Targa Resources Partners (NGLS-PA) 10-K 14 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Jun. 28, 2013	Feb. 10, 2014	Feb. 10, 2014
			Common Units [Member]	General Partner Units [Member]
Document and Entity Information [Line Items]	'	'	'	'
Entity Registrant Name	'Targa Resources Partners LP	'	'	'
Entity Central Index Key	'0001379661	'	'	'
Current Fiscal Year End Date	'--12-31	'	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'	'
Entity Voluntary Filers	'No	'	'	'
Entity Current Reporting Status	'Yes	'	'	'
Entity Filer Category	'Large Accelerated Filer	'	'	'
Entity Public Float	'	$4,678.10	'	'
Entity Common Stock, Shares Outstanding	'	'	112,390,094	2,293,677
Document Fiscal Year Focus	'2013	'	'	'
Document Fiscal Period Focus	'FY	'	'	'
Document Type	'10-K	'	'	'
Amendment Flag	'false	'	'	'
Document Period End Date	31-Dec-13	'	'	'

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$57.50	$68
Trade receivables, net of allowances of $0.9 million and $0.7 million	658.6	514.9
Inventories	150.7	99.4
Assets from risk management activities	2	29.3
Other current assets	7.1	3.3
Total current assets	875.9	714.9
Property, plant and equipment	5,751.60	4,701.20
Accumulated depreciation	-1,406.20	-1,168
Property, plant and equipment, net	4,345.40	3,533.20
Intangible assets, net	653.4	680.8
Long-term assets from risk management activities	3.1	5.1
Investment in unconsolidated affiliate	55.9	53.1
Other long-term assets	37.7	38.6
Total assets	5,971.40	5,025.70
Current liabilities:	'	'
Accounts payable and accrued liabilities	721.2	639.8
Accounts payable to Targa Resources Corp.	52.4	61.4
Liabilities from risk management activities	8	7.4
Total current liabilities	781.6	708.6
Long-term debt	2,905.30	2,393.30
Long-term liabilities from risk management activities	1.4	4.8
Deferred income taxes	12.1	11.2
Other long-term liabilities	52.6	47.7
Commitments and contingencies (see Note 16)	'	'
Owners' equity	'	'
Common unitholders (111,263,207 and 100,095,989 units issued and outstanding as of December 31, 2013 and December 31, 2012)	2,001.90	1,649.50
General partner (2,270,680 and 2,042,776 units issued and outstanding as of December 31, 2013 and December 31, 2012)	62	45.3
Accumulated other comprehensive income (loss)	-6.1	14.8
Partners' Capital	2,057.80	1,709.60
Noncontrolling interests in subsidiaries	160.6	150.5
Total owners' equity	2,218.40	1,860.10
Total liabilities and owners' equity	$5,971.40	$5,025.70

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Share data, unless otherwise specified
Current assets:	'	'
Allwance for receivables	$0.90	$0.70
Owners' equity	'	'
Common unitholders units issued (in units)	111,263,207	111,263,207
Common unitholders units outstanding (in units)	100,095,989	100,095,989
General partner units issued (in units)	2,270,680	2,042,776
General partner units outstanding (in units)	2,270,680	2,042,776

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CONSOLIDATED STATEMENTS OF OPERATIONS [Abstract]	'	'	'
Revenues	$6,556.20	$5,883.60	$6,987.10
Costs and expenses:	'	'	'
Product purchases	5,378.50	4,878.90	6,039
Operating expenses	376.2	313	287
Depreciation and amortization expenses	271.6	197.3	178.2
General and administrative expenses	143.1	131.6	127.8
Other operating expense	9.6	19.9	0.2
Income from operations	377.2	342.9	354.9
Other income (expense):	'	'	'
Interest expense, net	-131	-116.8	-107.7
Equity earnings	14.8	1.9	8.8
Loss on debt redemptions and amendments	-14.7	-12.8	0
Loss on mark-to-market derivative instruments	0	0	-5
Other	15.2	-7.8	-1.2
Income before income taxes	261.5	207.4	249.8
Income tax expense:	'	'	'
Current	-2	-2.5	-3.5
Deferred	-0.9	-1.7	-0.8
Total income tax benefit (expense)	-2.9	-4.2	-4.3
Net income	258.6	203.2	245.5
Less: Net income attributable to noncontrolling interests	25.1	28.6	41
Net income attributable to Targa Resources Partners LP	233.5	174.6	204.5
Net income attributable to general partner	107.5	66.7	38
Net income attributable to limited partners	126	107.9	166.5
Net income attributable to Targa Resources Partners LP	$233.50	$174.60	$204.50
Net income per limited partner unit - basic (in dollars per share)	$1.19	$1.20	$1.98
Net income per limited partner unit - diluted (in dollars per share)	$1.19	$1.20	$1.98
Weighted average units outstanding - basic (in shares)	105.5	90.1	84.1
Weighted average limited partner units outstanding - diluted (in shares)	105.7	90.2	84.2

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net income	$258.60	$203.20	$245.50
Commodity hedging contracts:	'	'	'
Change in fair value	-5.8	76.4	-33.4
Settlements reclassified to revenues	-21.2	-43.9	34.7
Interest rate swaps:	'	'	'
Change in fair value	0	0	-4.4
Settlements reclassified to interest expense, net	6.1	7.9	8.1
Other comprehensive income (loss)	-20.9	40.4	5
Comprehensive income	237.7	243.6	250.5
Less: Comprehensive income attributable to noncontrolling interests	25.1	28.6	41
Comprehensive income attributable to Targa Resources Partners LP	$212.60	$215	$209.50

CONSOLIDATED_STATEMENTS_OF_CHA

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY (USD $)	Limited Partner [Member]	General Partner [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Non-controlling Interests [Member]	Total
In Millions, except Share data
Beginning Balance at Dec. 31, 2010	$935.30	$15.10	($30.60)	$129.30	$1,049.10
Beginning Balance (in units) at Dec. 31, 2010	75,545,000	1,542,000	'	'	'
Compensation on equity grants (in units)	11,000	0	'	'	'
Compensation on equity grants	1.5	0	0	0	1.5
Accrual of distribution equivalent rights	'	'	'	'	-0.1
Proceeds from equity offerings (in units)	9,200,000	188,000	'	'	'
Proceeds from equity offerings	297.8	6.3	0	0	304.1
Contributions from Targa Resources Corp.	11.5	1.7	0	0	13.2
Distributions to noncontrolling interests	0	0	0	-31.4	-31.4
Other comprehensive income (loss)	0	0	5	0	5
Net income	166.5	38	0	41	245.5
Distributions	-191.4	-33.9	0	0	-225.3
Ending Balance at Dec. 31, 2011	1,221.20	27.2	-25.6	138.9	1,361.70
Ending Balance (in units) at Dec. 31, 2011	84,756,000	1,730,000	'	'	'
Compensation on equity grants (in units)	10,000	0	'	'	'
Compensation on equity grants	3.6	0	0	0	3.6
Accrual of distribution equivalent rights	-0.5	0	0	0	-0.5
Proceeds from equity offerings (in units)	15,330,000	313,000	'	'	'
Proceeds from equity offerings	543	11.5	0	0	554.5
Distributions to noncontrolling interests	0	0	0	-20.2	-20.2
Contribution from noncontrolling interests	0	0	0	3.2	3.2
Other comprehensive income (loss)	0	0	40.4	0	40.4
Net income	107.9	66.7	0	28.6	203.2
Distributions	-225.7	-60.1	0	0	-285.8
Ending Balance at Dec. 31, 2012	1,649.50	45.3	14.8	150.5	1,860.10
Ending Balance (in units) at Dec. 31, 2012	100,096,000	2,043,000	'	'	'
Compensation on equity grants (in units)	13,000	0	'	'	'
Compensation on equity grants	6	0	0	0	6
Accrual of distribution equivalent rights	-1.7	0	0	0	-1.7
Proceeds from equity offerings (in units)	11,154,000	228,000	'	'	'
Proceeds from equity offerings	517.8	10.8	0	0	528.6
Distributions to noncontrolling interests	0	0	0	-19.3	-19.3
Contribution from noncontrolling interests	0	0	0	4.3	4.3
Other comprehensive income (loss)	0	0	-20.9	0	-20.9
Net income	126	107.5	0	25.1	258.6
Distributions	-295.7	-101.6	0	0	-397.3
Ending Balance at Dec. 31, 2013	$2,001.90	$62	($6.10)	$160.60	$2,218.40
Ending Balance (in units) at Dec. 31, 2013	111,263,000	2,271,000	'	'	'

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities	'	'	'
Net income	$258.60	$203.20	$245.50
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Amortization in interest expense	15.5	17.6	12.4
Compensation on equity grants	6	3.6	1.5
Depreciation and other amortization expense	271.6	197.3	178.2
Accretion of asset retirement obligations	3.9	3.9	3.6
Deferred income tax expense	0.9	1.7	0.8
Equity earnings, net of distributions	-2.8	0	-0.4
Risk management activities	-0.5	5.3	-16.7
Loss on sale or disposition of assets	3.9	15.6	0.2
Loss on debt redemptions and amendments	14.7	12.8	0
Changes in operating assets and liabilities:	'	'	'
Receivables and other assets	-145.8	90.2	-109.2
Inventory	-84.5	5.9	-41.1
Accounts payable and other liabilities	69.9	-91.7	126.1
Net cash provided by operating activities	411.4	465.4	400.9
Cash flows from investing activities	'	'	'
Outlays for property, plant and equipment	-1,013.60	-582.3	-328.7
Business acquisitions, net of cash acquired	0	-996.2	-156.5
Purchase of material and supplies	-17.7	0	0
Investment in unconsolidated affiliate	0	-16.8	-21.2
Return of capital from unconsolidated affiliate	0	0.5	0
Other, net	5	1	0.3
Net cash used in investing activities	-1,026.30	-1,593.80	-506.1
Cash flows from financing activities	'	'	'
Proceeds from borrowings under credit facility	1,613	1,595	1,787
Repayments of credit facility	-1,838	-1,473	-2,054.30
Issuance of senior notes	625	1,000	325
Borrowings from accounts receivable securitization facility	373.3	0	0
Repayments of accounts receivable securitization facility	-93.6	0	0
Cash paid on note exchange	0	0	-27.7
Redemption of senior notes	-183.2	-217.7	0
Costs incurred in connection with financing arrangements	-15.3	-35.7	-18.2
Proceeds from equity offerings	535.5	575	316.1
Distributions	-397.3	-285.7	-225.2
Contributions from parent	0	1	13.2
Contributions from noncontrolling interests	4.3	3.2	0
Distributions to noncontrolling interests	-19.3	-21.3	-31.4
Net cash provided by financing activities	604.4	1,140.80	84.5
Net change in cash and cash equivalents	-10.5	12.4	-20.7
Cash and cash equivalents, begnning of period	68	55.6	76.3
Cash and cash equivalents, end of period	$57.50	$68	$55.60

Organization_and_Operations

Organization and Operations	12 Months Ended
	Dec. 31, 2013
Organization and Operations [Abstract]	'
Organization and Operations	'
	Note 1 — Organization and Operations
	Our Organization
	Targa Resources Partners LP is a publicly traded Delaware limited partnership formed in October 2006 by Targa Resources Corp. (“Targa” or “Parent”). Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange under the symbol “NGLS.” In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.
	Targa Resources GP LLC is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly owned subsidiary of Targa. As of December 31, 2013, Targa owned a 13.4% interest in us in the form of 2,270,680 general partner units and 12,945,659 common units. In addition, Targa Resources GP LLC also owns incentive distribution rights (“IDRs”), which entitle it to receive increasing cash distributions up to 48% of distributable cash for a quarter.
	Allocation of costs
	The employees supporting our operations are employed by Targa Resources LLC, a Delaware limited liability company and an indirect wholly owned subsidiary of Targa. Our financial statements include the direct costs of Targa employees deployed to our operating segments, as well as an allocation of costs associated with our usage of Targa centralized general and administrative services.
	Our Operations
	We are engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; gathering, storing  and terminaling crude oil; and storing, terminaling and selling refined petroleum products. See Note 21 for certain financial information for our business segments.

Basis_of_Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2013
Basis of Presentation [Abstract]	'
Basis of Presentation	'
	Note 2 — Basis of Presentation
	These accompanying financial statements and related notes present our consolidated financial position as of December 31, 2013 and 2012, and the results of operations, comprehensive income, cash flows and changes in owners’ equity for the years ended December 31, 2013, 2012 and 2011.
	We have prepared our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial results of our predecessors may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessors had been operated as unaffiliated entities. All significant intercompany balances and transactions have been eliminated. Certain amounts in prior periods have been reclassified to conform to the current year presentation.

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Significant Accounting Policies [Abstract]	'
Significant Accounting Policies	'
	Note 3 — Significant Accounting Policies
	Consolidation Policy
	Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests.
	We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee.
	Cash and Cash Equivalents
	Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
	Comprehensive Income
	Comprehensive income includes net income and other comprehensive income (“OCI”), which includes unrealized gains and losses on derivative instruments that are designated as hedges.
	Allowance for Doubtful Accounts
	Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.
	Inventories
	Our inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of cost or market using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are classified as Property, Plant and Equipment.  Inventories also include materials and supplies required for our Badlands expansion activities in North Dakota, which are valued using the specific identification method.
	Product Exchanges
	Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, a price differential may be billed or owed. The price differential is recorded as either accounts receivable or accrued liabilities.
	Gas Processing Imbalances
	Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.
	Derivative Instruments
	We employ derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which under GAAP, are not accounted for as derivatives.
	If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense.
	If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. The ultimate gain or loss on the derivative transaction upon settlement is also recognized as a component of other income and expense.
	We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.
	The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the unrealized gain or loss to earnings in the current period.
	We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
	For balance sheet classification purposes, we analyze the fair values of the derivative contracts on a deal by deal basis.
	Property, Plant and Equipment
	Property, plant and equipment are stated at acquisition value less accumulated depreciation. All of our property, plant and equipment purchased from Targa from 2007 to 2010 in drop-down transactions were stated at historical cost in the transactions recorded under common control accounting. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
	Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs.
	Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs.
	We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of operations. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations. See Note 6.
	Intangible Assets
	Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with businesses acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Amortization expense attributable to these assets is recorded in a manner that closely resembles the expected pattern in which we benefit from services provided to customers. See Note 6.
	Asset Retirement Obligations (“AROs”)
	AROs are legal obligations associated with the retirement of tangible long-lived assets that result from an asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The consolidated cost of the asset and the capitalized asset retirement obligation is depreciated using the straight-line method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing.
	Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows shall be recognized as an increase or a decrease in the carrying amount of the liability for an asset retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. Upon settlement, AROs will be extinguished by us at either the recorded amount or we will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost. See Note 7.
	Debt Issue Costs
	Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs.
	Accounts Receivable Securitization Facility
	Proceeds from the sale or contribution of certain receivables under our Accounts Receivable Securitization Facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Such borrowings are reflected as long-term debt on our balance sheets to the extent that we have the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities on our statements of cash flows.
	Environmental Liabilities and Other Loss Contingencies
	Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. See Note 16.
	Income Taxes
	We generally are not subject to federal income taxes.   For federal income tax purposes, our earnings or losses are included in the tax returns of our separate partners.  The taxable income or loss passed through to our partners may vary substantially from the net income or net loss we report in the consolidated statement of income.  We are also subject to the Texas margin tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas.
	Noncontrolling Interests
	Third-party ownership in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of the balance sheet. In the statements of operations and statements of comprehensive income, noncontrolling interests reflects the allocation of results to third-party investors.
	Revenue Recognition
	Our operating revenues are primarily derived from the following activities:
	•sales of natural gas, NGLs, condensate, crude oil and petroleum products;
	•services related to compressing, gathering, treating, and processing of natural gas; and
	•services related to NGL fractionation, terminaling and storage, transportation and treating.
	We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured.
	For natural gas processing activities, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we retain the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on a percent-of-liquids basis or a fee basis, depending on market conditions. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above.
	We generally report sales revenues gross in our consolidated statements of operations, as we typically act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership. However, buy-sell transactions with the same counterparty are reported on a net basis.
	Unit-Based Compensation
	We award unit-based compensation to employees, directors and non-management directors in the form of restricted common units and performance units. Compensation expense on restricted common units and performance unit awards that qualify as equity arrangements are measured by the fair value of the award as determined by the market at the date of grant. Compensation expense on performance unit awards that qualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured subsequently at each reporting date through the settlement period. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. See Note 20.
	Earnings per Unit
	We account for earnings per unit (“EPU”) in accordance with Accounting Standards Codification (“ASC”) Topic 260 – Earnings per Share. Diluted EPU reflects the potential dilution that could occur if securities or other contracts to issue common units were exercised or converted into common units or resulted in the issuance of common units so long as it does not have an anti-dilutive effect on EPU. The dilutive effect is determined through the application of the treasury method. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic EPU.
	The limited partners’ net income per unit is based on net income after allocation to the general partner’s 2% interest and incentive distribution rights. Because our Partnership Agreement limits the quarterly distribution payable to holders of incentive distribution rights to a percentage of Available Cash, the incentive distribution rights do not receive an allocation of earnings in excess of the incentive distributions for the period.
	Use of Estimates
	When preparing financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
	Recent Accounting Pronouncements
	In January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies that ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, applies to financial instruments or derivative transactions accounted for under ASC Topic 815. We currently present our derivative assets and liabilities on a gross basis on our statement of financial position. The amendments require disclosure of both gross and net amounts of derivative assets and liabilities that are subject to master netting arrangements with counterparties. We have provided these additional disclosures regarding the gross and net amounts of derivative assets and liabilities in Note 13.
	In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendment, required to be applied prospectively for reporting periods beginning after December 15, 2012, requires entities to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line item of net income. Our financial statement presentation complies with this standards update.

