general partners (incentive) | [1] | 43,900 | |||||||||||||||||
Distributions to general partners (2%) | 4,000 | ||||||||||||||||||
Total distributions to general and limited partners | $ 200,400 | ||||||||||||||||||
Distributions per limited partner unit (in dollars per unit) | $ / shares | $ 0.8250 | ||||||||||||||||||
Distributions Paid [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Date paid | Nov. 13, 2015 | Aug. 14, 2015 | May 15, 2015 | Feb. 13, 2015 | Nov. 14, 2014 | Aug. 14, 2014 | May 15, 2014 | Feb. 14, 2014 | Nov. 14, 2013 | Aug. 14, 2013 | May 15, 2013 | ||||||||
Distributions to limited partners common | $ 152,500 | $ 152,500 | $ 148,300 | $ 96,300 | $ 92,300 | $ 89,500 | $ 87,200 | $ 84,000 | $ 79,400 | $ 75,800 | $ 71,700 | ||||||||
Distributions to general partners (incentive) | 43,900 | [1] | 43,900 | [1] | 41,700 | [1] | 38,400 | 36,000 | 33,700 | 31,700 | 29,500 | 26,900 | 24,600 | 22,100 | |||||
Distributions to general partners (2%) | 4,000 | 4,000 | 3,900 | 2,700 | 2,600 | 2,500 | 2,400 | 2,300 | 2,200 | 2,000 | 1,900 | ||||||||
Total distributions to general and limited partners | $ 200,400 | $ 200,400 | $ 193,900 | $ 137,400 | $ 130,900 | $ 125,700 | $ 121,300 | $ 115,800 | $ 108,500 | $ 102,400 | $ 95,700 | ||||||||
Distributions per limited partner unit (in dollars per unit) | $ / shares | $ 0.8250 | $ 0.8250 | $ 0.8200 | $ 0.8100 | $ 0.7975 | $ 0.7800 | $ 0.7625 | $ 0.7475 | $ 0.7325 | $ 0.7150 | $ 0.6975 | ||||||||
Atlas Pipeline Partners [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Reallocation of IDR payments to common unitholders | $ 9,375 | $ 9,375 | $ 9,375 | $ 9,375 | |||||||||||||||
Number of quarterly distributions that will be reduced | Distribution | 16 | ||||||||||||||||||
Atlas Pipeline Partners [Member] | Distribution Rights First Quarter for 2016 [Member] | |||||||||||||||||||
Distributions declared and/or paid by the Partnership [Abstract] | |||||||||||||||||||
Reallocation of IDR payments to common unitholders | $ 6,250 | ||||||||||||||||||
[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 each of the quarters for 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and resulted in reallocation of IDR payments to common unitholders in the following amounts: $9.375 million per quarter for 2015. The IDR Giveback will result in reallocation of IDR payments to common unitholders of $6.25 million in the first quarter for 2016." |
Earnings per Limited Partner 87
Earnings per Limited Partner Unit (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Earnings per Limited Partner Unit [Abstract] | ||||||||||||
Net income (loss) | $ (243.7) | $ 53.3 | $ 53.3 | $ 77.8 | $ 114.7 | $ 138.2 | $ 120.9 | $ 131.3 | $ (59.3) | $ 505.1 | $ 258.6 | |
Less: Net income attributable to noncontrolling interests | (31.9) | 37.4 | 25.1 | |||||||||
Net income (loss) attributable to Targa Resources Partners LP | (27.4) | 467.7 | 233.5 | |||||||||
Net income attributable to preferred limited partners | 2.4 | 0 | 0 | |||||||||
Net income attributable to general partner | 167.7 | 148.7 | 107.5 | |||||||||
Net income (loss) attributable to limited partners | $ (232.6) | $ 3.6 | $ 1.2 | $ 30.3 | $ 67.7 | $ 89.7 | $ 73 | $ 88.6 | (197.5) | 319 | 126 | |
Net income (loss) attributable to Targa Resources Partners LP | $ (27.4) | $ 467.7 | $ 233.5 | |||||||||
Weighted average units outstanding - basic (in shares) | 172,300,000 | 114,700,000 | 105,500,000 | |||||||||
Net income (loss) available per limited partner unit - basic (in dollars per share) | $ (1.26) | $ 0.02 | $ 0.01 | $ 0.21 | $ 0.58 | $ 0.78 | $ 0.64 | $ 0.79 | $ (1.15) | $ 2.78 | $ 1.19 | |
Weighted average units outstanding (in shares) | 172,300,000 | 114,700,000 | 105,500,000 | |||||||||
Dilutive effect of unvested stock awards (in shares) | 0 | 400,000 | 200,000 | |||||||||
Weighted average units outstanding - diluted (in shares) | [1] | 172,300,000 | 115,100,000 | 105,700,000 | ||||||||
Net income (loss) available per limited partner unit - diluted | $ (1.26) | $ 0.02 | $ 0.01 | $ 0.21 | $ 0.58 | $ 0.78 | $ 0.64 | $ 0.78 | $ (1.15) | $ 2.77 | $ 1.19 | |
Shares excluded from computation of diluted earnings (in shares) | 697,989 | 168,495 | ||||||||||
[1] | For the year ended December 31, 2015 and 2014, approximately 697,989 and 168,495 units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such units would have been anti-dilutive. |
Derivative Instruments and He88
Derivative Instruments and Hedging Activities (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 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 | $ | 67.9 | |
Ineffectiveness gains | $ | $ 0.9 | |
Swaps [Member] | Natural Gas [Member] | Year 2016 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 83,264 | |
Swaps [Member] | Natural Gas [Member] | Year 2017 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 23,082 | |
Swaps [Member] | Natural Gas [Member] | Year 2018 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 | |
Swaps [Member] | NGL [Member] | Year 2016 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 4,473 | |
Swaps [Member] | NGL [Member] | Year 2017 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 1,078 | |
Swaps [Member] | NGL [Member] | Year 2018 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 208 | |
Swaps [Member] | Condensate [Member] | Year 2016 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 1,502 | |
Swaps [Member] | Condensate [Member] | Year 2017 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 500 | |
Swaps [Member] | Condensate [Member] | Year 2018 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 0 | |
Basis Swaps [Member] | Natural Gas [Member] | Year 2016 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 48,962 | |
Basis Swaps [Member] | Natural Gas [Member] | Year 2017 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 18,082 | |
Basis Swaps [Member] | Natural Gas [Member] | Year 2018 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 0 | |
Collars [Member] | Natural Gas [Member] | Year 2016 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 22,900 | |
Collars [Member] | Natural Gas [Member] | Year 2017 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 22,900 | |
Collars [Member] | Natural Gas [Member] | Year 2018 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in MMBtu per day) | MMBTU | 9,486 | |
Future [Member] | NGL [Member] | Year 2016 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 1,956 | |
Future [Member] | NGL [Member] | Year 2017 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 0 | |
Future [Member] | NGL [Member] | Year 2018 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 0 | |
Option/Collars [Member] | NGL [Member] | Year 2016 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 920 | |
Option/Collars [Member] | NGL [Member] | Year 2017 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 920 | |
