View Filing Data

$ 102.9

$ 81.0

Trade receivables, net of allowances of $0.0 million

621.0

567.3

Inventories

151.1

168.9

Deferred income taxes

0.0

0.1

Assets from risk management activities

92.3

44.4

Other current assets

33.8

20.9

Total current assets

1,001.1

882.6

Property, plant and equipment

11,798.4

6,521.1

Accumulated depreciation

(2,048.2)

(1,696.5)

Property, plant and equipment, net

9,750.2

4,824.6

Goodwill

551.4

^[1]

0.0

Intangible assets, net

1,695.7

591.9

Long-term assets from risk management activities

45.4

15.8

Investments in unconsolidated affiliates

264.2

50.2

Other long-term assets

110.2

88.4

Total assets

13,418.2

^[2]

6,453.5

Current liabilities:

^[3]

688.9

638.5

Deferred income taxes

33.5

0.6

Liabilities from risk management activities

4.3

5.2

Accounts receivable securitization facility

135.5

182.8

Total current liabilities

862.2

827.1

Common stock ($0.001 par value, 300,000,000 shares authorized), 56,444,353 shares issued and 56,018,925 shares outstanding as of September 30, 2015, and 42,532,353 shares issued and 42,143,463 shares outstanding as of December 31, 2014.

5,938.8

2,885.4

Long-term liabilities from risk management activities

4.0

0.0

Deferred income taxes, net

156.8

138.2

Other long-term liabilities

76.5

63.3

Contingencies (see Note 16)

Targa Resources Corp. stockholders' equity:

0.1

0.0

Preferred stock ($0.001 par value, 100,000,000 shares authorized, no shares issued and outstanding)

0.0

Additional paid-in capital

1,492.4

164.9

Retained earnings

12.6

25.5

Accumulated other comprehensive income (loss)

5.2

4.8

Treasury stock, at cost (425,428 shares as of September 30, 2015 and 388,890 as of December 31, 2014)

(28.5)

(25.4)

Total Targa Resources Corp. stockholders' equity

1,481.8

169.8

Noncontrolling interests in subsidiaries

4,898.1

2,369.7

Total owners' equity

6,379.9

2,539.5

Total liabilities and owners' equity

$ 13,418.2

$ 6,453.5

[1]	Total assets include goodwill. Goodwill has been preliminarily attributed to our Field Gathering and Processing segment.
[2]	Corporate assets at the Segment level primarily include investment in unconsolidated subsidiaries and debt issuance costs associated with Partnership's debt obligations.
[3]	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). Liabilities to creditors to whom we have issued checks that remain outstanding totaled $28.0 million and $13.6 million at September 30, 2015 and December 31, 2014 and are included above in accounts payable and accrued liabilities.

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Trade receivables, allowances	$ 0.0	$ 0.0
Owners' equity:
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	300,000,000	300,000,000
Common stock, shares issued (in shares)	56,444,353	42,532,353
Common stock, shares outstanding (in shares)	56,018,925	42,143,463
Preferred stock, par value (in dollar per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized (in shares)	100,000,000	100,000,000
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Treasury stock, shares (in shares)	425,428	388,890

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($)
shares in Millions, $ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Revenues

Sale of commodities

$ 1,321.3

$ 2,009.2

$ 4,119.6

$ 5,853.3

Fees from midstream services

310.8

279.1

891.6

730.4

Total revenues

1,632.1

2,288.3

5,011.2

6,583.7

Costs and expenses:

Product purchases

1,172.4

1,880.5

3,677.7

5,412.2

Operating expenses

133.6

112.8

381.9

323.7

165.8

87.6

448.3

253.1

General and administrative expenses

44.9

43.0

136.5

122.4

Other operating (income) expense

0.1

(4.3)

0.6

(5.3)

Income from operations

115.3

168.7

366.2

477.6

Other income (expense):

Interest expense, net

(70.4)

(36.9)

(195.6)

(106.5)

Breakdown by Fair Value Hierarchy Category for Financial Instruments Included in Consolidated Balance Sheets

(1.6)

4.7

(1.1)

13.8

Loss from financing activities

(0.5)

0.0

(13.4)

0.0

Other

2.0

(0.6)

(21.4)

(0.6)

Income before income taxes

44.8

135.9

134.7

384.3

Income tax (expense) benefit:

Current

(0.6)

(17.3)

(12.2)

(57.8)

Deferred

(23.4)

1.8

(41.9)

4.2

Income tax expense total

(24.0)

(15.5)

(54.1)

(53.6)

Net income

20.8

120.4

80.6

330.7

Less: Net income attributable to noncontrolling interests

8.1

89.7

49.2

253.9

Net income attributable to common shareholders

$ 12.7

$ 30.7

$ 31.4

$ 76.8

Net income available per common share - basic (in dollars per share)

$ 0.23

$ 0.73

$ 0.60

$ 1.83

Net income available per common share - diluted (in dollars per share)

$ 0.23

$ 0.73

$ 0.60

$ 1.82

Weighted average shares outstanding - basic (in shares)

56.0

42.0

52.6

42.0

Weighted average shares outstanding - diluted (in shares)

^[1]

56.1

42.1

52.7

42.1

[1]	For the three and nine months ended September 30, 2015, approximately 30,195 shares and 27,529 shares were excluded from the computation of diluted earnings per share because the inclusion of such shares would have been anti-dilutive.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Targa Resources Corp.
Net income attributable to common shareholders	$ 12.7	$ 30.7	$ 31.4	$ 76.8
Commodity hedging contracts:
Change in fair value, pre-tax	4.6	1.9	5.2	(0.6)
Change in fair value, related income tax	(1.7)	(0.7)	(2.0)	0.2
Change in fair value, after tax	2.9	1.2	3.2	(0.4)
Settlements reclassified to revenues, pre-tax	(1.8)	0.1	(4.5)	1.5
Settlements reclassified to revenues, related income tax	0.7	0.0	1.7	(0.5)
Settlements reclassified to revenues, after tax	(1.1)	0.1	(2.8)	1.0
Interest rate swaps:
Settlements reclassified to interest expense, net, pre-tax	0.0	0.0	0.0	0.3
Settlements reclassified to interest expense, net, related income tax	0.0	0.0	0.0	(0.1)
Settlements reclassified to interest expense, net, after tax	0.0	0.0	0.0	0.2
Other comprehensive income (loss) attributable to Targa Resources Corp., pre-tax	2.8	2.0	0.7	1.2
Other comprehensive income (loss) attributable to Targa Resources Corp., related income tax	(1.0)	(0.7)	(0.3)	(0.4)
Other comprehensive income (loss) attributable to Targa Resources Corp., after tax	1.8	1.3	0.4	0.8
Comprehensive income attributable to Targa Resources Corp.	14.5	32.0	31.8	77.6
Noncontrolling interests
Net income attributable to noncontrolling interests	8.1	89.7	49.2	253.9
Commodity hedging contracts:
Change in fair value, pre-tax	38.3	12.3	54.2	(3.9)
Change in fair value, related income tax	0.0	0.0	0.0	0.0
Change in fair value, after tax	38.3	12.3	54.2	(3.9)
Settlements reclassified to revenues, pre-tax	(14.9)	0.7	(36.6)	10.1
Settlements reclassified to revenues, related income tax	0.0	0.0	0.0	0.0
Settlements reclassified to revenues, after tax	(14.9)	0.7	(36.6)	10.1
Interest rate swaps:
Settlements reclassified to interest expense, net, pre-tax	0.0	0.0	0.0	2.1
Settlements reclassified to interest expense, net, related income tax	0.0	0.0	0.0	0.0
Settlements reclassified to interest expense, net, after tax	0.0	0.0	0.0	2.1
Other comprehensive income (loss) attributable to noncontrolling interests, pre-tax	23.4	13.0	17.6	8.3
Other comprehensive income (loss) attributable to noncontrolling interests, related income tax	0.0	0.0	0.0	0.0
Other comprehensive income (loss) attributable to noncontrolling interests, after tax	23.4	13.0	17.6	8.3
Comprehensive income attributable to noncontrolling interests	31.5	102.7	66.8	262.2
Total
Net income	20.8	120.4	80.6	330.7
Commodity hedging contracts:
Change in fair value, pre-tax	42.9	14.2	59.4	(4.5)
Change in fair value, related income tax	(1.7)	(0.7)	(2.0)	0.2
Change in fair value, after tax	41.2	13.5	57.4	(4.3)
Settlements reclassified to revenues, pre-tax	(16.7)	0.8	(41.1)	11.6
Settlements reclassified to revenues, related income tax	0.7	0.0	1.7	(0.5)
Settlements reclassified to revenues, after tax	(16.0)	0.8	(39.4)	11.1
Interest rate swap:
Settlements reclassified to interest expense, net, pre-tax	0.0	0.0	0.0	2.4
Settlements reclassified to interest expense, net, related income tax	0.0	0.0	0.0	(0.1)
Settlements reclassified to interest expense, net, after tax	0.0	0.0	0.0	2.3
Other comprehensive income (loss), pre-tax	26.2	15.0	18.3	9.5
Other comprehensive income (loss), related income tax	(1.0)	(0.7)	(0.3)	(0.4)
Other comprehensive income (loss), after tax	25.2	14.3	18.0	9.1
Total comprehensive income	$ 46.0	$ 134.7	$ 98.6	$ 339.8

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY (Unaudited) - USD ($) shares in Thousands, $ in Millions	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Shares [Member]	Noncontrolling Interests [Member]	Total
Balance at Dec. 31, 2013	$ 0.0	$ 151.6	$ 20.5	$ (0.5)	$ (22.8)	$ 1,942.5	$ 2,091.3
Balance (in shares) at Dec. 31, 2013	42,162				367
Compensation on equity grants	$ 0.0	3.8	0.0	0.0	$ 0.0	7.0	10.8
Compensation on equity grants (in shares)	0				0
Distribution equivalent rights	$ 0.0	0.0	0.0	0.0	$ 0.0	(2.0)	(2.0)
Shares issued under compensation program	$ 0.0	0.0	0.0	0.0	$ 0.0	0.0	0.0
Shares issued under compensation program (in shares)	3				0
Repurchase of common stock	$ 0.0	0.0	0.0	0.0	$ 0.0	0.0	0.0
Repurchase of common stock (in shares)	0				0
Common stock and Partnership units tendered for tax withholding obligations	$ 0.0	0.0	0.0	0.0	$ (2.6)	(4.8)	(7.4)
Common stock and Partnership units tendered for tax withholding obligations (in shares)	(22)				22
Sale of Partnership limited partner interests	$ 0.0	0.0	0.0	0.0	$ 0.0	257.2	257.2
Impact of Partnership equity transactions	0.0	14.1	0.0	0.0	0.0	(14.1)	0.0
Dividends	0.0	0.0	(66.5)	0.0	0.0	0.0	(66.5)
Dividends in excess of retained earnings	0.0	(15.7)	0.0	0.0	0.0	0.0	(15.7)
Distributions to noncontrolling interests	0.0	0.0	0.0	0.0	0.0	(257.7)	(257.7)
Other comprehensive income (loss)	0.0	0.0	0.0	0.8	0.0	8.3	9.1
Net income	0.0	0.0	76.8	0.0	0.0	253.9	330.7
Balance at Sep. 30, 2014	$ 0.0	153.8	30.8	0.3	$ (25.4)	2,190.3	2,349.8
Balance (in shares) at Sep. 30, 2014	42,143				389
Balance at Dec. 31, 2014	$ 0.0	164.9	25.5	4.8	$ (25.4)	2,369.7	2,539.5
Balance (in shares) at Dec. 31, 2014	42,143				389
Compensation on equity grants	$ 0.0	6.2	0.0	0.0	$ 0.0	12.8	19.0
Compensation on equity grants (in shares)	0				0
Distribution equivalent rights	$ 0.0	(0.6)	0.0	0.0	$ 0.0	(1.9)	(2.5)
Shares issued under compensation program	$ 0.0	0.0	0.0	0.0	$ 0.0	0.0	0.0
Shares issued under compensation program (in shares)	48				0
Common stock and Partnership units tendered for tax withholding obligations	$ 0.0	0.0	0.0	0.0	$ (3.1)	(5.2)	(8.3)
Common stock and Partnership units tendered for tax withholding obligations (in shares)	(36)				36
Sale of Partnership limited partner interests	$ 0.0	0.0	0.0	0.0	$ 0.0	315.4	315.4
Proceeds from equity issuances	$ 0.0	335.5	0.0	0.0	$ 0.0	0.0	335.5
Proceeds from equity issuances (in shares)	3,738				0
Impact of Partnership equity transactions	$ 0.0	56.5	0.0	0.0	$ 0.0	(56.5)	0.0
Dividends	0.0	0.0	(44.3)	0.0	0.0	0.0	(44.3)
Dividends in excess of retained earnings	0.0	(83.7)	0.0	0.0	0.0	0.0	(83.7)
Distributions to noncontrolling interests	0.0	0.0	0.0	0.0	0.0	(368.5)	(368.5)
Contributions from noncontrolling interests	0.0	0.0	0.0	0.0	0.0	16.4	16.4
Noncontrolling interest in acquired subsidiaries	0.0	0.0	0.0	0.0	0.0	113.4	113.4
Common stock issued in ATLS merger	$ 0.1	1,013.6	0.0	0.0	$ 0.0	0.0	1,013.7
Common stock issued in ATLS merger (in shares)	10,126				0
Issuance of Partnership units in APL merger	$ 0.0	0.0	0.0	0.0	$ 0.0	2,435.7	2,435.7
Other comprehensive income (loss)	0.0	0.0	0.0	0.4	0.0	17.6	18.0
Net income	0.0	0.0	31.4	0.0	0.0	49.2	80.6
Balance at Sep. 30, 2015	$ 0.1	$ 1,492.4	$ 12.6	$ 5.2	$ (28.5)	$ 4,898.1	$ 6,379.9
Balance (in shares) at Sep. 30, 2015	56,019				425

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities
Net income	$ 80.6	$ 330.7
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense	11.2	9.2
Compensation on equity grants	19.0	10.8
Depreciation and amortization expenses	448.3	253.1
Accretion of asset retirement obligations	4.0	3.3
Deferred income tax expense (benefit)	41.9	(4.2)
Equity (earnings) loss of unconsolidated affiliates	1.1	(13.8)
Distributions received from unconsolidated affiliates	10.1	13.8
Risk management activities	53.2	0.9
Gain on sale or disposition of assets	(0.2)	(5.6)
Loss from financing activities	13.4	0.0
Changes in operating assets and liabilities, net of business acquisitions:
Receivables and other assets	121.6	(41.3)
Inventory	31.2	(117.8)
Accounts payable and other liabilities	(139.9)	80.0
Net cash provided by operating activities	695.5	519.1
Cash flows from investing activities
Outlays for property, plant and equipment	(625.3)	(571.7)
Outlays for business acquisitions, net of cash acquired	(1,574.4)	0.0
Investment in unconsolidated affiliates	(6.6)	0.0
Return of capital from unconsolidated affiliates	1.1	4.2
Other, net	(3.0)	6.3
Net cash used in investing activities	(2,208.2)	(561.2)
Partnership debt obligations:
Proceeds from borrowings under credit facilities	1,646.0	1,295.0
Repayments of credit facilities	(1,211.0)	(1,115.0)
Proceeds from accounts receivable securitization facility	275.5	88.9
Repayments of accounts receivable securitization facility	(322.8)	(131.0)
Proceeds from issuance of senior notes	1,700.0	0.0
Redemption of APL senior notes	(1,168.8)	0.0
Non-Partnership debt obligations:
Proceeds from borrowings under credit facility	481.0	67.0
Repayments of credit facility	(138.0)	(59.0)
Proceeds from issuance of senior term loan	422.5	0.0
Repayments on senior term loan	(270.0)	0.0
Costs incurred in connection with financing arrangements	(43.0)	(2.7)
Proceeds from sale of common units of the Partnership	318.6	259.9
Repurchase of common units under Partnership compensation plans	(5.2)	(4.8)
Contributions from noncontrolling interests	16.4	0.0
Distributions to noncontrolling interests	(368.5)	(257.7)
Proceeds from TRC equity offerings	335.5	0.0
Repurchase of common stock under TRC compensation plans	(3.1)	(2.6)
Dividends to common shareholders	(128.0)	(82.2)
Payments of distribution equivalent rights	(2.5)	(1.6)
Net cash provided by financing activities	1,534.6	54.2
Net change in cash and cash equivalents	21.9	12.1
Cash and cash equivalents, beginning of period	81.0	66.7
Cash and cash equivalents, end of period	$ 102.9	$ 78.8

Organization	9 Months Ended
Organization	Sep. 30, 2015
Organization [Abstract]
Organization	Note 1 — Organization Targa Resources Corp. (“TRC”) is a publicly traded Delaware corporation formed in October 2005. Our common stock is listed on the New York Stock Exchange under the symbol “TRGP.” In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended to mean our consolidated business and operations.

- Definition

The entire disclosure for the nature of an entity's business, major products or services, principal markets including location, and the relative importance of its operations in each business and the basis for the determination, including but not limited to, assets, revenues, or earnings. For an entity that has not commenced principal operations, disclosures about the risks and uncertainties related to the activities in which the entity is currently engaged and an understanding of what those activities are being directed toward.

+ References + Details

Basis of Presentation

9 Months Ended

Sep. 30, 2015

Basis of Presentation [Abstract]

Basis of Presentation

Note 2 — Basis of Presentation

We have prepared these unaudited consolidated financial statements in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report.

The unaudited consolidated financial statements for the three and nine months ended September 30, 2015 and 2014 include all adjustments that we believe are necessary for a fair presentation of the results for interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation.

Our financial results for the three and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the full year.

One of our indirect subsidiaries is the sole general partner of Targa Resources Partners LP (“the Partnership” or “TRP”). Because we control the general partner of the Partnership, under GAAP, we must reflect our ownership interests in the Partnership on a consolidated basis. Accordingly, the Partnership’s financial results are included in our consolidated financial statements even though the distribution or transfer of Partnership assets is limited by the terms of the Partnership’s partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by us are reflected in our consolidated results of operations as net income attributable to noncontrolling interests and in our consolidated balance sheet equity section as noncontrolling interests in subsidiaries. Throughout these footnotes, we make a distinction where relevant between financial results of the Partnership versus those of a standalone parent and its non-partnership subsidiaries.

As of September 30, 2015, our interests in the Partnership consist of the following:

a 2% general partner interest, which we hold through our 100% ownership interest in the general partner of the Partnership;

all Incentive Distribution Rights (“IDRs”);

16,309,594 common units of the Partnership, representing an 8.8% limited partnership interest; and

a Special GP Interest representing retained tax benefits related to the contribution to the Partnership from us of the APL general partner interest acquired in the ATLS merger (see Note 4 – Business Acquisitions).

The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; gathering, storing and terminaling crude oil; and storing, terminaling and selling refined petroleum products. See Note 18 – Segment Information for an analysis of our and the Partnership’s operations by business segment.

The Partnership does not have any employees. We provide operational, general and administrative and other services to the Partnership, associated with the Partnership’s existing assets and assets acquired from third parties. We perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.

The Partnership Agreement governs our relationship with the Partnership regarding the reimbursement of costs incurred on behalf of the Partnership. We charge the Partnership for all the direct costs of the employees assigned to its operations, as well as all general and administrative support costs other than (1) costs attributable to our status as a separate reporting company and (2) our costs of providing management and support services to certain unaffiliated spun-off entities. The Partnership generally reimburses us monthly for cost allocations to the extent that we have made a cash outlay.

Subsequent Event

On November 2, 2015, we and the Partnership entered into an Agreement and Plan of Merger, by and among us, Spartan Merger Sub LLC, a subsidiary of ours ("Merger Sub"), the Partnership and the general partner of the Partnership pursuant to which we will acquire all of the outstanding common units representing limited partner interests in the Partnership not already owned by us or our subsidiaries. Upon the terms and conditions set forth in the Merger Agreement, Merger Sub will be merged with and into the Partnership, with the Partnership continuing as the surviving entity and as a subsidiary of ours (see Note 19 – Buy-in Acquisition).