Business_Acquisitions

Business Acquisitions	12 Months Ended
	Dec. 31, 2013
Business Acquisitions [Abstract]	'
Business Acquisitions	'
	Note 4 –Business Acquisitions
	2012 Acquisition
	Badlands
	On December 31, 2012, we completed the acquisition of Saddle Butte Pipeline, LLC’s ownership of its Williston Basin crude oil pipeline and terminal system and its natural gas gathering and processing operations (collectively “Badlands”), for cash consideration of $975.8 million, subject to a contingent payment.
	The acquired business, located in the Bakken and Three Forks Shale plays of the Williston basin in North Dakota, expands our portfolio of midstream assets and diversifies our business with the addition of fee-based crude oil gathering and natural gas gathering and processing. The Badlands financial results are included in our Field Gathering and Processing business segment.
	Pursuant to the Membership Interest Purchase and Sale Agreement (“MIPSA”), the acquisition is subject to a contingent payment of $50 million (the “contingent consideration”) if aggregate crude oil gathering volumes exceed certain stipulated monthly thresholds during the period from January 2013 through June 2014. If the threshold is not attained during the contingency period, no payment is owed. Accounting standards require that the contingent consideration be recorded at fair value at the date of acquisition and revalued at subsequent reporting dates under the acquisition method of accounting. At December 31, 2012, we recorded a $15.3 million accrued liability representing the fair value of this contingent consideration, determined by a probability based model measuring the likelihood of meeting certain volumetric measures identified in the MIPSA.
	Changes in the fair value of this accrued liability are included in earnings and reported as Other income (expense) in the Consolidated Statement of Operations. During 2013, the contingent consideration was re-estimated to be $0, resulting in an increase in Other income of $15.3 million in 2013. The elimination of the contingent liability reflects management’s belief that these stipulated volumetric thresholds will not be achieved during the contingency period.
	The following table summarizes the consideration paid for the Badlands acquisition and the determination of the assets and liabilities acquired at the December 31, 2012 acquisition date.
			31-Dec-12
	Cash		$	975.8
	Contingent consideration			15.3
	Total consideration		$	991.1
	Assets acquired and liabilities assumed
	Financial assets		$	35.4
	Inventory			16.2
	Property, plant and equipment			295.3
	Intangible assets			679.6
	Financial liabilities			(35.4	)
	Total net assets		$	991.1
	Intangible assets consist of customer contracts and relationships acquired in the Badlands acquisition. Using relevant information and assumptions, the fair value of acquired identifiable intangible assets at the date of acquisition was determined. Fair value is generally calculated as the present value of estimated future cash flows. Key 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. See Note 6 for details of amortization method for intangible assets.
	Pro Forma Results
	As the Badlands acquisition was completed on December 31, 2012, there were no results of operations attributable to this acquisition for 2012. In 2012, we incurred $6.1 million of acquisition-related costs associated with the Badlands acquisition (included in Other expense in our consolidated statement of operations).
	Our Annual Report for the year ended 2012 included preliminary pro forma information assuming that the Badlands acquisition has been completed on January 1, 2011. In 2013, we finalized amortization methods for Badlands intangible assets and estimated useful lives for both tangible and intangible assets of Badlands.
	The following unaudited pro forma consolidated results of operations for the years ended 2012 and 2011 has been updated to include the effects of our 2013 amortization method policy decisions.
			Year Ended December 31,
						2011
			2012
			(In millions, except per unit amounts)
	Revenues		$	5,907.80		$	6,990.70
	Net income			157.4			182.6
	Net income attributable to limited partners			63.1			104.6
	Net income per limited partner unit - Basic and diluted		$	0.63		$	1.1
	The pro forma consolidated results of operations include adjustments to include the reported results of the acquired company for 2012 and 2011, as adjusted to:
		·	exclude the financial results of assets retained by the seller;
		·	report revenues from the purchase and sale of crude oil inventory with the same counterparty on a net basis to conform to our accounting policy;
		·	report revenues from the purchases and sales of certain Badlands natural gas processing agreements in which we are in substance an agent rather than a principal on a net basis;
		·	include the incremental depreciation expenses associated with the fair value adjustments to property, plant and equipment as a result of applying the acquisition method of accounting (assumed straight-line method over useful lives of 15-20 years);
		·	include the amortization expense associated with the fair value adjustments to definite-lived intangibles in a manner that follows the expected pattern of services provided to customers, over a useful life of 20 years;
		·	include the financing costs associated with the debt offering and borrowings under our TRP Revolver  used to fund a portion of the acquisition;
		·	adjust the attribution of net income to general partners and limited partners, and the calculation of weighted average basic and diluted units to give effect to the equity offering used to fund a portion of the acquisition; and
		·	exclude $6.1 million of acquisition costs incurred in 2012 that were directly related to the transaction.
	The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.
	2011 Acquisitions
	In March 2011, we acquired a refined petroleum products and crude oil storage and terminaling facility in Channelview, Texas on Carpenter's Bayou along the Houston Ship Channel (the "Channelview Terminal") for $29.0 million. The Channelview Terminal, with storage capacity of 544 MBbl, can handle multiple grades of blend stocks, petroleum products and crude oil and has potential for expansion, as well as integration with our other logistics operations.
	In September 2011, we acquired two refined petroleum products and crude oil storage and terminaling facilities. At the time of the acquisition, the facility on the Hylebos Waterway in the Port of Tacoma, Washington has 758 MBbl of capacity and handles refined petroleum products, crude oil, LPGs and biofuels, including ethanol and biodiesel. The facility on the Patapsco River in Baltimore, Maryland has approximately 505 MBbl of storage capacity. Both terminals contain blending and heating capabilities, and have tanker truck and barge loading and unloading infrastructure. Total cash consideration including working capital for both facilities was $135 million.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2013
Inventories [Abstract]	'
Inventories	'
	Note 5 — Inventories
	The components of inventories consisted of the following:
		31-Dec-13		31-Dec-12
	Commodities	$	136.4	$	82.3
	Materials and supplies		14.3		17.1
		$	150.7	$	99.4

Property_Plant_and_Equipment_a

Property, Plant and Equipment and Intangible Assets	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment and Intangible Assets [Abstract]	'
Property, Plant and Equipment and Intangible Assets	'
	Note 6 — Property, Plant and Equipment and Intangible Assets
								Estimated useful life
		31-Dec-13			31-Dec-12			(In Years)
	Gathering systems	$	2,230.10		$	1,975.30		5 to 20
	Processing and fractionation facilities		1,598.00			1,251.60		5 to 25
	Terminaling and storage facilities		715.2			462		5 to 25
	Transportation assets		294.7			292.5		10 to 25
	Other property, plant and equipment		121.3			84.6		3 to 25
	Land		89.5			87.1			-
	Construction in progress		702.8			548.1			-
	Property, plant and equipment		5,751.60			4,701.20
	Accumulated depreciation		(1,406.2	)		(1,168.0	)
	Property, plant and equipment, net	$	4,345.40		$	3,533.20
	Intangible assets	$	681.8		$	681.9			20
	Accumulated amortization		(28.4	)		(1.1	)
	Intangible assets, net	$	653.4		$	680.8
	Intangible assets consist of customer contracts and customer relationships acquired in business acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate.
	Amortization expense attributable to these intangible assets is recorded using a method that closely reflects the cash flow pattern underlying the intangible asset valuation. Amortization of these assets was $27.3 million in 2013. The estimated amortization expense for these intangible assets is approximately $61.4 million, $80.1 million, $88.3 million, $81.5 million and $67.8 million for each of years 2014 through 2018.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations [Abstract]	'
Asset Retirement Obligations	'
	Note 7 — Asset Retirement Obligations
	Our asset retirement obligations primarily relate to certain gas gathering pipelines and processing facilities, and are included in our consolidated balance sheets as a component of other long-term liabilities. The changes in our aggregate asset retirement obligations are as follows:
		2013		2012			2011
	Beginning of period	$	45.2	$	42.3		$	37.5
	Change in cash flow estimate		1.4		(1.0	)		1.2
	Accretion expense		3.9		3.9			3.6
	End of period	$	50.5	$	45.2		$	42.3

Investment_in_Unconsolidated_A

Investment in Unconsolidated Affiliate	12 Months Ended
	Dec. 31, 2013
Investment in Unconsolidated Affiliate [Abstract]	'
Investment in Unconsolidated Affiliate	'
	Note 8 — Investment in Unconsolidated Affiliate
	At December 31, 2013, 2012 and 2011, our unconsolidated investment consisted of a 38.8% ownership interest in Gulf Coast Fractionators LP (“GCF”).
	The following table shows the activity related to our investment in an unconsolidated affiliate for the years indicated:
		2013		2012		2011
	Equity earnings	$	14.8	$	1.9	$	8.8
	Cash distributions		12		2.3		8.4
	Cash calls for expansion projects		-		16.8		21.2

Accounts_Payable_and_Accrued_L

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2013
Accounts Payable and Accrued Liabilities [Abstract]	'
Accounts Payable and Accrued Liabilities	'
	Note 9 — Accounts Payable and Accrued Liabilities
	The components of accounts payable and accrued liabilities consisted of the following:
		31-Dec-13		31-Dec-12
	Commodities	$	520.8	$	416.8
	Other goods and services		145.1		153.4
	Interest		35.8		39.4
	Compensation and benefits		1.3		-
	Other		18.3		30.2
		$	721.2	$	639.8

Debt_Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2013
Debt Obligations [Abstract]	'
Debt Obligations	'
	Note 10 — Debt Obligations
			31-Dec-13			31-Dec-12
	Senior secured revolving credit facility, variable rate, due October 2017 (1)		$	395		$	620
	Senior unsecured notes, 11¼% fixed rate, due July 2017 (2)			-			72.7
	Unamortized discount			-			(2.5	)
	Senior unsecured notes, 7⅞% fixed rate, due October 2018			250			250
	Senior unsecured notes, 6⅞% fixed rate, due February 2021			483.6			483.6
	Unamortized discount			(28.0	)		(30.5	)
	Senior unsecured notes, 6⅜% fixed rate, due August 2022			300			400
	Senior unsecured notes, 5¼% fixed rate, due May 2023			600			600
	Senior unsecured notes, 4¼% fixed rate, due November 2023			625			-
	Accounts receivable securitization facility, due December 2014 (3)			279.7			-
	Total long-term debt		$	2,905.30		$	2,393.30
	Letters of credit outstanding		$	86.8		$	45.3
	-1	As of December 31, 2013, availability under our $1.2 billion senior secured revolving credit facility was $718.2 million.
	-2	The outstanding balance of the 11¼% Notes was redeemed on July 15, 2013. See “Senior Notes Repayments and Redemptions” below.
	-3	All amounts outstanding under the Securitization Facility are reflected as long-term debt in our balance sheet because we have the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis.
	The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2013 for the next five years, and in total thereafter:
						Scheduled Maturities of Debt
			Total			2014			2017			2018		After 2018
	Senior secured revolving credit facility		$	395		$	-		$	395		$	-	$	-
	Senior unsecured notes			2,258.60			-			-			250		2,008.60
	Account receivable securitization facility			279.7			279.7			-			-		-
	Total		$	2,933.30		$	279.7		$	395		$	250	$	2,008.60
	The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2013:
			Range of Interest Rates			Weighted Average Interest Rate
			Incurred			Incurred
	Senior secured revolving credit facility			1.9% - 4.5	%		2.4	%
	Accounts receivable securitization facility			0.9	%		0.9	%
	Compliance with Debt Covenants
	As of December 31, 2013, we were in compliance with the covenants contained in our various debt agreements.
	Revolving Credit Agreement
	In October 2012, we entered into a Second Amended and Restated Credit Agreement that amended and replaced our variable rate Senior Secured Credit Facility due July 2015 (the “Previous Revolver”) to provide a variable rate Senior Secured Credit Facility due October 3, 2017 (the “TRP Revolver”). The TRP Revolver increased available commitments to $1.2 billion from $1.1 billion and allows the Partnership to request up to an additional $300.0 million in commitment increases.
	We incurred a $1.7 million loss related to a partial write-off of debt issue costs associated with the Previous Revolver as a result of a change in syndicate members under the new TRP Revolver. The remaining deferred debt issue costs along with the issue costs associated with the October 2012 amendment are amortized on a straight-line basis over the life of the TRP Revolver.
	The TRP Revolver bears interest, at our option, either at the base rate or the Eurodollar rate.  The base rate is equal to the highest of: (i) Bank of America’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin ranging from 0.75% to 1.75%. The Eurodollar rate is equal to LIBOR plus an applicable margin ranging from 1.75% to 2.75%.
	We are required to pay a commitment fee equal to an applicable rate ranging from 0.3% to 0.5% times the actual daily average unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable rate ranging from 1.75% to 2.75%.
	The TRP Revolver is collateralized by a majority of our assets. Borrowings are guaranteed by our restricted subsidiaries.
	The TRP Revolver restricts our ability to make distributions of available cash to unitholders if a default or an event of default (as defined in the TRP Revolver) exists or would result from such distribution. The TRP Revolver requires us to maintain a ratio of consolidated funded indebtedness to consolidated adjusted EBITDA of no more than 5.50 to 1.00. The TRP Revolver also requires us to maintain a ratio of consolidated EBITDA to consolidated interest expense of no less than 2.25 to 1.00. In addition, the TRP Revolver contains various covenants that may limit, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates (in each case, subject to our right to incur indebtedness or grant liens in connection with, and convey accounts receivable as part of, a permitted receivables financing).
	Senior Unsecured Notes
	In February 2011, we exchanged $158.6 million principal amount of our 6⅞% Notes plus payments of $28.6 million including $0.9 million of accrued interest for $158.6 million aggregate principal amount of our 11¼% Notes. The holders of the exchanged Notes are subject to the provisions of the 6⅞% Notes described below. The debt covenants related to the remaining $72.7 million of face value of the 11¼% Notes were removed. This exchange was accounted for as a debt modification whereby the financial effects of the exchange will be recognized over the term of the new debt issue.
	In January 2012, we privately placed $400.0 million in aggregate principal amount of our 6⅜% Notes, resulting in approximately $395.5 million of net proceeds, which were used to reduce the borrowings under the TRP Revolver and for general partnership purposes.
	In October 2012, $400.0 million in aggregate principal amount of our 5¼% Notes were issued at 99.5% of the face amount, resulting in gross proceeds of $398.0 million. An additional $200.0 million in aggregate principal amount of our 5¼% Notes were issued in December 2012 at 101.0% of the face amount, resulting in gross proceeds of $202.0 million. Both issuances are treated as a single class of debt securities and have identical terms.
	In November 2012, we redeemed all of the outstanding 8¼% Notes at a redemption price of 104.125% plus accrued interest through the redemption date. The redemption resulted in a premium paid on the redemption of $8.6 million, which is included as a cash outflow from financing activities in the Consolidated Statement of Cash Flows, and a write off of $2.5 million of unamortized debt issue costs.
	In May 2013, we privately placed $625.0 million in aggregate principal amount of 4¼% Notes. The 4¼% Notes resulted in approximately $618.1 million of net proceeds, which were used to reduce borrowings under the TRP Revolver and for general partnership purposes.
	In June 2013, we paid $106.4 million plus accrued interest, which included a premium of $6.4 million, to redeem $100.0 million of the outstanding 6⅜% Notes. The redemption resulted in a $7.4 million loss on debt redemption, including the write-off of $1.0 million of unamortized debt issue costs.
	In July 2013, we paid $76.8 million plus accrued interest, which included a premium of $4.1 million, per the terms of the note agreement to redeem the outstanding balance of the 11¼% Notes. The redemption resulted in a $7.4 million loss on debt redemption in the third quarter 2013, including the write-off of $1.0 million of unamortized debt issue costs.
	The terms of the senior unsecured notes outstanding as of December 31, 2013 were as follows:
	Note Issue		Issue Date		Per Annum	Due Date		Dates Interest Paid
					Interest Rate
	"7⅞% Notes"		Aug-10		7⅞%	15-Oct-18		April & October 15th
	"6⅞% Notes"		Feb-11		6⅞%	1-Feb-21		February & August 1st
	"6⅜% Notes"		Jan-12		6⅜%	1-Aug-22		February & August 1st
	"5¼% Notes"		Oct / Dec 2012		5¼%	1-May-23		May & November 1st
	"4¼% Notes"		May-13		4¼%	15-Nov-23		May & November 15th
	All issues of unsecured senior notes are obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under the TRP Revolver. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by us and our restricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the TRP Revolver, which is secured by substantially all of our assets and our Securitization Facility, which is secured by accounts receivable pledged under it, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually in arrears.
	Our senior unsecured notes and associated indenture agreements restrict our ability to make distributions to unitholders in the event of default (as defined in the indentures). The indentures also restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Corporation and no Default or Event of Default (each as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and we will cease to be subject to such covenants.
	We may redeem up to 35% of the aggregate principal amount of notes at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 90 days (180 days for the 6⅜% Notes, 5¼% Notes and 4¼ % Notes) of the date of the closing of such equity offering.
	Note Issue		Any Date Prior To		Price
	7⅞% Notes		15-Oct-13		107.88%
	6⅞% Notes		1-Feb-14		106.88%
	6⅜% Notes		1-Feb-15		106.38%
	5¼% Notes		1-Nov-15		105.25%
	4¼% Notes		15-May-16		104.25%
We may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed.
7⅞% Notes					6⅞% Notes						6⅜% Notes					5¼% Notes					4¼% Notes
Redemption Date:					Redemption Date:						Redemption Date:					Redemption Date:					Redemption Date:
15-Oct					1-Feb						1-Feb					1-Nov					15-May
Year		Price			Year			Price			Year		Price			Year		Price			Year		Price
2014			103.938	%		2016			103.438	%		2017		103.188	%		2017		102.625	%		2018		102.125	%
2015			101.969	%		2017			102.292	%		2018		102.125	%		2018		101.75	%		2019		101.417	%
2016 and thereafter			100	%		2018			101.146	%		2019		101.063	%		2019		100.875	%		2020		100.708	%
					2019 and thereafter				100	%	2020 and thereafter			100	%	2020 and thereafter			100	%	2021 and thereafter			100	%
Accounts Receivable Securitization Facility
In January 2013, we entered into the Securitization Facility to provide up to $200.0 million of borrowing capacity at commercial paper or LIBOR market index rates plus a margin through January 2014. Under this Securitization Facility, one of our consolidated subsidiaries (Targa Liquids Marketing and Trade LLC or “TLMT”) sells or contributes receivables, without recourse, to another of our consolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of this Securitization Facility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to a third-party financial institution. Eligible TRLLC receivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of TLMT or us. Any excess receivables are eligible to satisfy the claims of creditors of TLMT or us.
In December 2013, we entered into a Second Amendment to the Securitization Facility to increase the borrowing capacity to $300.0 million and extend the termination date to December 12, 2014.
April 2013 Shelf
In April 2013, we filed with the SEC a universal shelf registration statement (the “April 2013 Shelf”), which provides us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The April 2013 Shelf expires in April 2016. There was no activity under the April 2013 Shelf during the year ended December 31, 2013.
July 2013 Shelf
In July 2013, we filed with the SEC a universal shelf registration statement that allows us to issue up to an aggregate of $800.0 million of debt or equity securities (the “July 2013 Shelf”). The July 2013 Shelf expires in August 2016. See Note 11 for equity issuances under the July 2013 Shelf.
Debt Re-acquisitions Summary
The debt re-acquisitions described above were reported as follows in our Consolidated Statements of Operations:
		2013			2012
Premium over face value paid upon redemption:
6⅜ Notes		$	6.4		$	-
8¼ Notes			-			8.6
11¼ Notes			4.1			-
Recognition of unamortized discount:
11¼ Notes			2.2			-
Write-off of deferred debt issue costs:
8¼ Notes			-			2.5
6⅜ Notes			1			-
11¼ Notes			1			-
Partial write-off of TRP Revolver deferred debt issue cost related to 2012 amendment			-			1.7
Loss on debt redemptions and amendments		$	14.7		$	12.8