Option/Collars [Member] | NGL [Member] | Year 2018 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 32 | |
Option/Collars [Member] | Condensate [Member] | Year 2016 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 790 | |
Option/Collars [Member] | Condensate [Member] | Year 2017 [Member] | ||
Derivative [Line Items] | ||
Notional volumes of commodity hedges (in Bbl per day) | 790 | |
Option/Collars [Member] | Condensate [Member] | Year 2018 [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 | |
Gain on cash settlement | $ | $ 2.2 |
Derivative Instruments and He89
Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets | $ 127.1 | $ 60.2 |
Derivative liabilities | 7.6 | 5.2 |
Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 92.2 | 44.4 |
Long-term Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 34.9 | 15.8 |
Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 5.2 | 5.2 |
Long-term Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 2.4 | 0 |
Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 127 | 60.2 |
Derivative liabilities | 4.5 | 0 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Assets from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 92.1 | 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 | 34.9 | 15.8 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 2.1 | 0 |
Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Long-term Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 2.4 | 0 |
Not Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 0.1 | 0 |
Derivative liabilities | 3.1 | 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 | 0.1 | 0 |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Current Liabilities from Risk Management Activities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | $ 3.1 | $ 5.2 |
Derivative Instruments and He90
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative Asset [Abstract] | ||
Pro forma net presentation, asset | $ 119.5 | |
Gross asset | 127.1 | $ 60.2 |
Pro forma net presentation, asset, total | 119.5 | 55.8 |
Counterparties with Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 121.1 | 35.5 |
Gross liability | 7.6 | 4.4 |
Pro forma net presentation, asset | 113.5 | 31.1 |
Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 6 | 24.7 |
Current Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 92.2 | 44.4 |
Pro forma net presentation, asset, current | 87 | 40 |
Current Position [Member] | Counterparties with Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 86.9 | 35.5 |
Gross liability | 5.2 | 4.4 |
Pro forma net presentation, asset | 81.7 | 31.1 |
Current Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 5.3 | 8.9 |
Long-term Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 34.9 | 15.8 |
Pro forma net presentation, asset, noncurrent | 32.5 | 15.8 |
Long-term Position [Member] | Counterparties with Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | 34.2 | |
Gross liability | 2.4 | |
Pro forma net presentation, asset | 31.8 | |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Asset [Abstract] | ||
Gross asset | $ 0.7 | $ 15.8 |
Derivative Instruments and He91
Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative Liability [Abstract] | ||
Pro forma net presentation, liability | $ 119.5 | |
Gross liability | 7.6 | $ 5.2 |
Pro forma net presentation, liability, total | 0 | 0.8 |
Counterparties with Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Pro forma net presentation, liability | 113.5 | 31.1 |
Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 0 | 0.8 |
Current Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | 5.2 | 5.2 |
Pro forma net presentation, liability, current | 0 | 0.8 |
Current Position [Member] | Counterparties with Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Pro forma net presentation, liability | 0 | |
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 | 2.4 | 0 |
Pro forma net presentation, liability, noncurrent | 0 | 0 |
Long-term Position [Member] | Counterparties with Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross asset | 0 | |
Gross liability | 0 | |
Pro forma net presentation, liability | 0 | |
Long-term Position [Member] | Counterparties without Offsetting Position [Member] | ||
Derivative Liability [Abstract] | ||
Gross liability | $ 0 | $ 0 |
Derivative Instruments and He92
Derivative Instruments and Hedging Activities, Amounts Included in OCI, Income and AOCI (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) reclassified from OCI into income (effective portion) | $ 54.8 | $ (6.6) | $ 15.1 | |
Net gains on commodity hedges recorded in OCI that are expected to be reclassified to revenue within twelve months | 52.1 | |||
Interest Expense, Net [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) reclassified from OCI into income (effective portion) | 0 | (2.4) | (6.1) | |
Revenues [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) reclassified from OCI into income (effective portion) | 54.8 | (4.2) | 21.2 | |
Commodity Contracts [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Deferred gains (losses) included in accumulated OCI | [1] | 86.7 | 60.3 | |
Cash Flow Hedging [Member] | Commodity Contracts [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) recognized in OCI on derivatives (effective portion) | 81.3 | 59.8 | (5.8) | |
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Revenues [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) recognized in income on derivatives | $ (5.7) | $ (5.5) | $ (0.1) | |
[1] | Includes deferred net gains of $52.1 million as of December 31, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months. |
Fair Value Measurements, Breakd
Fair Value Measurements, Breakdown by Fair Value Hierarchy Category for Financial Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | ||
Fair Value Measurements [Abstract] | ||||
Derivatives financial instruments, fair value, net | $ 119.5 | |||
Derivative fair value of net asset if commodity price increases by 10 percent | 99.8 | |||
Derivative fair value of net asset if commodity price decreases by 10 percent | 138.1 | |||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Assets from commodity derivative contracts | 119.5 | $ 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 | 127.1 | [1] | 60.2 | |
Liability from commodity derivative contracts | 7.6 | [1] | 5.2 | |
TPL contingent consideration | [2] | 3 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Cash and cash equivalents | 135.4 | 72.3 | ||
Carrying Value [Member] | Senior Secured Revolving Credit Facility [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 280 | 0 | ||
Carrying Value [Member] | Senior Unsecured Notes [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 4,884 | 2,783.4 | ||
Carrying Value [Member] | Accounts Receivable Securitization Facility [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 219.3 | 182.8 | ||
Fair Value [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Assets from commodity derivative contracts | 127.1 | [1] | 60.2 | |