- Definition

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

+ References + Details

Significant Accounting Policies	9 Months Ended
Significant Accounting Policies	Sep. 30, 2015
Significant Accounting Policies [Abstract]
Significant Accounting Policies	Note 3 — Significant Accounting Policies Accounting Policy Updates The accounting policies that we follow are set forth in Note 3 of the Notes to Consolidated Financial Statements in our Annual Report. We have updated our policies during the nine months ended September 30, 2015 to include our accounting policy for goodwill related to the Atlas mergers. Goodwill Goodwill results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Impairment testing for goodwill is performed at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (also known as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available, and segment management regularly reviews the operating results of that component. Goodwill is subject to a test for impairment at least annually, as well as whenever events or changes in circumstances indicate it is more likely than not the fair value of an affected reporting unit is less than its carrying amount. We may first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount (including assigned goodwill) as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. If 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 allocated with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. 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. Recent Accounting Pronouncements In February 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . The amendments are intended to simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities and modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities. The amendments are effective for us in 2016, with early adoption permitted. We are currently evaluating the effect of the amendments for each of our less-than-wholly owned subsidiaries. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs . The amendments in this update require that debt issuance costs related to a recognized debt liability (other than revolving credit facilities) be presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update deals solely with financial statement display matters; recognition and measurement of debt issuance costs are unaffected. Unamortized debt issuance costs of $44.7 million and $29.9 million for term loans and notes were included in Other long-term assets on the Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014. In August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . The amendment clarifies ASU 2015-03 and provides that an entity may defer and present debt issuance costs for a line-of-credit or other revolving credit facility arrangement as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the arrangement. Unamortized debt issuance costs of $15.6 million and $8.6 million for revolving credit facilities were included in Other long-term assets on the Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014. We will continue to include debt issuance costs for our line-of-credit and revolving credit facility arrangements in Other long-term assets upon adoption of ASU 2015-03. We plan to adopt these standards as of December 31, 2015. In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 303): Simplifying the Measurement of Inventory. Topic 303 currently requires inventory to be measured at the lower of cost or market, where market could be replacement cost, net realizable value or net realizable value less a normal profit margin. The amendments in this update require that all inventory, excluding inventory that is measured using the last-in, first-out method or the retail inventory method, be measured at the lower of cost or net realizable value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This amendment has been adopted, with no impact on our consolidated financial statements or results of operations. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date . The amendment defers the effective date of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) by one year. As a result of the amendment, Topic 606 is effective for the annual period beginning December 15, 2017, and for annual and interim periods thereafter, with early adoption permitted. Earlier adoption is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact of Topic 606 on our revenue recognition practices. In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments . Topic 805 currently requires that adjustments to provisional amounts recorded in a business combination be recognized retrospectively as if the accounting had been completed at the acquisition date. The amendments in this update require that an acquirer recognize these measurement-period adjustments in the reporting period in which the adjustment amounts are determined, with the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments require disclosure of the amount recorded in current-period earnings that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments are effective for us in 2016, with early adoption permitted. We adopted the amendments on September 30, 2015 and have recognized the measurement-period adjustments for the Atlas mergers determined in the three months ended September 30, 2015 in current period earnings. See Note 4 for additional information regarding the nature and amount of the measurement-period adjustments.

- Definition

The entire disclosure for all significant accounting policies of the reporting entity.

+ References + Details

Business Acquisitions

9 Months Ended

Sep. 30, 2015

Business Acquisitions [Abstract]

Business Acquisitions

Note 4 – Business Acquisitions

2015 Acquisition

Atlas Mergers

On February 27, 2015, (i) Targa completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLS Merger Agreement”), by and among Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly owned subsidiary of Targa (“GP Merger Sub”), ATLS and Atlas Energy GP, LLC, a Delaware limited liability company and the general partner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the transactions contemplated by the Agreement and Plan of Merger (the “APL Merger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, 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.”

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.

The Partnership 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 the Partnership’s 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, we acquired ATLS for a total purchase price of approximately $1.6 billion (including all assumed liabilities).

Pursuant to the APL Merger Agreement, Targa agreed to cause the general partner of the Partnership to amend the Partnership’s Partnership Agreement, which we refer to as the IDR Giveback Amendment, in order to reduce aggregate distributions to us, 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 the Partnership’s 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 the Partnership’s 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. The Partnership issued 58,614,157 of its 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, we contributed $52.4 million to the Partnership to maintain our 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). We issued 10,126,532 of our 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. Our acquisition of ATLS resulted in our acquiring these common units (converted to 3,363,935 Partnership common units) valued at approximately $147.4 million (based on the $43.82 closing market price of a Partnership common unit 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 the Company 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 the Partnership’s 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 $1,065.7 million and a net loss of $1.0 million to the Company for the period from February 27, 2015 to September 30, 2015, and is reported in our Field Gathering and Processing segment. In 2015, we incurred $27.3 million of acquisition-related costs. These expenses are included in other expense in our Consolidated Statements of Operations for the nine months ended September 30, 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 nine months ended September 30, 2015 and September 30, 2014 assumes that the Partnership’s acquisition of APL and our 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 Nine Months Ended
	September 30, 2015			September 30, 2014

Revenues		$	5,299.9		$	8,659.5
Net income			63.2			340.5

The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making adjustments to:

Reflect the change in amortization expense resulting from the difference between the historical balances of APL’s intangible assets, net, and our preliminary estimate of the fair value of intangible assets acquired.

Reflect the change in depreciation expense resulting from the difference between the historical balances of APL’s property, plant and equipment, net, and our preliminary estimate of the fair value of property, plant and equipment acquired.

Reflect the change in interest expense resulting from our financing activities directly related to the Atlas mergers as compared with APL’s historical interest expense.

Reflect the changes in stock-based compensation expense related to the fair value of the unvested portion of replacement Partnership Long Term Incentive Plan (“LTIP”) awards which were issued in connection with the acquisition to APL phantom unitholders who continue to provide service as Targa employees following the completion of the APL merger.

Remove the results of operations attributable to APL businesses sold during the periods: (1) the May 2014 sale of APL’s 20% interest in West Texas LPG Pipeline Limited Partnership and (2) the February 2015 transfer to Atlas Resource Partners, L.P of 100% of APL’s interest in gas gathering assets located in the Appalachian Basin of Tennessee.

Exclude $27.3 million of acquisition-related costs incurred in 2015 from pro forma net income for the nine months ended September 30, 2015. Pro forma net income for the nine months ended September 30, 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:

Fair Value of Consideration Transferred:
Cash paid, net of cash acquired (1):
TRC	$	745.7
TRP		828.7
Common shares of TRC		1,008.5
Replacement restricted stock units awarded (2)		5.2
Common units of TRP		2,421.1
Replacement phantom units awarded (2)		15.0
Total	$	5,024.2

(1)

Net of cash acquired of $40.8 million.

(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.

As of February 27, 2015, our preliminary fair value determination related to the Atlas mergers was as follows. The excess of the purchase price over the estimated fair value of net assets acquired was approximately $551.4 million, which was recorded as goodwill.This determination is based on our preliminary valuation and is subject to revisions pending the completion of the valuation and other adjustments.

Preliminary fair value determination:	February 27, 2015
Trade and other current receivables, net	$	181.1
Other current assets		24.5
Assets from risk management activities		102.1
Property, plant and equipment		4,703.1
Investments in unconsolidated affiliates		219.7
Intangible assets		1,199.0
Other long-term assets		5.6
Current liabilities		(258.0	)
Long-term debt		(1,573.3	)
Deferred income tax liabilities, net		(8.6	)
Other long-term liabilities		(9.0	)
Total identifiable net assets		4,586.2
Noncontrolling interest in subsidiaries		(113.4	)
Goodwill		551.4
Total fair value consideration transferred	$	5,024.2

Our valuation of the acquired assets and liabilities is ongoing and may result in future measurement-period adjustments to these preliminary fair values. The fair values of property, plant and equipment, investments in unconsolidated affiliates, intangible assets representing customer contracts and customer relationships, deferred income taxes related to APL Arkoma, Inc., a taxable subsidiary acquired, and noncontrolling interest, which is calculated as a proportionate share of the fair value of the acquired joint ventures’ net assets, are preliminary pending completion of final valuations. As a result, goodwill is also preliminary, as it has been recorded as the excess of the purchase price over the estimated fair value of net assets acquired.

During the three months ended June 30, 2015, we recorded measurement period adjustments to our preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. As a result, the statement of operations for the three months ended March 31, 2015 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 preliminary acquisition date fair values due to the refinement of our valuation models, assumptions and inputs. In accordance with the recent 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.

The preliminary valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, as defined in Note 15 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.

The preliminary determination of goodwill of $551.4 million is attributable to the workforce of the acquired business and the expected synergies with us. The goodwill is expected to be amortizable for tax purposes. The attribution of the goodwill to reporting units for the purpose of required future impairment assessments will be completed in conjunction with our finalization of the fair value determination.

The fair value of assets acquired includes trade receivables of $178.1 million. The gross amount due under contracts is $178.1 million, all of which is expected to be collectible. The fair value of assets acquired includes receivables of $3.0 million reported in current receivables and $4.5 million reported in other long-term assets related to a contractual settlement with a counterparty. See Note 10-Debt Obligations for additional disclosures regarding related financing activities associated with the Atlas mergers.

Contingent Consideration

A liability arising from the contingent consideration for APL’s previous acquisition of a gas gathering system and related assets has been recognized at fair value. APL agreed to pay up to an additional $6.0 million if certain volumes are achieved on the acquired gathering system within a specified time period. The fair value of the remaining contingent payment is recorded within other long term liabilities on our Consolidated Balance Sheets. The range of the undiscounted amount that we could pay related to the remaining contingent payment is between $0.0 and $6.0 million. We finalized our acquisition analysis and modeling of this contingent liability during the three months ended June 30, 2015, which resulted in 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 Restricted Stock Units (“RSUs”)

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 after the acquisition. The vesting dates and terms remained unchanged from the existing ATLS awards, and will vest over the remaining terms of the awards, which are 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.

Each RSU will entitle the grantee to one common share on the vesting date and is an equity-settled award. The RSUs include dividend equivalents. When we declare and pay cash dividends, the holders of RSUs will be entitled within 60 days to receive cash payment of dividend equivalents in an amount equal to the cash dividends the holders would have received if they were the holders of record on the record date of the number of our common shares related to the RSUs.

The fair value of the RSUs was based on the closing price of our common shares at the close of trading on February 27, 2015. The fair value was allocated between the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and future compensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award.

Replacement Phantom Units

In connection with the APL merger, the Partnership 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 the Partnership declares and pays 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 the Partnership’s common units related to the replacement phantom units.

The fair value of the replacement phantom units was based on the closing price of the Partnership’s 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.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

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+ Details

Inventories

9 Months Ended

Sep. 30, 2015

Inventories [Abstract]

Inventories

Note 5 — Inventories

	September 30, 2015		December 31, 2014
Partnership:
Commodities	$	138.4		$	157.4
Materials and supplies		12.7			11.5
	$	151.1		$	168.9

- Definition

The entire disclosure for inventory. This may include, but is not limited to, the basis of stating inventory, the method of determining inventory cost, the major classes of inventory, and the nature of the cost elements included in inventory. If inventory is stated above cost, accrued net losses on firm purchase commitments for inventory and losses resulting from valuing inventory at the lower-of-cost-or-market may also be included. For LIFO inventory, may disclose the amount and basis for determining the excess of replacement or current cost over stated LIFO value and the effects of a LIFO quantities liquidation that impacts net income.

+ References + Details

Property, Plant and Equipment and Intangible Assets

9 Months Ended

Sep. 30, 2015

Property, Plant and Equipment and Intangible Assets [Abstract]

Property, Plant and Equipment and Intangible Assets

Note 6 — Property, Plant and Equipment and Intangible Assets

	September 30, 2015			December 31, 2014			Estimated Useful Lives (In Years)
Gathering systems	$	6,187.7		$	2,588.6		5 to 20
Processing and fractionation facilities		2,996.3			1,890.7		5 to 25
Terminaling and storage facilities		1,098.2			1,038.9		5 to 25
Transportation assets		439.5			359.0		10 to 25
Other property, plant and equipment		213.7			149.3		3 to 25
Land		108.6			95.6		-
Construction in progress		754.4			399.0		-
Property, plant and equipment		11,798.4			6,521.1
Accumulated depreciation		(2,048.2	)		(1,696.5	)
Property, plant and equipment, net	$	9,750.2		$	4,824.6

Intangible assets	$	1,880.6		$	681.8		20
Accumulated amortization		(184.9	)		(89.9	)
Intangible assets, net	$	1,695.7		$	591.9

Intangible assets consist of customer contracts and customer relationships acquired in our Atlas mergers and our Badlands business acquisition. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate.

The fair values of intangible assets acquired in the Atlas mergers have been recorded at a preliminary value of $1,199.0 million pending completion of final valuations. For the purpose of our preparing the accompanying consolidated financial statements, (which includes seven months of amortization of these intangible assets), we have amortized these intangible assets over a 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. The estimated annual amortization expense for intangible assets, including the preliminary Atlas valuation and straight-line treatment, is approximately $129.9 million, $148.1 million, $141.3 million, $127.6 million and $116.6 million for each of the years 2015 through 2019.

Asset Retirement Obligations

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

Note 7 — Asset Retirement Obligations

The Partnership’s 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 the Partnership’s ARO are as follows:

	Nine Months Ended September 30, 2015
Beginning of period	$	57.1
Preliminary fair value of ARO acquired with APL merger		4.0
Change in cash flow estimate		3.8
Accretion expense		4.0
End of period	$	68.9

- Definition

The entire disclosure for an asset retirement obligation and the associated long-lived asset. An asset retirement obligation is a legal obligation associated with the disposal or retirement from service of a tangible long-lived asset that results from the acquisition, construction or development, or the normal operations of a long-lived asset, except for certain obligations of lessees.

+ References + Details

Investments in Unconsolidated Affiliates

9 Months Ended

Sep. 30, 2015

Investments in Unconsolidated Affiliates [Abstract]

Investments in Unconsolidated Affiliates

Note 8 – Investments in Unconsolidated Affiliates

The Partnership’s 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; 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 the Partnership the degree of control required for consolidating them in our consolidated financial statements, but they do afford the Partnership significant influence required to employ the equity method of accounting.

The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates:

	Nine Months Ended September 30, 2015
	GCF			T2 Joint Ventures			Total
Beginning of period	$	50.2		$	-		$	50.2
Preliminary fair value of T2 Joint Ventures acquired		-			219.7			219.7
Equity earnings (loss)		10.1			(11.2	)		(1.1	)
Cash distributions (1)		(10.7	)		(0.5	)		(11.2	)
Cash calls for expansion projects		-			6.6			6.6
End of period	$	49.6		$	214.6		$	264.2

(1)

Includes $1.1 million distributions received from GCF and T2 Joint Ventures in excess of the Partnership’s share of cumulative earnings for the nine months ended September 30, 2015. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.

The Partnership’s recorded value of the T2 Joint Ventures is based on preliminary fair values at the date of acquisition which results in an excess fair value of $45.1 million over the book value of the Partnership’s capital accounts. This basis difference is attributable to depreciable tangible assets and is being amortized over the preliminary estimated useful lives of the underlying assets of 20 years on a straight-line basis and is included as a component of equity earnings. See Note 4 - Business Acquisitions for further information regarding the preliminary fair value determinations related to the Atlas mergers.

- Definition

The entire disclosure for equity method investments and joint ventures. Equity method investments are investments that give the investor the ability to exercise significant influence over the operating and financial policies of an investee. Joint ventures are entities owned and operated by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group.

+ References + Details

Accounts Payable and Accrued Liabilities

9 Months Ended

Sep. 30, 2015

Accounts Payable and Accrued Liabilities [Abstract]

Accounts Payable and Accrued Liabilities

Note 9 — Accounts Payable and Accrued Liabilities

	September 30, 2015						December 31, 2014
	Targa Resources Partners LP		TRC Non- Partnership		Targa Resources Corp. Consolidated (1)		Targa Resources Partners LP		TRC Non- Partnership			Targa Resources Corp. Consolidated (1)
Commodities	$	416.5	$	-	$	416.5	$	416.7	$	-		$	416.7
Other goods and services		100.5		1.2		101.7		108.9		2.2			111.1
Interest		68.0		0.7		68.7		37.3		-			37.3
Compensation and benefits		1.0		29.7		30.7		1.3		44.8			46.1
Income and other taxes		42.6		0.2		42.8		13.6		(1.9	)		11.7
Other		21.9		6.6		28.5		14.9		0.7			15.6
	$	650.5	$	38.4	$	688.9	$	592.7	$	45.8		$	638.5

(1)

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). Liabilities to creditors to whom we have issued checks that remain outstanding totaled $28.0 million and $13.6 million at September 30, 2015 and December 31, 2014 and are included above in accounts payable and accrued liabilities.

Debt Obligations

9 Months Ended

Sep. 30, 2015

Debt Obligations [Abstract]

Debt Obligations

Note 10 — Debt Obligations

	September 30, 2015			December 31, 2014
Current:
Obligations of the Partnership
Accounts receivable securitization facility, due December 2015 (1)	$	135.5		$	182.8
Long-term:
Non-Partnership obligations:
TRC Senior secured revolving credit facility, variable rate, due October 2017		-			102.0
TRC Senior secured revolving credit facility, variable rate, due February 2020 (2)		445.0			-
TRC Senior secured term loan, variable rate, due February 2022		160.0			-
Unamortized discount		(2.6	)		-
Obligations of the Partnership: (1)
Senior secured revolving credit facility, variable rate, due October 2017 (3)		435.0			-
Senior unsecured notes, 5% fixed rate, due January 2018		1,100.0			-
Senior unsecured notes, 4 ⅛ % fixed rate, due November 2019		800.0			800.0
Senior unsecured notes, 6 ⅝ % fixed rate, due October 2020 (4)		342.1			-
Unamortized premium		5.2			-
Senior unsecured notes, 6 ⅞ % fixed rate, due February 2021		483.6			483.6
Unamortized discount		(23.0	)		(25.2	)
Senior unsecured notes, 6 ⅜ % fixed rate, due August 2022		300.0			300.0
Senior unsecured notes, 5 ¼ % fixed rate, due May 2023		600.0			600.0
Senior unsecured notes, 4¼% fixed rate, due November 2023		625.0			625.0
Senior unsecured notes, 6¾% fixed rate, due March 2024		600.0			-
Senior unsecured APL notes, 6 ⅝ % fixed rate, due October 2020 (4) (5)		13.1			-
Unamortized premium		0.2			-
Senior unsecured APL notes, 4¾% fixed rate, due November 2021 (5)		6.5			-
Senior unsecured APL notes, 5⅞% fixed rate, due August 2023 (5)		48.1			-
Unamortized premium		0.6			-
Total long-term debt		5,938.8			2,885.4
Total debt	$	6,074.3		$	3,068.2
Irrevocable standby letters of credit:
Letters of credit outstanding under the TRC Senior secured credit facility (2)	$	-		$	-
Letters of credit outstanding under the Partnership senior secured revolving credit facility (3)		11.2			44.1
	$	11.2		$	44.1

(1)

While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.

(2)

As of September 30, 2015 , availability under TRC’s $670.0 million senior secured revolving credit facility was $225.0 million.

(3)

As of September 30, 2015 , availability under the Partnership’s $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,153.8 million.

(4)

In May 2015, the Partnership exchanged TRP 6⅝% Senior Notes with the same economic terms to holders of the 2020 APL Notes (as defined below) who validly tendered such notes for exchange to us.

(5)

Senior unsecured notes issued by APL entities and acquired in the ATLS mergers. While the Partnership consolidates the debt acquired in the Atlas mergers, neither we nor the Partnership guarantees the acquired debt of APL.

The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the nine months ended September 30, 2015:

	Range of Interest Rates Incurred	Weighted Average Interest Rate Incurred
TRC senior secured revolving credit facility	2.2% - 2.9%	2.8%
TRC senior secured term loan	5.75%	5.75%
Partnership's senior secured revolving credit facility	1.9% - 4.3%	2.2%
Partnership's accounts receivable securitization facility	0.9%	0.9%

Compliance with Debt Covenants

As of September 30, 2015, both the Partnership and we were in compliance with the covenants contained in our various debt agreements.

Partnership Financing Activities

Revolving Credit Agreement

In February 2015, the Partnership entered into the First Amendment, Waiver and Incremental Commitment Agreement (the “First Amendment”) that amended its Second Amended and Restated Credit Agreement (the “Original Agreement”). The First Amendment increased available commitments to $1.6 billion from $1.2 billion while retaining the Partnership’s ability to request up to an additional $300.0 million in commitment increases. In addition, the First Amendment amends certain provisions of the Original Agreement to designate each of APL and its subsidiaries as an “Unrestricted Subsidiary.” The Partnership used proceeds from borrowings under the credit facility to fund some of the cash components of the APL merger, including $701.4 million for the repayments of the APL Revolver and $28.8 million related to change of control payments.

Senior Unsecured Notes

In January 2015, the Partnership 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 the TRP Revolver 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 the Partnership’s other senior notes.

In September 2015, the Partnership Issuers issued $600 million in aggregate principal amount of 6 ¾ % Senior Notes due 2024 (the “6 ¾ % Notes”). The 6 ¾ % Notes resulted in approximately $595.0 million of net proceeds after costs, which were used to reduce borrowings under the TRP Revolver and for general partnership purposes. The 6 ¾ % Notes are unsecured senior obligations that have substantially the same terms and covenants as the Partnership’s other senior notes.

April 2015 Shelf

In April 2015, the Partnership filed with the SEC a universal shelf registration statement that allows it 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.

Accounts Receivable Securitization Facility

In August 2015, the Partnership reduced the maximum borrowing capacity of its accounts receivable securitization facility (the “Securitization Facility”) by $100.0 million to $200.0 million because it did not expect to fully utilize the former borrowing capacity in a lower commodity price environment. This reduction results in lower commitment fees on the unused portion of the Securitization Facility.