Partnership_Units_and_Related_

Partnership Units and Related Matters	12 Months Ended
	Dec. 31, 2013
Partnership Units and Related Matters [Abstract]	'
Partnership Equity and Distributions	'
	Note 11 — Partnership Units and Related Matters
	In accordance with the Partnership Agreement, we must distribute all of our available cash, as determined by the general partner, to unitholders of record within 45 days after the end of each quarter.
	Public Offerings of Common Units
	In 2010, we filed with the SEC a universal shelf registration statement (the “2010 Shelf”), which provided us with the ability to offer and sell an unlimited amount of debt and equity securities, subject to market conditions and our capital needs. The 2010 Shelf expired in April 2013. The following transactions were completed under the 2010 Shelf.
		·	August 2010 – 7,475,000 common units (including underwriters’ overallotment option) at a price of $24.80 per common unit, providing net proceeds of $177.8 million. Targa contributed $3.8 million to maintain its 2% general partner interest. We used the net proceeds from this offering to reduce borrowings under our Previous Revolver.
		·	January 2011 – 9,200,000 common units (including underwriters’ overallotment option) at a price of $33.67 per common unit, providing net proceeds of $298.0 million. Targa contributed $6.3 million to maintain its 2% general partner interest. We used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under our Previous Revolver.
		·	January 2012 – 4,405,000 common units (including underwriters’ overallotment option) at a price of $38.30 per common unit, providing net proceeds of $164.8 million. As part of this offering, Targa purchased 1,300,000 common units with an aggregate value of $49.8 million. In addition, Targa contributed $3.5 million to maintain its 2% general partner interest. We used the net proceeds from this offering for general partnership purposes, including the repayment of indebtedness.
		·	November 2012 – 10,925,000 common units (including underwriters’ overallotment option) at a price of $36.00 per common unit, providing net proceeds of $378.2 million. Targa contributed $8.0 million to maintain its 2% general partner interest. We used the net proceeds from this offering to fund a portion of the $975.8 million purchase price of the Badlands acquisition.
	In July 2012, we filed with the SEC a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue up to an aggregate of $300.0 million of debt or equity securities (the “2012 Shelf”). The 2012 Shelf expires in August 2015.
	In August 2012, we entered into an Equity Distribution Agreement (the “2012 EDA”) with Citigroup Global Markets Inc. (“Citigroup”) pursuant to which we may sell, at our option, up to an aggregate of $100.0 million of our common units through Citibank, as sales agent, under the 2012 Shelf. During the year ended December 31, 2013, we issued 2,420,046 common units under the 2012 EDA, receiving net proceeds of $94.8 million. Targa contributed $2.0 million to us to maintain its 2% general partner interest.
	In March 2013, we entered into a second Equity Distribution Agreement under the 2012 Shelf (the “March 2013 EDA”) with Citigroup, Deutsche Bank Securities Inc. (“Deutsche Bank”), Raymond James & Associates, Inc. (“Raymond James”) and UBS Securities LLC (“UBS”), as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $200.0 million of our common units. During the year ended December 31, 2013, we issued 4,204,751 common units receiving net proceeds of $197.5 million. Targa contributed $4.1 million to maintain its 2% general partner interest.
	In August 2013, we entered into an Equity Distribution Agreement under the July 2013 Shelf (the “August 2013 EDA”) with Citigroup, Deutsche Bank, Morgan Stanley & Co. LLC, Raymond James, RBC Capital Markets, LLC, UBS and Wells Fargo Securities, LLC, as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $400.0 million of our common units. During the year ended 2013, we issued 4,529,641 common units under the August 2013 EDA, receiving net proceeds of $225.6 million. Targa contributed $4.7 million to us to maintain its 2% general partner interest.
	Subsequent Event
	In January 2014, we issued 1,118,147 common units and received proceeds of $56.2 million, net of commissions and fees, pursuant to the August 2013 EDA. Targa contributed $1.2 million to maintain its 2% general partner interest.
	Distributions
	In accordance with the Partnership Agreement, we must distribute all of our available cash, as determined by the general partner, to unitholders of record within 45 days after the end of each quarter. The following table details the distributions declared and/or paid by us for the year ended December 31, 2013, 2012 and 2011.
				Distributions
	Three Months Ended		Date Paid or to be Paid	Limited		General Partner						Distributions
				Partners								per Limited
				Common		Incentive			2%	Total		Partner Unit
				(In millions, except per unit amounts)
	2013
	31-Dec-13		14-Feb-14	$	84	$	29.5	$	2.3	$	115.8	$	0.7475
	30-Sep-13		14-Nov-13		79.4		26.9		2.2		108.5		0.7325
	30-Jun-13		14-Aug-13		75.8		24.6		2		102.4		0.715
	31-Mar-13		15-May-13		71.7		22.1		1.9		95.7		0.6975
	2012
	31-Dec-12		14-Feb-13	$	69	$	20.1	$	1.8	$	90.9	$	0.68
	30-Sep-12		14-Nov-12		59.1		16.1		1.5		76.7		0.6625
	30-Jun-12		14-Aug-12		57.3		14.4		1.5		73.2		0.6425
	31-Mar-12		15-May-12		55.5		12.7		1.4		69.6		0.6225
	2011
	31-Dec-11		14-Feb-12	$	53.7	$	11	$	1.3	$	66	$	0.6025
	30-Sep-11		14-Nov-11		49.4		8.8		1.2		59.4		0.5825
	30-Jun-11		12-Aug-11		48.3		7.8		1.2		57.3		0.57
	31-Mar-11		13-May-11		47.3		6.8		1.1		55.2		0.5575

Earnings_per_Limited_Partner_U

Earnings per Limited Partner Unit	12 Months Ended
	Dec. 31, 2013
Earnings per Limited Partner Unit [Abstract]	'
Earnings per Limited Partner Unit	'
	Note 12 — Earnings per Limited Partner Unit
	The following table sets forth the computation of basic and diluted net income per limited partner unit for the years ended December 31, 2013, 2012 and 2011:
		Year Ended December 31,
		2013		2012		2011
	Net income	$	258.6	$	203.2	$	245.5
	Less: Net income attributable to noncontrolling interests		25.1		28.6		41
	Net income attributable to Targa Resources Partners LP	$	233.5	$	174.6	$	204.5
	Net income attributable to general partner		107.5		66.7		38
	Net income attributable to limited partners		126		107.9		166.5
	Net income attributable to Targa Resources Partners LP	$	233.5	$	174.6	$	204.5
	Weighted average units outstanding - basic		105.5		90.1		84.1
	Net income available per limited partner unit - basic	$	1.19	$	1.2	$	1.98
	Weighted average units outstanding		105.5		90.1		84.1
	Dilutive effect of unvested stock awards		0.2		0.1		0.1
	Weighted average units outstanding - diluted		105.7		90.2		84.2
	Net income available per limited partner unit - diluted	$	1.19	$	1.2	$	1.98

Derivative_Instruments_and_Hed

Derivative Instruments and Hedging Activities	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities [Abstract]	'
Derivative Instruments and Hedging Activities	'
	Note 13 — Derivative Instruments and Hedging Activities
	Commodity Hedges
	The primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. We have hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in our Field Gathering and Processing operations and (ii) NGL and condensate equity volumes predominately in our Field Gathering and Processing segment and the LOU business unit in our Coastal Gathering and Processing segment that result from its percent-of-proceeds processing arrangements. These hedge positions will move favorably in periods of falling prices and unfavorably in periods of rising prices. We have designated these derivative contracts as cash flow hedges for accounting purposes.
	The hedges generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane, isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices for delivery at various locations, which closely approximate our actual natural gas and NGL delivery points.
	We hedge a portion of our condensate sales using crude oil hedges that are based on the New York Mercantile Exchange (“NYMEX”) futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying condensate equity volumes.
	At December 31, 2013, the notional volumes of our commodity hedges for equity volumes were:
	Commodity		Instrument		Unit		2014				2015				2016
	Natural Gas		Swaps		MMBtu/d			48,050				34,551				25,500
	NGL		Swaps		Bbl/d			1,125				-				-
	Condensate		Swaps		Bbl/d			2,450				-				-
	We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges, and we record changes in fair value and cash settlements to revenues.
	Our derivative contracts are subject to netting arrangements that allow net cash settlement of offsetting asset and liability positions with the same counterparty. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:
				Fair Value as of December 31, 2013								Fair Value as of December 31, 2012
		Balance Sheet		Derivative				Derivative				Derivative				Derivative
		Location		Assets				Liabilities				Assets				Liabilities
	Derivatives designated as hedging instruments
	Commodity contracts	Current		$	2			$	(7.7	)		$	29.2			$	(7.2	)
		Long-term			3.1				(1.4	)			5.1				(4.8	)
	Total derivatives designated as hedging instruments			$	5.1			$	(9.1	)		$	34.3			$	(12.0	)
	Derivatives not designated as hedging instruments
	Commodity contracts	Current		$	-			$	(0.3	)		$	0.1			$	(0.2	)
	Total derivatives not designated as hedging instruments			$	-			$	(0.3	)		$	0.1			$	(0.2	)
	Total current position			$	2			$	(8.0	)		$	29.3			$	(7.4	)
	Total long-term position				3.1				(1.4	)			5.1				(4.8	)
	Total derivatives			$	5.1			$	(9.4	)		$	34.4			$	(12.2	)
	The pro forma impact of reporting derivatives in the Consolidated Balance Sheet is as follows:
			Gross Presentation								Pro forma Net Presentation
			Asset				Liability				Asset				Liability
	31-Dec-13		Position				Position				Position				Position
	Current position
	Counterparties with offsetting position		$	1.9			$	(4.4	)		$	-			$	(2.5	)
	Counterparties without offsetting position - assets			0.1				-				0.1				-
	Counterparties without offsetting position - liabilities			-				(3.6	)			-				(3.6	)
				2				(8.0	)			0.1				(6.1	)
	Long-term position
	Counterparties with offsetting position			0.7				(1.2	)			-				(0.5	)
	Counterparties without offsetting position - assets			2.4				-				2.4				-
	Counterparties without offsetting position - liabilities			-				(0.2	)			-				(0.2	)
				3.1				(1.4	)			2.4				(0.7	)
	Total derivatives
	Counterparties with offsetting position			2.6				(5.6	)			-				(3.0	)
	Counterparties without offsetting position - assets			2.5				-				2.5				-
	Counterparties without offsetting position - liabilities			-				(3.8	)			-				(3.8	)
			$	5.1			$	(9.4	)		$	2.5			$	(6.8	)
	31-Dec-12
	Current position
	Counterparties with offsetting position		$	23.8			$	(7.4	)		$	16.4			$	-
	Counterparties without offsetting position - assets			5.5				-				5.5				-
	Counterparties without offsetting position - liabilities			-				-				-				-
				29.3				(7.4	)			21.9				-
	Long-term position
	Counterparties with offsetting position			4.4				(2.8	)			1.6				-
	Counterparties without offsetting position - assets			0.7				-				0.7				-
	Counterparties without offsetting position - liabilities			-				(2.0	)			-				(2.0	)
				5.1				(4.8	)			2.3				(2.0	)
	Total derivatives
	Counterparties with offsetting position			28.2				(10.2	)			18				-
	Counterparties without offsetting position - assets			6.2				-				6.2				-
	Counterparties without offsetting position - liabilities			-				(2.0	)			-				(2.0	)
			$	34.4			$	(12.2	)		$	24.2			$	(2.0	)
	The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets.
	The estimated fair value of our derivative instruments was a net liability of $4.3 million as of December 31, 2013. The estimated fair value is net of an adjustment for credit risk based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented.
	Our payment obligations in connection with substantially all of these hedging transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders.
The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue and expense for the periods indicated:
Derivatives in Cash Flow	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
Hedging Relationships	2013				2012				2011
Interest rate contracts		$	-			$	-			$	(4.4	)
Commodity contracts			(5.8	)			76.4				(33.4	)
		$	(5.8	)		$	76.4			$	(37.8	)
	Gain (Loss) Reclassified from OCI into Income (Effective Portion)
Location of Gain (Loss)	2013				2012				2011
Interest expense, net		$	(6.1	)		$	(7.9	)		$	(8.1	)
Revenues			21.2				43.9				(34.7	)
		$	15.1			$	36			$	(42.8	)
Hedge ineffectiveness was immaterial for all periods presented.
Our consolidated earnings are also affected by our use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. Gain (loss) recognized on commodity derivatives not designated as hedging instruments was immaterial for all periods presented.
Derivatives Not Designated as		Location of Gain Recognized in		Gain (Loss) Recognized in Income on Derivatives
Hedging Instruments		Income on Derivatives		2013				2012				2011
Commodity contracts		Revenue		$	(0.1	)		$	0.7			$	1.7
Interest rate swaps		Other income (expense)			-				-				(5.0	)
The following table shows the deferred gains (losses) included in accumulated OCI that will be reclassified into earnings through the end of 2016:
		31-Dec-13				31-Dec-12
Commodity hedges		$	(3.7	)		$	23.1
Interest rate hedges			(2.4	)			(8.5	)
As of December 31, 2013, net losses of $5.6 million on commodity hedges and net losses of $2.4 million on terminated interest rate swaps recorded in OCI are expected to be reclassified to revenue and interest expense during the next twelve months.
See Note 14 for additional disclosures related to derivative instruments and hedging activities.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements [Abstract]	'
Fair Value Measurements	'
	Note 14 — Fair Value Measurements
	Under GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivative financial instruments are reported at fair value in our consolidated balance sheet. Other financial instruments are reported at historical cost or amortized cost in our consolidated balance sheet, with fair value measurements for these instruments provided as supplemental information.
	The following are additional qualitative and quantitative disclosures regarding fair value measurements of financial instruments.
	Fair Value of Derivative Financial Instruments
	Our derivative instruments consist of financially settled commodity swaps and option contracts and fixed price commodity contracts with certain counterparties. We determine the fair value of our derivative contracts using a discounted cash flow model for swaps and a standard option-pricing model for options, based on inputs that are readily available in public markets. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold.
	The fair values of our derivative instruments, which aggregate to a net liability position of $4.3 million as of December 31, 2013, are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. This liability position reflects the present value, adjusted for counterparty credit risk, of the amount we expect to receive in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the result would be a fair value reflecting a net liability of $29.9 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 $21.3 million, ignoring an adjustment for counterparty credit risk.
	Fair Value of Other Financial Instruments
	The contingent consideration obligation related to our Badlands acquisition is reported at fair value. 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. As such, long-term debt is primarily the other financial instrument for which our carrying value could vary significantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows:
		·	TRP Revolver and Securitization Facility are based on carrying value which approximates fair value as its interest rate is 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 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:
			31-Dec-13
			Carrying Value			Fair Value
						Total			Level 1		Level 2		Level 3
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Fair Value:
	Assets from commodity derivative contracts		$	5.1		$	5.1		$	-	$	3.4	$	1.7
	Liabilities from commodity derivative contracts			9.4			9.4			-		8.4		1
	Badlands contingent consideration liability			-			-			-		-		-
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Carrying Value:
	Cash and cash equivalents			57.5			57.5			-		-		-
	Senior secured revolving credit facility			395			395			-		395		-
	Senior unsecured notes			2,230.60			2,253.50			-		2,253.50		-
	Accounts receivable securitization facility			279.7			279.7			-		279.7		-
			31-Dec-12
			Carrying Value			Fair Value
						Total			Level 1		Level 2		Level 3
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Fair Value:
	Assets from commodity derivative contracts		$	34.4		$	34.4		$	-	$	34.4	$	-
	Liabilities from commodity derivative contracts			12.2			12.2			-		11.6		0.6
	Badlands contingent consideration liability			15.3			15.3			-		-		15.3
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Carrying Value:
	Cash and cash equivalents			68			68			-		-		-
	Senior secured revolving credit facility			620			620			-		620		-
	Senior unsecured notes			1,773.30			1,945.20			-		1,945.20		-
	Additional Information Regarding Level 3 Fair Value Measurements Included in Our Consolidated Balance Sheets
	As of December 31, 2013, we reported certain of our natural gas basis swaps 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 basis swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For these derivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observable prices are not available.
	As of December 31, 2013, we had thirteen natural gas basis swaps categorized as Level 3. The significant unobservable inputs used in the fair value measurements of our Level 3 derivatives are the forward natural gas basis curves, for which a significant portion of the derivative’s term is beyond available forward pricing. The change in the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.
	The Badlands acquisition agreement also provided for a contingent payment of $50 million conditioned on achieving stipulated crude gathering volumes by mid-2014. In 2012, we recorded a contingent consideration liability of $15.3 million as part of the purchase consideration for the Badlands acquisition (see Note 4). The fair value of this contingent liability was determined using a probability-based model measuring the likelihood of meeting certain volumetric measures identified in the MIPSA. These probability-based inputs are not observable; the entire valuation of the contingent consideration is categorized in Level 3. As of December 2013, management does not believe that these thresholds will be achieved during the contingency period.
	The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
			Commodity			Contingent
			Derivative			Liability
			Contracts Liability/
			(Asset)
	Balance, December 31, 2010		$	(11.6	)	$	-
	Settlements included in Revenue			3.7			-
	Transfers out of Level 3			7.9			-
	Balance, December 31, 2011			-			-
	Valuation of contingent liability			-			15.3
	Settlements included in Revenue			(0.1	)		-
	Unrealized losses included in OCI			0.7			-
	Balance, December 31, 2012			0.6			15.3
	Settlements included in Revenue			(1.3	)		-
	Change in valuation of contingent liability included in Other Income			-			(15.3	)
	Balance, December 31, 2013		$	(0.7	)	$	-
	During 2011, we transferred $7.9 million in derivative assets out of Level 3 and into Level 2. This transfer related to long-term OTC swaps executed in 2010 for NGL products with calendar year 2013 deliveries for which pricing was extrapolated (Level 3) for some periods. As of December 31, 2011, all products had actively traded contracts through December 2013 with open interest and settlement prices. Accordingly, we were no longer required to extrapolate to value our contracts and reclassified these instruments as Level 2.
	There has been no material transfer of assets or liabilities among the three levels of the fair value hierarchy during the years ended December 31, 2013 or 2012.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Note  15 — Related Party Transactions
	Targa Resources Corp.
	Targa provides general and administrative and other services to us associated with our existing assets and assets acquired from third parties. The Partnership Agreement governs the reimbursement of costs incurred on the behalf of us.
	The employees supporting our operations are employees of Targa. We reimburse Targa for the payment of certain operating expenses, including compensation and benefits of operating personnel assigned to our assets, and for the provision of various general and administrative services for our benefit. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Since October 1, 2010, after the final conveyance of assets to us by Targa, substantially all of Targa’s general and administrative costs have been and will continue to be allocated to us, other than Targa’s direct costs of being a separate public reporting company.
	Targa has reimbursed us for maintenance capital expenditures totaling $17.0 million as of December 31, 2013, which are required to be made in connection with a settlement agreement with the New Mexico Environment Department relating to air emissions at three gas processing plants operated by our Versado Gas Processors, LLC joint venture, with $0.2 million reimbursed to us during the year ended December 31, 2013. These capital projects are substantially complete.
	The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.
		2013		2012		2011
	Parent billings of payroll and related costs included in operating expense	$	109.7	$	97.2	$	87.4
	Parent allocation of general & administrative expense		134.3		124		115.2
	Cash distributions to Targa based on unit ownership		138.2		92.7		60.3
	Contributions from Targa, net		-		1		13.2
	Transactions with Unconsolidated Affiliate
	For the years 2013, 2012 and 2011, transactions with GCF included in revenues were $0.4 million, $0.1 million and $0.8 million. For the same periods, transactions with GCF included in costs and expenses were $6.3 million, $1.9 million and $0.4 million. These transactions were at market prices consistent with similar transactions with other nonaffiliated entities. We are subject to paying a deficiency fee in instances where we do not deliver minimum volume requirements as outlined in our partnership and fractionation agreements with GCF.
	Relationship with Laredo Petroleum Holdings Inc.
	Peter Kagan, a director of our general partner, is a Managing Director of Warburg Pincus LLC and is also a director of Laredo Petroleum Holdings Inc. (“Laredo”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Laredo. Purchases from Laredo during 2013 totaled $108.6 million. These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies [Abstract]	'
Commitments and Contingencies	'
	Note 16 — Commitments and Contingencies
	Future lease obligations are presented below in aggregate and for each of the next five fiscal years.
			In Aggregate		2014		2015		2016		2017		2018
	Operating leases (1)		$	33.9	$	8	$	7.8	$	7.4	$	6.1	$	4.6
	Land site lease and right-of-way (2)			7.9		1.7		1.6		1.6		1.6		1.4
			$	41.8	$	9.7	$	9.4	$	9	$	7.7	$	6
	-1	Includes minimum payments on lease obligations for office space, railcars and tractors.
	-2	Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates through 2099.
	Total expenses on lease obligations were:
			2013		2012		2011
	Operating leases (1)		$	23.3	$	16.1	$	14.2
	Land site lease and right-of-way			3.6		3.3		2.8
	-1	Includes short-term leases for items such as compressors and equipment.
	Environmental
	Environmental liabilities were not significant as of December 31, 2013.
	Legal Proceedings
	We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business that have been filed or are pending against us. We believe all such matters are without merit or involve amounts which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows.