Liability from commodity derivative contracts | 7.6 | [1] | 5.2 | |
TPL contingent consideration | [2] | 3 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Cash and cash equivalents | 135.4 | 72.3 | ||
Fair Value [Member] | Senior Secured Revolving Credit Facility [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 280 | 0 | ||
Fair Value [Member] | Senior Unsecured Notes [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 4,192 | 2,731.5 | ||
Fair Value [Member] | Accounts Receivable Securitization Facility [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Long-term debt | 219.3 | 182.8 | ||
Fair Value [Member] | Level 1 [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Assets from commodity derivative contracts | 0 | [1] | 0 | |
Liability from commodity derivative contracts | 0.3 | [1] | 0 | |
TPL contingent consideration | [2] | 0 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Cash and cash equivalents | 0 | 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 | 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 | 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 | 182.8 | ||
Fair Value [Member] | Level 2 [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Assets from commodity derivative contracts | 123.1 | [1] | 58.4 | |
Liability from commodity derivative contracts | 7 | [1] | 5.1 | |
TPL contingent consideration | [2] | 0 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Cash and cash equivalents | 0 | 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 | 280 | 0 | ||
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 | 4,192 | 2,731.5 | ||
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 | 219.3 | 0 | ||
Fair Value [Member] | Level 3 [Member] | ||||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract] | ||||
Assets from commodity derivative contracts | 4 | [1] | 1.8 | |
Liability from commodity derivative contracts | 0.3 | [1] | 0.1 | |
TPL contingent consideration | [2] | 3 | ||
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract] | ||||
Cash and cash equivalents | 0 | 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 | 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 | 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 | $ 0 | ||
[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. |
Fair Value Measurements, Change
Fair Value Measurements, Changes in Fair Value of Financial Instruments Classified as Level 3 (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015USD ($)Swap | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Fair Value Measurements [Abstract] | |||
Number of natural gas basis swaps categorized as Level 3 | Swap | 14 | ||
Contingent Liability [Member] | |||
Changes in fair value of financial instruments classified as Level 3 in the fair value hierarchy [Roll Forward] | |||
Balance, beginning of period | $ 0 | $ 0 | $ 15.3 |
Settlements included in Revenue | 0 | 0 | |
TPL contingent consideration fair value at acquisition date (see Note 4-Business Acquisitions) | 4.2 | ||
Change in valuation of contingent liability included in Other Income | (1.2) | (15.3) | |
Unrealized losses included in OCI | 0 | ||
New Level 3 instruments | 0 | ||
Transfers out of Level 3 | 0 | 0 | |
Balance, end of period | 3 | 0 | 0 |
Commodity Derivative Contracts (Asset)/Liability [Member] | |||
Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] | |||
Balance, beginning of period | (1.7) | (0.7) | 0.6 |
Settlements included in Revenue | (0.2) | (1.3) | |
Unrealized losses included in OCI | (1.1) | ||
New Level 3 instruments | (3.7) | ||
Transfers out of Level 3 | 1.7 | 0.3 | |
Balance, end of period | $ (3.7) | $ (1.7) | $ (0.7) |
Related Party Transactions (Det
Related Party Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Summary of transactions with Targa [Abstract] | |||
Cash contributions from Targa to maintain its 2% general partner ownership | $ 60.1 | $ 7.7 | $ 10.8 |
General partner interest | 2.00% | 2.00% | |
Targa Resources Corp. [Member] | |||
Summary of transactions with Targa [Abstract] | |||
Targa billings of payroll and related costs included in operating expense | $ 153.8 | $ 124.9 | 109.7 |
Targa allocation of general and administrative expense | 136.2 | 129.4 | 134.3 |
Cash distributions to Targa based on IDR and unit ownership | 233.4 | 180.7 | 138.2 |
Cash contributions from Targa to maintain its 2% general partner ownership | $ 60.1 | 7.7 | 10.8 |
General partner interest | 2.00% | ||
GCF [Member] | |||
Summary of transactions with Targa [Abstract] | |||
Revenues from transactions with related party | $ 0.5 | 0.8 | 0.4 |
Costs and expenses from transactions with related party | 5.8 | $ 7.6 | $ 6.3 |
T2 Eagle Ford [Member] | |||
Summary of transactions with Targa [Abstract] | |||
Costs and expenses from transactions with related party | 2.8 | ||
Payable to related party | 1.8 | ||
T2 La Salle [Member] | |||
Summary of transactions with Targa [Abstract] | |||
Costs and expenses from transactions with related party | $ 1.1 |
Commitments (Leases) (Details)
Commitments (Leases) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Future lease obligations in aggregate and for each of the next five fiscal years [Abstract] | ||||
In Aggregate | $ 53.1 | |||
2,016 | 18.4 | |||
2,017 | 13.1 | |||
2,018 | 11 | |||
2,019 | 5.8 | |||
2,020 | 4.8 | |||
Operating Leases [Member] | ||||
Future lease obligations in aggregate and for each of the next five fiscal years [Abstract] | ||||
In Aggregate | [1] | 42.1 | ||
2,016 | [1] | 16 | ||
2,017 | [1] | 10.8 | ||
2,018 | [1] | 8.8 | ||
2,019 | [1] | 3.7 | ||
2,020 | [1] | 2.8 | ||
Total expenses on lease obligations | [2] | 40.4 | $ 24.4 | $ 23.3 |
Land Site Lease and Right-of-Way [Member] | ||||
Future lease obligations in aggregate and for each of the next five fiscal years [Abstract] | ||||
In Aggregate | [3] | 11 | ||
2,016 | [3] | 2.4 | ||
2,017 | [3] | 2.3 | ||
2,018 | [3] | 2.2 | ||
2,019 | [3] | 2.1 | ||
2,020 | [3] | 2 | ||
Total expenses on lease obligations | $ 4.2 | $ 4.1 | $ 3.6 | |
[1] | Includes minimum payments on lease obligations for office space, railcars and tractors. | |||
[2] | Includes short-term leases for items such as compressors and equipment. | |||
[3] | Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates, with varying terms, some of which are perpetual. |
Contingencies (Details)
Contingencies (Details) | Jan. 06, 2016PlaintiffLawsuit | Dec. 16, 2015Plaintiff | Nov. 04, 2015USD ($) | Jun. 18, 2015USD ($) | Nov. 30, 2014Plaintiff | Dec. 31, 2014Plaintiff | Dec. 31, 2015ThermalOxidizers |
State Court Lawsuit [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Number of plaintiffs | Plaintiff | 2 | ||||||
Federal Court Lawsuits [Member] | Subsequent Event [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Number of plaintiffs | Plaintiff | 2 | ||||||
Number of putative class action lawsuits filed | Lawsuit | 2 | ||||||