Merger Financing Activities

ATLS Merger Financing Activities

In connection with the closing of the Atlas mergers, we entered into a Credit Agreement (the “TRC Credit Agreement”), dated as of February 27, 2015, among us, each lender from time to time party thereto and Bank of America, N.A. as administrative agent, collateral agent, swing line lender and letter of credit issuer. The TRC Credit Agreement provides for a new five year revolving credit facility in an aggregate principal amount up to $670 million and a seven year variable rate term loan facility in an aggregate principal amount of $430 million. This facility was issued at a 1.75% discount. The outstanding term loans are Eurodollar rate loans with an interest rate of LIBOR (with a LIBOR floor of 1%) plus an applicable rate of 4.75%. We used the net proceeds from the term loan issuance and the revolving credit facility to fund cash components of the ATLS merger, including cash merger consideration and approximately $160.2 million related to change of control payments made by ATLS, cash settlements of equity awards and transaction fees and expenses. In March 2015, we repaid $188.0 million of the term loan and wrote off $3.3 million of the discount and $5.7 million of debt issuance costs. In June 2015, we repaid $82.0 million of the term loan and wrote off $1.4 million of the discount and $2.4 million of debt issuance costs. The write-off of the discount and debt issuance costs are reflected as Loss from financing activities on the Consolidated Statements of Operations for the three and nine months ended September 30, 2015.

APL Senior Notes Tender Offers

In January 2015, the Partnership 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”), the Partnership 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”) for 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, the Partnership 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. The Partnership recognized $0.5 million of costs associated with the Exchange Offer, which is included as a Loss on financing activities on our Consolidated Statements of Operations.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References + Details

Partnership Units and Related Matters

9 Months Ended

Sep. 30, 2015

Partnership Units and Related Matters [Abstract]

Partnership Units and Related Matters

Note 11 — Partnership Units and Related Matters

Issuances of Common Units

As part of the Atlas merger, the Partnership 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, which were issued to us.

As of January 1, 2015 the Partnership had approximately $158.4 million of capacity available under its May 2014 Equity Distribution Agreement (the “May 2014 EDA”). In May 2015, the Partnership entered into an additional Equity Distribution Agreement under the April 2015 Shelf (the “May 2015 EDA”), pursuant to which it may sell through its sales agents, at its option, up to an aggregate of $1.0 billion of common units. During the nine months ended September 30, 2015, the Partnership issued 7,377,380 common units under its EDAs, receiving proceeds of $316.1 million (net of commissions). As of September 30, 2015, approximately $4.2 million of capacity and $835.6 million of capacity remain under the May 2014 EDA and May 2015 EDA. During the nine months ended September 30, 2015 we contributed $6.5 million to us to maintain our 2% general partner interest

Subsequent Event-Preferred Units

In October 2015, under the Partnership’s April 2013 Shelf, the Partnership 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, the Partnership sold an additional 600,000 Preferred Units at a price of $25.00 per unit. The Partnership received net proceeds after costs of approximately $121.1 million. The Partnership used the net proceeds from this offering to reduce borrowings under the TRP Revolver 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 will be 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 the Partnership’s general partner. Distributions on the Preferred Units will be payable out of amounts legally available therefor from and including the date of original issue to, but not including, November 1, 2020, at a rate equal to 9.00% per annum of the stated liquidation preference. On and after November 1, 2020, distributions on the Series A 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 the Partnership’s 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 the Partnership’s existing and future indebtedness (including (i) indebtedness outstanding under the TRP Revolver, (ii) the Partnership’s 5% Notes, the Partnership’s 4⅛% Senior Notes due 2019, our 6⅝% Notes, the Partnership’s 6⅞% Senior Notes due 2021, the Partnership’s 6⅜% Senior Notes due 2022, the Partnership’s 5¼% Senior Notes due 2023, the Partnership’s 4¼% Senior Notes due 2023 and the Partnership’s 6¾% Notes and (iii) indebtedness outstanding under the Partnership’s 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, the Partnership 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, the Partnership (or a third party with its prior written consent) may redeem the Preferred Units following certain changes of control, as described in the Partnership Agreement . If the Partnership (or a third party with its 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 unit as set forth in the Partnership Agreement . If the Partnership (or a third party with its prior written consent) exercises its 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 will have no voting rights except for certain exceptions set forth in the Partnership Agreement .

On October 20, 2015, the Partnership announced that the board of directors of its general partner declared a prorated monthly cash distribution of $0.10 per Preferred Unit. This cash distribution is the initial distribution payable on the Preferred Units for the period from October 15, 2015 through October 31, 2015, and will be paid November 16, 2015 on all outstanding Preferred Units to holders of record as of the close of business on October 30, 2015.

Distributions

In accordance with the Partnership Agreement, the Partnership must distribute all of its available cash, after the preferred distribution, as defined in the Partnership Agreement, and as determined by the general partner, to common unitholders of record within 45 days after the end of each quarter. The following table details the distributions declared and/or paid by the Partnership, net of IDR Giveback, for the nine months ended September 30, 2015:

		Distributions
Three Months Ended	Date Paid or to be Paid	Limited Partners		General Partner								Distributions to Targa Resources Corp.		Distributions per limited partner unit
Three Months Ended	Date Paid or to be Paid	Common		Incentive Distribution Rights					2%	Total		Distributions to Targa Resources Corp.		Distributions per limited partner unit

(In millions, except per unit amounts)
September 30, 2015	November 13, 2015	$	152.5	$	43.9	(1	)	$	4.0	$	200.4	$	61.4	$	0.8250
June 30, 2015	August 14, 2015		152.5		43.9	(1	)		4.0		200.4		61.4		0.8250
March 31, 2015	May 15, 2015		148.3		41.7	(1	)		3.9		193.9		59.0		0.8200
December 31, 2014	February 13, 2015		96.3		38.4				2.7		137.4		51.6		0.8100

(1)

Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDR’s of $9.375 million were allocated to common unitholders in the first, second and third quarters of 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and will result in reallocation of IDR payments to common unitholders in the following amounts: $9.375 million per quarter for 2015, $6.25 million per quarter for 2016, $2.5 million per quarter for 2017 and $1.25 million per quarter for 2018.

- Definition

The entire disclosure for the formation, structure, control and ownership of the partnership. Disclosures related to accounts comprising partners' capital. Includes balances of general partners' capital account, limited partners' capital account, preferred partners' capital account and total partners' capital account and units outstanding; accumulated other comprehensive income; amount and nature of changes to amount of partner's capital and units outstanding by class, rights and privileges for each class of units; distribution policies and distributions paid by unit class; impact of and correction of an error in previously issued financial statements; limitations of partners' liability; redemption, conversion and distribution policies; and deferred compensation related to the issuance of units.

+ References + Details

Common Stock and Related Matters

9 Months Ended

Sep. 30, 2015

Common Stock and Related Matters [Abstract]

Common Stock and Related Matters

Note 12 — Common Stock and Related Matters

On February 27, 2015, we issued 10,126,532 shares of our common stock valued at approximately $1.0 billion in exchange for ATLS common units as part of the ATLS merger (based on the $99.58 closing market price of our common shares on the NYSE as of February 27, 2015). In addition, we awarded 81,740 RSUs in connection with the ATLS mergers.

Public Offering

During March 2015, we sold, in a public offering, 3,250,000 shares of our common stock under a registration statement on Form S-3 at a price of $91 per share of common stock, providing net proceeds of $292.8 million to us. Pursuant to the exercise of the underwriters’ overallotment option, we also sold an additional 487,500 shares of our common stock, providing additional net proceeds of $43.9 million. The proceeds from this offering were used to repay a portion of the outstanding borrowings under our term loan, to make a capital contribution of $52.4 million to the Partnership to maintain our 2% general partnership interest in the Partnership and for general corporate purposes.

Dividends

The following table details the dividends declared and/or paid by us for the nine months ended September 30, 2015:

Three Months Ended	Date Paid or To Be Paid	Total Dividend Declared		Amount of Dividend Paid		Accrued Dividends (1)		Dividend Declared per Share of Common Stock

(In millions, except per share amounts)
September 30, 2015	November 16, 2015	$	51.2	$	50.9	$	0.3	$	0.91000
June 30, 2015	August 17, 2015		49.2		49.0		0.2		0.87500
March 31, 2015	May 18, 2015		46.6		46.4		0.2		0.83000
December 31, 2014	February 17, 2015		32.8		32.6		0.2		0.77500

(1)	Represents accrued dividends on restricted stock units that are payable upon vesting.

Dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close of the prior quarter, with any excess recorded as a reduction of additional paid-in capital.

Earnings per Common Share

9 Months Ended

Sep. 30, 2015

Earnings per Common Share [Abstract]

Earnings per Common Share

Note 13 — Earnings per Common Share

The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Net income	$	20.8	$	120.4	$	80.6	$	330.7
Less: Net income attributable to noncontrolling interests		8.1		89.7		49.2		253.9
Net income attributable to common shareholders	$	12.7	$	30.7	$	31.4	$	76.8

Weighted average shares outstanding - basic		56.0		42.0		52.6		42.0

Net income available per common share - basic	$	0.23	$	0.73	$	0.60	$	1.83

Weighted average shares outstanding		56.0		42.0		52.6		42.0
Dilutive effect of unvested stock awards		0.1		0.1		0.1		0.1
Weighted average shares outstanding - diluted (1)		56.1		42.1		52.7		42.1

Net income available per common share - diluted	$	0.23	$	0.73	$	0.60	$	1.82

(1)	For the three and nine months ended September 30, 2015, approximately 30,195 shares and 27,529 shares were excluded from the computation of diluted earnings per share because the inclusion of such shares would have been anti-dilutive.

- Definition

The entire disclosure for earnings per share.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Section 45
-Paragraph 3
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Subparagraph (SX 210.5-03.21)
-URI http://asc.fasb.org/extlink&oid=26872669&loc=d3e20235-122688

+ Details

Derivative Instruments and Hedging Activities

9 Months Ended

Sep. 30, 2015

Derivative Instruments and Hedging Activities [Abstract]

Derivative Instruments and Hedging Activities

Note 14 — Derivative Instruments and Hedging Activities

The Partnership’s Commodity Hedges

The primary purpose of the Partnership’s commodity risk management activities is to manage its exposure to commodity price risk and reduce volatility in its operating cash flow due to fluctuations in commodity prices. The Partnership has hedged the commodity prices associated with a portion of its expected (i) natural gas equity volumes in its Field Gathering and Processing segment and (ii) NGL and condensate equity volumes predominately in its Field Gathering and Processing segment and the LOU business unit in its 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. The Partnership has 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 the Partnership’s physical equity volumes. The Partnership’s 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 the Partnership’s 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. The Partnership’s natural gas and NGL hedges are settled using published index prices for delivery at various locations.

The Partnership hedges a portion of its 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 the Partnership to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of its 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 $20.7 million and $52.2 million related to these novated contracts were received during the three and nine months ended September 30, 2015 and were reflected as a reduction of the acquisition date fair value of the APL derivative assets acquired with no effect on results of operations.

The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financing element representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness can either potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses on qualifying derivatives that can be deferred from inclusion in periodic net income. Certain novated APL crude options with a fair value of $7.7 million as of the acquisition date did not fall within the “highly effective” correlation range required to qualify as a hedging instrument for accounting purposes. These non-qualifying hedges resulted in $1.3 million and $1.0 million of mark-to-market gains for the three and nine months ended September 30, 2015. These crude oil options expired during 2015. Additionally, for the three and nine months ended September 30, 2015, the Partnership recorded $0.4 million and $1.3 million of ineffectiveness gains related to otherwise qualifying APL derivatives, primarily natural gas swaps.

At September 30, 2015, the notional volumes of the Partnership’s commodity derivative contracts were:

Commodity	Instrument	Unit	2015		2016		2017		2018
Natural Gas	Swaps	MMBtu/d		163,456		79,399		23,082		-
Natural Gas	Basis Swaps	MMBtu/d		88,099		48,962		18,082		-
Natural Gas	Collars	MMBtu/d		15,400		22,900		22,900		9,486
NGL	Swaps	Bbl/d		4,268		2,674		1,078		208
NGL	Options/Collars	Bbl/d		920		920		920		32
Condensate	Swaps	Bbl/d		1,663		1,082		500		-
Condensate	Options/Collars	Bbl/d		1,605		790		790		101

The Partnership also enters into derivative instruments to help manage other short-term commodity-related business risks. The Partnership has not designated these derivatives as hedges and records changes in fair value and cash settlements to revenues.

The Partnership’s derivative contracts are subject to netting arrangements that permit its 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 September 30, 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	$	89.0	$	2.1	$	44.4	$	-
	Long-term		45.4		4.0		15.8		-
Total derivatives designated as hedging instruments		$	134.4	$	6.1	$	60.2	$	-

Derivatives not designated as hedging instruments
Commodity contracts	Current	$	3.3	$	2.2	$	-	$	5.2
Total derivatives not designated as hedging instruments		$	3.3	$	2.2	$	-	$	5.2

Total current position		$	92.3	$	4.3	$	44.4	$	5.2
Total long-term position			45.4		4.0		15.8		-
Total derivatives		$	137.7	$	8.3	$	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
September 30, 2015	Asset Position		Liability Position		Asset Position		Liability Position
Current position
Counterparties with offsetting position	$	87.3	$	4.3	$	83.0	$	-
Counterparties without offsetting position - assets		5.0		-		5.0		-
Counterparties without offsetting position - liabilities		-		-		-		-
		92.3		4.3		88.0		-
Long-term position
Counterparties with offsetting position		44.3		4.0		40.3		-
Counterparties without offsetting position - assets		1.1		-		1.1		-
Counterparties without offsetting position - liabilities		-		-		-		-
		45.4		4.0		41.4		-
Total derivatives
Counterparties with offsetting position		131.6		8.3		123.3		-
Counterparties without offsetting position - assets		6.1		-		6.1		-
Counterparties without offsetting position - liabilities		-		-		-		-
	$	137.7	$	8.3	$	129.4	$	-

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

The Partnership’s payment obligations in connection with substantially all of these hedging transactions are secured by a first priority lien in the collateral securing its senior secured indebtedness that ranks equal in right of payment with liens granted in favor of its senior secured lenders.

The fair value of the Partnership’s 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 the Partnership’s derivative instruments was a net asset of $129.4 million as of September 30, 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.

The following tables reflect amounts recorded in Other Comprehensive Income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Commodity contracts	$	42.9	$	14.2	$	59.4	$	(4.5	)

Location of Gain (Loss)	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
Location of Gain (Loss)	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Interest expense, net	$	-	$	-		$	-	$	(2.4	)
Revenues		16.7		(0.8	)		41.1		(11.6	)
	$	16.7	$	(0.8	)	$	41.1	$	(14.0	)

Our consolidated earnings are also affected by the Partnership’s 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.

Derivatives Not Designated as Hedging Instruments	Location of Gain Recognized in Income on Derivatives
			Gain (Loss) Recognized in Income on Derivatives

			Three Months Ended September 30,				Nine Months Ended September 30,
			2015		2014		2015		2014
Commodity contracts	Revenue	$	(4.0)	$	(1.5)	$	(0.9)	$	(1.4)

The following table shows the deferred gains (losses) included in accumulated OCI, which will be reclassified into earnings before income taxes through the end of 2018 based on valuations as of the balance sheet date:

		September 30, 2015					December 31, 2014
Commodity hedges, before tax (1)		$	78.5			$	60.3

(1)	Includes deferred net gains of $45.1 million as of September 30, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months.

See Note 15 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

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+ Details

Fair Value Measurements

9 Months Ended

Sep. 30, 2015

Fair Value Measurements [Abstract]

Fair Value Measurements

Note 15 — 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

The Partnership’s derivative instruments consist of financially settled commodity swaps and option contracts and fixed-price commodity contracts with certain counterparties. The Partnership determines the fair value of its derivative contracts using present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. The Partnership has consistently applied these valuation techniques in all periods presented and we believe the Partnership has obtained the most accurate information available for the types of derivative contracts the Partnership holds.

The fair values of the Partnership’s derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. This financial position of these derivatives at September 30, 2015, a net asset position of $129.4 million, reflects the present value, adjusted for counterparty credit risk, of the amount the Partnership expects to receive or pay in the future on its 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 $105.3 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 $152.0 million, ignoring an adjustment for counterparty credit risk.

Fair Value of Other Financial Instruments

Due to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accounts receivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:

•

Our and the Partnership’s senior secured revolving credit facilities and the Partnership’s Securitization Facility are based on carrying value, which approximates fair value as their interest rates are based on prevailing market rates; and

•

Senior unsecured notes are based on quoted market prices derived from trades of the debt.

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:

	September 30, 2015
	Carrying Value		Fair Value
	Carrying Value		Total		Level 1		Level 2		Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value
Assets from commodity derivative contracts (1)	$	137.7	$	137.7	$	-	$	133.1	$	4.6
Liabilities from commodity derivative contracts (1)		8.3		8.3		-		7.0		1.3
TPL contingent consideration (2)		4.2		4.2		-		-		4.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		102.9		102.9		-		-		-
TRC Senior secured revolving credit facility		445.0		445.0		-		445.0		-
TRC Term Loan		157.4		159.5		-		159.5		-
Partnership's Senior secured revolving credit facility		435.0		435.0		-		435.0		-
Partnership's Senior unsecured notes		4,901.4		4,567.5		-		4,567.5		-
Partnership's accounts receivable securitization facility		135.5		135.5		-		135.5		-

(1)

The fair value of the derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 14 – 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 the Partnership’s 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 September 30, 2015, the Partnership had 23 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair value measurements of the Partnership’s Level 3 derivatives are the forward natural gas curves, for which a significant portion of the derivative’s term is beyond available forward pricing. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.

T he following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

	Commodity Derivative Contracts (Asset)/Liability			Contingent Liability
Balance, December 31, 2014	$	(1.7	)	$	-
TPL contingent consideration (Note 4 - Business Acquisitions)		-			4.2
New Level 3 instruments		(3.3	)		-
Transfers out of Level 3		1.7			-
Balance, September 30, 2015	$	(3.3	)	$	4.2

For the nine months ended September 30, 2015, the Partnership transferred $1.7 million in derivative liabilities out of Level 3 and into Level 2. These transfers relate to long-term over-the-counter swaps for natural gas and NGL products with deliveries for which observable market prices were available.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 21
-URI http://asc.fasb.org/extlink&oid=49121117&loc=d3e13537-108611

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=49121117&loc=d3e13504-108611

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=49121117&loc=d3e13433-108611

+ Details

Contingencies	9 Months Ended
Contingencies	Sep. 30, 2015
Contingencies [Abstract]
Contingencies	Note 16 – Contingencies Legal Proceedings 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 are styled (a) Michael Evnin v. Atlas Pipeline Partners, L.P., et al ., in the Court of Common Pleas for Allegheny County, Pennsylvania; (b) William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., in the District Court of Tulsa County, Oklahoma (the “Tulsa Lawsuit”); (c) Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al ., in the Court of Common Pleas for Allegheny County, Pennsylvania; (d) Mike Welborn v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; and (e) Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania, though the Tulsa Lawsuit has since been voluntarily dismissed. The Evnin, Greenthal, Welborn and Feldbaum lawsuits have been consolidated as In re Atlas Pipeline Partners, L.P. Unitholder Litigation , Case No. GD-14-019245, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated APL Lawsuit”). In October and November 2014, two public unitholders of ATLS (the “ATLS Plaintiffs” and, together with the APL Plaintiffs, the “Atlas Lawsuit Plaintiffs”) filed putative class action lawsuits against ATLS, ATLS GP, its managers, Targa and GP Merger Sub (the “ATLS Lawsuit Defendants” and, together with the APL Lawsuit Defendants, the “Atlas Lawsuit Defendants”). These lawsuits are styled (a) Rick Kane v. Atlas Energy, L.P., et al. , in the Court of Common Pleas for Allegheny County, Pennsylvania and (b) Jeffrey Ayers v. Atlas Energy, L.P., et al. , in the Court of Common Pleas for Allegheny County, Pennsylvania (the “ATLS Lawsuits”). The ATLS Lawsuits have been consolidated as In re Atlas Energy, L.P. Unitholder Litigation , Case No. GD-14-019658, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated ATLS Lawsuit” and, together with the Consolidated APL Lawsuit, the “Consolidated Atlas Lawsuits”), though the Kane lawsuit has since been voluntarily dismissed. The Atlas Lawsuit Plaintiffs alleged a variety of causes of action challenging the Atlas mergers. Generally, the APL Plaintiffs alleged that (a) APL GP’s managers have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, the Partnership, the general partner, MLP Merger Sub, APL, ATLS and APL GP have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The APL Plaintiffs further alleged that (a) the premium offered to APL’s unitholders was inadequate, (b) APL agreed to contractual terms that would allegedly dissuade other potential acquirers from seeking to acquire APL, and (c) APL GP’s managers favored their self-interests over the interests of APL’s unitholders. The APL Plaintiffs in the Consolidated APL Lawsuit also alleged that the registration statement filed on November 19, 2014 failed, among other things, to disclose allegedly material details concerning (i) Stifel, Nicolaus & Company, Incorporated’s analysis of the Atlas mergers; (ii) APL and the Partnership’s financial projections; and (iii) the background of the Atlas mergers. Generally, the ATLS Plaintiffs alleged that (a) ATLS GP’s directors have breached the covenant of good faith and/or their fiduciary duties and (b) Targa, GP Merger Sub, and ATLS have aided and abetted in these alleged breaches of the covenant of good faith and/or fiduciary duties. The ATLS Plaintiffs further alleged that (a) the premium offered to the ATLS unitholders was inadequate, (b) ATLS agreed to contractual terms that would allegedly dissuade other potential acquirers from seeking to acquire ATLS, (c) ATLS GP’s directors favored their self-interests over the interests of the ATLS unitholders and (d) the registration statement failed to disclose allegedly material details concerning, among other things, (i) Wells Fargo Securities, LLC, Stifel, Nicolaus & Company, Incorporated, and Deutsche Bank Securities Inc.’s analyses of the Atlas mergers; (ii) the Partnership, Targa, APL, and ATLS’ financial projections; and (iii) the background of the Atlas mergers. Based on these allegations, the Atlas Lawsuit Plaintiffs sought to enjoin the Atlas Lawsuit Defendants from proceeding with or consummating the Atlas mergers unless and until APL and ATLS adopted and implemented processes to obtain the best possible terms for their respective unitholders. The Atlas Lawsuit Plaintiffs also sought rescission, damages, and attorneys’ fees. The parties to the Consolidated Atlas Lawsuits agreed to settle the Consolidated Atlas Lawsuits on February 9, 2015. In general, the settlements provide that in consideration for the dismissal of the Consolidated Atlas Lawsuits, ATLS and APL would provide supplemental disclosures regarding the Atlas mergers in a filing with the SEC on Form 8-K, 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. The parties to the Consolidated Atlas Lawsuits have executed the settlement agreements and the settlement notices to the putative class members have been submitted to the Court for approval. Environmental Proceeding 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, the Partnership signed an Agreed Order that will resolve all alleged violations stated in the NOEs. The Executive Director of the TCEQ signed the Agreed Order on September 11, 2015, and the Partnership anticipates the TCEQ Commissioners will approve the Agreed Order during their November 4, 2015 meeting. Under the Agreed Order, the Partnership is required to (1) pay an administrative penalty in the amount of $115,644; (2) pay $115,643 to fund certain supplemental environmental projects, and (3) 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. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