Significant_Risks_and_Uncertai

Significant Risks and Uncertainties	12 Months Ended
	Dec. 31, 2013
Significant Risks and Uncertainties [Abstract]	'
Significant Risks and Uncertainties	'
	Note 17 — Significant Risks and Uncertainties
	Nature of Operations in Midstream Energy Industry
	We operate in the midstream energy industry. Our business activities include gathering, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products and changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.
	Our profitability could be impacted by a decline in the volume of natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration and development activities, or otherwise, could result in a decline in the volume of natural gas, NGLs and condensate handled by our facilities.
	A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.
	The principal market risks are exposure to changes in commodity prices, as well as changes in interest rates.
	Commodity Price Risk
	A majority of the revenues from the gathering and processing business are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes as payment for services. The prices of natural gas and NGLs are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control.
	In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a significant portion of our expected natural gas equity volumes through 2016 and NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). We hedge a higher percentage of our expected equity volumes in the current year as compared to future years where the volume forecasting risk is greater. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGLs and pays the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may expose us to the risk of financial loss in certain circumstances.
	The fair value of commodity 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. See Note 13.
	Interest Rate Risk
	We are exposed to changes in interest rates, primarily as a result of our variable rate borrowings under our credit facility.
	Counterparty Risk – Credit and Concentration
	Derivative Counterparty Risk
	Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.
	We have master netting provisions in the International Swap Dealers Association agreements with all of our derivative counterparties. These netting provisions allow us to net settle asset and liability positions with the same counterparties, and would reduce our maximum loss due to counterparty credit risk by $2.2 million as of December 31, 2013. The range of losses attributable to our individual counterparties would be between $1.0 million and $1.2 million, depending on the counterparty in default.
	Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value, representing expected future receipts, at the reporting date. At such times, these outstanding instruments expose us to losses in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.
	As of December 31, 2013, affiliates of Bank of America Merrill Lynch (“BAML”), Securities Americas LLC (“Natixis”) and Barclays PLC (“Barclays”), accounted for 37%, 26% and 24%, of our counterparty credit exposure related to commodity derivative instruments. BAML, Natixis and Barclays are major financial institutions that possess investment grade credit ratings based upon minimum credit ratings assigned by Moody’s Investors Service, Inc. and Standard & Poor’s Corporation.
	Customer Credit Risk
	We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met. The following table summarizes the activity affecting our allowance for bad debts:
		2013			2012			2011
	Balance at beginning of year	$	0.7		$	2.2		$	7.7
	Additions		0.2			-			0.5
	Deductions		-			(1.5	)		(6.0	)
	Balance at end of year	$	0.9		$	0.7		$	2.2
	Significant Commercial Relationships
	No customer accounted for more than 10% of our consolidated revenues for 2013.
		2013			2012			2011
	% of consolidated revenues
	Chevron Phillips Chemical Company LLC		8	%		10	%		12	%
	All transactions in the above table were associated with the Marketing and Distribution segment.
	Casualty or Other Risks
	Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverage which is customary for the nature and scope of our operations. A portion of the insurance costs described above is allocated to us by Targa through the Partnership Agreement described in Note 15.
	Management believes that Targa has adequate insurance coverage, although insurance may not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Targa may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.
	If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our obligations. Furthermore, even when a business interruption event is covered, it could affect interperiod results as we would not recognize the contingent gain until realized in a period following the incident.

Other_Operating_Expense

Other Operating Expense	12 Months Ended
	Dec. 31, 2013
Other Operating Expense [Abstract]	'
Other Operating Expense	'
	Note 18 — Other Operating Expense
			2013		2012				2011
	Abandoned Project Costs		$	0.7	$	-			$	-
	Loss on sale or disposal of assets			3.9		15.6	(1	)		0.2
	Casualty loss			4.3		3.6				-
	Miscellaneous business tax			0.7		0.7				-
			$	9.6	$	19.9			$	0.2
	-1	Includes a $15.4 million loss due to a write-off of our investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Supplemental Cash Flow Information	'
	Note 19 — Supplemental Cash Flow Information
			2013			2012			2011
	Cash:
	Interest paid, net of capitalized interest (1)		$	119.1		$	92.5		$	92.7
	Income taxes paid, net of refunds			2.3			2.3			2.5
	Non-cash:
	Deadstock inventory transferred to property, plant and equipment			30.4			3			0.7
	Badlands acquisition contingent consideration			-			15.3			-
	Accrued distribution equivalent rights			1.7			0.5			0.1
	Change in capital accruals			(0.4	)		(34.4	)		(4.8	)
	Transfers from materials and supplies to property, plant and equipment			20.5			-			-
	Change in ARO estimate			1.4			(1.0	)		1.2
	-1	Interest capitalized on expansion projects was $28.0 million, $13.6 million and $3.4 million for the years ended December 31, 2013, 2012 and 2011.