Atlas Unitholder Litigation [Member] | Atlas Pipeline Partners [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Number of plaintiffs | Plaintiff | 5 | ||||||
Atlas Unitholder Litigation [Member] | Atlas Energy [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Number of plaintiffs | Plaintiff | 2 | ||||||
Environment Proceeding [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Number of regenerative thermal oxidizers | ThermalOxidizers | 2 | ||||||
Contingencies penalty amount | $ | $ 115,644 | ||||||
Period within which to install a flare gas recovery unit at Mont Belvieu Fractionator | 1 year | ||||||
Environment Proceeding [Member] | Minimum [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Litigation settlement amount | $ | $ 100,000 | ||||||
Environment Proceeding [Member] | Maximum [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Litigation settlement amount | $ | $ 300,000 | ||||||
Environment Proceeding [Member] | Supplemental Environmental Projects [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Contingencies penalty amount | $ | $ 115,643 | ||||||
Environment Proceeding [Member] | Versado Gas Processors LLC [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Ownership interest in joint venture | 63.00% |
Income Tax (Details)
Income Tax (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Provision for Income Taxes [Abstract] | |||
Current expense | $ 0.8 | $ 3.2 | $ 2 |
Deferred expense (benefit) | (0.2) | 1.6 | 0.9 |
Total income tax expense (benefit) | 0.6 | 4.8 | $ 2.9 |
Deferred tax assets [Abstract] | |||
Net operating loss carryforwards | 19.8 | 0 | |
Deferred tax liabilities [Abstract] | |||
Property, plant, and equipment | (47) | (13.7) | |
Net deferred tax asset/(liability) | $ (27.2) | $ (13.7) | |
Texas margin tax rate | 0.75% | ||
TPL Arkoma, Inc. [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Net operating loss carryforwards | $ 51.3 | ||
TPL Arkoma, Inc. [Member] | Minimum [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Operating loss carryforwards expiry date | Dec. 31, 2029 | ||
TPL Arkoma, Inc. [Member] | Maximum [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Operating loss carryforwards expiry date | Dec. 31, 2035 |
Significant Risks and Uncerta99
Significant Risks and Uncertainties (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Significant Risks and Uncertainties [Abstract] | |||
Reduction of maximum loss due to counterparty credit risk by master netting provision | $ 7.6 | ||
Potential minimum loss attributable to individual counterparties | 0.4 | ||
Potential maximum loss attributable to individual counterparties | 38.9 | ||
Allowance for Bad Debts [Member] | |||
Summary of activity affecting allowance for bad debts [Roll Forward] | |||
Balance at beginning of year | 0 | $ 0.9 | $ 0.7 |
Additions | 0.1 | 0 | 0.2 |
Deductions | (0.9) | 0 | |
Balance at end of year | $ 0.1 | $ 0 | $ 0.9 |
Supplier Concentration Risk [Member] | Consolidated Purchases [Member] | ONEOK Hydrocarbon LP [Member] | |||
Concentration Risk [Line Items] | |||
Concentration risk percentage | 12.00% |
Other Operating (Income) Exp100
Other Operating (Income) Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Operating (Income) Expense [Abstract] | |||
Loss (gain) on sale or disposal of assets | $ (8) | $ (4.8) | $ 3.9 |
Casualty (gain) loss | (0.2) | 0.1 | 4.3 |
Miscellaneous business tax | 0.5 | 0.4 | 0.7 |
Other | 0.6 | 1.3 | 0.7 |
Total other operating (income) expense | $ (7.1) | $ (3) | $ 9.6 |
Supplemental Cash Flow Infor101
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | Feb. 27, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash [Abstract] | |||||
Interest paid, net of capitalized interest | [1] | $ 193.1 | $ 131 | $ 119.1 | |
Income taxes paid, net of refunds | 3.4 | 2.7 | 2.3 | ||
Non-cash investing activities [Abstract] | |||||
Deadstock commodity inventory transferred to property, plant and equipment | 1.2 | 14.8 | 30.4 | ||
Impact of capital expenditure accruals on property, plant and equipment | 43.8 | 19 | (0.4) | ||
Transfers from materials and supplies inventory to property, plant and equipment | 3.7 | 4.6 | 20.5 | ||
Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate | 3.8 | 2.1 | 1.4 | ||
Property, plant and equipment in consideration of contract amendment | [2] | 22.6 | 0 | 0 | |
Non-cash financing activities [Abstract] | |||||
Debt additions and retirements related to exchange of TRP 6.625% Notes for APL 6.625% Notes | 342.1 | 0 | 0 | ||
Reductions in Owner's Equity related to accrued distributions on unvested equity awards under share compensation arrangements | 1.6 | 1.4 | 1.7 | ||
Receivables from equity issuances | 0 | 1 | 0 | ||
Accrued distributions of preferred unit | 0.9 | 0 | 0 | ||
Non-cash balance sheet movements related to business acquisition: (see Note 4) [Abstract] | |||||
Non-cash merger consideration - common units and replacement equity awards | 2,583.5 | 0 | 0 | ||
Special GP Interest | 1,612.4 | 0 | 0 | ||
Current liabilities retained by Targa | (0.4) | 0 | 0 | ||
Net non-cash balance sheet movements excluded from consolidated statements of cash flows | 4,195.5 | 0 | 0 | ||
Net cash merger consideration included in investing activities | 828.7 | 0 | 0 | ||
Total fair value of consideration transferred | 5,024.2 | 0 | 0 | ||
Interest capitalized on major projects | $ 13.2 | $ 16.1 | $ 28 | ||
Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate percentage | 6.625% | ||||
Atlas Pipeline Partners [Member] | |||||
Non-cash balance sheet movements related to business acquisition: (see Note 4) [Abstract] | |||||
Net cash merger consideration included in investing activities | [3] | $ 828.7 | |||
Atlas Pipeline Partners [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate percentage | 6.625% | ||||
[1] | Interest capitalized on major projects was $13.2 million, $16.1 million and $28.0 million for 2015, 2014 and 2013. | ||||
[2] | We measured the estimated fair value of the assets transferred to us using significant other observable inputs representative of a Level 2 fair value measurement. | ||||
[3] | We acquired $35.3 million of cash. |
Compensation Plans, Partnership
Compensation Plans, Partnership Performance Units and Phantom Units (Details) - $ / shares | Jan. 15, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Phantom Units [Member] | ||||
Nonvested, number of units [Roll Forward] | ||||
Granted (in shares) | 25,162 | |||
Forfeited (in shares) | 0 | |||
Weighted-average grant-date fair value [Roll Forward] | ||||
Granted (in dollars per share) | $ 36.87 | |||
Replacement Phantom Units [Member] | ||||
Nonvested, number of units [Roll Forward] | ||||
Outstanding, beginning of period (in shares) | 0 | |||
Granted (in shares) | 629,231 | |||
Vested (in shares) | (224,021) | |||
Forfeited (in shares) | (49,852) | |||
Outstanding, end of period (in shares) | 355,358 | 0 | ||