Supplemental Cash Flow Information

9 Months Ended

Sep. 30, 2015

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Note 17 - Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2015			2014
Cash:
Interest paid, net of capitalized interest (1)	$	163.4		$	90.3
Income taxes paid, net of refunds		13.3			55.2
Non-cash Investing and Financing balance sheet movements:
Debt additions and retirements related to exchange of TRP 6⅝% Notes for APL 6⅝% Notes		342.1			-
Deadstock commodity inventories transferred to property, plant and equipment		1.2			15.2
Reductions in Owner's Equity related to accrued dividends on unvested equity awards under share compensation arrangements		0.3			0.5
Impact of capital expenditure accruals on property, plant and equipment		(57.2	)		(40.6	)
Transfers from materials and supplies inventory to property, plant and equipment		2.9			2.7
Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate		3.8			2.1

Non-cash balance sheet movements related to business acquisition: (see Note 4)
Non-cash merger consideration - common units and replacement equity awards	$	2,436.1		$	-
Non-cash merger consideration - common shares and replacement equity awards		1,013.7			-
Net non-cash balance sheet movements excluded from consolidated statements of cash flows		3,449.8			-
Net cash merger consideration included in investing activities		1,574.4			-
Total fair value of consideration transferred	$	5,024.2		$	-

(1)	Interest capitalized on major projects was $9.1 million and $14.3 million for the nine months ended September 30, 2015 and 2014.

- Definition

The entire disclosure for supplemental cash flow activities, including cash, noncash, and part noncash transactions, for the period. Noncash is defined as information about all investing and financing activities of an enterprise during a period that affect recognized assets or liabilities but that do not result in cash receipts or cash payments in the period. "Part noncash" refers to that portion of the transaction not resulting in cash receipts or cash payments in the period.

+ References + Details

Segment Information

9 Months Ended

Sep. 30, 2015

Segment Information [Abstract]

Segment Information

Note 18 — Segment Information

The Partnership reports its operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution. The operating margin results of the Partnership’s commodity derivative activities are reported in Other.

The Partnership’s 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.

The Partnership’s Logistics and Marketing division is also referred to as its Downstream Business. The Partnership’s 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 the Partnership’s other operations, including services to LPG exporters, as well as transporting natural gas and NGLs.

The Partnership’s 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 the Partnership’s Gathering and Processing segments and are predominantly located in Mont Belvieu, and Galena Park, Texas and Lake Charles, Louisiana.

The Partnership’s 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 the Partnership’s 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 the Partnership from its 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 the Partnership’s 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 mergers and integration efforts related to the Atlas mergers.

Reportable segment information is shown in the following tables. We have segregated the following segment information between Partnership and non-Partnership activities:

	Three Months Ended September 30, 2015
	Partnership
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other		Corporate and Eliminations			Total Partnership		TRC Non- Partnership		Consolidated
Revenues
Sales of commodities	$	419.5	$	50.8	$	31.3	$	797.9	$	21.8	$	-		$	1,321.3	$	-	$	1,321.3
Fees from midstream services		108.4		8.9		82.4		111.1		-		-			310.8		-		310.8
		527.9		59.7		113.7		909.0		21.8		-			1,632.1		-		1,632.1
Intersegment revenues
Sales of commodities		195.8		57.6		3.2		67.3		-		(323.9	)		-		-		-
Fees from midstream services		2.4		-		64.6		5.4		-		(72.4	)		-		-		-
		198.2		57.6		67.8		72.7		-		(396.3	)		-		-		-
Revenues	$	726.1	$	117.3	$	181.5	$	981.7	$	21.8	$	(396.3	)	$	1,632.1	$	-	$	1,632.1
Operating margin	$	132.6	$	7.9	$	103.6	$	60.2	$	21.8	$	-		$	326.1	$	-	$	326.1
Other financial information:
Total assets (1)	$	10,088.7	$	346.2	$	1,854.0	$	543.8	$	137.6	$	352.9		$	13,323.2	$	95.0	$	13,418.2
Goodwill (2)	$	551.4	$	-	$	-	$	-	$	-	$	-		$	551.4	$	-	$	551.4
Capital expenditures	$	109.6	$	5.5	$	67.5	$	0.9	$	-	$	2.7		$	186.2	$	-	$	186.2
Business acquisition	$	5,024.2	$	-	$	-	$	-	$	-	$	-		$	5,024.2	$	-	$	5,024.2

(1)	Corporate assets at the Segment level primarily include investments in unconsolidated subsidiaries and debt issuance costs associated with the Partnership’s debt obligations.

(2)	Total assets include goodwill. Goodwill has been preliminarily attributed to our Field Gathering and Processing segment.

	Three Months Ended September 30, 2014
	Partnership
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other			Corporate and Eliminations			Total Partnership		TRC Non- Partnership		Consolidated
Revenues
Sales of commodities	$	49.4	$	83.4	$	23.1	$	1,855.6	$	(2.3	)	$	-			2,009.2	$	-	$	2,009.2
Fees from midstream services		49.4		8.0		75.5		146.2		-			-			279.1		-		279.1
		98.8		91.4		98.6		2,001.8		(2.3	)		-			2,288.3		-		2,288.3
Intersegment revenues
Sales of commodities		386.0		143.6		1.3		116.1		-			(647.0	)		-		-		-
Fees from midstream services		1.7		-		85.9		10.1		-			(97.7	)		-		-		-
		387.7		143.6		87.2		126.2		-			(744.7	)		-		-		-
Revenues	$	486.5	$	235.0	$	185.8	$	2,128.0	$	(2.3	)	$	(744.7	)		2,288.3	$	-	$	2,288.3
Operating margin	$	98.0	$	19.1	$	118.6	$	61.6	$	(2.3	)	$	-			295.0	$	-	$	295.0
Other financial information:
Total assets	$	3,359.0	$	368.6	$	1,650.2	$	917.2	$	6.7		$	115.5			6,417.2	$	74.7	$	6,491.9
Capital expenditures	$	74.0	$	2.3	$	59.8	$	4.6	$	-		$	2.2			142.9	$	-	$	142.9

	Nine Months Ended September 30, 2015
	Partnership
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other		Corporate and Eliminations			Total Partnership		TRC Non- Partnership			Total



Revenues
Sales of commodities	$	1,021.4	$	156.1	$	89.4	$	2,792.0	$	60.7	$	-		$	4,119.6	$	-		$	4,119.6
Fees from midstream services		277.8		25.1		259.9		328.8		-		-			891.6		-			891.6
		1,299.2		181.2		349.3		3,120.8		60.7		-			5,011.2		-			5,011.2
Intersegment revenues															-
Sales of commodities		624.1		178.0		6.4		214.4		-		(1,022.9	)		-		-			-
Fees from midstream services		6.3		-		200.0		15.2		-		(221.5	)		-		-			-
		630.4		178.0		206.4		229.6		-		(1,244.4	)		-		-			-
Revenues	$	1,929.6	$	359.2	$	555.7	$	3,350.4	$	60.7	$	(1,244.4	)	$	5,011.2	$	-		$	5,011.2
Operating margin	$	349.9	$	22.1	$	341.7	$	177.3	$	60.7	$	-		$	951.7	$	(0.1	)	$	951.6
Other financial information:
Total assets (1)	$	10,088.7	$	346.2	$	1,854.0	$	543.8	$	137.6	$	352.9		$	13,323.2	$	95.0		$	13,418.2
Goodwill (2)	$	551.4	$	-	$	-	$	-	$	-	$	-		$	551.4	$	-		$	551.4
Capital expenditures	$	345.2	$	11.4	$	199.6	$	9.8	$	-	$	5.0		$	571.0	$	-		$	571.0
Business acquisition	$	5,024.2	$	-	$	-	$	-	$	-	$	-		$	5,024.2	$	-		$	5,024.2

(1)	Corporate assets at the Segment level primarily include investments in unconsolidated subsidiaries and debt issuance costs associated with the Partnership’s debt obligations.

(2)	Total assets include goodwill. Goodwill has been preliminarily attributed to our Field Gathering and Processing segment.

	Nine Months Ended September 30, 2014
	Partnership
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other			Corporate and Eliminations			Total Partnership		TRC Non- Partnership			Total



Revenues
Sales of commodities	$	158.0	$	273.7	$	73.0	$	5,361.0	$	(12.4	)	$	-		$	5,853.3	$	-		$	5,853.3
Fees from midstream services		133.5		26.1		216.3		354.5		-			-			730.4		-			730.4
		291.5		299.8		289.3		5,715.5		(12.4	)		-			6,583.7		-			6,583.7
Intersegment revenues
Sales of commodities		1,168.2		484.0		2.7		383.6		-			(2,038.5	)		-		-			-
Fees from midstream services		3.9		0.1		224.5		25.5		-			(254.0	)		-		-			-
		1,172.1		484.1		227.2		409.1		-			(2,292.5	)		-		-			-
Revenues	$	1,463.6	$	783.9	$	516.5	$	6,124.6	$	(12.4	)	$	(2,292.5	)	$	6,583.7	$	-		$	6,583.7
Operating margin	$	289.8	$	67.0	$	324.0	$	179.5	$	(12.4	)	$	-		$	847.9	$	(0.1	)	$	847.8
Other financial information:
Total assets	$	3,359.0	$	368.6	$	1,650.2	$	917.2	$	6.7		$	115.5		$	6,417.2	$	74.7		$	6,491.9
Capital expenditures	$	301.4	$	9.7	$	195.9	$	23.2	$	-		$	3.6		$	533.8	$	-		$	533.8

The following table shows our consolidated revenues by product and service for the periods presented:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Sales of commodities:
Natural gas	$	456.1	$	335.4		$	1,201.6	$	1,085.8
NGL		772.2		1,614.8			2,656.9		4,601.2
Condensate		40.4		38.6			113.1		108.7
Petroleum products		30.8		22.4			87.3		70.7
Derivative activities		21.8		(2.0	)		60.7		(13.1	)
		1,321.3		2,009.2			4,119.6		5,853.3
Fees from midstream services:
Fractionating and treating		55.7		55.3			160.1		153.5
Storage, terminaling, transportation and export		126.8		158.8			384.6		385.8
Gathering and processing		106.6		51.9			280.7		142.6
Other		21.7		13.1			66.2		48.5
		310.8		279.1			891.6		730.4
Total revenues	$	1,632.1	$	2,288.3		$	5,011.2	$	6,583.7

The following table shows a reconciliation of operating margin to net income for the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Reconciliation of operating margin to net income:
Operating margin	$	326.1		$	295.0		$	951.6		$	847.8
Depreciation and amortization expense		(165.8	)		(87.6	)		(448.3	)		(253.1	)
General and administrative expense		(44.9	)		(43.0	)		(136.5	)		(122.4	)
Interest expense, net		(70.4	)		(36.9	)		(195.6	)		(106.5	)
Other, net		(0.2	)		8.4			(36.5	)		18.5
Income tax expense		(24.0	)		(15.5	)		(54.1	)		(53.6	)
Net income	$	20.8		$	120.4		$	80.6		$	330.7

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
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-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
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-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 29
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8906-108599

+ Details

Buy-in Acquisition	9 Months Ended
Buy-in Acquisition	Sep. 30, 2015
Buy-in Acquisition [Abstract]
Buy-in Acquisition	Note 19 — Buy-in Acquisition On November 3, 2015 we and Partnership announced that we will acquire all of the Partnership's outstanding common units not already owned by us in an all stock-for-unit transaction at a ratio of 0.62 of our common shares per common unit of the Partnership. Following completion of the transaction, all of the Partnership's outstanding common units will be owned by us and will no longer be publicly traded. The incentive distribution rights owned by us will be eliminated. All of the Partnership's outstanding debt and Series A preferred units will remain outstanding. No additional financing is required for the transaction. Our Board of Directors, the Conflicts Committee of the Board of Directors of the general partner of the Partnership and the Partnership's Board have approved the merger agreement. Subject to customary approvals and conditions, including the expiration or termination of all waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act, the transaction is expected to close in the first quarter of 2016. The transaction is subject to the approval of the Partnership's common unitholders and our shareholders.

Significant Accounting Policies (Policies)	9 Months Ended
Significant Accounting Policies (Policies)	Sep. 30, 2015
Significant Accounting Policies [Abstract]
Accounting Policy Updates	Accounting Policy Updates The accounting policies that we follow are set forth in Note 3 of the Notes to Consolidated Financial Statements in our Annual Report. We have updated our policies during the nine months ended September 30, 2015 to include our accounting policy for goodwill related to the Atlas mergers.
Goodwill	Goodwill Goodwill results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business. Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Impairment testing for goodwill is performed at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (also known as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available, and segment management regularly reviews the operating results of that component. Goodwill is subject to a test for impairment at least annually, as well as whenever events or changes in circumstances indicate it is more likely than not the fair value of an affected reporting unit is less than its carrying amount. We may first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount (including assigned goodwill) as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. If 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 allocated with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. 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.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In February 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis . The amendments are intended to simplify the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities and modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities. The amendments are effective for us in 2016, with early adoption permitted. We are currently evaluating the effect of the amendments for each of our less-than-wholly owned subsidiaries. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs . The amendments in this update require that debt issuance costs related to a recognized debt liability (other than revolving credit facilities) be presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update deals solely with financial statement display matters; recognition and measurement of debt issuance costs are unaffected. Unamortized debt issuance costs of $44.7 million and $29.9 million for term loans and notes were included in Other long-term assets on the Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014. In August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements . The amendment clarifies ASU 2015-03 and provides that an entity may defer and present debt issuance costs for a line-of-credit or other revolving credit facility arrangement as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the arrangement. Unamortized debt issuance costs of $15.6 million and $8.6 million for revolving credit facilities were included in Other long-term assets on the Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014. We will continue to include debt issuance costs for our line-of-credit and revolving credit facility arrangements in Other long-term assets upon adoption of ASU 2015-03. We plan to adopt these standards as of December 31, 2015. In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 303): Simplifying the Measurement of Inventory. Topic 303 currently requires inventory to be measured at the lower of cost or market, where market could be replacement cost, net realizable value or net realizable value less a normal profit margin. The amendments in this update require that all inventory, excluding inventory that is measured using the last-in, first-out method or the retail inventory method, be measured at the lower of cost or net realizable value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This amendment has been adopted, with no impact on our consolidated financial statements or results of operations. In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date . The amendment defers the effective date of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) by one year. As a result of the amendment, Topic 606 is effective for the annual period beginning December 15, 2017, and for annual and interim periods thereafter, with early adoption permitted. Earlier adoption is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We expect to adopt this guidance on January 1, 2018 and are continuing to evaluate the impact of Topic 606 on our revenue recognition practices. In September 2015, the FASB issued ASU 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments . Topic 805 currently requires that adjustments to provisional amounts recorded in a business combination be recognized retrospectively as if the accounting had been completed at the acquisition date. The amendments in this update require that an acquirer recognize these measurement-period adjustments in the reporting period in which the adjustment amounts are determined, with the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments require disclosure of the amount recorded in current-period earnings that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments are effective for us in 2016, with early adoption permitted. We adopted the amendments on September 30, 2015 and have recognized the measurement-period adjustments for the Atlas mergers determined in the three months ended September 30, 2015 in current period earnings. See Note 4 for additional information regarding the nature and amount of the measurement-period adjustments.

- Definition

Disclosure of accounting policy for goodwill. This accounting policy also may address how an entity assesses and measures impairment of goodwill, how reporting units are determined, how goodwill is allocated to such units, and how the fair values of the reporting units are determined.

+ References + Details

Business Acquisitions (Tables)

9 Months Ended

Sep. 30, 2015

Business Acquisitions [Abstract]

Pro Forma Consolidated Results of Operations

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 Nine Months Ended
	September 30, 2015			September 30, 2014

Revenues		$	5,299.9		$	8,659.5
Net income			63.2			340.5

Consideration Transferred to Acquire ATLS and APL

The following table summarizes the consideration transferred to acquire ATLS and APL:

Fair Value of Consideration Transferred:
Cash paid, net of cash acquired (1):
TRC	$	745.7
TRP		828.7
Common shares of TRC		1,008.5
Replacement restricted stock units awarded (2)		5.2
Common units of TRP		2,421.1
Replacement phantom units awarded (2)		15.0
Total	$	5,024.2

(1)

Net of cash acquired of $40.8 million.

(2)

Preliminary Fair Value Determination Related to the Atlas Mergers

Preliminary fair value determination:	February 27, 2015
Trade and other current receivables, net	$	181.1
Other current assets		24.5
Assets from risk management activities		102.1
Property, plant and equipment		4,703.1
Investments in unconsolidated affiliates		219.7
Intangible assets		1,199.0
Other long-term assets		5.6
Current liabilities		(258.0	)
Long-term debt		(1,573.3	)
Deferred income tax liabilities, net		(8.6	)
Other long-term liabilities		(9.0	)
Total identifiable net assets		4,586.2
Noncontrolling interest in subsidiaries		(113.4	)
Goodwill		551.4
Total fair value consideration transferred	$	5,024.2

- Definition

Tabular disclosure of a material business combination completed during the period, including background, timing, and recognized assets and liabilities. This table does not include leveraged buyouts.

+ References + Details

Inventories (Tables)

9 Months Ended

Sep. 30, 2015

Inventories [Abstract]

Components of Inventories

	September 30, 2015		December 31, 2014
Partnership:
Commodities	$	138.4		$	157.4
Materials and supplies		12.7			11.5
	$	151.1		$	168.9

Property, Plant and Equipment and Intangible Assets (Tables)

9 Months Ended

Sep. 30, 2015

Property, Plant and Equipment and Intangible Assets [Abstract]

Property, Plant and Equipment and Intangible Assets

	September 30, 2015			December 31, 2014			Estimated Useful Lives (In Years)
Gathering systems	$	6,187.7		$	2,588.6		5 to 20
Processing and fractionation facilities		2,996.3			1,890.7		5 to 25
Terminaling and storage facilities		1,098.2			1,038.9		5 to 25
Transportation assets		439.5			359.0		10 to 25
Other property, plant and equipment		213.7			149.3		3 to 25
Land		108.6			95.6		-
Construction in progress		754.4			399.0		-
Property, plant and equipment		11,798.4			6,521.1
Accumulated depreciation		(2,048.2	)		(1,696.5	)
Property, plant and equipment, net	$	9,750.2		$	4,824.6

Intangible assets	$	1,880.6		$	681.8		20
Accumulated amortization		(184.9	)		(89.9	)
Intangible assets, net	$	1,695.7		$	591.9

- Definition

Tabular disclosure of physical assets used in the normal conduct of business and not intended for resale. Includes, but is not limited to, balances by class of assets, depreciation and depletion expense and method used, including composite depreciation, and accumulated deprecation.