Compensation_Plans

Compensation Plans	12 Months Ended
	Dec. 31, 2013
Compensation Plans [Abstract]	'
Compensation Plans	'
	Note 20 — Compensation Plans
	For the years ended December 31, 2013, 2012 and 2011 our results include compensation expenses from the following sources:
		·	Partnership Long-Term Incentive Plan
		o	Performance Units
		o	Director grants
	Allocated compensation cost related to:
		·	Targa Resources Investments Inc. Long-Term Incentive Plan — Cash-settled Performance Units
		·	2010 TRC Stock Incentive Plan
		o	Restricted Stock Awards
		o	Restricted Stock Units Awards
		·	TRC Equity-Settled Awards
		·	Targa 401(k) Plan
	Long-Term Incentive Plans
	Performance Units
	In 2007, both Targa and we adopted Long-Term Incentive Plans (“LTIP”) for employees, consultants, directors and non-employee directors of Targa and its affiliates who perform services for Targa or its affiliates. The performance units granted under these plans are linked to the performance of our common units. These plans provide for, among other things, the grant of both cash-settled and equity-settled performance units. Performance unit awards may also include distribution equivalent rights (“DERs”). The LTIPs are administered by the compensation committee (the “Committee”) of the Targa Board of Directors. Total units authorized under the LTIP are 1,680,000.
	Each performance unit will entitle the grantee to the value of our common unit on the vesting date multiplied by a stipulated vesting percentage determined from our ranking in a defined peer group. Currently, the performance period for most awards is three years, except for certain awards granted in December 2013, which provide for two, three or four-year vesting periods. The grantee will receive the vested unit value in cash or common units depending on the terms of the grant. The grantee may also be entitled to the value of any DERs based on the notional distributions accumulated during the vesting period times the vesting percentage. DERs are cash settled for both paid in cash and equity-settled performance units.
	Compensation cost for equity-settled performance units is recognized as an expense over the performance period based on fair value at the grant date. Fair value is calculated using a simulated unit price that incorporates peer ranking. DERs associated with equity-settled performance units are accrued over the performance period as a reduction of owners’ equity.
	Compensation expense for cash-settled performance units and any related DERs will ultimately be equal to the cash paid to the grantee upon vesting. However, throughout the performance period we must record an accrued expense based on an estimate of that future pay-out. Targa used a Monte Carlo simulation model to estimate accruals throughout the vesting period. In 2012, Targa changed the volatility assumption in the Monte Carlo simulation model from implied volatility to historical volatility. We consider historical volatility to be more appropriate than implied volatility because it provides a more reliable indication of future volatility.
	Our LTIP – Equity-Settled Performance Units
	We started issuing equity-settled performance units in 2011. The following table summarizes activities of our equity-settled performance units for the years ended December 31, 2013, 2012, and 2011.
			Number				Weighted Average
			of units				Grant-Date Fair Value
	Outstanding at December 31,  2010			-			$	-
	Granted			135,870				33.94
	Outstanding at December 31,  2011			135,870				33.94
	Granted			171,750				41.94
	Outstanding at December 31,  2012			307,620				38.4
	Granted			244,578				46.54
	Outstanding at December 31,  2013			552,198				42.01
	Subsequent Event. On January 14, 2014, the Committee made awards to the executive management of the general partner for the 2014 compensation cycle of 111,745 equity-settled performance units under our LTIP that will vest in June 2017.
	Director Grants
	Starting in 2011, the common units granted to our non-management directors vested immediately at the grant date. The awards granted before 2011 settled with the delivery of common units and were subject to a three-year vesting, without a performance condition, and vested ratably on each anniversary of the grant date. In 2013, the awards granted before 2011 vested.
	The following table summarizes activity of the common unit-based awards granted to our Directors for the years ended December 31, 2013, 2012 and 2011 (in units and dollars):
			Number of units				Weighted Average
							Grant-Date Fair Value
	Outstanding at December 31,  2010			39,074			$	16.12
	Granted			10,600				33.53
	Vested and paid			(29,843	)			22.18
	Outstanding at December 31,  2011			19,831				16.31
	Granted			9,980				38.72
	Vested and paid			(25,311	)			23.86
	Outstanding at December 31,  2012			4,500				23.51
	Granted			12,780				39.33
	Vested and paid			(17,280	)			35.21
	Outstanding at December 31,  2013			-				-
	Subsequent Event. On January 14, 2014, the Committee made awards of 8,740 of our common units (1,748 units to each of our non-management directors). The awards vested immediately at the grant date.
	TRC LTIP – Cash-settled Performance Units
	The following table summarizes the cash-settled performance units for the year ended 2013 awarded under the Targa LTIP (in units and millions of dollars):
			Program Year
			2010 Plan				2011 Plan			2012 Plan			2013 Plan			Total
	Units outstanding January 1, 2013			306,253				122,550			140,820			-			569,623
	Granted			-				3,000			3,200			145,970			152,170
	Vested and paid			(305,853	)			-			-			-			(305,853	)
	Forfeited			(400	)			(680	)		(1,560	)		(1,010	)		(3,650	)
	Units outstanding December 31, 2013			-				124,870			142,460			144,960			412,290
	Calculated fair market value as of December 31, 2013						$	10.6		$	10.4		$	7.6		$	28.6
	Current liability						$	8.7		$	-		$	-		$	8.7
	Long-term liability							-			4.9			1			5.9
	Liability as of December 31, 2013						$	8.7		$	4.9		$	1		$	14.6
	To be recognized in future periods						$	1.9		$	5.5		$	6.6		$	14
	Vesting date						Jun-14			Jun-15			Jun-16
	The remaining weighted average recognition period for the unrecognized compensation cost is approximately 1.8 years.
	2010 TRC Stock Incentive Plan
The Targa Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as incentive options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock awards (“Phantom Stock Awards”), (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards (collectively referred to a “Awards”).
Restricted Stock – Total shares authorized under this plan are 5,000,000. Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends. The following table summarizes the restricted stock awards in shares and in dollars for the years indicated:
						Weighted-average
		Number of shares				Grant-Date Fair
						Value
Outstanding at December 31, 2010 (1)			1,350,000			$	22
Granted (2)			84,220				33.39
Outstanding at December 31, 2011			1,434,220				22.67
Granted (2)			91,090				42.5
Forfeited			(8,930	)			23.99
Vested (3)			(805,350	)			22
Outstanding at December 31, 2012			711,030				25.95
Granted (2)			30,623				57.59
Forfeited			(2,740	)			27.28
Vested (3)			(534,940	)			22
Outstanding at December 31, 2013			203,973				41.05
-1	These awards were issued in conjunction with the Targa IPO and vest over a three year period at 60% in 2012 and the remaining 40% in 2013.
-2	These awards will cliff vest at the end of three years.
-3	Awards vested in 2013 and 2012 were 40% and 60% of the awards issued in conjunction with the Targa IPO, net of forfeitures.  Targa repurchased 169,159 and 197,731 shares from employees at $79.01 and $47.88 per share in 2013 and 2012 to satisfy the employees’ minimum statutory tax withholdings on the vested awards.  The repurchased shares are recorded in treasury stock at cost.
The compensation expense of the restricted stocks was calculated based on the fair value of the stock at the grant date.
Restricted Stock Units (“RSUs”) – RSUs are similar to restricted stock, except that shares of common stock are not issued until the RSUs vest. The following table summarizes the restricted stock awards in shares and in dollars for the years indicated.
						Weighted-average
		Number of shares				Grant-Date Fair
						Value
Outstanding at December 31, 2012			-			$	-
Granted			55,790				69.9
Forfeited			(240	)			67.07
Outstanding at December 31, 2013			55,550				69.92
Subsequent Event. On January 14, 2014, the compensation committee (the “Committee”) made restricted stock awards of 22,017 shares to executive management under the TRC Plan for the 2014 compensation cycle that will cliff vest in three years from the grant date.
The following table summarizes the compensation expenses under the various compensation plans recognized for the years indicate:
		2013				2012			2011
LTIP - Equity-Settled Performance Units		$	5.5			$	3.1		$	1
Director Grants			0.5				0.5			0.5
Allocated from Targa
TRC LTIP - Cash-Settled Performance Units			21.9				14.2			13.3
2010 TRC Stock Incentive Plan - Restricted Stock			6.3				13.7			13.4
2010 TRC Stock Incentive Plan - Restricted Stock Units			0.4				-			-
The table below summarizes the unrecognized compensation expenses and the approximate remaining weighted average vesting periods related to our various compensation plans as of December 31, 2013:
	31-Dec-13				Weighted Average
					Remaining Vesting
					Period
	(In millions)				(In years)
LTIP Equity-Settled Performance Units		$	16.3				2
2010 TRC Stock Incentive Plan - Restricted Stock			3.3				1.6
2010 TRC Stock Incentive Plan - Restricted Stock Units			3.6				2.8
The total fair values of share-based awards on the dates they vested are as follows:
		2013				2012			2011
TRC LTIP - Cash-Settled Performance Units		$	25.2			$	22.2		$	5.5
Director Grants			0.7				1			1
2010 TRC Stock Incentive Plan - Restricted Stock (1)			42.2				40.3			-
Accrued dividends settled			2.4				2			-
-1	Targa recognized $1.6 million and $1.3 million in tax benefits for 2013 and 2012 that were associated with the vesting of the 40% and 60% restricted stock related to Targa IPO.
Targa 401(k) Plan
Targa has a 401(k) plan whereby it matches 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan).  Targa also contributes an amount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. Targa made contributions to the 401(k) plan totaling $9.6 million, $8.7 million and $7.8 million during 2013, 2012 and 2011.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Information	'
	Note 21 — Segment Information
	We report our operations in two divisions: (i) Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution. The financial results of our hedging activities are reported in Other.
	Our Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities. The Field Gathering and Processing segment's assets are located in North Texas and the Permian Basin of West Texas and New Mexico. With the Badlands acquisition on December 31, 2012, this segment's assets now include the Badlands crude oil and natural gas gathering, terminaling and processing assets in North Dakota. Because the acquisition closed on December 31, 2012, Badlands had no operational impact for 2012. The Coastal Gathering and Processing segment's assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.
	Our Logistics and Marketing division is also referred to as our Downstream Business. Our Downstream Business includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value added services such as storing, terminaling, distributing and marketing of NGLs, refined petroleum products and crude oil. It also includes certain natural gas supply and marketing activities in support of our other operations, as well as transporting natural gas and NGLs.
	Our Logistics Assets segment is involved in transporting, storing, and fractionating mixed NGLs; storing, terminaling, and transporting finished NGLs, including services for exported LPGs; and storing and terminaling refined petroleum products and crude oil. These assets are generally connected to and supplied in part by our Gathering and Processing segments and are predominantly located in Mont Belvieu, and Galena Park, Texas and Lake Charles, Louisiana.
	Our Marketing and Distribution segment covers activities required to distribute and market raw and finished NGLs and all natural gas marketing activities. It includes (1) marketing our own NGL production and purchasing NGL products 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; providing propane, butane and services to LPG exporters; and (4) marketing natural gas available to us from our Gathering and Processing division and the purchase and resale and other value added activities related to third-party natural gas in selected United States markets.
	Other contains the results of our commodity hedging activities included in operating margin. Eliminations of inter-segment transactions are reflected in the corporate and eliminations column.
	Our reportable segment information is shown in the following tables:
		Year Ended December 31, 2013
		Field			Coastal
		Gathering			Gathering						Marketing					Corporate
		and			and			Logistics			and					and
		Processing			Processing			Assets			Distribution		Other			Eliminations			Total
	Revenues
	Sales of commodities	$	188.8		$	305		$	140.5		$	5,319.30	$	21.4		$	0.1		$	5,975.10
	Fees from midstream services		112.8			33.4			216			217.1		-			(0.1	)		579.2
	Business interruption insurance		1.1			0.2			-			0.6		-			-			1.9
			302.7			338.6			356.5			5,537.00		21.4			-			6,556.20
	Intersegment revenues
	Sales of commodities		1,218.90			642.2			3.9			478.6		-			(2,343.6	)		-
	Fees from midstream services		3.4			1			176.5			29.8		-			(210.7	)		-
			1,222.30			643.2			180.4			508.4		-			(2,554.3	)		-
	Revenues	$	1,525.00		$	981.8		$	536.9		$	6,045.40	$	21.4		$	(2,554.3	)	$	6,556.20
	Operating margin	$	270.5		$	85.4		$	282.3		$	141.9	$	21.4		$	-		$	801.5
	Other financial information:
	Total assets	$	3,200.70		$	383.8		$	1,503.60		$	756.1	$	5.1		$	122.1		$	5,971.40
	Capital expenditures	$	557.8		$	20.6		$	444.7		$	6.3	$	-		$	5.1		$	1,034.50
		Year Ended December 31, 2012
		Field			Coastal
		Gathering			Gathering						Marketing					Corporate
		and			and			Logistics			and					and
		Processing			Processing			Assets			Distribution		Other			Eliminations			Total
	Revenues
	Sales of commodities	$	172.7		$	240.6		$	184.4		$	4,890.20	$	41.1		$	-		$	5,529.00
	Fees from midstream services		39.5			23.6			170.7			120.9		-			(0.1	)		354.6
			212.2			264.2			355.1			5,011.10		41.1			(0.1	)		5,883.60
	Intersegment revenues
	Sales of commodities		1,150.70			701.1			1.8			565		-			(2,418.6	)		-
	Fees from midstream services		1.3			0.1			106.5			32		-			(139.9	)		-
			1,152.00			701.2			108.3			597		-			(2,558.5	)		-
	Revenues	$	1,364.20		$	965.4		$	463.4		$	5,608.10	$	41.1		$	(2,558.6	)	$	5,883.60
	Operating margin	$	231.2		$	115.1		$	188.3		$	116	$	41.1		$	-		$	691.7
	Other financial information:
	Total assets	$	2,797.90		$	414.1		$	1,100.90		$	548.6	$	34.4		$	129.8		$	5,025.70
	Capital expenditures	$	222.1		$	9.4		$	359		$	12.3	$	-		$	13.9		$	616.7
	Business acquisitions		970.4		$	25.8		$	-		$	-	$	-		$	-		$	996.2
		Year Ended December 31, 2011
		Field			Coastal
		Gathering			Gathering						Marketing					Corporate
		and			and			Logistics			and					and
		Processing			Processing			Assets			Distribution		Other			Eliminations			Total
	Revenues
	Sales of commodities	$	184.9		$	325.7		$	43.2		$	6,209.90	$	(37.6	)	$	-		$	6,726.10
	Fees from midstream services		27.5			19.8			130			83.8		-			(0.1	)		261
			212.4			345.5			173.2			6,293.70		(37.6	)		(0.1	)		6,987.10
	Intersegment revenues
	Sales of commodities		1,428.40			952.9			1			636.5		-			(3,018.8	)		-
	Fees from midstream services		1.1			0.4			89.3			36.6		-			(127.4	)		-
			1,429.50			953.3			90.3			673.1		-			(3,146.2	)		-
	Revenues	$	1,641.90		$	1,298.80		$	263.5		$	6,966.80	$	(37.6	)	$	(3,146.3	)	$	6,987.10
	Operating margin	$	287.9		$	174.3		$	123.1		$	113.4	$	(37.6	)	$	-		$	661.1
	Other financial information:
	Total assets	$	1,666.20		$	427.5		$	775.4		$	650.5	$	51.9		$	86.5		$	3,658.00
Capital expenditures	$	167.5		$	12.8		$	147.4		$	3.5	$	-		$	2.3		$	333.5
Business acquisitions	$	-		$	-		$	156.5		$	-	$	-		$	-		$	156.5
The following table shows our consolidated revenues by product and service for the periods presented:
	2013			2012			2011
Sales of commodities
Natural gas	$	1,224.70		$	926.9		$	1,120.70
NGL		4,470.90			4,265.70			5,496.90
Condensate		121.8			114.1			103
Petroleum products		136			180.1			43.1
Derivative activities		21.7			42.2			(37.6	)
		5,975.10			5,529.00			6,726.10
Fees from midstream services
Fractionating and treating		152			115.6			86.7
Storage, terminaling, transportation and export		275.5			159.2			110.4
Gathering and processing		114.1			45			33.1
Other		37.6			34.8			30.8
		579.2			354.6			261
Business interruption insurance		1.9			-			-
Total revenues	$	6,556.20		$	5,883.60			6,987.10
The following table shows a reconciliation of operating margin to net income for the periods presented:
	2013			2012			2011
Reconciliation of operating margin to net income:
Operating margin	$	801.5		$	691.7		$	661.1
Depreciation and amortization expense		(271.6	)		(197.3	)		(178.2	)
General and administrative expense		(143.1	)		(131.6	)		(127.8	)
Interest expense, net		(131.0	)		(116.8	)		(107.7	)
Income tax expense		(2.9	)		(4.2	)		(4.3	)
Other, net		5.7			(38.6	)		2.4
Net income	$	258.6		$	203.2		$	245.5

Selected_Quarterly_Financial_D

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
Selected Quarterly Financial Data (Unaudited) [Abstract]	'
Selected Quarterly Financial Data (Unaudited)	'
	Note 22 — Selected Quarterly Financial Data (Unaudited)
	Our results of operations by quarter for the years ended December 31, 2013 and 2012 were as follows:
		First		Second		Third		Fourth
		Quarter		Quarter		Quarter		Quarter		Total
		(In millions, except per unit amounts)
	2013
	Revenues	$	1,397.80	$	1,441.60	$	1,556.90	$	2,159.90	$	6,556.20
	Gross margin		260.3		265.2		297.1		355.1		1,177.70
	Operating income		76.2		63.2		91		146.8		377.2
	Net income		45.3		32.7		65		115.6		258.6
	Net income allocable to limited partners		16.1		1.2		31.6		77.1		126
	Net income per limited partner unit
	- basic	$	0.16	$	0.01	$	0.3	$	0.7	$	1.19
	- diluted	$	0.16	$	0.01	$	0.3	$	0.7	$	1.19
	2012
	Revenues	$	1,645.50	$	1,318.40	$	1,392.90	$	1,526.80	$	5,883.60
	Gross margin		261.4		243.8		239.9		259.6		1,004.70
	Operating income		110.2		85.5		61.3		85.9		342.9
	Net income		81.8		54.7		28.1		38.6		203.2
	Net income allocable to limited partners		56		31.4		7.5		13		107.9
	Net income per limited partner unit
	- basic	$	0.64	$	0.35	$	0.08	$	0.14	$	1.2
	- diluted	$	0.63	$	0.35	$	0.08	$	0.14	$	1.2

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Significant Accounting Policies [Abstract]	'
Consolidation Policy	'
	Consolidation Policy
	Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests.
	We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
Comprehensive Income	'
	Comprehensive Income
	Comprehensive income includes net income and other comprehensive income (“OCI”), which includes unrealized gains and losses on derivative instruments that are designated as hedges.
Allowance for Doubtful Accounts	'
	Allowance for Doubtful Accounts
	Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.
Inventories	'
	Inventories
	Our inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of cost or market using the average cost method. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) are classified as Property, Plant and Equipment.  Inventories also include materials and supplies required for our Badlands expansion activities in North Dakota, which are valued using the specific identification method.
Product Exchanges	'
	Product Exchanges
	Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, a price differential may be billed or owed. The price differential is recorded as either accounts receivable or accrued liabilities.
Gas Processing Imbalances	'
	Gas Processing Imbalances
	Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.
Derivative Instruments	'
	Derivative Instruments
	We employ derivative instruments to manage the volatility of cash flows due to fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which under GAAP, are not accounted for as derivatives.
	If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense.
	If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. The ultimate gain or loss on the derivative transaction upon settlement is also recognized as a component of other income and expense.
	We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.
	The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the unrealized gain or loss to earnings in the current period.
	We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.
	For balance sheet classification purposes, we analyze the fair values of the derivative contracts on a deal by deal basis.
Property, Plant and Equipment	'
	Property, Plant and Equipment
	Property, plant and equipment are stated at acquisition value less accumulated depreciation. All of our property, plant and equipment purchased from Targa from 2007 to 2010 in drop-down transactions were stated at historical cost in the transactions recorded under common control accounting. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.
	Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs.
	Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs.
	We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of operations. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations. See Note 6.
Intangible Assets	'
	Intangible Assets
	Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with businesses acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Amortization expense attributable to these assets is recorded in a manner that closely resembles the expected pattern in which we benefit from services provided to customers. See Note 6.
Asset Retirement Obligations ("AROs")	'
	Asset Retirement Obligations (“AROs”)
	AROs are legal obligations associated with the retirement of tangible long-lived assets that result from an asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The consolidated cost of the asset and the capitalized asset retirement obligation is depreciated using the straight-line method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing.
	Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows shall be recognized as an increase or a decrease in the carrying amount of the liability for an asset retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. Upon settlement, AROs will be extinguished by us at either the recorded amount or we will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost. See Note 7.
Debt Issue Costs	'
	Debt Issue Costs
	Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issue costs.
Accounts Receivable Securitization Facility	'
	Accounts Receivable Securitization Facility
	Proceeds from the sale or contribution of certain receivables under our Accounts Receivable Securitization Facility (the “Securitization Facility”) are treated as collateralized borrowings in our financial statements. Such borrowings are reflected as long-term debt on our balance sheets to the extent that we have the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis. Proceeds and repayments under the Securitization Facility are reflected as cash flows from financing activities on our statements of cash flows.
Environmental Liabilities and Other Loss Contingencies	'
	Environmental Liabilities and Other Loss Contingencies
	Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. See Note 16.
Income Taxes	'
	Income Taxes
	We generally are not subject to federal income taxes.   For federal income tax purposes, our earnings or losses are included in the tax returns of our separate partners.  The taxable income or loss passed through to our partners may vary substantially from the net income or net loss we report in the consolidated statement of income.  We are also subject to the Texas margin tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas.
Noncontrolling Interests	'
	Noncontrolling Interests
	Third-party ownership in the net assets of our consolidated subsidiaries is shown as noncontrolling interests within the equity section of the balance sheet. In the statements of operations and statements of comprehensive income, noncontrolling interests reflects the allocation of results to third-party investors.
Revenue Recognition	'
	Revenue Recognition
	Our operating revenues are primarily derived from the following activities:
	•sales of natural gas, NGLs, condensate, crude oil and petroleum products;
	•services related to compressing, gathering, treating, and processing of natural gas; and
	•services related to NGL fractionation, terminaling and storage, transportation and treating.
	We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured.
	For natural gas processing activities, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we retain the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on a percent-of-liquids basis or a fee basis, depending on market conditions. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above.
	We generally report sales revenues gross in our consolidated statements of operations, as we typically act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership. However, buy-sell transactions with the same counterparty are reported on a net basis.
Unit-Based Compensation	'
	Unit-Based Compensation
	We award unit-based compensation to employees, directors and non-management directors in the form of restricted common units and performance units. Compensation expense on restricted common units and performance unit awards that qualify as equity arrangements are measured by the fair value of the award as determined by the market at the date of grant. Compensation expense on performance unit awards that qualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured subsequently at each reporting date through the settlement period. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. See Note 20.
Earnings per Unit	'
	Earnings per Unit
	We account for earnings per unit (“EPU”) in accordance with Accounting Standards Codification (“ASC”) Topic 260 – Earnings per Share. Diluted EPU reflects the potential dilution that could occur if securities or other contracts to issue common units were exercised or converted into common units or resulted in the issuance of common units so long as it does not have an anti-dilutive effect on EPU. The dilutive effect is determined through the application of the treasury method. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic EPU.
	The limited partners’ net income per unit is based on net income after allocation to the general partner’s 2% interest and incentive distribution rights. Because our Partnership Agreement limits the quarterly distribution payable to holders of incentive distribution rights to a percentage of Available Cash, the incentive distribution rights do not receive an allocation of earnings in excess of the incentive distributions for the period.
Use of Estimates	'
	Use of Estimates
	When preparing financial statements in conformity with GAAP, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.
Recent Accounting Pronouncements	'
	Recent Accounting Pronouncements
	In January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies that ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, applies to financial instruments or derivative transactions accounted for under ASC Topic 815. We currently present our derivative assets and liabilities on a gross basis on our statement of financial position. The amendments require disclosure of both gross and net amounts of derivative assets and liabilities that are subject to master netting arrangements with counterparties. We have provided these additional disclosures regarding the gross and net amounts of derivative assets and liabilities in Note 13.
	In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendment, required to be applied prospectively for reporting periods beginning after December 15, 2012, requires entities to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line item of net income. Our financial statement presentation complies with this standards update.