Weighted-average grant-date fair value [Roll Forward] | ||||
Outstanding, beginning of period (in dollars per share) | $ 0 | |||
Granted (in dollars per share) | 43.82 | |||
Vested (in dollars per share) | 43.82 | |||
Forfeited (in dollars per share) | 43.82 | |||
Outstanding, end of period (in dollars per share) | $ 43.82 | $ 0 | ||
Dividend payment period | 60 days | |||
Replacement Phantom Units [Member] | Subsequent Event [Member] | ||||
Nonvested, number of units [Roll Forward] | ||||
Vested (in shares) | (3,405) | |||
Weighted-average grant-date fair value [Roll Forward] | ||||
Treasury units repurchased (in shares) | 1,289 | |||
Unit repurchase price (in dollars per share) | $ 10.65 | |||
Replacement Phantom Units [Member] | Vesting Term One [Member] | ||||
Weighted-average grant-date fair value [Roll Forward] | ||||
Vesting period of original term | 4 years | |||
Vesting percentage original term | 25.00% | |||
Replacement Phantom Units [Member] | Vesting Term Two [Member] | ||||
Weighted-average grant-date fair value [Roll Forward] | ||||
Vesting period of original term | 3 years | |||
Vesting percentage original term | 33.00% | |||
Partnership Long-term Incentive Plan [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Total number of units authorized (in shares) | 1,680,000 | |||
Partnership Long-term Incentive Plan [Member] | Performance Units [Member] | Award Granted in December 2013 [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Performance period | 3 years | |||
Partnership Long-term Incentive Plan [Member] | Performance Units [Member] | Award Granted in December 2013 [Member] | Vesting Term One [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Performance period | 2 years | |||
Partnership Long-term Incentive Plan [Member] | Performance Units [Member] | Award Granted in December 2013 [Member] | Vesting Term Two [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Performance period | 3 years | |||
Partnership Long-term Incentive Plan [Member] | Performance Units [Member] | Award Granted in December 2013 [Member] | Vesting Term Three [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Performance period | 4 years | |||
Partnership Long-term Incentive Plan [Member] | Equity-Settled Performance Units [Member] | ||||
Nonvested, number of units [Roll Forward] | ||||
Outstanding, beginning of period (in shares) | 577,403 | 552,198 | 307,620 | |
Granted (in shares) | 277,242 | 168,495 | 244,578 | |
Vested (in shares) | (178,900) | (137,170) | ||
Forfeited (in shares) | (6,120) | |||
Outstanding, end of period (in shares) | 675,745 | 577,403 | 552,198 | |
Weighted-average grant-date fair value [Roll Forward] | ||||
Outstanding, beginning of period (in dollars per share) | $ 48.26 | $ 42.01 | $ 38.40 | |
Granted (in dollars per share) | 34.48 | 57.19 | 46.54 | |
Vested (in dollars per share) | 41.92 | 34.02 | ||
Forfeited (in dollars per share) | 49.39 | |||
Outstanding, end of period (in dollars per share) | $ 44.29 | $ 48.26 | $ 42.01 | |
Partnership Long-term Incentive Plan [Member] | Equity-Settled Phantom Units [Member] | Minimum [Member] | ||||
Weighted-average grant-date fair value [Roll Forward] | ||||
Vesting period of original term | 1 year | |||
Partnership Long-term Incentive Plan [Member] | Equity-Settled Phantom Units [Member] | Maximum [Member] | ||||
Weighted-average grant-date fair value [Roll Forward] | ||||
Vesting period of original term | 5 years |
Compensation Plans, Partners103
Compensation Plans, Partnership Director Grants (Details) - Director Grants [Member] - $ / shares | Jan. 19, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Partnership Long-term Incentive Plan [Member] | Non-Management Directors [Member] | Subsequent Event [Member] | ||||
Nonvested, number of units [Roll Forward] | ||||
Granted (in shares) | 26,792 | |||
Director Grants and Incentive Plan [Member] | ||||
Nonvested, number of units [Roll Forward] | ||||
Outstanding, beginning of period (in shares) | 0 | 0 | 4,500 | |
Granted (in shares) | 10,565 | 8,740 | 12,780 | |
Vested (in shares) | (10,565) | (8,740) | (17,280) | |
Outstanding, end of period (in shares) | 0 | 0 | 0 | |
Weighted-average grant-date fair value [Roll Forward] | ||||
Outstanding, beginning of period (in dollars per share) | $ 0 | $ 0 | $ 23.51 | |
Granted (in dollars per share) | 44.67 | 50.29 | 39.33 | |
Vested (in dollars per share) | 44.67 | 50.29 | 35.21 | |
Outstanding, end of period (in dollars per share) | $ 0 | $ 0 | $ 0 |
Compensation Plans, TRC LTIP Ca
Compensation Plans, TRC LTIP Cash-Settled Performance Units (Details) - Cash-Settled Performance Units [Member] | 12 Months Ended |
Dec. 31, 2015USD ($)shares | |
Nonvested, number of units [Roll Forward] | |
Outstanding, beginning of period (in shares) | 402,930 |
Granted (in shares) | 198,280 |
Vested and paid (in shares) | (138,460) |
Forfeited (in shares) | (10,760) |
Outstanding, end of period (in shares) | 451,990 |
Calculated fair market value as of period end | $ | $ 2,645,093 |
Current liability | $ | 511,247 |
Long-term liability | $ | 402,386 |
Liability as of year end | $ | 913,633 |
To be recognized in future periods | $ | $ 1,731,460 |
Weighted average recognition period for unrecognized compensation cost | 2 years 3 months 18 days |
2012 Long Term Incentive Plan [Member] | |
Nonvested, number of units [Roll Forward] | |
Outstanding, beginning of period (in shares) | 138,460 |
Granted (in shares) | 0 |
Vested and paid (in shares) | (138,460) |
Forfeited (in shares) | 0 |
Outstanding, end of period (in shares) | 0 |
2013 Long Term Incentive Plan [Member] | |
Nonvested, number of units [Roll Forward] | |
Outstanding, beginning of period (in shares) | 142,110 |
Granted (in shares) | 0 |
Vested and paid (in shares) | 0 |
Forfeited (in shares) | (2,410) |
Outstanding, end of period (in shares) | 139,700 |
Calculated fair market value as of period end | $ | $ 622,496 |
Current liability | $ | 511,247 |
Long-term liability | $ | 0 |
Liability as of year end | $ | 511,247 |
To be recognized in future periods | $ | $ 111,249 |
Vesting date | Jun. 1, 2016 |
2014 Long Term Incentive Plan [Member] | |
Nonvested, number of units [Roll Forward] | |
Outstanding, beginning of period (in shares) | 122,360 |
Granted (in shares) | 0 |
Vested and paid (in shares) | 0 |
Forfeited (in shares) | (2,460) |
Outstanding, end of period (in shares) | 119,900 |
Calculated fair market value as of period end | $ | $ 359,684 |
Current liability | $ | 0 |
Long-term liability | $ | 172,926 |
Liability as of year end | $ | 172,926 |
To be recognized in future periods | $ | $ 186,758 |
Vesting date | Jun. 1, 2017 |
2015 Long Term Incentive Plan [Member] | |
Nonvested, number of units [Roll Forward] | |
Outstanding, beginning of period (in shares) | 0 |
Granted (in shares) | 198,280 |
Vested and paid (in shares) | 0 |
Forfeited (in shares) | (5,890) |
Outstanding, end of period (in shares) | 192,390 |