+ References + Details

Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligations [Abstract]

Changes in the Partnership's Aggregate Asset Retirement Obligations

	Nine Months Ended September 30, 2015
Beginning of period	$	57.1
Preliminary fair value of ARO acquired with APL merger		4.0
Change in cash flow estimate		3.8
Accretion expense		4.0
End of period	$	68.9

Investments in Unconsolidated Affiliates (Tables)

9 Months Ended

Sep. 30, 2015

Investments in Unconsolidated Affiliates [Abstract]

The following table shows the activity related to the Partnership’s investment in unconsolidated affiliates:

	Nine Months Ended September 30, 2015
	GCF			T2 Joint Ventures			Total
Beginning of period	$	50.2		$	-		$	50.2
Preliminary fair value of T2 Joint Ventures acquired		-			219.7			219.7
Equity earnings (loss)		10.1			(11.2	)		(1.1	)
Cash distributions (1)		(10.7	)		(0.5	)		(11.2	)
Cash calls for expansion projects		-			6.6			6.6
End of period	$	49.6		$	214.6		$	264.2

(1)

Accounts Payable and Accrued Liabilities (Tables)

9 Months Ended

Sep. 30, 2015

Accounts Payable and Accrued Liabilities [Abstract]

Schedule of Accounts Payable and Accrued Liabilities

	September 30, 2015						December 31, 2014
	Targa Resources Partners LP		TRC Non- Partnership		Targa Resources Corp. Consolidated (1)		Targa Resources Partners LP		TRC Non- Partnership			Targa Resources Corp. Consolidated (1)
Commodities	$	416.5	$	-	$	416.5	$	416.7	$	-		$	416.7
Other goods and services		100.5		1.2		101.7		108.9		2.2			111.1
Interest		68.0		0.7		68.7		37.3		-			37.3
Compensation and benefits		1.0		29.7		30.7		1.3		44.8			46.1
Income and other taxes		42.6		0.2		42.8		13.6		(1.9	)		11.7
Other		21.9		6.6		28.5		14.9		0.7			15.6
	$	650.5	$	38.4	$	688.9	$	592.7	$	45.8		$	638.5

(1)

Debt Obligations (Tables)

9 Months Ended

Sep. 30, 2015

Debt Obligations [Abstract]

Schedule of Outstanding Debt

	September 30, 2015			December 31, 2014
Current:
Obligations of the Partnership
Accounts receivable securitization facility, due December 2015 (1)	$	135.5		$	182.8
Long-term:
Non-Partnership obligations:
TRC Senior secured revolving credit facility, variable rate, due October 2017		-			102.0
TRC Senior secured revolving credit facility, variable rate, due February 2020 (2)		445.0			-
TRC Senior secured term loan, variable rate, due February 2022		160.0			-
Unamortized discount		(2.6	)		-
Obligations of the Partnership: (1)
Senior secured revolving credit facility, variable rate, due October 2017 (3)		435.0			-
Senior unsecured notes, 5% fixed rate, due January 2018		1,100.0			-
Senior unsecured notes, 4 ⅛ % fixed rate, due November 2019		800.0			800.0
Senior unsecured notes, 6 ⅝ % fixed rate, due October 2020 (4)		342.1			-
Unamortized premium		5.2			-
Senior unsecured notes, 6 ⅞ % fixed rate, due February 2021		483.6			483.6
Unamortized discount		(23.0	)		(25.2	)
Senior unsecured notes, 6 ⅜ % fixed rate, due August 2022		300.0			300.0
Senior unsecured notes, 5 ¼ % fixed rate, due May 2023		600.0			600.0
Senior unsecured notes, 4¼% fixed rate, due November 2023		625.0			625.0
Senior unsecured notes, 6¾% fixed rate, due March 2024		600.0			-
Senior unsecured APL notes, 6 ⅝ % fixed rate, due October 2020 (4) (5)		13.1			-
Unamortized premium		0.2			-
Senior unsecured APL notes, 4¾% fixed rate, due November 2021 (5)		6.5			-
Senior unsecured APL notes, 5⅞% fixed rate, due August 2023 (5)		48.1			-
Unamortized premium		0.6			-
Total long-term debt		5,938.8			2,885.4
Total debt	$	6,074.3		$	3,068.2
Irrevocable standby letters of credit:
Letters of credit outstanding under the TRC Senior secured credit facility (2)	$	-		$	-
Letters of credit outstanding under the Partnership senior secured revolving credit facility (3)		11.2			44.1
	$	11.2		$	44.1

(1)

While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.

(2)

As of September 30, 2015 , availability under TRC’s $670.0 million senior secured revolving credit facility was $225.0 million.

(3)

As of September 30, 2015 , availability under the Partnership’s $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,153.8 million.

(4)

In May 2015, the Partnership exchanged TRP 6⅝% Senior Notes with the same economic terms to holders of the 2020 APL Notes (as defined below) who validly tendered such notes for exchange to us.

(5)

Interest Rates Incurred on Variable-Rate Debt Obligations

The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the nine months ended September 30, 2015:

	Range of Interest Rates Incurred	Weighted Average Interest Rate Incurred
TRC senior secured revolving credit facility	2.2% - 2.9%	2.8%
TRC senior secured term loan	5.75%	5.75%
Partnership's senior secured revolving credit facility	1.9% - 4.3%	2.2%
Partnership's accounts receivable securitization facility	0.9%	0.9%

Summary of Results of Tender Offers

The results of the APL Notes Tender Offers were:

Senior Notes	Outstanding Note Balance		Amount Tendered		Premium Paid		Accrued Interest Paid		Total Tender Offer payments		% Tendered			Note Balance after Tender Offers
	($ amounts in millions)
6⅝% due 2020	$	500.0	$	140.1	$	2.1	$	3.7	$	145.9		28.02	%	$	359.9
4¾% due 2021		400.0		393.5		5.9		5.3		404.7		98.38	%		6.5
5⅞% due 2023		650.0		601.9		8.7		2.6		613.2		92.60	%		48.1
Total	$	1,550.0	$	1,135.5	$	16.7	$	11.6	$	1,163.8				$	414.5

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 235
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-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
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-Name Accounting Standards Codification
-Topic 835
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+ Details

Partnership Units and Related Matters (Tables)

9 Months Ended

Sep. 30, 2015

Partnership Units and Related Matters [Abstract]

Schedule of Distributions

The following table details the distributions declared and/or paid by the Partnership, net of IDR Giveback, for the nine months ended September 30, 2015:

		Distributions
Three Months Ended	Date Paid or to be Paid	Limited Partners		General Partner								Distributions to Targa Resources Corp.		Distributions per limited partner unit
Three Months Ended	Date Paid or to be Paid	Common		Incentive Distribution Rights					2%	Total		Distributions to Targa Resources Corp.		Distributions per limited partner unit

(In millions, except per unit amounts)
September 30, 2015	November 13, 2015	$	152.5	$	43.9	(1	)	$	4.0	$	200.4	$	61.4	$	0.8250
June 30, 2015	August 14, 2015		152.5		43.9	(1	)		4.0		200.4		61.4		0.8250
March 31, 2015	May 15, 2015		148.3		41.7	(1	)		3.9		193.9		59.0		0.8200
December 31, 2014	February 13, 2015		96.3		38.4				2.7		137.4		51.6		0.8100

(1)

- Definition

Tabular disclosure of payment of cash or stock made to limited partner of limited partnership (LP).

+ References + Details

Common Stock and Related Matters (Tables)

9 Months Ended

Sep. 30, 2015

Common Stock and Related Matters [Abstract]

Distributions Declared and/or Paid

The following table details the dividends declared and/or paid by us for the nine months ended September 30, 2015:

Three Months Ended	Date Paid or To Be Paid	Total Dividend Declared		Amount of Dividend Paid		Accrued Dividends (1)		Dividend Declared per Share of Common Stock

(In millions, except per share amounts)
September 30, 2015	November 16, 2015	$	51.2	$	50.9	$	0.3	$	0.91000
June 30, 2015	August 17, 2015		49.2		49.0		0.2		0.87500
March 31, 2015	May 18, 2015		46.6		46.4		0.2		0.83000
December 31, 2014	February 17, 2015		32.8		32.6		0.2		0.77500

(1)	Represents accrued dividends on restricted stock units that are payable upon vesting.

Earnings per Common Share (Tables)

9 Months Ended

Sep. 30, 2015

Earnings per Common Share [Abstract]

Earnings per Common Share

The following table sets forth a reconciliation of net income and weighted average shares outstanding used in computing basic and diluted net income per common share:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Net income	$	20.8	$	120.4	$	80.6	$	330.7
Less: Net income attributable to noncontrolling interests		8.1		89.7		49.2		253.9
Net income attributable to common shareholders	$	12.7	$	30.7	$	31.4	$	76.8

Weighted average shares outstanding - basic		56.0		42.0		52.6		42.0

Net income available per common share - basic	$	0.23	$	0.73	$	0.60	$	1.83

Weighted average shares outstanding		56.0		42.0		52.6		42.0
Dilutive effect of unvested stock awards		0.1		0.1		0.1		0.1
Weighted average shares outstanding - diluted (1)		56.1		42.1		52.7		42.1

Net income available per common share - diluted	$	0.23	$	0.73	$	0.60	$	1.82

(1)	For the three and nine months ended September 30, 2015, approximately 30,195 shares and 27,529 shares were excluded from the computation of diluted earnings per share because the inclusion of such shares would have been anti-dilutive.

Derivative Instruments and Hedging Activities (Tables)

9 Months Ended

Sep. 30, 2015

Derivative Instruments and Hedging Activities [Abstract]

Notional Volume of Commodity Hedges

At September 30, 2015, the notional volumes of the Partnership’s commodity derivative contracts were:

Commodity	Instrument	Unit	2015		2016		2017		2018
Natural Gas	Swaps	MMBtu/d		163,456		79,399		23,082		-
Natural Gas	Basis Swaps	MMBtu/d		88,099		48,962		18,082		-
Natural Gas	Collars	MMBtu/d		15,400		22,900		22,900		9,486
NGL	Swaps	Bbl/d		4,268		2,674		1,078		208
NGL	Options/Collars	Bbl/d		920		920		920		32
Condensate	Swaps	Bbl/d		1,663		1,082		500		-
Condensate	Options/Collars	Bbl/d		1,605		790		790		101

Fair Values of Derivative Instruments

The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:

		Fair Value as of September 30, 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	$	89.0	$	2.1	$	44.4	$	-
	Long-term		45.4		4.0		15.8		-
Total derivatives designated as hedging instruments		$	134.4	$	6.1	$	60.2	$	-

Derivatives not designated as hedging instruments
Commodity contracts	Current	$	3.3	$	2.2	$	-	$	5.2
Total derivatives not designated as hedging instruments		$	3.3	$	2.2	$	-	$	5.2

Total current position		$	92.3	$	4.3	$	44.4	$	5.2
Total long-term position			45.4		4.0		15.8		-
Total derivatives		$	137.7	$	8.3	$	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
September 30, 2015	Asset Position		Liability Position		Asset Position		Liability Position
Current position
Counterparties with offsetting position	$	87.3	$	4.3	$	83.0	$	-
Counterparties without offsetting position - assets		5.0		-		5.0		-
Counterparties without offsetting position - liabilities		-		-		-		-
		92.3		4.3		88.0		-
Long-term position
Counterparties with offsetting position		44.3		4.0		40.3		-
Counterparties without offsetting position - assets		1.1		-		1.1		-
Counterparties without offsetting position - liabilities		-		-		-		-
		45.4		4.0		41.4		-
Total derivatives
Counterparties with offsetting position		131.6		8.3		123.3		-
Counterparties without offsetting position - assets		6.1		-		6.1		-
Counterparties without offsetting position - liabilities		-		-		-		-
	$	137.7	$	8.3	$	129.4	$	-

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:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Commodity contracts	$	42.9	$	14.2	$	59.4	$	(4.5	)

Location of Gain (Loss)	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
Location of Gain (Loss)	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Interest expense, net	$	-	$	-		$	-	$	(2.4	)
Revenues		16.7		(0.8	)		41.1		(11.6	)
	$	16.7	$	(0.8	)	$	41.1	$	(14.0	)

Gain (Loss) Recognized in Income on Derivatives

Derivatives Not Designated as Hedging Instruments	Location of Gain Recognized in Income on Derivatives
			Gain (Loss) Recognized in Income on Derivatives

			Three Months Ended September 30,				Nine Months Ended September 30,
			2015		2014		2015		2014
Commodity contracts	Revenue	$	(4.0)	$	(1.5)	$	(0.9)	$	(1.4)

Deferred Gains (Losses) Included in Accumulated OCI

		September 30, 2015					December 31, 2014
Commodity hedges, before tax (1)		$	78.5			$	60.3

(1)	Includes deferred net gains of $45.1 million as of September 30, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months.

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

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+ Details

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2015

Fair Value Measurements [Abstract]

	September 30, 2015
	Carrying Value		Fair Value
	Carrying Value		Total		Level 1		Level 2		Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value
Assets from commodity derivative contracts (1)	$	137.7	$	137.7	$	-	$	133.1	$	4.6
Liabilities from commodity derivative contracts (1)		8.3		8.3		-		7.0		1.3
TPL contingent consideration (2)		4.2		4.2		-		-		4.2
Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value:
Cash and cash equivalents		102.9		102.9		-		-		-
TRC Senior secured revolving credit facility		445.0		445.0		-		445.0		-
TRC Term Loan		157.4		159.5		-		159.5		-
Partnership's Senior secured revolving credit facility		435.0		435.0		-		435.0		-
Partnership's Senior unsecured notes		4,901.4		4,567.5		-		4,567.5		-
Partnership's accounts receivable securitization facility		135.5		135.5		-		135.5		-

(1)

(2)	See Note 4 – Business Acquisitions.

Reconciliation of the Changes in Fair Value of Financial Instruments Classified As Level 3

T he following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

	Commodity Derivative Contracts (Asset)/Liability			Contingent Liability
Balance, December 31, 2014	$	(1.7	)	$	-
TPL contingent consideration (Note 4 - Business Acquisitions)		-			4.2
New Level 3 instruments		(3.3	)		-
Transfers out of Level 3		1.7			-
Balance, September 30, 2015	$	(3.3	)	$	4.2

- Definition

Tabular disclosure of the fair value of financial instruments, including financial assets and financial liabilities, and the measurements of those instruments, assets, and liabilities.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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- Definition

Tabular disclosure of the fair value measurement of liabilities using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets), and gains or losses recognized in other comprehensive income (loss) and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (2) purchases, sales, issues, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs) by class of liability.

+ References + Details

Supplemental Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2015

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

	Nine Months Ended September 30,
	2015			2014
Cash:
Interest paid, net of capitalized interest (1)	$	163.4		$	90.3
Income taxes paid, net of refunds		13.3			55.2
Non-cash Investing and Financing balance sheet movements:
Debt additions and retirements related to exchange of TRP 6⅝% Notes for APL 6⅝% Notes		342.1			-
Deadstock commodity inventories transferred to property, plant and equipment		1.2			15.2
Reductions in Owner's Equity related to accrued dividends on unvested equity awards under share compensation arrangements		0.3			0.5
Impact of capital expenditure accruals on property, plant and equipment		(57.2	)		(40.6	)
Transfers from materials and supplies inventory to property, plant and equipment		2.9			2.7
Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate		3.8			2.1

Non-cash balance sheet movements related to business acquisition: (see Note 4)
Non-cash merger consideration - common units and replacement equity awards	$	2,436.1		$	-
Non-cash merger consideration - common shares and replacement equity awards		1,013.7			-
Net non-cash balance sheet movements excluded from consolidated statements of cash flows		3,449.8			-
Net cash merger consideration included in investing activities		1,574.4			-
Total fair value of consideration transferred	$	5,024.2		$	-

(1)	Interest capitalized on major projects was $9.1 million and $14.3 million for the nine months ended September 30, 2015 and 2014.

Segment Information (Tables)

9 Months Ended

Sep. 30, 2015

Segment Information [Abstract]

Information by Segment

Reportable segment information is shown in the following tables. We have segregated the following segment information between Partnership and non-Partnership activities:

	Three Months Ended September 30, 2015
	Partnership
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other		Corporate and Eliminations			Total Partnership		TRC Non- Partnership		Consolidated
Revenues
Sales of commodities	$	419.5	$	50.8	$	31.3	$	797.9	$	21.8	$	-		$	1,321.3	$	-	$	1,321.3
Fees from midstream services		108.4		8.9		82.4		111.1		-		-			310.8		-		310.8
		527.9		59.7		113.7		909.0		21.8		-			1,632.1		-		1,632.1
Intersegment revenues
Sales of commodities		195.8		57.6		3.2		67.3		-		(323.9	)		-		-		-
Fees from midstream services		2.4		-		64.6		5.4		-		(72.4	)		-		-		-
		198.2		57.6		67.8		72.7		-		(396.3	)		-		-		-
Revenues	$	726.1	$	117.3	$	181.5	$	981.7	$	21.8	$	(396.3	)	$	1,632.1	$	-	$	1,632.1
Operating margin	$	132.6	$	7.9	$	103.6	$	60.2	$	21.8	$	-		$	326.1	$	-	$	326.1
Other financial information:
Total assets (1)	$	10,088.7	$	346.2	$	1,854.0	$	543.8	$	137.6	$	352.9		$	13,323.2	$	95.0	$	13,418.2
Goodwill (2)	$	551.4	$	-	$	-	$	-	$	-	$	-		$	551.4	$	-	$	551.4
Capital expenditures	$	109.6	$	5.5	$	67.5	$	0.9	$	-	$	2.7		$	186.2	$	-	$	186.2
Business acquisition	$	5,024.2	$	-	$	-	$	-	$	-	$	-		$	5,024.2	$	-	$	5,024.2

(1)	Corporate assets at the Segment level primarily include investments in unconsolidated subsidiaries and debt issuance costs associated with the Partnership’s debt obligations.

(2)	Total assets include goodwill. Goodwill has been preliminarily attributed to our Field Gathering and Processing segment.

	Three Months Ended September 30, 2014
	Partnership
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other			Corporate and Eliminations			Total Partnership		TRC Non- Partnership		Consolidated
Revenues
Sales of commodities	$	49.4	$	83.4	$	23.1	$	1,855.6	$	(2.3	)	$	-			2,009.2	$	-	$	2,009.2
Fees from midstream services		49.4		8.0		75.5		146.2		-			-			279.1		-		279.1
		98.8		91.4		98.6		2,001.8		(2.3	)		-			2,288.3		-		2,288.3
Intersegment revenues
Sales of commodities		386.0		143.6		1.3		116.1		-			(647.0	)		-		-		-
Fees from midstream services		1.7		-		85.9		10.1		-			(97.7	)		-		-		-
		387.7		143.6		87.2		126.2		-			(744.7	)		-		-		-
Revenues	$	486.5	$	235.0	$	185.8	$	2,128.0	$	(2.3	)	$	(744.7	)		2,288.3	$	-	$	2,288.3
Operating margin	$	98.0	$	19.1	$	118.6	$	61.6	$	(2.3	)	$	-			295.0	$	-	$	295.0
Other financial information:
Total assets	$	3,359.0	$	368.6	$	1,650.2	$	917.2	$	6.7		$	115.5			6,417.2	$	74.7	$	6,491.9
Capital expenditures	$	74.0	$	2.3	$	59.8	$	4.6	$	-		$	2.2			142.9	$	-	$	142.9

	Nine Months Ended September 30, 2015
	Partnership
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other		Corporate and Eliminations			Total Partnership		TRC Non- Partnership			Total



Revenues
Sales of commodities	$	1,021.4	$	156.1	$	89.4	$	2,792.0	$	60.7	$	-		$	4,119.6	$	-		$	4,119.6
Fees from midstream services		277.8		25.1		259.9		328.8		-		-			891.6		-			891.6
		1,299.2		181.2		349.3		3,120.8		60.7		-			5,011.2		-			5,011.2
Intersegment revenues															-
Sales of commodities		624.1		178.0		6.4		214.4		-		(1,022.9	)		-		-			-
Fees from midstream services		6.3		-		200.0		15.2		-		(221.5	)		-		-			-
		630.4		178.0		206.4		229.6		-		(1,244.4	)		-		-			-
Revenues	$	1,929.6	$	359.2	$	555.7	$	3,350.4	$	60.7	$	(1,244.4	)	$	5,011.2	$	-		$	5,011.2
Operating margin	$	349.9	$	22.1	$	341.7	$	177.3	$	60.7	$	-		$	951.7	$	(0.1	)	$	951.6
Other financial information:
Total assets (1)	$	10,088.7	$	346.2	$	1,854.0	$	543.8	$	137.6	$	352.9		$	13,323.2	$	95.0		$	13,418.2
Goodwill (2)	$	551.4	$	-	$	-	$	-	$	-	$	-		$	551.4	$	-		$	551.4
Capital expenditures	$	345.2	$	11.4	$	199.6	$	9.8	$	-	$	5.0		$	571.0	$	-		$	571.0
Business acquisition	$	5,024.2	$	-	$	-	$	-	$	-	$	-		$	5,024.2	$	-		$	5,024.2

(1)	Corporate assets at the Segment level primarily include investments in unconsolidated subsidiaries and debt issuance costs associated with the Partnership’s debt obligations.

(2)	Total assets include goodwill. Goodwill has been preliminarily attributed to our Field Gathering and Processing segment.