Business_Acquisitions_Tables

Business Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2013
Business Acquisitions [Abstract]	'
Summary of consideration paid and preliminary determination of assets and liabilities acquired	'
	The following table summarizes the consideration paid for the Badlands acquisition and the determination of the assets and liabilities acquired at the December 31, 2012 acquisition date.
		31-Dec-12
	Cash	$	975.8
	Contingent consideration		15.3
	Total consideration	$	991.1
	Assets acquired and liabilities assumed
	Financial assets	$	35.4
	Inventory		16.2
	Property, plant and equipment		295.3
	Intangible assets		679.6
	Financial liabilities		(35.4	)
	Total net assets	$	991.1
Pro forma consolidated results of operations	'
	The following unaudited pro forma consolidated results of operations for the years ended 2012 and 2011 has been updated to include the effects of our 2013 amortization method policy decisions.
		Year Ended December 31,
					2011
		2012
		(In millions, except per unit amounts)
	Revenues	$	5,907.80		$	6,990.70
	Net income		157.4			182.6
	Net income attributable to limited partners		63.1			104.6
	Net income per limited partner unit - Basic and diluted	$	0.63		$	1.1

Inventories_Tables

Inventories (Tables)	12 Months Ended
	Dec. 31, 2013
Inventories [Abstract]	'
Components of inventory	'
	The components of inventories consisted of the following:
		31-Dec-13		31-Dec-12
	Commodities	$	136.4	$	82.3
	Materials and supplies		14.3		17.1
		$	150.7	$	99.4

Property_Plant_and_Equipment_a1

Property, Plant and Equipment and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment and Intangible Assets [Abstract]	'
Schedule of property, plant and equipment and intangible assets	'
								Estimated useful life
		31-Dec-13			31-Dec-12			(In Years)
	Gathering systems	$	2,230.10		$	1,975.30		5 to 20
	Processing and fractionation facilities		1,598.00			1,251.60		5 to 25
	Terminaling and storage facilities		715.2			462		5 to 25
	Transportation assets		294.7			292.5		10 to 25
	Other property, plant and equipment		121.3			84.6		3 to 25
	Land		89.5			87.1			-
	Construction in progress		702.8			548.1			-
	Property, plant and equipment		5,751.60			4,701.20
	Accumulated depreciation		(1,406.2	)		(1,168.0	)
	Property, plant and equipment, net	$	4,345.40		$	3,533.20
	Intangible assets	$	681.8		$	681.9			20
	Accumulated amortization		(28.4	)		(1.1	)
	Intangible assets, net	$	653.4		$	680.8

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligations [Abstract]	'
Schedule of change in asset retirement obligation	'
	Our asset retirement obligations primarily relate to certain gas gathering pipelines and processing facilities, and are included in our consolidated balance sheets as a component of other long-term liabilities. The changes in our aggregate asset retirement obligations are as follows:
		2013		2012			2011
	Beginning of period	$	45.2	$	42.3		$	37.5
	Change in cash flow estimate		1.4		(1.0	)		1.2
	Accretion expense		3.9		3.9			3.6
	End of period	$	50.5	$	45.2		$	42.3

Investment_in_Unconsolidated_A1

Investment in Unconsolidated Affiliate (Tables)	12 Months Ended
	Dec. 31, 2013
Investment in Unconsolidated Affiliate [Abstract]	'
Investment in unconsolidated affiliate	'
	The following table shows the activity related to our investment in an unconsolidated affiliate for the years indicated:
		2013		2012		2011
	Equity earnings	$	14.8	$	1.9	$	8.8
	Cash distributions		12		2.3		8.4
	Cash calls for expansion projects		-		16.8		21.2

Accounts_Payable_and_Accrued_L1

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Accounts Payable and Accrued Liabilities [Abstract]	'
Schedule of Accounts Payable and Accrued Liabilities	'
	The components of accounts payable and accrued liabilities consisted of the following:
		31-Dec-13		31-Dec-12
	Commodities	$	520.8	$	416.8
	Other goods and services		145.1		153.4
	Interest		35.8		39.4
	Compensation and benefits		1.3		-
	Other		18.3		30.2
		$	721.2	$	639.8

Debt_Obligations_Tables

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Obligations [Abstract]	'
Schedule of Outstanding Debt	'
			31-Dec-13			31-Dec-12
	Senior secured revolving credit facility, variable rate, due October 2017 (1)		$	395		$	620
	Senior unsecured notes, 11¼% fixed rate, due July 2017 (2)			-			72.7
	Unamortized discount			-			(2.5	)
	Senior unsecured notes, 7⅞% fixed rate, due October 2018			250			250
	Senior unsecured notes, 6⅞% fixed rate, due February 2021			483.6			483.6
	Unamortized discount			(28.0	)		(30.5	)
	Senior unsecured notes, 6⅜% fixed rate, due August 2022			300			400
	Senior unsecured notes, 5¼% fixed rate, due May 2023			600			600
	Senior unsecured notes, 4¼% fixed rate, due November 2023			625			-
	Accounts receivable securitization facility, due December 2014 (3)			279.7			-
	Total long-term debt		$	2,905.30		$	2,393.30
	Letters of credit outstanding		$	86.8		$	45.3
	-1	As of December 31, 2013, availability under our $1.2 billion senior secured revolving credit facility was $718.2 million.
	-2	The outstanding balance of the 11¼% Notes was redeemed on July 15, 2013. See “Senior Notes Repayments and Redemptions” below.
	-3	All amounts outstanding under the Securitization Facility are reflected as long-term debt in our balance sheet because we have the ability and intent to fund the Securitization Facility’s borrowings on a long-term basis.
Schedule of contractually scheduled maturities of debt obligations outstanding	'
	The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2013 for the next five years, and in total thereafter:
						Scheduled Maturities of Debt
			Total			2014			2017			2018		After 2018
	Senior secured revolving credit facility		$	395		$	-		$	395		$	-	$	-
	Senior unsecured notes			2,258.60			-			-			250		2,008.60
	Account receivable securitization facility			279.7			279.7			-			-		-
	Total		$	2,933.30		$	279.7		$	395		$	250	$	2,008.60
Range of interest rates paid and weighted average interest rate paid on our variable-rate debt obligations	'
	The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year ended December 31, 2013:
			Range of Interest Rates			Weighted Average Interest Rate
			Incurred			Incurred
	Senior secured revolving credit facility			1.9% - 4.5	%		2.4	%
	Accounts receivable securitization facility			0.9	%		0.9	%
Terms of the senior unsecured notes outstanding	'
	The terms of the senior unsecured notes outstanding as of December 31, 2013 were as follows:
	Note Issue		Issue Date		Per Annum	Due Date		Dates Interest Paid
					Interest Rate
	"7⅞% Notes"		Aug-10		7⅞%	15-Oct-18		April & October 15th
	"6⅞% Notes"		Feb-11		6⅞%	1-Feb-21		February & August 1st
	"6⅜% Notes"		Jan-12		6⅜%	1-Aug-22		February & August 1st
	"5¼% Notes"		Oct / Dec 2012		5¼%	1-May-23		May & November 1st
	"4¼% Notes"		May-13		4¼%	15-Nov-23		May & November 15th
Schedule of redemption prices for issued debt	'
	We may redeem up to 35% of the aggregate principal amount of notes at the redemption dates and prices set forth below (expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or more equity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and (ii) the redemption occurs within 90 days (180 days for the 6⅜% Notes, 5¼% Notes and 4¼ % Notes) of the date of the closing of such equity offering.
	Note Issue		Any Date Prior To		Price
	7⅞% Notes		15-Oct-13		107.88%
	6⅞% Notes		1-Feb-14		106.88%
	6⅜% Notes		1-Feb-15		106.38%
	5¼% Notes		1-Nov-15		105.25%
	4¼% Notes		15-May-16		104.25%
	We may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed.
	7⅞% Notes					6⅞% Notes						6⅜% Notes					5¼% Notes					4¼% Notes
	Redemption Date:					Redemption Date:						Redemption Date:					Redemption Date:					Redemption Date:
	15-Oct					1-Feb						1-Feb					1-Nov					15-May
	Year		Price			Year			Price			Year		Price			Year		Price			Year		Price
	2014			103.938	%		2016			103.438	%		2017		103.188	%		2017		102.625	%		2018		102.125	%
	2015			101.969	%		2017			102.292	%		2018		102.125	%		2018		101.75	%		2019		101.417	%
	2016 and thereafter			100	%		2018			101.146	%		2019		101.063	%		2019		100.875	%		2020		100.708	%
						2019 and thereafter				100	%	2020 and thereafter			100	%	2020 and thereafter			100	%	2021 and thereafter			100	%
Debt re-acquisitions as reported in the Consolidated Statements of Operations	'
	The debt re-acquisitions described above were reported as follows in our Consolidated Statements of Operations:
			2013			2012
	Premium over face value paid upon redemption:
	6⅜ Notes		$	6.4		$	-
	8¼ Notes			-			8.6
	11¼ Notes			4.1			-
	Recognition of unamortized discount:
	11¼ Notes			2.2			-
	Write-off of deferred debt issue costs:
	8¼ Notes			-			2.5
	6⅜ Notes			1			-
	11¼ Notes			1			-
	Partial write-off of TRP Revolver deferred debt issue cost related to 2012 amendment			-			1.7
	Loss on debt redemptions and amendments		$	14.7		$	12.8

Partnership_Units_and_Related_1

Partnership Units and Related Matters (Tables)	12 Months Ended
	Dec. 31, 2013
Partnership Units and Related Matters [Abstract]	'
Schedule of distributions	'
	In accordance with the Partnership Agreement, we must distribute all of our available cash, as determined by the general partner, to unitholders of record within 45 days after the end of each quarter. The following table details the distributions declared and/or paid by us for the year ended December 31, 2013, 2012 and 2011.
			Distributions
	Three Months Ended	Date Paid or to be Paid	Limited		General Partner						Distributions
			Partners								per Limited
			Common		Incentive			2%	Total		Partner Unit
			(In millions, except per unit amounts)
	2013
	31-Dec-13	14-Feb-14	$	84	$	29.5	$	2.3	$	115.8	$	0.7475
	30-Sep-13	14-Nov-13		79.4		26.9		2.2		108.5		0.7325
	30-Jun-13	14-Aug-13		75.8		24.6		2		102.4		0.715
	31-Mar-13	15-May-13		71.7		22.1		1.9		95.7		0.6975
	2012
	31-Dec-12	14-Feb-13	$	69	$	20.1	$	1.8	$	90.9	$	0.68
	30-Sep-12	14-Nov-12		59.1		16.1		1.5		76.7		0.6625
	30-Jun-12	14-Aug-12		57.3		14.4		1.5		73.2		0.6425
	31-Mar-12	15-May-12		55.5		12.7		1.4		69.6		0.6225
	2011
	31-Dec-11	14-Feb-12	$	53.7	$	11	$	1.3	$	66	$	0.6025
	30-Sep-11	14-Nov-11		49.4		8.8		1.2		59.4		0.5825
	30-Jun-11	12-Aug-11		48.3		7.8		1.2		57.3		0.57
	31-Mar-11	13-May-11		47.3		6.8		1.1		55.2		0.5575

Earnings_per_Limited_Partner_U1

Earnings per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings per Limited Partner Unit [Abstract]	'
Computation of basic and diluted net income per limited partner unit	'
	The following table sets forth the computation of basic and diluted net income per limited partner unit for the years ended December 31, 2013, 2012 and 2011:
		Year Ended December 31,
		2013		2012		2011
	Net income	$	258.6	$	203.2	$	245.5
	Less: Net income attributable to noncontrolling interests		25.1		28.6		41
	Net income attributable to Targa Resources Partners LP	$	233.5	$	174.6	$	204.5
	Net income attributable to general partner		107.5		66.7		38
	Net income attributable to limited partners		126		107.9		166.5
	Net income attributable to Targa Resources Partners LP	$	233.5	$	174.6	$	204.5
	Weighted average units outstanding - basic		105.5		90.1		84.1
	Net income available per limited partner unit - basic	$	1.19	$	1.2	$	1.98
	Weighted average units outstanding		105.5		90.1		84.1
	Dilutive effect of unvested stock awards		0.2		0.1		0.1
	Weighted average units outstanding - diluted		105.7		90.2		84.2
	Net income available per limited partner unit - diluted	$	1.19	$	1.2	$	1.98

Derivative_Instruments_and_Hed1

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities [Abstract]	'
Notional volume of commodity hedges	'
	At December 31, 2013, the notional volumes of our commodity hedges for equity volumes were:
	Commodity		Instrument		Unit		2014				2015				2016
	Natural Gas		Swaps		MMBtu/d			48,050				34,551				25,500
	NGL		Swaps		Bbl/d			1,125				-				-
	Condensate		Swaps		Bbl/d			2,450				-				-
Fair values of derivative instruments	'
	Our derivative contracts are subject to netting arrangements that allow net cash settlement of offsetting asset and liability positions with the same counterparty. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their location in our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis:
				Fair Value as of December 31, 2013								Fair Value as of December 31, 2012
		Balance Sheet		Derivative				Derivative				Derivative				Derivative
		Location		Assets				Liabilities				Assets				Liabilities
	Derivatives designated as hedging instruments
	Commodity contracts	Current		$	2			$	(7.7	)		$	29.2			$	(7.2	)
		Long-term			3.1				(1.4	)			5.1				(4.8	)
	Total derivatives designated as hedging instruments			$	5.1			$	(9.1	)		$	34.3			$	(12.0	)
	Derivatives not designated as hedging instruments
	Commodity contracts	Current		$	-			$	(0.3	)		$	0.1			$	(0.2	)
	Total derivatives not designated as hedging instruments			$	-			$	(0.3	)		$	0.1			$	(0.2	)
	Total current position			$	2			$	(8.0	)		$	29.3			$	(7.4	)
	Total long-term position				3.1				(1.4	)			5.1				(4.8	)
	Total derivatives			$	5.1			$	(9.4	)		$	34.4			$	(12.2	)
Pro forma impact of derivatives net in Consolidated Balance Sheet	'
	The pro forma impact of reporting derivatives in the Consolidated Balance Sheet is as follows:
			Gross Presentation								Pro forma Net Presentation
			Asset				Liability				Asset				Liability
	31-Dec-13		Position				Position				Position				Position
	Current position
	Counterparties with offsetting position		$	1.9			$	(4.4	)		$	-			$	(2.5	)
	Counterparties without offsetting position - assets			0.1				-				0.1				-
	Counterparties without offsetting position - liabilities			-				(3.6	)			-				(3.6	)
				2				(8.0	)			0.1				(6.1	)
	Long-term position
	Counterparties with offsetting position			0.7				(1.2	)			-				(0.5	)
	Counterparties without offsetting position - assets			2.4				-				2.4				-
	Counterparties without offsetting position - liabilities			-				(0.2	)			-				(0.2	)
				3.1				(1.4	)			2.4				(0.7	)
	Total derivatives
	Counterparties with offsetting position			2.6				(5.6	)			-				(3.0	)
	Counterparties without offsetting position - assets			2.5				-				2.5				-
	Counterparties without offsetting position - liabilities			-				(3.8	)			-				(3.8	)
			$	5.1			$	(9.4	)		$	2.5			$	(6.8	)
	31-Dec-12
	Current position
	Counterparties with offsetting position		$	23.8			$	(7.4	)		$	16.4			$	-
	Counterparties without offsetting position - assets			5.5				-				5.5				-
	Counterparties without offsetting position - liabilities			-				-				-				-
				29.3				(7.4	)			21.9				-
	Long-term position
	Counterparties with offsetting position			4.4				(2.8	)			1.6				-
	Counterparties without offsetting position - assets			0.7				-				0.7				-
	Counterparties without offsetting position - liabilities			-				(2.0	)			-				(2.0	)
				5.1				(4.8	)			2.3				(2.0	)
	Total derivatives
	Counterparties with offsetting position			28.2				(10.2	)			18				-
	Counterparties without offsetting position - assets			6.2				-				6.2				-
	Counterparties without offsetting position - liabilities			-				(2.0	)			-				(2.0	)
			$	34.4			$	(12.2	)		$	24.2			$	(2.0	)
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	'
	The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue and expense for the periods indicated:
	Derivatives in Cash Flow	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)
	Hedging Relationships	2013				2012				2011
	Interest rate contracts		$	-			$	-			$	(4.4	)
	Commodity contracts			(5.8	)			76.4				(33.4	)
			$	(5.8	)		$	76.4			$	(37.8	)
		Gain (Loss) Reclassified from OCI into Income (Effective Portion)
	Location of Gain (Loss)	2013				2012				2011
	Interest expense, net		$	(6.1	)		$	(7.9	)		$	(8.1	)
	Revenues			21.2				43.9				(34.7	)
			$	15.1			$	36			$	(42.8	)
Gain (loss) recognized on commodity derivatives not designated as hedging instruments	'
	Our consolidated earnings are also affected by our use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. Gain (loss) recognized on commodity derivatives not designated as hedging instruments was immaterial for all periods presented.
	Derivatives Not Designated as		Location of Gain Recognized in		Gain (Loss) Recognized in Income on Derivatives
	Hedging Instruments		Income on Derivatives		2013				2012				2011
	Commodity contracts		Revenue		$	(0.1	)		$	0.7			$	1.7
	Interest rate swaps		Other income (expense)			-				-				(5.0	)
Schedule of gain (loss) on financial instruments	'
	The following table shows the deferred gains (losses) included in accumulated OCI that will be reclassified into earnings through the end of 2016:
			31-Dec-13				31-Dec-12
	Commodity hedges		$	(3.7	)		$	23.1
	Interest rate hedges			(2.4	)			(8.5	)

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Measurements [Abstract]	'
Fair value of assets and liabilities measured on a recurring basis	'
	The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our Consolidated Balance Sheets at fair value and (2) supplemental fair value disclosures for other financial instruments:
		31-Dec-13
		Carrying Value			Fair Value
					Total			Level 1		Level 2		Level 3
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Fair Value:
	Assets from commodity derivative contracts	$	5.1		$	5.1		$	-	$	3.4	$	1.7
	Liabilities from commodity derivative contracts		9.4			9.4			-		8.4		1
	Badlands contingent consideration liability		-			-			-		-		-
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Carrying Value:
	Cash and cash equivalents		57.5			57.5			-		-		-
	Senior secured revolving credit facility		395			395			-		395		-
	Senior unsecured notes		2,230.60			2,253.50			-		2,253.50		-
	Accounts receivable securitization facility		279.7			279.7			-		279.7		-
		31-Dec-12
		Carrying Value			Fair Value
					Total			Level 1		Level 2		Level 3
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Fair Value:
	Assets from commodity derivative contracts	$	34.4		$	34.4		$	-	$	34.4	$	-
	Liabilities from commodity derivative contracts		12.2			12.2			-		11.6		0.6
	Badlands contingent consideration liability		15.3			15.3			-		-		15.3
	Financial Instruments Recorded on Our Consolidated Balance Sheet at Carrying Value:
	Cash and cash equivalents		68			68			-		-		-
	Senior secured revolving credit facility		620			620			-		620		-
	Senior unsecured notes		1,773.30			1,945.20			-		1,945.20		-
Reconciliation of changes in fair value of financial instruments classified as level 3	'
	The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy:
		Commodity			Contingent
		Derivative			Liability
		Contracts Liability/
		(Asset)
	Balance, December 31, 2010	$	(11.6	)	$	-
	Settlements included in Revenue		3.7			-
	Transfers out of Level 3		7.9			-
	Balance, December 31, 2011		-			-
	Valuation of contingent liability		-			15.3
	Settlements included in Revenue		(0.1	)		-
	Unrealized losses included in OCI		0.7			-
	Balance, December 31, 2012		0.6			15.3
	Settlements included in Revenue		(1.3	)		-
	Change in valuation of contingent liability included in Other Income		-			(15.3	)
	Balance, December 31, 2013	$	(0.7	)	$	-

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Summary of transactions with affiliates	'
	The following table summarizes transactions with Targa. Management believes these transactions are executed on terms that are fair and reasonable.
		2013		2012		2011
	Parent billings of payroll and related costs included in operating expense	$	109.7	$	97.2	$	87.4
	Parent allocation of general & administrative expense		134.3		124		115.2
	Cash distributions to Targa based on unit ownership		138.2		92.7		60.3
	Contributions from Targa, net		-		1		13.2

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies [Abstract]	'
Future commitments related to certain contractual obligations	'
	Future lease obligations are presented below in aggregate and for each of the next five fiscal years.
			In Aggregate		2014		2015		2016		2017		2018
	Operating leases (1)		$	33.9	$	8	$	7.8	$	7.4	$	6.1	$	4.6
	Land site lease and right-of-way (2)			7.9		1.7		1.6		1.6		1.6		1.4
			$	41.8	$	9.7	$	9.4	$	9	$	7.7	$	6
	-1	Includes minimum payments on lease obligations for office space, railcars and tractors.
	-2	Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates through 2099.
Total expenses related to operating leases, capacity payments and land site lease and right-of-way agreements	'
	Total expenses on lease obligations were:
			2013		2012		2011
	Operating leases (1)		$	23.3	$	16.1	$	14.2
	Land site lease and right-of-way			3.6		3.3		2.8
	-1	Includes short-term leases for items such as compressors and equipment.