Calculated fair market value as of period end | $ | $ 1,662,913 |
Current liability | $ | 0 |
Long-term liability | $ | 229,460 |
Liability as of year end | $ | 229,460 |
To be recognized in future periods | $ | $ 1,433,453 |
Vesting date | Jun. 1, 2018 |
Compensation Plans, 2010 TRC St
Compensation Plans, 2010 TRC Stock Incentive Plan (Details) - $ / shares | Jan. 15, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Restricted Stock Units (RSUs) [Member] | |||||||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Vesting period of awards | 4 years | ||||||
Dividend payment period | 60 days | ||||||
Restricted Stock Units (RSUs) [Member] | Vesting Term One [Member] | |||||||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Vesting percentage original term | 25.00% | ||||||
Restricted Stock Units (RSUs) [Member] | Vesting Term Two [Member] | |||||||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Vesting percentage original term | 25.00% | ||||||
Restricted Stock Units (RSUs) [Member] | Vesting Term Three [Member] | |||||||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Vesting percentage original term | 75.00% | ||||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Total units authorized (in shares) | 5,000,000 | ||||||
Nonvested, number of shares [Roll Forward] | |||||||
Outstanding, beginning of period (in shares) | 119,193 | 203,973 | 711,030 | ||||
Granted (in shares) | [1] | 30,623 | |||||
Forfeited (in shares) | (1,980) | (2,740) | |||||
Vested (in shares) | (88,570) | (82,800) | (534,940) | [2] | |||
Outstanding, end of period (in shares) | 30,623 | 119,193 | 203,973 | 711,030 | |||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Outstanding, beginning of period (in dollars per share) | $ 46.35 | $ 41.05 | $ 25.95 | ||||
Granted (in dollars per share) | [1] | 57.59 | |||||
Forfeited (in dollars per share) | 42.82 | 27.28 | |||||
Vested (in dollars per share) | 42.46 | 33.37 | 22 | [2] | |||
Outstanding, end of period (in dollars per share) | $ 57.59 | $ 46.35 | $ 41.05 | $ 25.95 | |||
Vesting period of awards | 3 years | ||||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock [Member] | Subsequent Event [Member] | |||||||
Nonvested, number of shares [Roll Forward] | |||||||
Granted (in shares) | 440,163 | ||||||
2010 TRC Stock Incentive Plan [Member] | Replacement Restricted Stock Units (RSUs) [Member] | |||||||
Nonvested, number of shares [Roll Forward] | |||||||
Outstanding, beginning of period (in shares) | 0 | ||||||
Granted (in shares) | 81,740 | ||||||
Forfeited (in shares) | (1,556) | ||||||
Vested (in shares) | (41,539) | ||||||
Outstanding, end of period (in shares) | 38,645 | 0 | |||||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Outstanding, beginning of period (in dollars per share) | $ 0 | ||||||
Granted (in dollars per share) | 99.58 | ||||||
Forfeited (in dollars per share) | 99.58 | ||||||
Vested (in dollars per share) | 99.58 | ||||||
Outstanding, end of period (in dollars per share) | $ 99.58 | $ 0 | |||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | |||||||
Nonvested, number of shares [Roll Forward] | |||||||
Outstanding, beginning of period (in shares) | 108,367 | 55,550 | 0 | ||||
Granted (in shares) | 140,477 | 54,357 | 55,790 | ||||
Forfeited (in shares) | (2,530) | (1,440) | (240) | ||||
Vested (in shares) | (2,220) | (100) | |||||
Outstanding, end of period (in shares) | 244,094 | 108,367 | 55,550 | 0 | |||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Outstanding, beginning of period (in dollars per share) | $ 91.41 | $ 69.92 | $ 0 | ||||
Granted (in dollars per share) | 83.54 | 112.89 | 69.90 | ||||
Forfeited (in dollars per share) | 86.73 | 75.81 | 67.07 | ||||
Vested (in dollars per share) | 81.56 | 67.07 | |||||
Outstanding, end of period (in dollars per share) | $ 87.02 | $ 91.41 | $ 69.92 | $ 0 | |||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Minimum [Member] | |||||||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Vesting period of awards | 1 year | ||||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Maximum [Member] | |||||||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Vesting period of awards | 5 years | ||||||
2010 TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member] | |||||||
Nonvested, number of shares [Roll Forward] | |||||||
Granted (in shares) | 29,123 | ||||||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Stock repurchased from employees (in shares) | 6,861 | ||||||
Stock repurchase price (in dollars per share) | $ 17.04 | ||||||
2010 TRC Stock Incentive Plan [Member] | IPO Stock Awards [Member] | Stock Awards Vesting over 24 Months [Member] | |||||||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Award vesting percentage | 40.00% | ||||||
2010 TRC Stock Incentive Plan [Member] | IPO Stock Awards [Member] | Stock Awards Vesting in Three Years [Member] | |||||||
Weighted-average grant-date fair value [Roll Forward] | |||||||
Award vesting percentage | 60.00% | ||||||
[1] | These awards will cliff vest at the end of three years. | ||||||
[2] | Awards vested in 2013 were 60% of the awards issued in conjunction with the Targa IPO, net of forfeitures. 40% of the awards vested prior to 2013. |
Compensation Plans, Compensatio
Compensation Plans, Compensation Expenses and Fair Value of Share-Based Awards (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Cash-Settled Performance Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
To be recognized in future periods | $ 1,731,460 | |||
Weighted average recognition period for unrecognized compensation cost | 2 years 3 months 18 days | |||
Accrued Dividends Settled [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Fair value of units vested during the period | $ 200,000 | $ 500,000 | $ 2,400,000 | |
Partnership Long-term Incentive Plan [Member] | Equity-Settled Performance Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expenses recognized | 9,500,000 | 8,800,000 | 5,500,000 | |
To be recognized in future periods | $ 13,300,000 | |||
Weighted average recognition period for unrecognized compensation cost | 1 year 10 months 24 days | |||
Fair value of units vested during the period | $ 7,900,000 | 10,000,000 | 0 | |
Partnership Long-term Incentive Plan [Member] | Equity-Settled Phantom Units - Replacement Phantom Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expenses recognized | 6,400,000 | 0 | 0 | |
To be recognized in future periods | $ 5,800,000 | |||
Weighted average recognition period for unrecognized compensation cost | 1 year 3 months 18 days | |||
Fair value of units vested during the period | $ 8,800,000 | 0 | 0 | |
Partnership Long-term Incentive Plan [Member] | Equity-Settled Phantom Units - Phantom Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expenses recognized | 200,000 | 0 | 0 | |
To be recognized in future periods | $ 800,000 | |||
Weighted average recognition period for unrecognized compensation cost | 3 years 3 months 18 days | |||