	Nine Months Ended September 30, 2014
	Partnership
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other			Corporate and Eliminations			Total Partnership		TRC Non- Partnership			Total



Revenues
Sales of commodities	$	158.0	$	273.7	$	73.0	$	5,361.0	$	(12.4	)	$	-		$	5,853.3	$	-		$	5,853.3
Fees from midstream services		133.5		26.1		216.3		354.5		-			-			730.4		-			730.4
		291.5		299.8		289.3		5,715.5		(12.4	)		-			6,583.7		-			6,583.7
Intersegment revenues
Sales of commodities		1,168.2		484.0		2.7		383.6		-			(2,038.5	)		-		-			-
Fees from midstream services		3.9		0.1		224.5		25.5		-			(254.0	)		-		-			-
		1,172.1		484.1		227.2		409.1		-			(2,292.5	)		-		-			-
Revenues	$	1,463.6	$	783.9	$	516.5	$	6,124.6	$	(12.4	)	$	(2,292.5	)	$	6,583.7	$	-		$	6,583.7
Operating margin	$	289.8	$	67.0	$	324.0	$	179.5	$	(12.4	)	$	-		$	847.9	$	(0.1	)	$	847.8
Other financial information:
Total assets	$	3,359.0	$	368.6	$	1,650.2	$	917.2	$	6.7		$	115.5		$	6,417.2	$	74.7		$	6,491.9
Capital expenditures	$	301.4	$	9.7	$	195.9	$	23.2	$	-		$	3.6		$	533.8	$	-		$	533.8

Revenues by Product and Service

The following table shows our consolidated revenues by product and service for the periods presented:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Sales of commodities:
Natural gas	$	456.1	$	335.4		$	1,201.6	$	1,085.8
NGL		772.2		1,614.8			2,656.9		4,601.2
Condensate		40.4		38.6			113.1		108.7
Petroleum products		30.8		22.4			87.3		70.7
Derivative activities		21.8		(2.0	)		60.7		(13.1	)
		1,321.3		2,009.2			4,119.6		5,853.3
Fees from midstream services:
Fractionating and treating		55.7		55.3			160.1		153.5
Storage, terminaling, transportation and export		126.8		158.8			384.6		385.8
Gathering and processing		106.6		51.9			280.7		142.6
Other		21.7		13.1			66.2		48.5
		310.8		279.1			891.6		730.4
Total revenues	$	1,632.1	$	2,288.3		$	5,011.2	$	6,583.7

Reconciliation of Operating Margin to Net Income

The following table shows a reconciliation of operating margin to net income for the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Reconciliation of operating margin to net income:
Operating margin	$	326.1		$	295.0		$	951.6		$	847.8
Depreciation and amortization expense		(165.8	)		(87.6	)		(448.3	)		(253.1	)
General and administrative expense		(44.9	)		(43.0	)		(136.5	)		(122.4	)
Interest expense, net		(70.4	)		(36.9	)		(195.6	)		(106.5	)
Other, net		(0.2	)		8.4			(36.5	)		18.5
Income tax expense		(24.0	)		(15.5	)		(54.1	)		(53.6	)
Net income	$	20.8		$	120.4		$	80.6		$	330.7

- Definition

Tabular disclosure of all significant reconciling items in the reconciliation of total profit or loss from reportable segments, to the entity's consolidated income before income taxes, extraordinary items, and discontinued operations.

+ References + Details

- Definition

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8906-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8813-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 21
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8721-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 350
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35741047&loc=d3e13816-109267

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8736-108599

+ Details

Basis of Presentation (Details)	9 Months Ended
Basis of Presentation (Details)	Sep. 30, 2015 shares
Partnership Ownership Disclosure [Abstract]
General partner ownership interest	2.00%
Parent's percentage ownership in the general partner of the Partnership	100.00%
Number of Partnership common units owned (in units)	16,309,594
Limited Partner [Member]
Partnership Ownership Disclosure [Abstract]
General partner ownership interest	8.80%

Significant Accounting Policies (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Term Loans and Notes [Member]
Debt Instrument [Line Items]
Unamortized debt issuance costs	$ 44.7	$ 29.9
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized debt issuance costs	$ 15.6	$ 8.6

Business Acquisitions (Details)		1 Months Ended	3 Months Ended			7 Months Ended	9 Months Ended
Business Acquisitions (Details)	Feb. 27, 2015 USD ($) Transaction $ / shares shares	Mar. 31, 2015 USD ($)	Sep. 30, 2015 USD ($) $ / shares	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Sep. 30, 2015 USD ($) $ / shares	Sep. 30, 2015 USD ($) MMcf / d Quarter mi $ / shares	Dec. 31, 2014 $ / shares
Business Acquisition [Line Items]
Number of separate legal transactions involved in mergers \| Transaction	2
Percentage of general partner's interest maintained							2.00%
Common units par value (in dollars per share) \| $ / shares			$ 0.001			$ 0.001	$ 0.001	$ 0.001
Acquisition-related expenses							$ 27,300,000
Revenues from acquired business						$ 1,065,700,000
Net income (loss) from acquired business						$ (1,000,000)
Targa Pipeline Partners LP [Member]
Business Acquisition [Line Items]
Processing capacity \| MMcf / d							2,053
Length of additional pipelines \| mi							12,220
Common Stock [Member]
Business Acquisition [Line Items]
Amount contributed to maintain general partner ownership percentage		$ 52,400,000
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 in 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
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
Amount contributed to maintain general partner ownership percentage		$ 52,400,000
Percentage of general partner's interest maintained		2.00%
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] \| Class E Preferred Units [Member]
Business Acquisition [Line Items]
Percentage of cumulative redeemable perpetual preferred units	8.25%
Atlas Pipeline Partners [Member] \| Phantom Unit Awards [Member]
Business Acquisition [Line Items]
Cash payment representing accelerated vesting of a portion of employees APL phantom awards	$ 600,000
Total distribution of common shares (in shares) \| shares	629,231
Atlas Pipeline Partners [Member] \| Change Of Control Payments [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition	$ 28,800,000
Atlas Pipeline Partners [Member] \| Common Units [Member] \| Atlas Energy [Member]
Business Acquisition [Line Items]
Common units owned by parent prior to closing (in units) \| shares	5,754,253
Atlas Pipeline Partners [Member] \| Revolving Credit Facility [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition	$ 701,400,000
Atlas Pipeline Partners [Member] \| Distribution Rights Year 1 [Member]
Business Acquisition [Line Items]
Reduction in incentive distribution							$ 9,375,000
Atlas Pipeline Partners [Member] \| Distribution Rights Year 2 [Member]
Business Acquisition [Line Items]
Reduction in incentive distribution							6,250,000
Atlas Pipeline Partners [Member] \| Distribution Rights Year 3 [Member]
Business Acquisition [Line Items]
Reduction in incentive distribution							2,500,000
Atlas Pipeline Partners [Member] \| Distribution Rights Year 4 [Member]
Business Acquisition [Line Items]
Reduction in incentive distribution							$ 1,250,000
Atlas Energy [Member]
Business Acquisition [Line Items]
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
Cash payment related to one-time cash payments and cash settlements of equity awards	7,300,000
Reduction in purchase price	$ (154,700,000)
Atlas Energy [Member] \| Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Total distribution of common shares (in shares) \| shares	81,740
Atlas Energy [Member] \| Phantom Unit Awards [Member]
Business Acquisition [Line Items]
Cash payment related to one-time cash payments and cash settlements of equity awards	$ 4,500,000
Atlas Energy [Member] \| Change Of Control Payments [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition	149,200,000
Atlas Energy [Member] \| Equity Award Settlements [Member]
Business Acquisition [Line Items]
Cash payments related to acquisition	$ 88,000,000
Atlas Energy [Member] \| Common Units [Member]
Business Acquisition [Line Items]
Total distribution of common shares (in shares) \| shares	10,126,532
Common units acquired	$ 147,400,000
Atlas Energy [Member] \| Common Units [Member] \| Targa Resources Partners LP [Member]
Business Acquisition [Line Items]
Total distribution of common shares (in shares) \| shares	3,363,935

Business Acquisitions, Pro Forma Impact of Atlas Mergers on Consolidated Statements of Operations (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Pro forma consolidated results of operations [Abstract]
Revenues	$ 5,299.9	$ 8,659.5
Net income	63.2	$ 340.5
Acquisition-related expenses	$ 27.3
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 Value of Consideration Transferred (Details) - USD ($)
$ in Millions

9 Months Ended

Feb. 27, 2015

Sep. 30, 2015

Sep. 30, 2014

Fair Value of Consideration Transferred [Abstract]

Cash paid, net of cash acquired

$ 1,574.4

$ 0.0

$ 5,024.2

5,024.2

Cash acquired from acquisition

40.8

TRC Non-Partnership [Member]

Fair Value of Consideration Transferred [Abstract]

Cash paid, net of cash acquired

^[1]

745.7

0.0

Fair Value of Consideration Transferred [Abstract]

Cash paid, net of cash acquired

^[1]

828.7

$ 5,024.2

Restricted Stock Units (RSUs) [Member]

Fair Value of Consideration Transferred [Abstract]

^[2]

5.2

Phantom Unit Awards [Member]

Fair Value of Consideration Transferred [Abstract]

^[2]

15.0

Common Units [Member] | Targa Resources Partners LP [Member]

Fair Value of Consideration Transferred [Abstract]

2,421.1

Common Stock [Member]

Fair Value of Consideration Transferred [Abstract]

$ 1,008.5

[1]	Net of cash acquired of $40.8 million.
[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.

Business Acquisitions, Preliminary Fair Value Determination (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Mar. 31, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Feb. 27, 2015

Dec. 31, 2014

Preliminary fair value determination [Abstract]

Trade receivables, net

$ 181.1

Other current assets

24.5

Assets from risk management activities

102.1

Property, plant and equipment

4,703.1

Investments in unconsolidated affiliates

219.7

Intangible assets

$ 1,199.0

1,199.0

Other long-term assets

5.6

Current liabilities

(258.0)

(1,573.3)

Deferred income tax liabilities, net

(8.6)

Other long-term liabilities

(9.0)

Total identifiable net assets

4,586.2

Noncontrolling interest in subsidiaries

(113.4)

Goodwill

551.4

^[1]

551.4

^[1]

551.4

$ 0.0

Total fair value consideration transferred

5,024.2

Measurement-period adjustments to preliminary acquisition date fair values [Abstract]

Revenues

1,632.1

$ 2,288.3

5,011.2

$ 6,583.7

Operating expenses

133.6

112.8

381.9

323.7

165.8

87.6

448.3

253.1

(1.6)

$ 4.7

$ (1.1)

$ 13.8

Trade receivables, fair value

178.1

Trade receivables, gross amount

178.1

Contractual receivables included in current receivables

3.0

Contractual receivables included in other long term assets

$ 4.5

Measurement Period Adjustments [Member]

Measurement-period adjustments to preliminary acquisition date fair values [Abstract]

Property, plant and equipment

9.9

Investments in unconsolidated affiliates

5.5

Intangible assets

(5.0)

Current liabilities

2.4

Other assets

(1.0)

Other current assets

(0.6)

Goodwill

(6.4)

Revenues

0.6

Operating expenses

(1.9)

(0.1)

Accounting Standards Update 2015-16 [Member] | Measurement Period Adjustments [Member]

$ (0.1)

Measurement-period adjustments to preliminary acquisition date fair values [Abstract]

$ (1.0)

$ 0.3

[1]	Total assets include goodwill. Goodwill has been preliminarily attributed to our Field Gathering and Processing segment.

Business Acquisitions, Contingent Consideration, Replacement Restricted Stock Units and Replacement Phantom Units(Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Jun. 30, 2015
Restricted Stock Units (RSUs) [Member]
Business Acquisition [Line Items]
Vesting period of original term	4 years
Number of common units called by replacement equity unit (in shares)	1
Dividend payment period	60 days
Restricted Stock Units (RSUs) [Member] \| Vesting Term One [Member]
Business Acquisition [Line Items]
Vesting percentage original term	25.00%
Restricted Stock Units (RSUs) [Member] \| Vesting Term Two [Member]
Business Acquisition [Line Items]
Vesting percentage original term	25.00%
Restricted Stock Units (RSUs) [Member] \| Vesting Term Three [Member]
Business Acquisition [Line Items]
Vesting percentage original term	75.00%
Phantom Unit Awards [Member]
Business Acquisition [Line Items]
Number of common units called by replacement equity unit (in shares)	1
Dividend payment period	60 days
Phantom Unit Awards [Member] \| Vesting Term One [Member]
Business Acquisition [Line Items]
Vesting percentage original term	25.00%
Vesting period of original term	4 years
Phantom Unit Awards [Member] \| Vesting Term Two [Member]
Business Acquisition [Line Items]
Vesting percentage original term	33.00%
Vesting period of original term	3 years
Atlas Pipeline Partners [Member]
Business Acquisition [Line Items]
Contingent consideration additional amount	$ 6.0
Contingent liability acquisition date fair value		$ 4.2
Contingent consideration liability lower range	0.0
Contingent consideration liability higher range	$ 6.0

Inventories (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Partnership [Abstract]
Commodities	$ 138.4	$ 157.4
Materials and supplies	12.7	11.5
Inventories, Net	$ 151.1	$ 168.9

- Definition

Amount after valuation and LIFO reserves of inventory expected to be sold, or consumed within one year or operating cycle, if longer.

+ References + Details

- Definition

Aggregated amount of unprocessed materials to be used in manufacturing or production process and supplies that will be consumed. This amount is net of valuation reserves and adjustments.

+ References + Details

Property, Plant and Equipment and Intangible Assets (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Feb. 27, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 11,798.4		$ 6,521.1
Accumulated depreciation	(2,048.2)		(1,696.5)
Property, plant and equipment, net	9,750.2		4,824.6
Intangible assets net [Abstract]
Intangible assets	1,880.6		681.8
Accumulated amortization	(184.9)		(89.9)
Intangible assets, net	$ 1,695.7		591.9
Estimated useful lives	20 years
Preliminary value of intangible assets acquired	$ 1,199.0	$ 1,199.0
Amortization period of acquired intangible assets used for preparing financial statements	7 months
Estimated annual amortization expense for intangible assets [Abstract]
2015	$ 129.9
2016	148.1
2017	141.3
2018	127.6
2019	116.6
Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 6,187.7		2,588.6
Gathering Systems [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Gathering Systems [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	20 years
Processing and Fractionation Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 2,996.3		1,890.7
Processing and Fractionation Facilities [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Processing and Fractionation Facilities [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	25 years
Terminaling and Storage Facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 1,098.2		1,038.9
Terminaling and Storage Facilities [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years
Terminaling and Storage Facilities [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	25 years
Transportation Assets [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 439.5		359.0
Transportation Assets [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	10 years
Transportation Assets [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	25 years
Other Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 213.7		149.3
Other Property, Plant and Equipment [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	3 years
Other Property, Plant and Equipment [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives	25 years
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 108.6		95.6
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 754.4		$ 399.0

Asset Retirement Obligations (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Changes in aggregate asset retirement obligations [Roll Forward]
Beginning of period	$ 57.1
Preliminary fair value of ARO acquired with APL merger	4.0
Change in cash flow estimate	3.8	$ 2.1
Accretion expense	4.0	$ 3.3
End of period	$ 68.9

- Definition

The carrying amount of a liability for an asset retirement obligation. An asset retirement obligation is a legal obligation associated with the disposal or retirement of a tangible long-lived asset that results from the acquisition, construction or development, or the normal operations of a long-lived asset, except for certain obligations of lessees.

+ References + Details

- Definition

Amount of accretion expense recognized during the period that is associated with an asset retirement obligation. Accretion expense measures and incorporates changes due to the passage of time into the carrying amount of the liability.

+ References + Details

Investments in Unconsolidated Affiliates (Details)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

USD ($)

JointVenture

Sep. 30, 2014

USD ($)

Sep. 30, 2015

USD ($)

JointVenture

Sep. 30, 2014

USD ($)

Schedule of Equity Method Investments [Line Items]

Number of non-operated joint ventures acquired in Atlas mergers | JointVenture

Beginning of period

$ 50.2

Preliminary fair value of T2 Joint Ventures acquired

219.7

$ (1.6)

$ 4.7

(1.1)

$ 13.8

Cash distributions

^[1]

(11.2)

Cash calls for expansion projects

6.6

End of period

264.2

Return of capital from unconsolidated affiliates

1.1

$ 4.2

Basis difference on preliminary fair values

$ 45.1

Preliminary estimated useful lives of the underlying assets

20 years

Gulf Coast Fractionators LP [Member]

Schedule of Equity Method Investments [Line Items]

38.80%

Beginning of period

$ 50.2

Preliminary fair value of T2 Joint Ventures acquired

0.0

10.1

Cash distributions

^[1]

(10.7)

Cash calls for expansion projects

0.0

End of period

$ 49.6

T2 LaSalle [Member]

Schedule of Equity Method Investments [Line Items]

75.00%

T2 Eagle Ford [Member]

Schedule of Equity Method Investments [Line Items]

50.00%

T2 EF Co-Gen [Member]

Schedule of Equity Method Investments [Line Items]

50.00%

T2 Joint Ventures [Member]

Schedule of Equity Method Investments [Line Items]

Beginning of period

$ 0.0

Preliminary fair value of T2 Joint Ventures acquired

219.7

(11.2)

Cash distributions

^[1]

(0.5)

Cash calls for expansion projects

6.6

End of period

$ 214.6

[1]

Includes $1.1 million distributions received from GCF and T2 Joint Ventures in excess of the Partnership's share of cumulative earnings for the nine months ended September 30, 2015. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in the Consolidated Statements of Cash Flows.

Accounts Payable and Accrued Liabilities (Details) - USD ($)
$ in Millions

Sep. 30, 2015

Dec. 31, 2014

Components of accounts payable and accrued liabilities [Abstract]

Commodities

^[1]

$ 416.5

$ 416.7

Other goods and services

^[1]

101.7

111.1

Interest

^[1]

68.7

37.3

Compensation and benefits

^[1]

30.7

46.1

Income and other taxes

^[1]

42.8

11.7

Other

^[1]

28.5

15.6

^[1]

688.9

638.5

Outstanding checks

28.0

13.6

Components of accounts payable and accrued liabilities [Abstract]

Commodities

416.5

416.7

Other goods and services

100.5

108.9

Interest

68.0

37.3

Compensation and benefits

1.0

1.3

Income and other taxes

42.6

13.6

Other

21.9

14.9

650.5

592.7

TRC Non Partnership [Member]

Components of accounts payable and accrued liabilities [Abstract]

Commodities

0.0

Other goods and services

1.2

2.2

Interest

0.7

0.0

Compensation and benefits

29.7

44.8

Income and other taxes

0.2

(1.9)

Other

6.6

0.7

$ 38.4

$ 45.8

[1]

Debt Obligations (Details) - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2015

Aug. 31, 2015

Dec. 31, 2014

$ 5,938.8

$ 2,885.4

Total debt

6,074.3

3,068.2

Letters of credit outstanding

11.2

44.1

TRC Senior Secured Term Loan due February 2022 [Member]

160.0

0.0

Unamortized discount

$ (2.6)

0.0

Feb. 28, 2022

Senior Secured Credit Facility [Member]

Range of interest rates and weighted average interest rate [Abstract]

Range of interest rates incurred, minimum

2.20%

Range of interest rates incurred, maximum

2.90%

2.80%

Senior Secured Term Loan [Member]

Range of interest rates and weighted average interest rate [Abstract]

Range of interest rates incurred

5.75%

Revolving Credit Facility [Member] | TRC Senior Secured Revolving Credit Facility [Member]

5.75%

$ 0.0

102.0

Revolving Credit Facility [Member] | TRC Senior Secured Revolving Credit Facility due February 2020 [Member]

Oct. 31, 2017

^[1]

$ 445.0

0.0

Targa Pipeline Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]

Feb. 29, 2020

Letters of credit outstanding

^[1]

$ 0.0

0.0

Maximum borrowing capacity

670.0

Remaining borrowing capacity

225.0

^[2],[3],[4]

13.1

0.0

Unamortized premium

^[4]

$ 0.2

0.0

6.625%

Targa Pipeline Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 4 3/4% Notes due November 2021 [Member]

Oct. 31, 2020

^[3],[4]

$ 6.5

0.0

4.75%

Targa Pipeline Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5 7/8% Notes due August 2023 [Member]

Nov. 30, 2021

^[3],[4]

$ 48.1

0.0

Unamortized premium

^[4]

$ 0.6

0.0

5.875%

Targa Resources Partners LP [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]

Aug. 31, 2023

6.625%

Targa Resources Partners LP [Member] | Senior Secured 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

4.30%

Targa Resources Partners LP [Member] | Revolving Credit Facility [Member] | TRP Senior Secured Revolving Credit Facility due October 2017 [Member]

2.20%

^[4],[5]

$ 435.0

0.0

Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5% Notes due January 2018 [Member]

Oct. 31, 2017

Letters of credit outstanding

^[5]

$ 11.2

44.1

Maximum borrowing capacity

1,600.0

Remaining borrowing capacity

1,153.8

^[4]

$ 1,100.0

0.0

5.00%

Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 4 1/8% notes due November 2019 [Member]

Jan. 31, 2018

^[4]

$ 800.0

800.0

4.125%

Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]

Nov. 30, 2019

Unamortized discount

^[2],[4]

$ 342.1

0.0

Unamortized premium

^[4]

$ 5.2

0.0

6.625%

Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 7/8% Notes due February 2021 [Member]

Oct. 31, 2020

^[4]

$ 483.6

483.6

Unamortized discount

^[4]

$ (23.0)

(25.2)

6.875%

Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 3/8% Notes due August 2022 [Member]

Feb. 28, 2021

^[4]

$ 300.0

300.0

6.375%

Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 5 1/4% Notes due May 2023 [Member]

Aug. 31, 2022

^[4]

$ 600.0

600.0

5.25%

Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 4 1/4% Notes due November 2023 [Member]

May 31, 2023

^[4]

$ 625.0

625.0

4.25%

Targa Resources Partners LP [Member] | Senior Unsecured Notes [Member] | Senior Unsecured 6 3/4% Notes due March 2024 [Member]

Nov. 30, 2023

^[4]

$ 600.0

0.0

6.75%

Targa Resources Partners LP [Member] | Accounts Receivable Securitization Facility [Member]

Mar. 31, 2024

Maximum borrowing capacity

$ 200.0

Range of interest rates and weighted average interest rate [Abstract]

Range of interest rates incurred

0.90%

Targa Resources Partners LP [Member] | Accounts Receivable Securitization Facility [Member] | Accounts Receivable Securitization Facility due December 2015 [Member]

0.90%

Current Obligations of the Partnership [Abstract]

Current debt

^[4]

$ 135.5

$ 182.8

Dec. 31, 2015

[1]	As of September 30, 2015, availability under TRC's $670.0 million senior secured revolving credit facility was $225.0 million.
[2]	In May 2015, the Partnership exchanged TRP 6.625% Senior Notes with the same economic terms to holders of the 2020 APL Notes, (as defined below) who validly tendered such notes for exchange to us.
[3]	Senior unsecured notes issued by APL entities and acquired in the ATLS mergers. While the Partnership consolidates the debt acquired in the Atlas mergers, neither we nor the Partnership guarantees the acquired debt of APL.
[4]	While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.
[5]	As of September 30, 2015, availability under the Partnership's $1.6 billion senior secured revolving credit facility ("TRP Revolver") was $1,153.8 million.