Significant_Risks_and_Uncertai1

Significant Risks and Uncertainties (Tables)	12 Months Ended
	Dec. 31, 2013
Significant Risks and Uncertainties [Abstract]	'
Allowance for bad debts	'
	We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met. The following table summarizes the activity affecting our allowance for bad debts:
		2013			2012			2011
	Balance at beginning of year	$	0.7		$	2.2		$	7.7
	Additions		0.2			-			0.5
	Deductions		-			(1.5	)		(6.0	)
	Balance at end of year	$	0.9		$	0.7		$	2.2
Customer concentration	'
	No customer accounted for more than 10% of our consolidated revenues for 2013.
		2013			2012			2011
	% of consolidated revenues
	Chevron Phillips Chemical Company LLC		8	%		10	%		12	%

Other_Operating_Expense_Tables

Other Operating Expense (Tables)	12 Months Ended
	Dec. 31, 2013
Other Operating Expense [Abstract]	'
Other operating expense	'
			2013		2012				2011
	Abandoned Project Costs		$	0.7	$	-			$	-
	Loss on sale or disposal of assets			3.9		15.6	(1	)		0.2
	Casualty loss			4.3		3.6				-
	Miscellaneous business tax			0.7		0.7				-
			$	9.6	$	19.9			$	0.2
	-1	Includes a $15.4 million loss due to a write-off of our investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant.

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Supplemental cash flow information	'
			2013			2012			2011
	Cash:
	Interest paid, net of capitalized interest (1)		$	119.1		$	92.5		$	92.7
	Income taxes paid, net of refunds			2.3			2.3			2.5
	Non-cash:
	Deadstock inventory transferred to property, plant and equipment			30.4			3			0.7
	Badlands acquisition contingent consideration			-			15.3			-
	Accrued distribution equivalent rights			1.7			0.5			0.1
	Change in capital accruals			(0.4	)		(34.4	)		(4.8	)
	Transfers from materials and supplies to property, plant and equipment			20.5			-			-
	Change in ARO estimate			1.4			(1.0	)		1.2
	-1	Interest capitalized on expansion projects was $28.0 million, $13.6 million and $3.4 million for the years ended December 31, 2013, 2012 and 2011.

Compensation_Plans_Tables

Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Compensation Plans [Abstract]	'
Nonvested share activity	'
	We started issuing equity-settled performance units in 2011. The following table summarizes activities of our equity-settled performance units for the years ended December 31, 2013, 2012, and 2011.
			Number				Weighted Average
			of units				Grant-Date Fair Value
	Outstanding at December 31,  2010			-			$	-
	Granted			135,870				33.94
	Outstanding at December 31,  2011			135,870				33.94
	Granted			171,750				41.94
	Outstanding at December 31,  2012			307,620				38.4
	Granted			244,578				46.54
	Outstanding at December 31,  2013			552,198				42.01
	The following table summarizes activity of the common unit-based awards granted to our Directors for the years ended December 31, 2013, 2012 and 2011 (in units and dollars):
			Number of units				Weighted Average
							Grant-Date Fair Value
	Outstanding at December 31,  2010			39,074			$	16.12
	Granted			10,600				33.53
	Vested and paid			(29,843	)			22.18
	Outstanding at December 31,  2011			19,831				16.31
	Granted			9,980				38.72
	Vested and paid			(25,311	)			23.86
	Outstanding at December 31,  2012			4,500				23.51
	Granted			12,780				39.33
	Vested and paid			(17,280	)			35.21
	Outstanding at December 31,  2013			-				-
Nonvested performance based units activity	'
	The following table summarizes the cash-settled performance units for the year ended 2013 awarded under the Targa LTIP (in units and millions of dollars):
			Program Year
			2010 Plan				2011 Plan			2012 Plan			2013 Plan			Total
	Units outstanding January 1, 2013			306,253				122,550			140,820			-			569,623
	Granted			-				3,000			3,200			145,970			152,170
	Vested and paid			(305,853	)			-			-			-			(305,853	)
	Forfeited			(400	)			(680	)		(1,560	)		(1,010	)		(3,650	)
	Units outstanding December 31, 2013			-				124,870			142,460			144,960			412,290
	Calculated fair market value as of December 31, 2013						$	10.6		$	10.4		$	7.6		$	28.6
	Current liability						$	8.7		$	-		$	-		$	8.7
	Long-term liability							-			4.9			1			5.9
	Liability as of December 31, 2013						$	8.7		$	4.9		$	1		$	14.6
	To be recognized in future periods						$	1.9		$	5.5		$	6.6		$	14
	Vesting date						Jun-14			Jun-15			Jun-16
Share based compensation restricted stock and restricted stock units activity	'
	Restricted Stock – Total shares authorized under this plan are 5,000,000. Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared and recorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends. The following table summarizes the restricted stock awards in shares and in dollars for the years indicated:
							Weighted-average
			Number of shares				Grant-Date Fair
							Value
	Outstanding at December 31, 2010 (1)			1,350,000			$	22
	Granted (2)			84,220				33.39
	Outstanding at December 31, 2011			1,434,220				22.67
	Granted (2)			91,090				42.5
	Forfeited			(8,930	)			23.99
	Vested (3)			(805,350	)			22
	Outstanding at December 31, 2012			711,030				25.95
	Granted (2)			30,623				57.59
	Forfeited			(2,740	)			27.28
	Vested (3)			(534,940	)			22
	Outstanding at December 31, 2013			203,973				41.05
	-1	These awards were issued in conjunction with the Targa IPO and vest over a three year period at 60% in 2012 and the remaining 40% in 2013.
	-2	These awards will cliff vest at the end of three years.
	-3	Awards vested in 2013 and 2012 were 40% and 60% of the awards issued in conjunction with the Targa IPO, net of forfeitures.  Targa repurchased 169,159 and 197,731 shares from employees at $79.01 and $47.88 per share in 2013 and 2012 to satisfy the employees’ minimum statutory tax withholdings on the vested awards.  The repurchased shares are recorded in treasury stock at cost.
	The compensation expense of the restricted stocks was calculated based on the fair value of the stock at the grant date.
	Restricted Stock Units (“RSUs”) – RSUs are similar to restricted stock, except that shares of common stock are not issued until the RSUs vest. The following table summarizes the restricted stock awards in shares and in dollars for the years indicated.
							Weighted-average
			Number of shares				Grant-Date Fair
							Value
	Outstanding at December 31, 2012			-			$	-
	Granted			55,790				69.9
	Forfeited			(240	)			67.07
	Outstanding at December 31, 2013			55,550				69.92
Summary compensation expenses under the various compensation plans	'
	The following table summarizes the compensation expenses under the various compensation plans recognized for the years indicate:
			2013				2012			2011
	LTIP - Equity-Settled Performance Units		$	5.5			$	3.1		$	1
	Director Grants			0.5				0.5			0.5
	Allocated from Targa
	TRC LTIP - Cash-Settled Performance Units			21.9				14.2			13.3
	2010 TRC Stock Incentive Plan - Restricted Stock			6.3				13.7			13.4
	2010 TRC Stock Incentive Plan - Restricted Stock Units			0.4				-			-
Summary the unrecognized compensation expenses	'
	The table below summarizes the unrecognized compensation expenses and the approximate remaining weighted average vesting periods related to our various compensation plans as of December 31, 2013:
		31-Dec-13				Weighted Average
						Remaining Vesting
						Period
		(In millions)				(In years)
	LTIP Equity-Settled Performance Units		$	16.3				2
	2010 TRC Stock Incentive Plan - Restricted Stock			3.3				1.6
	2010 TRC Stock Incentive Plan - Restricted Stock Units			3.6				2.8
Fair values of share-based awards on the dates vested	'
	The total fair values of share-based awards on the dates they vested are as follows:
			2013				2012			2011
	TRC LTIP - Cash-Settled Performance Units		$	25.2			$	22.2		$	5.5
	Director Grants			0.7				1			1
	2010 TRC Stock Incentive Plan - Restricted Stock (1)			42.2				40.3			-
	Accrued dividends settled			2.4				2			-
	-1	Targa recognized $1.6 million and $1.3 million in tax benefits for 2013 and 2012 that were associated with the vesting of the 40% and 60% restricted stock related to Targa IPO.

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Information by segment	'
	Our reportable segment information is shown in the following tables:
		Year Ended December 31, 2013
		Field			Coastal
		Gathering			Gathering						Marketing					Corporate
		and			and			Logistics			and					and
		Processing			Processing			Assets			Distribution		Other			Eliminations			Total
	Revenues
	Sales of commodities	$	188.8		$	305		$	140.5		$	5,319.30	$	21.4		$	0.1		$	5,975.10
	Fees from midstream services		112.8			33.4			216			217.1		-			(0.1	)		579.2
	Business interruption insurance		1.1			0.2			-			0.6		-			-			1.9
			302.7			338.6			356.5			5,537.00		21.4			-			6,556.20
	Intersegment revenues
	Sales of commodities		1,218.90			642.2			3.9			478.6		-			(2,343.6	)		-
	Fees from midstream services		3.4			1			176.5			29.8		-			(210.7	)		-
			1,222.30			643.2			180.4			508.4		-			(2,554.3	)		-
	Revenues	$	1,525.00		$	981.8		$	536.9		$	6,045.40	$	21.4		$	(2,554.3	)	$	6,556.20
	Operating margin	$	270.5		$	85.4		$	282.3		$	141.9	$	21.4		$	-		$	801.5
	Other financial information:
	Total assets	$	3,200.70		$	383.8		$	1,503.60		$	756.1	$	5.1		$	122.1		$	5,971.40
	Capital expenditures	$	557.8		$	20.6		$	444.7		$	6.3	$	-		$	5.1		$	1,034.50
		Year Ended December 31, 2012
		Field			Coastal
		Gathering			Gathering						Marketing					Corporate
		and			and			Logistics			and					and
		Processing			Processing			Assets			Distribution		Other			Eliminations			Total
	Revenues
	Sales of commodities	$	172.7		$	240.6		$	184.4		$	4,890.20	$	41.1		$	-		$	5,529.00
	Fees from midstream services		39.5			23.6			170.7			120.9		-			(0.1	)		354.6
			212.2			264.2			355.1			5,011.10		41.1			(0.1	)		5,883.60
	Intersegment revenues
	Sales of commodities		1,150.70			701.1			1.8			565		-			(2,418.6	)		-
	Fees from midstream services		1.3			0.1			106.5			32		-			(139.9	)		-
			1,152.00			701.2			108.3			597		-			(2,558.5	)		-
	Revenues	$	1,364.20		$	965.4		$	463.4		$	5,608.10	$	41.1		$	(2,558.6	)	$	5,883.60
	Operating margin	$	231.2		$	115.1		$	188.3		$	116	$	41.1		$	-		$	691.7
	Other financial information:
	Total assets	$	2,797.90		$	414.1		$	1,100.90		$	548.6	$	34.4		$	129.8		$	5,025.70
	Capital expenditures	$	222.1		$	9.4		$	359		$	12.3	$	-		$	13.9		$	616.7
	Business acquisitions		970.4		$	25.8		$	-		$	-	$	-		$	-		$	996.2
		Year Ended December 31, 2011
		Field			Coastal
		Gathering			Gathering						Marketing					Corporate
		and			and			Logistics			and					and
		Processing			Processing			Assets			Distribution		Other			Eliminations			Total
	Revenues
	Sales of commodities	$	184.9		$	325.7		$	43.2		$	6,209.90	$	(37.6	)	$	-		$	6,726.10
	Fees from midstream services		27.5			19.8			130			83.8		-			(0.1	)		261
			212.4			345.5			173.2			6,293.70		(37.6	)		(0.1	)		6,987.10
	Intersegment revenues
	Sales of commodities		1,428.40			952.9			1			636.5		-			(3,018.8	)		-
	Fees from midstream services		1.1			0.4			89.3			36.6		-			(127.4	)		-
			1,429.50			953.3			90.3			673.1		-			(3,146.2	)		-
	Revenues	$	1,641.90		$	1,298.80		$	263.5		$	6,966.80	$	(37.6	)	$	(3,146.3	)	$	6,987.10
	Operating margin	$	287.9		$	174.3		$	123.1		$	113.4	$	(37.6	)	$	-		$	661.1
	Other financial information:
	Total assets	$	1,666.20		$	427.5		$	775.4		$	650.5	$	51.9		$	86.5		$	3,658.00
	Capital expenditures	$	167.5		$	12.8		$	147.4		$	3.5	$	-		$	2.3		$	333.5
	Business acquisitions	$	-		$	-		$	156.5		$	-	$	-		$	-		$	156.5
Revenues by product and service	'
	The following table shows our consolidated revenues by product and service for the periods presented:
		2013			2012			2011
	Sales of commodities
	Natural gas	$	1,224.70		$	926.9		$	1,120.70
	NGL		4,470.90			4,265.70			5,496.90
	Condensate		121.8			114.1			103
	Petroleum products		136			180.1			43.1
	Derivative activities		21.7			42.2			(37.6	)
			5,975.10			5,529.00			6,726.10
	Fees from midstream services
	Fractionating and treating		152			115.6			86.7
	Storage, terminaling, transportation and export		275.5			159.2			110.4
	Gathering and processing		114.1			45			33.1
	Other		37.6			34.8			30.8
			579.2			354.6			261
	Business interruption insurance		1.9			-			-
	Total revenues	$	6,556.20		$	5,883.60			6,987.10
Reconciliation of operating margin to net income	'
	The following table shows a reconciliation of operating margin to net income for the periods presented:
		2013			2012			2011
	Reconciliation of operating margin to net income:
	Operating margin	$	801.5		$	691.7		$	661.1
	Depreciation and amortization expense		(271.6	)		(197.3	)		(178.2	)
	General and administrative expense		(143.1	)		(131.6	)		(127.8	)
	Interest expense, net		(131.0	)		(116.8	)		(107.7	)
	Income tax expense		(2.9	)		(4.2	)		(4.3	)
	Other, net		5.7			(38.6	)		2.4
	Net income	$	258.6		$	203.2		$	245.5

Selected_Quarterly_Financial_D1

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Selected Quarterly Financial Data (Unaudited) [Abstract]	'
Selected quarterly financial data (Unaudited)	'
	Our results of operations by quarter for the years ended December 31, 2013 and 2012 were as follows:
		First		Second		Third		Fourth
		Quarter		Quarter		Quarter		Quarter		Total
		(In millions, except per unit amounts)
	2013
	Revenues	$	1,397.80	$	1,441.60	$	1,556.90	$	2,159.90	$	6,556.20
	Gross margin		260.3		265.2		297.1		355.1		1,177.70
	Operating income		76.2		63.2		91		146.8		377.2
	Net income		45.3		32.7		65		115.6		258.6
	Net income allocable to limited partners		16.1		1.2		31.6		77.1		126
	Net income per limited partner unit
	- basic	$	0.16	$	0.01	$	0.3	$	0.7	$	1.19
	- diluted	$	0.16	$	0.01	$	0.3	$	0.7	$	1.19
	2012
	Revenues	$	1,645.50	$	1,318.40	$	1,392.90	$	1,526.80	$	5,883.60
	Gross margin		261.4		243.8		239.9		259.6		1,004.70
	Operating income		110.2		85.5		61.3		85.9		342.9
	Net income		81.8		54.7		28.1		38.6		203.2
	Net income allocable to limited partners		56		31.4		7.5		13		107.9
	Net income per limited partner unit
	- basic	$	0.64	$	0.35	$	0.08	$	0.14	$	1.2
	- diluted	$	0.63	$	0.35	$	0.08	$	0.14	$	1.2

Organization_and_Operations_De

Organization and Operations (Details)	Dec. 31, 2013	Dec. 31, 2012
Organization and Operations [Abstract]	'	'
General partner interest (in hundredths)	2.00%	'
Ownership interest by related party and subsidiaries (in hundredths)	13.40%	'
General partner units outstanding (in units)	2,270,680	2,042,776
Common units held by related party (in units)	12,945,659	'
Increasing cash distributions as percentage of distributable cash for a quarter (in hundredths)	48.00%	'