Partnership Long-term Incentive Plan [Member] | Director Grants [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expenses recognized | $ 500,000 | 400,000 | 500,000 | |
Fair value of units vested during the period | 500,000 | 400,000 | 700,000 | |
2010 TRC Stock Incentive Plan [Member] | Restricted Stock [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expenses recognized | 1,100,000 | 2,200,000 | 6,300,000 | |
To be recognized in future periods | $ 0 | |||
Weighted average recognition period for unrecognized compensation cost | 1 month 6 days | |||
Fair value of units vested during the period | [1] | $ 7,300,000 | 7,100,000 | 42,200,000 |
Recognized tax benefits | 1,100,000 | 1,000,000 | 1,600,000 | |
2010 TRC Stock Incentive Plan [Member] | Equity Settled (RSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expenses recognized | 5,400,000 | 2,500,000 | 400,000 | |
To be recognized in future periods | $ 13,100,000 | |||
Weighted average recognition period for unrecognized compensation cost | 2 years 3 months 18 days | |||
2010 TRC Stock Incentive Plan [Member] | Equity Settled Replacement (RSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expenses recognized | $ 1,300,000 | 0 | 0 | |
To be recognized in future periods | $ 1,500,000 | |||
Weighted average recognition period for unrecognized compensation cost | 1 year 4 months 24 days | |||
Fair value of units vested during the period | $ 3,800,000 | 0 | 0 | |
TRC Long-term Incentive Plan [Member] | Cash-Settled Performance Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Compensation expenses recognized | (2,200,000) | 11,000,000 | 21,900,000 | |
Fair value of units vested during the period | 7,800,000 | 14,700,000 | 25,200,000 | |
Accrued Distribution Equivalent Rights Settled [Member] | Equity-Settled Performance Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Fair value of units vested during the period | 1,700,000 | 1,600,000 | 0 | |
Accrued Distribution Equivalent Rights Settled [Member] | Equity-Settled Phantom Units - Replacement Phantom Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Fair value of units vested during the period | $ 1,100,000 | $ 0 | $ 0 | |
[1] | Targa recognized $1.1 million, $1.0 million and $1.6 million in tax benefits associated with the vesting of the restricted stock for 2015, 2014 and 2013. |
Compensation Plans, 401(k) Plan
Compensation Plans, 401(k) Plan (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
401(k) Plan [Abstract] | |||
Employer matching contribution percent | 100.00% | ||
Percentage of employees' gross pay for which employer contributes matching contribution | 5.00% | ||
Percentage of additional contribution per employee made by employer | 3.00% | ||
Percentage of contributions made in cash | 100.00% | ||
Contributions to defined contribution plan | $ 13.8 | $ 10.5 | $ 9.6 |
Segment Information, Revenues a
Segment Information, Revenues and Operating Margin (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)DivisionSegment | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Segment Reporting Information [Line Items] | |||||||||||
Number of divisions | Division | 2 | ||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | $ 5,465.4 | $ 7,595.2 | $ 5,728.2 | ||||||||
Fees from midstream services | 1,193.2 | 1,021.3 | 586.7 | ||||||||
Revenues | $ 1,647.4 | $ 1,632.1 | $ 1,699.4 | $ 1,679.7 | $ 2,032.9 | $ 2,288.3 | $ 2,000.6 | $ 2,294.7 | 6,658.6 | 8,616.5 | 6,314.9 |
Operating margin | $ 1,281 | 1,136.6 | 801.5 | ||||||||
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] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | $ 2,580 | 1,884.1 | 1,525 | ||||||||
Operating margin | 484.8 | 372.3 | 270.5 | ||||||||
Coastal Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 467.5 | 967 | 981.8 | ||||||||
Operating margin | $ 30.3 | 77.6 | 85.4 | ||||||||
Logistics and Marketing [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Number of reportable segments per division | Segment | 2 | ||||||||||
Logistics Assets [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | $ 707.9 | 705.4 | 536.9 | ||||||||
Operating margin | 439.5 | 445.1 | 282.3 | ||||||||
Marketing and Distribution [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 4,537.4 | 7,971.5 | 5,804.1 | ||||||||
Operating margin | 242.2 | 249.6 | 141.9 | ||||||||
Other [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | 84.2 | (8) | 21.4 | ||||||||
Operating margin | 84.2 | (8) | 21.4 | ||||||||
Corporate and Elimination [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Revenues | (1,718.4) | (2,903.5) | (2,554.3) | ||||||||
Operating margin | 0 | 0 | 0 | ||||||||
Operating Segments [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 1,283 | 197.4 | 188.8 | ||||||||
Fees from midstream services | 394.3 | 190.3 | 113.9 | ||||||||
Revenues | 1,677.3 | 387.7 | 302.7 | ||||||||
Operating Segments [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 202.4 | 355 | 305 | ||||||||
Fees from midstream services | 32.8 | 34.4 | 33.6 | ||||||||
Revenues | 235.2 | 389.4 | 338.6 | ||||||||
Operating Segments [Member] | Logistics Assets [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 104.4 | 99.1 | 140.5 | ||||||||
Fees from midstream services | 330.2 | 293.6 | 216 | ||||||||
Revenues | 434.6 | 392.7 | 356.5 | ||||||||
Operating Segments [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 3,791.4 | 6,951.7 | 5,072.4 | ||||||||
Fees from midstream services | 435.9 | 503 | 223.3 | ||||||||
Revenues | 4,227.3 | 7,454.7 | 5,295.7 | ||||||||
Operating Segments [Member] | Other [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 84.2 | (8) | 21.4 | ||||||||
Fees from midstream services | 0 | 0 | 0 | ||||||||
Revenues | 84.2 | (8) | 21.4 | ||||||||
Operating Segments [Member] | Corporate and Elimination [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 0 | 0 | 0.1 | ||||||||
Fees from midstream services | 0 | 0 | (0.1) | ||||||||
Revenues | 0 | 0 | 0 | ||||||||
Intersegment Eliminations [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 0 | 0 | 0 | ||||||||
Fees from midstream services | 0 | 0 | 0 | ||||||||
Revenues | 0 | 0 | 0 | ||||||||
Intersegment Eliminations [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 894 | 1,491.2 | 1,218.9 | ||||||||
Fees from midstream services | 8.7 | 5.2 | 3.4 | ||||||||
Revenues | 902.7 | 1,496.4 | 1,222.3 | ||||||||
Intersegment Eliminations [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 232.3 | 577.6 | 642.2 | ||||||||
Fees from midstream services | 0 | 0 | 1 | ||||||||
Revenues | 232.3 | 577.6 | 643.2 | ||||||||
Intersegment Eliminations [Member] | Logistics Assets [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 9.1 | 4.4 | 3.9 | ||||||||
Fees from midstream services | 264.2 | 308.3 | 176.5 | ||||||||
Revenues | 273.3 | 312.7 | 180.4 | ||||||||
Intersegment Eliminations [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 290.6 | 486.7 | 478.6 | ||||||||