Debt Obligations, Partnership and Merger Financing Activities (Details) - USD ($) $ in Millions			1 Months Ended					9 Months Ended
	Aug. 31, 2015	Feb. 27, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Feb. 28, 2015	Jan. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Apr. 30, 2015
Debt Instrument [Line Items]
Net proceeds from issuance of senior notes								$ 1,700.0	$ 0.0
Atlas Energy [Member]
Debt Instrument [Line Items]
Cash payments related to acquisition		$ 514.7
Atlas Pipeline Partners [Member]
Debt Instrument [Line Items]
Cash payments related to change of control payments						$ 28.8
Senior Secured Term Loan [Member] \| TRC Credit Agreement [Member]
Debt Instrument [Line Items]
Expiration period for credit facility								7 years
Aggregate principal amount			$ 430.0					$ 430.0
Debt instrument discount rate								1.75%
Cash payments related to change of control payments			160.2					$ 160.2
Repayment of term loan				$ 82.0	$ 188.0
Write off of debt discount				1.4	3.3
Write off of debt issuance cost				$ 2.4	$ 5.7
Senior Secured Term Loan [Member] \| TRC Credit Agreement [Member] \| London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate								4.75%
Senior Secured Term Loan [Member] \| TRC Credit Agreement [Member] \| London Interbank Offered Rate (LIBOR) [Member] \| Interest Rate Floor [Member]
Debt Instrument [Line Items]
Debt instrument, floor interest rate								1.00%
Shelf Offering April 2015 Shelf [Member]
Debt Instrument [Line Items]
Aggregate amount of debt or equity securities allowed under shelf agreement										$ 1,000.0
Revolving Credit Facility [Member] \| TRC Credit Agreement [Member]
Debt Instrument [Line Items]
Expiration period for credit facility								5 years
Aggregate principal amount			670.0					$ 670.0
Revolving Credit Facility [Member] \| Atlas Pipeline Partners [Member]
Debt Instrument [Line Items]
Cash payments related to acquisition						701.4
Targa Resources Partners LP [Member] \| Revolving Credit Facility [Member] \| TRP Senior Secured Revolving Credit Facility due October 2017 [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity			1,600.0					1,600.0
Targa Resources Partners LP [Member] \| Revolving Credit Facility [Member] \| First Amendment [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity						1,600.0
Additional commitment increase available upon request						$ 300.0
Targa Resources Partners LP [Member] \| Revolving Credit Facility [Member] \| Original Agreement [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity							$ 1,200.0
Additional commitment increase available upon request							300.0
Targa Resources Partners LP [Member] \| Accounts Receivable Securitization Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 200.0
Reduction in maximum borrowing capacity	$ 100.0
Partnership Issuers [Member] \| Senior Unsecured Notes [Member] \| Senior Unsecured 5% Notes due January 2018 [Member]
Debt Instrument [Line Items]
Aggregate principal amount							1,100.0
Net proceeds from issuance of senior notes							$ 1,089.8
Partnership Issuers [Member] \| Senior Unsecured Notes [Member] \| Senior Unsecured 6 3/4% Notes due March 2024 [Member]
Debt Instrument [Line Items]
Aggregate principal amount			600.0					$ 600.0
Net proceeds from issuance of senior notes			$ 595.0

Debt Obligations, APL Senior Notes Tender Offers (Details) - USD ($) $ in Thousands		1 Months Ended	2 Months Ended
	Feb. 27, 2015	Mar. 31, 2015	Feb. 27, 2015
Atlas Pipeline Partners [Member]
Results of tender offers [Abstract]
Amount Tendered and Paid	$ 1,200,000
APL Senior Notes Tender Offers [Member]
Results of tender offers [Abstract]
Outstanding Note Balance			$ 1,550,000
Amount Tendered and Paid			1,135,500
Premium Paid			16,700
Accrued Interest Paid			11,600
Total Tender Offer payments			1,163,800
Note Balance after Tender Offers	414,500		414,500
APL Senior Notes Tender Offers [Member] \| Senior Unsecured 6 5/8% Notes due October 2020 [Member]
Results of tender offers [Abstract]
Outstanding Note Balance			500,000
Amount Tendered and Paid			140,100
Premium Paid			2,100
Accrued Interest Paid			3,700
Total Tender Offer payments			$ 145,900
Tendered percentage			28.02%
Note Balance after Tender Offers	359,900		$ 359,900
APL Senior Notes Tender Offers [Member] \| Senior Unsecured 4 3/4% Notes due November 2021 [Member]
Results of tender offers [Abstract]
Outstanding Note Balance			400,000
Amount Tendered and Paid			393,500
Premium Paid			5,900
Accrued Interest Paid			5,300
Total Tender Offer payments			$ 404,700
Tendered percentage			98.38%
Note Balance after Tender Offers	6,500		$ 6,500
APL Senior Notes Tender Offers [Member] \| Senior Unsecured 5 7/8% Notes due August 2023 [Member]
Results of tender offers [Abstract]
Outstanding Note Balance			650,000
Amount Tendered and Paid			601,900
Premium Paid			8,700
Accrued Interest Paid			2,600
Total Tender Offer payments			$ 613,200
Tendered percentage			92.60%
Note Balance after Tender Offers	$ 48,100		$ 48,100
APL Senior Notes with Offers Tendered [Member] \| Senior Unsecured 6 5/8% Notes due October 2020 [Member] \| Atlas Pipeline Partners [Member]
Results of tender offers [Abstract]
Total Tender Offer payments		$ 5,000

Debt Obligations, Debt Redemption (Details) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	9 Months Ended
	Mar. 31, 2015	Feb. 27, 2015	Sep. 30, 2015	Sep. 30, 2014
Results of tender offers [Abstract]
Repayment of debt			$ 1,168,800	$ 0
APL Senior Notes Tender Offers [Member]
Results of tender offers [Abstract]
Total tender offer payments		$ 1,163,800
APL Senior Notes Tender Offers [Member] \| Atlas Pipeline Partners [Member]
Results of tender offers [Abstract]
Repayment of debt			$ 1,168,800
APL Senior Notes Tender Offers [Member] \| Senior Unsecured 6 5/8% Notes due October 2020 [Member]
Results of tender offers [Abstract]
Total tender offer payments		$ 145,900
APL Senior Notes with Offers Tendered [Member] \| Senior Unsecured 6 5/8% Notes due October 2020 [Member] \| Atlas Pipeline Partners [Member]
Results of tender offers [Abstract]
Repayment of debt	$ 4,800
Total tender offer payments	$ 5,000

Debt Obligations, Exchange Offer and Consent Solicitation and TRP Note Guarantees (Details) - Senior Unsecured 6 5/8% Notes due October 2020 [Member] - Atlas Pipeline Partners [Member] - USD ($) $ in Millions		9 Months Ended
	Apr. 27, 2015	Sep. 30, 2015	May 31, 2015
Partnership Issuers [Member]
Debt Instrument [Line Items]
Aggregate principal amount outstanding			$ 342.1
Unamortized premium			$ 5.6
Targa Resources Partners LP [Member]
Debt Instrument [Line Items]
Tendered percentage	96.30%
Costs associated with exchange offer		$ 0.5

- Definition

Including the current and noncurrent portions, carrying value as of the balance sheet date of Notes with the highest claim on the assets of the issuer in case of bankruptcy or liquidation (with maturities initially due after one year or beyond the operating cycle if longer). Senior note holders are paid off in full before any payments are made to junior note holders.

+ References + Details

Partnership Units and Related Matters, Issuances of Common Units (Details) - USD ($) $ / shares in Units, $ in Millions			1 Months Ended				9 Months Ended
	Oct. 20, 2015	Feb. 27, 2015	Oct. 31, 2015	May 31, 2015	Mar. 31, 2015	Jan. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Partnership Equity [Abstract]
General partner ownership interest							2.00%
Preferred unit, price per unit (in dollars per share)							$ 0.001	$ 0.001
Senior Notes 6 5/8% due 2021 [Member]
Partnership Equity [Abstract]
Interest rate of partnership indebtedness percentage							6.625%
Targa Resources Partners LP [Member] \| Senior Notes 5% Due 2019 [Member]
Partnership Equity [Abstract]
Interest rate of partnership indebtedness percentage							5.00%
Maturity date							Dec. 31, 2019
Targa Resources Partners LP [Member] \| Senior Notes 4 1/8% due 2019 [Member]
Partnership Equity [Abstract]
Interest rate of partnership indebtedness percentage							4.125%
Targa Resources Partners LP [Member] \| Senior Notes 6 7/8% due 2021 [Member]
Partnership Equity [Abstract]
Interest rate of partnership indebtedness percentage							6.875%
Maturity date							Dec. 31, 2021
Targa Resources Partners LP [Member] \| Senior Notes 6 3/8% due 2022 [Member]
Partnership Equity [Abstract]
Interest rate of partnership indebtedness percentage							6.375%
Maturity date							Dec. 31, 2022
Targa Resources Partners LP [Member] \| Senior Notes 5 1/4% due 2023 [Member]
Partnership Equity [Abstract]
Interest rate of partnership indebtedness percentage							5.25%
Maturity date							Dec. 31, 2023
Targa Resources Partners LP [Member] \| Senior Notes 4 1/4% due 2023 [Member]
Partnership Equity [Abstract]
Interest rate of partnership indebtedness percentage							4.25%
Maturity date							Dec. 31, 2023
Targa Resources Partners LP [Member] \| Senior Notes 6 3/4% due 2023 [Member]
Partnership Equity [Abstract]
Interest rate of partnership indebtedness percentage							6.75%
Series A Preferred Units [Member]
Partnership Equity [Abstract]
Preferred unit, redemption price (in dollars per share)							$ 25
Series A Preferred Units [Member] \| Initial Distribution from October 15, 2015 through October 31, 2015 [Member]
Partnership Equity [Abstract]
Date of declaration for cash distribution							Oct. 20, 2015
Payment date for cash distribution							Nov. 16, 2015
Date of record for cash distribution							Oct. 30, 2015
Series A Preferred Units [Member] \| Subsequent Event [Member]
Partnership Equity [Abstract]
Cash distribution declared per unit (in dollars per share)	$ 0.10
Series A Preferred Units [Member] \| Subsequent Event [Member] \| LIBOR [Member]
Partnership Equity [Abstract]
Percentage of variable interest rate for distribution on preferred units			7.71%
Atlas Energy [Member] \| Common Units [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)		10,126,532
Atlas Energy [Member] \| Common Units [Member] \| Targa Resources Partners LP [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)		3,363,935
Atlas Pipeline Partners [Member]
Partnership Equity [Abstract]
Amount contributed to maintain general partner ownership percentage					$ 52.4
General partner ownership interest					2.00%
Atlas Pipeline Partners [Member] \| Common Unit Holders [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)		58,614,157
May 2014 EDA [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)							7,377,380
Dollar amount of common units able to sell from equity distribution agreement						$ 158.4
Net proceeds from public offering							$ 316.1
Amount which remain available under the shelf agreement							4.2
Amount contributed to maintain general partner ownership percentage							$ 6.5
General partner ownership interest							2.00%
May 2015 EDA [Member]
Partnership Equity [Abstract]
Number of common units included in public offerings (in shares)							7,377,380
Dollar amount of common units able to sell from equity distribution agreement				$ 1,000.0
Net proceeds from public offering							$ 316.1
Amount which remain available under the shelf agreement							835.6
Amount contributed to maintain general partner ownership percentage							$ 6.5
General partner ownership interest							2.00%
April 2013 Shelf [Member] \| Series A Preferred Units [Member] \| Subsequent Event [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)			$ 25.00
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 Related Matters, Distributions (Details)

3 Months Ended

9 Months Ended

Sep. 30, 2015

USD ($)

$ / shares

Jun. 30, 2015

USD ($)

$ / shares

Mar. 31, 2015

USD ($)

$ / shares

Dec. 31, 2014

USD ($)

$ / shares

Sep. 30, 2015

USD ($)

QuarterlyDistribution

Partnership Equity [Abstract]

Number of days from end of each quarter by when cash is distributed to unit holders

45 days

Distributions declared and/or paid by the Partnership [Abstract]

Number of quarterly distributions that will be reduced | QuarterlyDistribution

Distributions Declared [Member]

Distributions declared and/or paid by the Partnership [Abstract]

Nov. 13, 2015

Distributions to limited partners common

$ 152,500,000

Distributions to general partners (Incentive distribution rights)

^[1]

43,900,000

Distributions to general partner (2%)

4,000,000

Total distributions to general and limited partners

200,400,000

Distributions to Targa Resources Corp.

$ 61,400,000

Distributions per limited partner unit (in dollars per unit) | $ / shares

$ 0.8250

Distributions Paid [Member]

Distributions declared and/or paid by the Partnership [Abstract]

Aug. 14, 2015

May 15, 2015

Feb. 13, 2015

Distributions to limited partners common

$ 152,500,000

$ 148,300,000

$ 96,300,000

Distributions to general partners (Incentive distribution rights)

43,900,000

^[1]

41,700,000

^[1]

38,400,000

Distributions to general partner (2%)

4,000,000

3,900,000

2,700,000

Total distributions to general and limited partners

200,400,000

193,900,000

137,400,000

Distributions to Targa Resources Corp.

$ 61,400,000

$ 59,000,000

$ 51,600,000

Distributions per limited partner unit (in dollars per unit) | $ / shares

$ 0.8250

$ 0.8200

$ 0.8100

Atlas Pipeline Partners [Member]

Distributions declared and/or paid by the Partnership [Abstract]

$ 9,375,000

Atlas Pipeline Partners [Member] | Distribution Rights Year 1 [Member]

Distributions declared and/or paid by the Partnership [Abstract]

$ 9,375,000

Atlas Pipeline Partners [Member] | Distribution Rights Year 2 [Member]

Distributions declared and/or paid by the Partnership [Abstract]

6,250,000

Atlas Pipeline Partners [Member] | Distribution Rights Year 3 [Member]

Distributions declared and/or paid by the Partnership [Abstract]

2,500,000

Atlas Pipeline Partners [Member] | Distribution Rights Year 4 [Member]

Distributions declared and/or paid by the Partnership [Abstract]

$ 1,250,000

[1]

Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDR's of $9.375 million were allocated to common unitholders in the first and second quarter of 2015. The IDR Giveback Amendment covers sixteen quarterly distribution declarations following the completion of the Atlas mergers on February 27, 2015 and will result in reallocation of IDR payments to common unitholders at the following amounts: $9.375 million per quarter for 2015, $6.25 million per quarter for 2016, $2.5 million per quarter for 2017 and $1.25 million per quarter for 2018.

Common Stock and Related Matters (Details) - USD ($)
$ / shares in Units, $ in Millions

1 Months Ended

3 Months Ended

9 Months Ended

Feb. 27, 2015

Mar. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2015

Sep. 30, 2014

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Value of shares issued in exchange for ATLS common units

$ 0.1

$ 0.0

$ 0.1

Common stock closing market price (in dollars per share)

$ 99.58

Common stock net proceeds of public offering

$ 335.5

General partnership interest

2.00%

Additional net proceeds from public offering pursuant to exercise of underwriters' overallotment option

$ 128.0

$ 82.2

Common Stock [Member]

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Number of shares issued in public offering (in shares)

3,250,000

3,738,000

Common stock issued price per share (in dollars per share)

$ 91

Common stock net proceeds of public offering

$ 292.8

$ 0.0

Number of additional shares sold in public offering (in shares)

487,500

$ 43.9

Payments to capital contribution in partnership

$ 52.4

General partnership interest

2.00%

Dividend Declared, Q3 2015 [Member]

Nov. 16, 2015

$ 51.2

50.9

^[1]

$ 0.3

Dividend declared per share of common stock (in dollars per share)

$ 0.91000

Dividend Declared, Q2 2015 [Member]

Aug. 17, 2015

$ 49.2

49.0

^[1]

$ 0.2

Dividend declared per share of common stock (in dollars per share)

$ 0.87500

Dividend Declared, Q1 2015 [Member]

May 18, 2015

$ 46.6

46.4

^[1]

$ 0.2

Dividend declared per share of common stock (in dollars per share)

$ 0.83000

Dividend Declared, Q4 2014 [Member]

Feb. 17, 2015

$ 32.8

32.6

Antidilutive shares excluded from the computation of diluted earnings per share (in shares)

^[1]

$ 0.2

Dividend declared per share of common stock (in dollars per share)

$ 0.77500

Atlas Energy [Member]

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Number of shares issued in exchange for ATLS common units (in shares)

10,126,532

Value of shares issued in exchange for ATLS common units

$ 1,000.0

Replacement restricted stock units (in shares)

81,740

[1]	Represents accrued dividends on restricted stock units that are payable upon vesting.

Earnings per Common Share (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Earnings per Common Share [Abstract]

Net income

$ 20.8

$ 120.4

$ 80.6

$ 330.7

Less: Net income attributable to noncontrolling interests

8.1

89.7

49.2

253.9

Net income attributable to common shareholders

$ 12.7

$ 30.7

$ 31.4

$ 76.8

Weighted average shares outstanding - basic (in shares)

56,000,000

42,000,000

52,600,000

42,000,000

Net income available per common share - basic (in dollars per share)

$ 0.23

$ 0.73

$ 0.60

$ 1.83

Weighted average shares outstanding (in shares)

56,000,000

42,000,000

52,600,000

42,000,000

Dilutive effect of unvested stock awards (in shares)

100,000

Weighted average shares outstanding - diluted (in shares)

^[1]

56,100,000

42,100,000

52,700,000

42,100,000

Net income available per common share - diluted (in dollars per share)

$ 0.23

$ 0.73

$ 0.60

$ 1.82

30,195

27,529

[1]	For the three and nine months ended September 30, 2015, approximately 30,195 shares and 27,529 shares were excluded from the computation of diluted earnings per share because the inclusion of such shares would have been anti-dilutive.