Fees from midstream services | 19.5 | 30.1 | 29.8 | ||||||||
Revenues | 310.1 | 516.8 | 508.4 | ||||||||
Intersegment Eliminations [Member] | Other [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | 0 | 0 | 0 | ||||||||
Fees from midstream services | 0 | 0 | 0 | ||||||||
Revenues | 0 | 0 | 0 | ||||||||
Intersegment Eliminations [Member] | Corporate and Elimination [Member] | |||||||||||
Revenues [Abstract] | |||||||||||
Sales of commodities | (1,426) | (2,559.9) | (2,343.6) | ||||||||
Fees from midstream services | (292.4) | (343.6) | (210.7) | ||||||||
Revenues | $ (1,718.4) | $ (2,903.5) | $ (2,554.3) |
Segment Information, Other Fina
Segment Information, Other Financial Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||||||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Feb. 27, 2015 | |||
Other financial information [Abstract] | |||||||||
Total assets | $ 13,165 | [1] | $ 6,377.2 | $ 5,971.4 | |||||
Goodwill | 417 | [2] | 0 | $ 707 | $ 707 | $ 707 | $ 707 | ||
Capital expenditures | 777.2 | 747.8 | 1,034.5 | ||||||
Business acquisition | 5,024.2 | $ 5,024.2 | |||||||
Operating Segments [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 9,892.3 | [1] | 3,409 | 3,200.7 | |||||
Goodwill | [2] | 417 | |||||||
Capital expenditures | 481.5 | 423.1 | 557.8 | ||||||
Business acquisition | 5,024.2 | ||||||||
Operating Segments [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 290.2 | [1] | 367.2 | 383.8 | |||||
Goodwill | [2] | 0 | |||||||
Capital expenditures | 14.8 | 14 | 20.6 | ||||||
Business acquisition | 0 | ||||||||
Operating Segments [Member] | Logistics Assets [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 1,912.2 | [1] | 1,717.3 | 1,503.6 | |||||
Goodwill | [2] | 0 | |||||||
Capital expenditures | 257.6 | 274.4 | 444.7 | ||||||
Business acquisition | 0 | ||||||||
Operating Segments [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 605.5 | [1] | 708.5 | 756.1 | |||||
Goodwill | [2] | 0 | |||||||
Capital expenditures | 14.4 | 30.2 | 6.3 | ||||||
Business acquisition | 0 | ||||||||
Operating Segments [Member] | Other [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 127.1 | [1] | 60.2 | 5.1 | |||||
Goodwill | [2] | 0 | |||||||
Capital expenditures | 0 | 0 | 0 | ||||||
Business acquisition | 0 | ||||||||
Operating Segments [Member] | Corporate and Elimination [Member] | |||||||||
Other financial information [Abstract] | |||||||||
Total assets | 337.7 | [1] | 115 | 122.1 | |||||
Goodwill | [2] | 0 | |||||||
Capital expenditures | 8.9 | $ 6.1 | $ 5.1 | ||||||
Business acquisition | $ 0 | ||||||||
[1] | Corporate assets at the Segment level primarily include investments in unconsolidated subsidiaries and debt issuance cost associated with our debt obligations | ||||||||
[2] | Total assets include goodwill. Goodwill has been attributed to our Field Gathering and Processing segment - See Note 4 - Business Acquisitions. |
Segment Information, Revenues b
Segment Information, Revenues by Product and Service (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | $ 5,465.4 | $ 7,595.2 | $ 5,728.2 | ||||||||
Fees from midstream services | 1,193.2 | 1,021.3 | 586.7 | ||||||||
Total revenues | $ 1,647.4 | $ 1,632.1 | $ 1,699.4 | $ 1,679.7 | $ 2,032.9 | $ 2,288.3 | $ 2,000.6 | $ 2,294.7 | 6,658.6 | 8,616.5 | 6,314.9 |
Natural Gas [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | 1,594.5 | 1,414.1 | 1,225 | ||||||||
NGL [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | 3,558.7 | 5,960.1 | 4,224 | ||||||||
Condensate [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | 142.4 | 134.3 | 121.8 | ||||||||
Petroleum Products [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | 101.6 | 96.3 | 136 | ||||||||
Derivative Activities [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Sales of commodities | 68.2 | (9.6) | 21.4 | ||||||||
Fractionating and Treating [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Fees from midstream services | 209 | 208.9 | 133.9 | ||||||||
Storage, Terminaling, Transportation and Export [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Fees from midstream services | 506.2 | 548.1 | 280.3 | ||||||||
Gathering and Processing [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Fees from midstream services | 393.7 | 196.9 | 114.1 | ||||||||
Other [Member] | |||||||||||
Revenue from External Customer [Line Items] | |||||||||||
Fees from midstream services | $ 84.3 | $ 67.4 | $ 58.4 |
Segment Information, Reconcilia
Segment Information, Reconciliation of Operating Margin to Net Income (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Reconciliation of operating margin to net income (loss) [Abstract] | |||||||||||
Operating margin | $ 1,281 | $ 1,136.6 | $ 801.5 | ||||||||
Depreciation and amortization expense | $ (166.7) | $ (164.9) | $ (119.6) | (677.1) | (346.5) | (271.6) | |||||
General and administrative expense | (153.6) | (139.8) | (143.1) | ||||||||
Provisional goodwill impairment | $ (290) | (290) | 0 | 0 | |||||||
Interest expense, net | (207.8) | (143.8) | (131) | ||||||||
Other, net | (11.2) | 3.4 | 5.7 | ||||||||
Income tax expense | (0.6) | (4.8) | (2.9) | ||||||||
Net income (loss) | $ (243.7) | $ 53.3 | $ 53.3 | $ 77.8 | $ 114.7 | $ 138.2 | $ 120.9 | $ 131.3 | $ (59.3) | $ 505.1 | $ 258.6 |
Selected Quarterly Financial112
Selected Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Selected Quarterly Financial Data (Unaudited) [Abstract] | |||||||||||||
Revenues | $ 1,647.4 | $ 1,632.1 | $ 1,699.4 | $ 1,679.7 | $ 2,032.9 | $ 2,288.3 | $ 2,000.6 | $ 2,294.7 | $ 6,658.6 | $ 8,616.5 | $ 6,314.9 | ||
Gross margin | 452.2 | 459.7 | 462.3 | 411.4 | 398.2 | 407.8 | 384 | 379.6 | 1,785.6 | 1,569.6 | |||
Operating income (loss) | (205.7) | [1],[2] | 117.3 | 114.8 | 141 | 168.4 | [1] | 171.4 | 152.9 | 160.6 | 167.4 | 653.3 | 377.2 |
Net income (loss) | (243.7) | 53.3 | 53.3 | 77.8 | 114.7 | 138.2 | 120.9 | 131.3 | (59.3) | 505.1 | 258.6 | ||
Net income attributable to limited partners (loss) | $ (232.6) | $ 3.6 | $ 1.2 | $ 30.3 | $ 67.7 | $ 89.7 | $ 73 | $ 88.6 | $ (197.5) | $ 319 | $ 126 | ||
Net income (loss) per limited partner unit [Abstract] | |||||||||||||
basic (in dollars per share) | $ (1.26) | $ 0.02 | $ 0.01 | $ 0.21 | $ 0.58 | $ 0.78 | $ 0.64 | $ 0.79 | $ (1.15) | $ 2.78 | $ 1.19 | ||
diluted (in dollars per share) | $ (1.26) | $ 0.02 | $ 0.01 | $ 0.21 | $ 0.58 | $ 0.78 | $ 0.64 | $ 0.78 | $ (1.15) | $ 2.77 | $ 1.19 | ||
Impairment loss | $ 32.6 | $ 3.2 | $ 32.6 | $ 3.2 | |||||||||
Goodwill impairment | $ 290 | $ 290 | $ 0 | $ 0 | |||||||||
[1] | Included $32.6 million in the fourth quarter of 2015 and $3.2 million in the fourth quarter of 2014 losses due to the impairments. See Note 6 - Property, Plant and Equipment and Intangible Assets. | ||||||||||||
[2] | Included a provisional goodwill impairment of $290.0 million in the fourth quarter of 2015. See Note 4 -Business Acquisitions. |