Derivative Instruments and Hedging Activities (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015 USD ($)	Sep. 30, 2015 USD ($) MMBTU bbl	Feb. 27, 2015 USD ($)
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 \| $	$ 20.7	$ 52.2
Ineffectiveness gains \| $	0.4	$ 1.3
Swaps [Member] \| Year 2015 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		163,456
Swaps [Member] \| Year 2015 [Member] \| NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		4,268
Swaps [Member] \| Year 2015 [Member] \| Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		1,663
Swaps [Member] \| Year 2016 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		79,399
Swaps [Member] \| Year 2016 [Member] \| NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		2,674
Swaps [Member] \| Year 2016 [Member] \| Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		1,082
Swaps [Member] \| Year 2017 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		23,082
Swaps [Member] \| Year 2017 [Member] \| NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		1,078
Swaps [Member] \| Year 2017 [Member] \| Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		500
Swaps [Member] \| Year 2018 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		0
Swaps [Member] \| Year 2018 [Member] \| NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		208
Swaps [Member] \| Year 2018 [Member] \| Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		0
Basis Swaps [Member] \| Year 2015 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		88,099
Basis Swaps [Member] \| Year 2016 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		48,962
Basis Swaps [Member] \| Year 2017 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		18,082
Basis Swaps [Member] \| Year 2018 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		0
Collars [Member] \| Year 2015 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		15,400
Collars [Member] \| Year 2016 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		22,900
Collars [Member] \| Year 2017 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		22,900
Collars [Member] \| Year 2018 [Member] \| Natural Gas [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (MMBtu per day) \| MMBTU		9,486
Option/Collars [Member] \| Year 2015 [Member] \| NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		920
Option/Collars [Member] \| Year 2015 [Member] \| Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		1,605
Option/Collars [Member] \| Year 2016 [Member] \| NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		920
Option/Collars [Member] \| Year 2016 [Member] \| Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		790
Option/Collars [Member] \| Year 2017 [Member] \| NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		920
Option/Collars [Member] \| Year 2017 [Member] \| Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		790
Option/Collars [Member] \| Year 2018 [Member] \| NGL [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		32
Option/Collars [Member] \| Year 2018 [Member] \| Condensate [Member]
Derivative [Line Items]
Notional volumes of commodity hedges (Bbl per day)		101
Options [Member] \| Crude Oil [Member] \| Atlas Pipeline Partners [Member]
Derivative [Line Items]
Fair value of derivative assets \| $			$ 7.7
Mark-to-market gains \| $	$ 1.3	$ 1.0

Derivative Instruments and Hedging Activities, Fair Values Derivatives, Balance Sheet Location, by Derivative Contract Type (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative assets	$ 137.7	$ 60.2
Derivative liabilities	8.3	5.2
Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	92.3	44.4
Long-Term Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	45.4	15.8
Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	4.3	5.2
Long-Term Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	4.0	0.0
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	134.4	60.2
Derivative liabilities	6.1	0.0
Designated as Hedging Instrument [Member] \| Commodity Contracts [Member] \| Current Assets from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	89.0	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	45.4	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	0.0
Designated as Hedging Instrument [Member] \| Commodity Contracts [Member] \| Long-Term Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	4.0	0.0
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	3.3	0.0
Derivative liabilities	2.2	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	3.3	0.0
Not Designated as Hedging Instrument [Member] \| Commodity Contracts [Member] \| Current Liabilities from Risk Management Activities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 2.2	$ 5.2

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Assets (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivative Asset [Abstract]
Pro forma net presentation, asset	$ 129.4
Gross asset	137.7	$ 60.2
Pro forma net presentation, asset, total	129.4	55.8
Counterparties with Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	131.6	35.5
Gross liability	8.3	4.4
Pro forma net presentation, asset	123.3	31.1
Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	6.1	24.7
Current Position [Member]
Derivative Asset [Abstract]
Gross asset	92.3	44.4
Pro forma net presentation, asset, current	88.0	40.0
Current Position [Member] \| Counterparties with Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	87.3	35.5
Gross liability	4.3	4.4
Pro forma net presentation, asset	83.0	31.1
Current Position [Member] \| Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	5.0	8.9
Long-term Position [Member]
Derivative Asset [Abstract]
Gross asset	45.4	15.8
Pro forma net presentation, asset, noncurrent	41.4	15.8
Long-term Position [Member] \| Counterparties with Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	44.3	0.0
Gross liability	4.0	0.0
Pro forma net presentation, asset	40.3	0.0
Long-term Position [Member] \| Counterparties without Offsetting Position [Member]
Derivative Asset [Abstract]
Gross asset	$ 1.1	$ 15.8

Derivative Instruments and Hedging Activities, Pro Forma Impact - Offsetting Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivative Liability [Abstract]
Gross liability	$ 8.3	$ 5.2
Pro forma net presentation, liability, total	0.0	0.8
Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	0.0	0.8
Current Position [Member]
Derivative Liability [Abstract]
Gross liability	4.3	5.2
Pro forma net presentation, liability, current	0.0	0.8
Current Position [Member] \| Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	0.0	0.8
Long-term Position [Member]
Derivative Liability [Abstract]
Gross liability	4.0	0.0
Pro forma net presentation, liability, noncurrent	0.0	0.0
Long-term Position [Member] \| Counterparties without Offsetting Position [Member]
Derivative Liability [Abstract]
Gross liability	$ 0.0	$ 0.0

- Definition

Fair value, before effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities elected not to be offset. Excludes liabilities not subject to a master netting arrangement.

+ References + Details

- Definition

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities not subject to a master netting arrangement and not elected to be offset.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 20
-Section 55
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=51825145&loc=SL20226008-175313

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
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-Section 50
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-URI http://asc.fasb.org/extlink&oid=49121117&loc=d3e13495-108611

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Paragraph 3
-Subparagraph (c)
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Topic 815
-SubTopic 10
-Section 45
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6945355&loc=d3e41228-113958

+ Details

- Definition

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset, expected to be settled within one year or normal operating cycle, if longer. Includes assets not subject to a master netting arrangement and not elected to be offset.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 20
-Section 50
-Paragraph 3
-Subparagraph (c)
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Current Liabilities
-URI http://asc.fasb.org/extlink&oid=6509677

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 45
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6945355&loc=d3e41228-113958

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
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-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=49121117&loc=d3e13495-108611

+ Details

- Definition

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset, expected to be settled after one year or the normal operating cycle, if longer. Includes assets not subject to a master netting arrangement and not elected to be offset.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 20
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=51824906&loc=SL20225862-175312

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=49121117&loc=d3e13495-108611

+ Details

Derivative Instruments and Hedging Activities, Amounts Included in OCI, Income and AOCI (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Dec. 31, 2014

Cash Flow Hedging [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from OCI into income (effective portion)

$ 16.7

$ (0.8)

$ 41.1

$ (14.0)

Cash Flow Hedging [Member] | Interest Expense, Net [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from OCI into income (effective portion)

0.0

(2.4)

Cash Flow Hedging [Member] | Revenues [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) reclassified from OCI into income (effective portion)

16.7

(0.8)

41.1

(11.6)

Cash Flow Hedging [Member] | Commodity Contracts [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) recognized in OCI on derivatives (effective portion)

42.9

14.2

59.4

(4.5)

Deferred gains (losses) included in accumulated OCI, before tax

^[1]

78.5

$ 60.3

Net losses on commodity hedges recorded in OCI that are expected to be reclassified to revenue within twelve months

45.1

Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member] | Revenues [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gain (loss) recognized in income on derivatives

$ (4.0)

$ (1.5)

$ (0.9)

$ (1.4)

[1]	Includes deferred net gains of $45.1 million as of September 30, 2015 related to contracts that will be settled and reclassified to revenue over the next 12 months.

Fair Value Measurements (Details)
$ in Millions

9 Months Ended

Sep. 30, 2015

USD ($)

Swap

Dec. 31, 2014

USD ($)

Fair Value Measurements [Abstract]

Derivative financial instruments, fair value, net

$ 129.4

Derivative fair value of net asset if commodity price increases by 10 percent

105.3

Derivative fair value of net asset if commodity price decreases by 10 percent

152.0

Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]

129.4

$ 55.8

Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward] [Roll Forward]

$ 0.0

$ 0.8

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

Number of natural gas basis swaps categorized as Level 3 | Swap

Balance, beginning of period

$ (1.7)

TPL contingent consideration (Note 4 - Business Acquisitions)

0.0

New Level 3 instruments

(3.3)

Transfers out of Level 3

1.7

Balance, end of period

(3.3)

Level 1 [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]

^[1]

0.0

^[1]

0.0

^[2]

0.0

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 1 [Member] | TRC Senior Secured Revolving Credit Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 1 [Member] | Senior Secured Term Loan [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 1 [Member] | Partnership's Senior Secured Revolving Credit Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 1 [Member] | Partnership's Senior Unsecured Notes [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 1 [Member] | Partnership's Accounts Receivable Securitization Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 2 [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]

^[1]

133.1

^[1]

7.0

^[2]

0.0

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 2 [Member] | TRC Senior Secured Revolving Credit Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

445.0

Level 2 [Member] | Senior Secured Term Loan [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

159.5

Level 2 [Member] | Partnership's Senior Secured Revolving Credit Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

435.0

Level 2 [Member] | Partnership's Senior Unsecured Notes [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

4,567.5

Level 2 [Member] | Partnership's Accounts Receivable Securitization Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

135.5

Level 3 [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]

^[1]

4.6

^[1]

1.3

^[2]

4.2

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 3 [Member] | TRC Senior Secured Revolving Credit Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 3 [Member] | Senior Secured Term Loan [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 3 [Member] | Partnership's Senior Secured Revolving Credit Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 3 [Member] | Partnership's Senior Unsecured Notes [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Level 3 [Member] | Partnership's Accounts Receivable Securitization Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

0.0

Carrying Value [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]

^[1]

137.7

^[1]

8.3

^[2]

4.2

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

102.9

Carrying Value [Member] | TRC Senior Secured Revolving Credit Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

445.0

Carrying Value [Member] | Senior Secured Term Loan [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

Carrying Value [Member] | Partnership's Senior Secured Revolving Credit Facility [Member]

157.4

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

435.0

Carrying Value [Member] | Partnership's Senior Unsecured Notes [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

Carrying Value [Member] | Partnership's Accounts Receivable Securitization Facility [Member]

4,901.4

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

135.5

Fair Value [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value [Abstract]

^[1]

137.7

^[1]

8.3

^[2]

4.2

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

102.9

Fair Value [Member] | TRC Senior Secured Revolving Credit Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

445.0

Fair Value [Member] | Senior Secured Term Loan [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

159.5

Fair Value [Member] | Partnership's Senior Secured Revolving Credit Facility [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

435.0

Fair Value [Member] | Partnership's Senior Unsecured Notes [Member]

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

Fair Value [Member] | Partnership's Accounts Receivable Securitization Facility [Member]

4,567.5

Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value [Abstract]

Changes in fair value of financial instruments classified as Level 3 in fair value hierarchy [Roll Forward]

135.5

Contingent Liability [Member]

Balance, beginning of period

0.0

TPL contingent consideration (Note 4 - Business Acquisitions)

4.2

New Level 3 instruments

0.0

Transfers out of Level 3

0.0

Balance, end of period

$ 4.2

[1]

The fair value of the derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 14. 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

Contingencies (Details)		2 Months Ended	3 Months Ended	9 Months Ended
Contingencies (Details)	Nov. 04, 2015 USD ($)	Nov. 30, 2014 Unitholder	Dec. 31, 2014 Unitholder	Sep. 30, 2015 ThermalOxidizers
Atlas Unitholder Litigation [Member] \| Atlas Pipeline Partners [Member]
Loss Contingencies [Line Items]
Number of public unitholders \| Unitholder			5
Atlas Unitholder Litigation [Member] \| Atlas Energy [Member]
Loss Contingencies [Line Items]
Number of public unitholders \| Unitholder		2
Environment Proceeding [Member]
Loss Contingencies [Line Items]
Number of regenerative thermal oxidizers \| ThermalOxidizers				2
Period within which to install a flare gas recovery unit at Mont Belvieu Fractionator				1 year
Environment Proceeding [Member] \| Subsequent Event [Member]
Loss Contingencies [Line Items]
Contingencies penalty amount \| $	$ 115,644
Environment Proceeding [Member] \| Subsequent Event [Member] \| Supplemental Environmental Projects [Member]
Loss Contingencies [Line Items]
Contingencies penalty amount \| $	$ 115,643

Supplemental Cash Flow Information (Details) - USD ($)
$ in Millions

9 Months Ended

Feb. 27, 2015

Sep. 30, 2015

Sep. 30, 2014

Cash [Abstract]

Interest paid, net of capitalized interest

^[1]

$ 163.4

$ 90.3

Income taxes paid, net of refunds

13.3

55.2

Non-cash Investing and Financing balance sheet movements [Abstract]

Debt additions and retirements related to exchange of TRP 6.625% Notes for APL 6.625% Notes

342.1

0.0

Deadstock commodity inventories transferred to property, plant and equipment

1.2

15.2

Reductions in Owner's Equity related to accrued dividends on unvested equity awards under share compensation arrangements

0.3

0.5

Impact of capital expenditure accruals on property, plant and equipment

(57.2)

(40.6)

Transfers from materials and supplies inventory to property, plant and equipment

2.9

2.7

Change in ARO liability and property, plant and equipment due to revised future ARO cash flow estimate

3.8

2.1

Non-cash balance sheet movements related to business acquisition: (see Note 4) [Abstract]

Non-cash merger consideration - common units and replacement equity awards

2,436.1

0.0

Non-cash merger consideration - common shares and replacement equity awards

1,013.7

0.0

Net non-cash balance sheet movements excluded from consolidated statements of cash flows

3,449.8

0.0

Net cash merger consideration included in investing activities

1,574.4

0.0

Atlas Pipeline Partners [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]

5,024.2

0.0

Interest capitalized on major projects

$ 9.1

$ 14.3

Debt Instrument [Line Items]

6.625%

Targa Resources Partners LP [Member] | Senior Unsecured 6 5/8% Notes due October 2020 [Member]

Non-cash balance sheet movements related to business acquisition: (see Note 4) [Abstract]

Net cash merger consideration included in investing activities

^[2]

$ 828.7

Debt Instrument [Line Items]

6.625%

[1]	Interest capitalized on major projects was $9.1 million and $14.3 million for the nine months ended September 30, 2015 and 2014.
[2]	Net of cash acquired of $40.8 million.

Segment Information, Revenues and Operating Margin (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)	Sep. 30, 2015 USD ($) Division Segment	Sep. 30, 2014 USD ($)
Segment Reporting Information [Line Items]
Number of divisions \| Division			2
Revenues [Abstract]
Sale of commodities	$ 1,321.3	$ 2,009.2	$ 4,119.6	$ 5,853.3
Fees from midstream services	310.8	279.1	891.6	730.4
Revenues	1,632.1	2,288.3	5,011.2	6,583.7
Operating margin	326.1	295.0	951.6	847.8
Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	1,321.3	2,009.2	4,119.6	5,853.3
Fees from midstream services	310.8	279.1	891.6	730.4
Revenues	1,632.1	2,288.3	5,011.2	6,583.7
Operating margin	326.1	295.0	951.7	847.9
TRC Non-Partnership [Member]
Revenues [Abstract]
Sale of commodities	0.0	0.0	0.0	0.0
Fees from midstream services	0.0	0.0	0.0	0.0
Revenues	0.0	0.0	0.0	0.0
Operating margin	0.0	0.0	$ (0.1)	(0.1)
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] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Revenues	726.1	486.5	$ 1,929.6	1,463.6
Operating margin	132.6	98.0	349.9	289.8
Coastal Gathering and Processing [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Revenues	117.3	235.0	359.2	783.9
Operating margin	7.9	19.1	$ 22.1	67.0
Logistics and Marketing [Member]
Segment Reporting Information [Line Items]
Number of reportable segments per division \| Segment			2
Logistics Assets [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Revenues	181.5	185.8	$ 555.7	516.5
Operating margin	103.6	118.6	341.7	324.0
Marketing and Distribution [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Revenues	981.7	2,128.0	3,350.4	6,124.6
Operating margin	60.2	61.6	177.3	179.5
Other Segment [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Revenues	21.8	(2.3)	60.7	(12.4)
Operating margin	21.8	(2.3)	60.7	(12.4)
Corporate and Eliminations [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Revenues	(396.3)	(744.7)	(1,244.4)	(2,292.5)
Operating margin	0.0	0.0	0.0	0.0
Operating Segments [Member] \| Field Gathering and Processing [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	419.5	49.4	1,021.4	158.0
Fees from midstream services	108.4	49.4	277.8	133.5
Revenues	527.9	98.8	1,299.2	291.5
Operating Segments [Member] \| Coastal Gathering and Processing [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	50.8	83.4	156.1	273.7
Fees from midstream services	8.9	8.0	25.1	26.1
Revenues	59.7	91.4	181.2	299.8
Operating Segments [Member] \| Logistics Assets [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	31.3	23.1	89.4	73.0
Fees from midstream services	82.4	75.5	259.9	216.3
Revenues	113.7	98.6	349.3	289.3
Operating Segments [Member] \| Marketing and Distribution [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	797.9	1,855.6	2,792.0	5,361.0
Fees from midstream services	111.1	146.2	328.8	354.5
Revenues	909.0	2,001.8	3,120.8	5,715.5
Operating Segments [Member] \| Other Segment [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	21.8	(2.3)	60.7	(12.4)
Fees from midstream services	0.0	0.0	0.0	0.0
Revenues	21.8	(2.3)	60.7	(12.4)
Operating Segments [Member] \| Corporate and Eliminations [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	0.0	0.0	0.0	0.0
Fees from midstream services	0.0	0.0	0.0	0.0
Revenues	0.0	0.0	0.0	0.0
Intersegment Eliminations [Member]
Revenues [Abstract]
Sale of commodities	0.0	0.0	0.0	0.0
Fees from midstream services	0.0	0.0	0.0	0.0
Revenues	0.0	0.0	0.0	0.0
Intersegment Eliminations [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	0.0	0.0	0.0	0.0
Fees from midstream services	0.0	0.0	0.0	0.0
Revenues	0.0	0.0	0.0	0.0
Intersegment Eliminations [Member] \| TRC Non-Partnership [Member]
Revenues [Abstract]
Sale of commodities	0.0	0.0	0.0	0.0
Fees from midstream services	0.0	0.0	0.0	0.0
Revenues	0.0	0.0	0.0	0.0
Intersegment Eliminations [Member] \| Field Gathering and Processing [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	195.8	386.0	624.1	1,168.2
Fees from midstream services	2.4	1.7	6.3	3.9
Revenues	198.2	387.7	630.4	1,172.1
Intersegment Eliminations [Member] \| Coastal Gathering and Processing [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	57.6	143.6	178.0	484.0
Fees from midstream services	0.0	0.0	0.0	0.1
Revenues	57.6	143.6	178.0	484.1
Intersegment Eliminations [Member] \| Logistics Assets [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	3.2	1.3	6.4	2.7
Fees from midstream services	64.6	85.9	200.0	224.5
Revenues	67.8	87.2	206.4	227.2
Intersegment Eliminations [Member] \| Marketing and Distribution [Member] \| Reportable Segments [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	67.3	116.1	214.4	383.6
Fees from midstream services	5.4	10.1	15.2	25.5
Revenues	72.7	126.2	229.6	409.1
Intersegment Eliminations [Member] \| Other Segment [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	0.0	0.0	0.0	0.0
Fees from midstream services	0.0	0.0	0.0	0.0
Revenues	0.0	0.0	0.0	0.0
Intersegment Eliminations [Member] \| Corporate and Eliminations [Member] \| Targa Resources Partners LP [Member]
Revenues [Abstract]
Sale of commodities	(323.9)	(647.0)	(1,022.9)	(2,038.5)
Fees from midstream services	(72.4)	(97.7)	(221.5)	(254.0)
Revenues	$ (396.3)	$ (744.7)	$ (1,244.4)	$ (2,292.5)

Segment Information, Other Financial Information (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2015

Sep. 30, 2014

Sep. 30, 2015

Sep. 30, 2014

Feb. 27, 2015

Dec. 31, 2014

Total assets

$ 13,418.2

^[1]

$ 6,491.9

$ 13,418.2

^[1]

$ 6,491.9

$ 6,453.5

Goodwill

551.4

^[2]

551.4

^[2]

$ 551.4

$ 0.0

186.2

142.9

571.0

533.8

5,024.2

$ 5,024.2

Total assets

13,323.2

^[1]

6,417.2

13,323.2

^[1]

6,417.2

Goodwill

^[2]

551.4

186.2

142.9

571.0

533.8

5,024.2

TRC Non-Partnership [Member]

Total assets

95.0

^[1]

74.7

95.0

^[1]

74.7

Goodwill

^[2]

0.0

0.0

Operating Segments [Member] | Field Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]

0.0

Total assets

10,088.7

^[1]

3,359.0

10,088.7

^[1]

3,359.0

Goodwill

^[2]

551.4

109.6

74.0

345.2

301.4

Operating Segments [Member] | Coastal Gathering and Processing [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]

5,024.2

Total assets

346.2

^[1]

368.6

346.2

^[1]

368.6

Goodwill

^[2]

0.0

5.5

2.3

11.4

9.7

Operating Segments [Member] | Logistics Assets [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]

0.0

Total assets

1,854.0

^[1]

1,650.2

1,854.0

^[1]

1,650.2

Goodwill

^[2]

0.0

67.5

59.8

199.6

195.9

Operating Segments [Member] | Marketing and Distribution [Member] | Reportable Segments [Member] | Targa Resources Partners LP [Member]

0.0

Total assets

543.8

^[1]

917.2

543.8

^[1]

917.2

Goodwill

^[2]

0.0

0.9

4.6

9.8

23.2

Operating Segments [Member] | Other Segment [Member] | Targa Resources Partners LP [Member]

0.0

Total assets

137.6

^[1]

6.7

137.6

^[1]

6.7

Goodwill

^[2]

0.0

0.0

Operating Segments [Member] | Corporate and Eliminations [Member] | Targa Resources Partners LP [Member]

0.0

Total assets

352.9

^[1]

115.5

352.9

^[1]

115.5

Goodwill

^[2]

0.0

2.7

$ 2.2

5.0

$ 3.6