Significant_Accounting_Policie2

Significant Accounting Policies (Details)	Dec. 31, 2013
Income Taxes [Abstract]	'
Margin tax rate (in hundredths)	1.00%
Earnings per Limited Partner Unit [Abstract]	'
General partner's interest and incentive distribution rights (in hundredths)	2.00%
Minimum [Member]	'
Consolidation [Line Items]	'
Equity method of accounting ownership interest (in hundredths)	20.00%
Maximum [Member]	'
Consolidation [Line Items]	'
Equity method of accounting ownership interest (in hundredths)	50.00%

Business_Acquisitions_Details

Business Acquisitions (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition, Equity Interests Issued or Issuable [Line Items]	'	'	'
Amount of purchase price paid in cash	$0	$996.20	$156.50
Consideration paid [Abstract]	'	'	'
Cash	0	996.2	156.5
Pro forma consolidated results of operations [Abstract]	'	'	'
Useful life of acquired definite-lived intangibles - pro-forma	'	'20 years	'
Minimum [Member]	'	'	'
Pro forma consolidated results of operations [Abstract]	'	'	'
Useful life of acquired property, plant, and equipment - pro-forma	'	'15 years	'
Maximum [Member]	'	'	'
Pro forma consolidated results of operations [Abstract]	'	'	'
Useful life of acquired property, plant, and equipment - pro-forma	'	'20 years	'
Channelview Acquisition [Member]	'	'	'
Business Acquisition, Equity Interests Issued or Issuable [Line Items]	'	'	'
Amount of purchase price paid in cash	'	'	29
Acquired terminal capacity (Bbl)	'	'	544,000
Number of refined petroleum products and crude oil storage and terminaling facilities acquired	'	'	2
Consideration paid [Abstract]	'	'	'
Cash	'	'	29
Baltimore Acquisition [Member]	'	'	'
Business Acquisition, Equity Interests Issued or Issuable [Line Items]	'	'	'
Acquired terminal capacity (Bbl)	'	'	505,000
Tacoma Acquisition [Member]	'	'	'
Business Acquisition, Equity Interests Issued or Issuable [Line Items]	'	'	'
Acquired terminal capacity (Bbl)	'	'	758,000
Total of Baltimore and Tacoma Acquisitions [Member]	'	'	'
Business Acquisition, Equity Interests Issued or Issuable [Line Items]	'	'	'
Amount of purchase price paid in cash	'	'	135
Consideration paid [Abstract]	'	'	'
Cash	'	'	135
Badlands [Member]	'	'	'
Business Acquisition, Equity Interests Issued or Issuable [Line Items]	'	'	'
Amount of purchase price paid in cash	'	975.8	'
Contingent consideration	'	50	'
Accrued liability representing fair value of contingent consideration	0	15.3	'
Decrease in contingent consideration	15.3	'	'
Consideration paid [Abstract]	'	'	'
Cash	'	975.8	'
Contingent consideration	'	15.3	'
Total consideration	'	991.1	'
Assets acquired and liabilities assumed [Abstract]	'	'	'
Financial assets	'	35.4	'
Inventory	'	16.2	'
Property, plant and equipment	'	295.3	'
Intangible assets	'	679.6	'
Financial liabilities	'	-35.4	'
Total net assets	'	991.1	'
Pro forma consolidated results of operations [Abstract]	'	'	'
Revenues	'	5,907.80	6,990.70
Net income	'	157.4	182.6
Net income attributable to limited partners	'	63.1	104.6
Net income per limited partner unit - Basic and diluted (in dollars per share)	'	$0.63	$1.10
Acquisition-related costs	'	$6.10	'

InventoriesDetails

Inventories(Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Components of inventory [Abstract]	'	'
Commodities	$136.40	$82.30
Materials and supplies	14.3	17.1
Total inventory	$150.70	$99.40

Property_Plant_and_Equipment_a2

Property, Plant and Equipment and Intangible Assets (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	$5,751.60	$4,701.20
Accumulated depreciation	-1,406.20	-1,168
Property, plant and equipment, net	4,345.40	3,533.20
Intangible assets	681.8	681.9
Accumulated Amortization	-28.4	-1.1
Intangible assets, net	653.4	680.8
Finite-Lived Intangible Assets, Future Amortization Expense [Abstract]	'	'
2014	61.4	'
2015	80.1	'
2016	88.3	'
2017	81.5	'
2018	67.8	'
Intangible Assets [Member]	'	'
Finite-Lived Intangible Assets [Line Items]	'	'
Intangible assets, estimated useful lives (in years)	'20 years	'
Amortization expense	27.3	'
Gathering systems [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	2,230.10	1,975.30
Gathering systems [Member] | Minimum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives (in years)	'5 years	'
Gathering systems [Member] | Maximum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives (in years)	'20 years	'
Processing and fractionation facilities [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	1,598	1,251.60
Processing and fractionation facilities [Member] | Minimum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives (in years)	'5 years	'
Processing and fractionation facilities [Member] | Maximum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives (in years)	'25 years	'
Terminaling and storage facilities [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	715.2	462
Terminaling and storage facilities [Member] | Minimum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives (in years)	'5 years	'
Terminaling and storage facilities [Member] | Maximum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives (in years)	'25 years	'
Transportation assets [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	294.7	292.5
Transportation assets [Member] | Minimum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives (in years)	'10 years	'
Transportation assets [Member] | Maximum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives (in years)	'25 years	'
Other property, plant and equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	121.3	84.6
Other property, plant and equipment [Member] | Minimum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives (in years)	'3 years	'
Other property, plant and equipment [Member] | Maximum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Estimated useful lives (in years)	'25 years	'
Land [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	89.5	87.1
Estimated useful lives (in years)	'0 years	'
Construction in progress [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment	$702.80	$548.10
Estimated useful lives (in years)	'0 years	'

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in aggregate asset retirement obligations [Roll Forward]	'	'	'
Beginning of period	$45.20	$42.30	$37.50
Change in cash flow estimate	1.4	-1	1.2
Accretion expense	3.9	3.9	3.6
End of period	$50.50	$45.20	$42.30

Investment_in_Unconsolidated_A2

Investment in Unconsolidated Affiliate (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]	'	'	'
Equity earnings	$14.80	$1.90	$8.80
GCF [Member]	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'
Ownership interest (in hundredths)	38.80%	38.80%	38.80%
Equity earnings	14.8	1.9	8.8
Cash distributions	12	2.3	8.4
Cash calls for expansion projects	$0	$16.80	$21.20

Accounts_Payable_and_Accrued_L2

Accounts Payable and Accrued Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Accounts Payable and Accrued Liabilities [Abstract]	'	'
Commodities	$520.80	$416.80
Other goods and services	145.1	153.4
Interest	35.8	39.4
Compensation and benefits	1.3	0
Other	18.3	30.2
Accounts payable and accrued liabilities	$721.20	$639.80

Debt_Obligations_Longterm_Debt

Debt Obligations, Long-term Debt (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Oct. 31, 2012

Dec. 31, 2013

In Millions, unless otherwise specified

Secured Debt [Member]

Unsecured Debt [Member]

Accounts Receivable Securitization Facility [Member]

Accounts Receivable Securitization Facility [Member]

TRC Senior Secured Revolving Credit Facility due 2017 [Member]

TRC Senior Secured Revolving Credit Facility due 2017 [Member]

Senior unsecured notes due 2017 [Member]

Senior unsecured notes due 2017 [Member]

Senior Unsecured 7 7/8% Notes due October 2018 [Member]

Senior Unsecured 7 7/8% Notes due October 2018 [Member]

Senior Unsecured 7 7/8% Notes due October 2018 [Member]

Senior Unsecured 6 7/8% Notes due February 2021 [Member]

Senior Unsecured 6 7/8% Notes due February 2021 [Member]

Senior Unsecured 6 7/8% Notes due February 2021 [Member]

Senior Unsecured 6 3/8% Notes due August 2022 [Member]

Senior Unsecured 6 3/8% Notes due August 2022 [Member]

Senior Unsecured 6 3/8% Notes due August 2022 [Member]

Senior unsecured notes due 2023 [Member]

Senior unsecured notes due 2023 [Member]

Senior unsecured notes due 2023 [Member]

Senior Unsecured 4 1/4% Notes due November 2023 [Member]

Senior Unsecured 4 1/4% Notes due November 2023 [Member]

Senior Unsecured 4 1/4% Notes due November 2023 [Member]

TRP Revolver [Member]

TRP Revolver [Member]

Senior secured credit facility [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Schedule of Debt Instruments [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt

$2,905.30

$2,393.30

'

'

$279.70

[1]

$0

[1]

$395

[2]

$620

[2]

$0

[3]

$72.70

[3]

$250

$250

'

$483.60

$483.60

'

$300

$400

'

$600

$600

'

$625

$0

'

'

'

'

Unamortized discount

'

'

'

'

'

'

'

'

0

-2.5

'

'

'

-28

-30.5

'

'

'

'

'

'

'

'

'

'

'

'

'

Maturity date

'

'

'

'

31-Dec-14

'

31-Oct-17

'

31-Jul-17

'

15-Oct-18

'

15-Oct-18

1-Feb-21

'

1-Feb-21

1-Aug-22

'

1-Aug-22

1-May-23

'

1-May-23

15-Nov-23

'

15-Nov-23

'

'

'

Interest rate on fixed rate debt (in hundredths)

'

'

'

'

'

'

'

'

11.25%

'

7.88%

'

'

6.88%

'

'

6.38%

'

'

5.25%

'

'

4.25%

'

'

'

'

'

Letters of credit outstanding

86.8

45.3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of Credit Facility, Maximum Borrowing Capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200

1,200

'

Availability of credit under senior secured credit facility

'

'

'

'

'

'

718.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Range of Interest Rates Incurred, Minimum (in hundredths)

'

'

'

'

0.90%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.90%

Range of Interest Rates Incurred, Maximum (in hundredths)

'

'

'

'

0.90%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.50%

Weighted Average Interest Rate Incurred (in hundredths)

'

'

'

'

0.90%

'

'

'

'

'

'

'

7.88%

'

'

6.88%

'

'

6.38%

'

'

5.25%

'

'

4.25%

'

'

2.40%

Maturities of Long-term Debt [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Total

2,933.30

'

395

2,258.60

279.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Maturities, Repayments 2014

279.7

'

0

0

279.7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Maturities, Repayments 2017

395

'

395

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Maturities, Repayments 2018

250

'

0

250

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Maturities, Repayments after Year 2018

$2,008.60

'

$0

$2,008.60

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

All amounts outstanding under the Securitization Facility are reflected as long-term debt in our balance sheet because we have the ability and intent to fund the Securitization Facilitybs borrowings on a long-term basis.

[2]

As of December 31, 2013, availability under our $1.2B billion senior secured revolving credit facility was $718.2B million.

[3]

The outstanding balance of the 11B

Debt_Obligations_Revolving_Cre

Debt Obligations, Revolving Credit Agreement (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Oct. 31, 2012
TRP Revolver [Member]	'	'
Revolving Credit Agreement [Abstract]	'	'
Maximum borrowing capacity	$1,200	$1,200
Additional commitment increase available upon request	300	300
Maximum consolidated leverage ratio	5.5	'
Minimum ratio of consolidated EBITDA to consolidated interest expense	2.25	'
TRP Revolver [Member] | Maximum [Member]	'	'
Revolving Credit Agreement [Abstract]	'	'
Commitment fee percentage (in hundredths)	0.50%	'
Interest rate percentage (in hundredths)	2.75%	'
TRP Revolver [Member] | Minimum [Member]	'	'
Revolving Credit Agreement [Abstract]	'	'
Commitment fee percentage (in hundredths)	0.30%	'
Interest rate percentage (in hundredths)	1.75%	'
TRP Revolver [Member] | Federal Funds Rate [Member]	'	'
Revolving Credit Agreement [Abstract]	'	'
Basis spread on variable rate (in hundredths)	0.50%	'
TRP Revolver [Member] | Base Rate [Member] | Maximum [Member]	'	'
Revolving Credit Agreement [Abstract]	'	'
Basis spread on variable rate (in hundredths)	1.75%	'
TRP Revolver [Member] | Base Rate [Member] | Minimum [Member]	'	'
Revolving Credit Agreement [Abstract]	'	'
Basis spread on variable rate (in hundredths)	0.75%	'
TRP Revolver [Member] | Eurodollar [Member] | Maximum [Member]	'	'
Revolving Credit Agreement [Abstract]	'	'
Basis spread on variable rate (in hundredths)	2.75%	'
TRP Revolver [Member] | Eurodollar [Member] | Minimum [Member]	'	'
Revolving Credit Agreement [Abstract]	'	'
Basis spread on variable rate (in hundredths)	1.75%	'
TRP Revolver [Member] | London Interbank Offered Rate (LIBOR) [Member]	'	'
Revolving Credit Agreement [Abstract]	'	'
Basis spread on variable rate (in hundredths)	1.00%	'
Senior Secured Revolving Credit Facility due July 2015 [Member]	'	'
Revolving Credit Agreement [Abstract]	'	'
Maximum borrowing capacity	'	$1,100

Debt_Obligations_Senior_Unsecu

Debt Obligations, Senior Unsecured Notes (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Nov. 30, 2012

Jul. 31, 2013

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Jan. 31, 2012

Dec. 31, 2013

31-May-13

Oct. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Senior Unsecured 11 1/4% Notes due July 2017 [Member]

Senior Unsecured 7 7/8% Notes due October 2018 [Member]

Senior Unsecured 6 7/8% Notes due February 2021 [Member]

Senior Unsecured 6 3/8% Notes due August 2022 [Member]

Senior Unsecured 5 1/4% Notes due May 2023 [Member]

Senior Unsecured 4 1/4% Notes due November 2023 [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Senior Unsecured 11 1/4% Notes due July 2017 [Member]

Senior Unsecured 11 1/4% Notes due July 2017 [Member]

Senior Unsecured 11 1/4% Notes due July 2017 [Member]

Senior Unsecured 7 7/8% Notes due October 2018 [Member]

Senior Unsecured 6 7/8% Notes due February 2021 [Member]

Senior Unsecured 6 7/8% Notes due February 2021 [Member]

Senior Unsecured 6 3/8% Notes due August 2022 [Member]

Senior Unsecured 6 3/8% Notes due August 2022 [Member]

Senior Unsecured 5 1/4% Notes due May 2023 [Member]

Senior Unsecured 5 1/4% Notes due May 2023 [Member]

Senior Unsecured 5 1/4% Notes due May 2023 [Member]

Senior Unsecured 5 1/4% Notes due May 2023 [Member]

Senior Unsecured 4 1/4% Notes due November 2023 [Member]

The Partnership's Senior Unsecured Notes [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Principal amount of debt exchanged

'

'

'

'

'

'

'

'

'

'

'

'

($158.60)

'

'

$158.60

$400

'

$625

$400

'

$200

'

Cash paid on note exchange

0

0

-27.7

'

'

'

'

'

'

'

'

'

'

'

'

28.6

'

'

'

'

'

'

'

Accrued Interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.9

'

'

'

'

'

'

'

Remaining face value of debt whose debt covenants have been removed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

72.7

'

'

'

'

'

'

'

Aggregate principal amount issued

'

'

'

'

'

'

'

'

'

'

'

'

-158.6

'

'

158.6

400

'

625

400

'

200

'

Net proceeds from private placement of notes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

395.5

'

618.1

'

'

'

'

Percentage of face amount issued (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

99.50%

'

101.00%

'

Gross proceeds from issuance of notes

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

398

'

202

'

Redemption price, percentage of face value (in hundredths)

'

'

'

'

'

'

'

'

'

104.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt redeemed

183.2

217.7

0

'

'

'

'

'

'

'

76.8

'

'

'

106.4

'

'

'

'

'

'

'

'

Face amount of notes redeemed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100

'

'

'

'

'

'

'

'

Pretax gain on extinguishment of debt

'

'

'

'

'

'

'

'

'

'

$7.40

'

'

'

$7.40

'

'

'

'

'

'

'

'

Terms of the Senior Unsecured Notes Outstanding [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Issue Date

'

'

'

'

'

'

'

'

'

'

'

'

'

1-Aug-10

'

1-Feb-11

'

1-Jan-12

'

'

'

'

1-May-13

Issue Date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'Oct / Dec 2012

'

'

Per Annum Interest Rate (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

7.88%

'

6.88%

'

6.38%

'

'

5.25%

'

4.25%

Due Date

'

'

'

31-Jul-17

15-Oct-18

1-Feb-21

1-Aug-22

1-May-23

15-Nov-23

'

'

'

'

15-Oct-18

'

1-Feb-21

'

1-Aug-22

'

'

1-May-23

'

15-Nov-23

Dates Interest Paid

'

'

'

'

'

'

'

'

'

'

'

'

'

'April & October 15th

'

'February & August 1st

'

'February & August 1st

'

'

'May & November 1st

'

'May & November 15th

Maximum percentage of aggregate principal amount of debt redeemable by the Partnership with equity offerings (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

35.00%

'

35.00%

'

35.00%

'

'

35.00%

'

35.00%

Redemption condition, minimum percentage of aggregate principal amount outstanding immediately after occurrence of redemption (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

65.00%

'

65.00%

'

65.00%

'

65.00%

'

'

65.00%

'

65.00%

Redemption condition, maximum number of days from date of closing of equity offerings (in days)

'

'

'

'

'

'

'

'

'

'

'

'180

'

'90

'

'90

'

'180

'

'

'180

'

'180

Redemption Dates and Prices [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dates Interest Paid

'

'

'

'

'

'

'

'

'

'

'

'

'

15-Oct-13

'

1-Feb-14

'

1-Feb-15

'

'

1-Nov-15

'

15-May-16

Debt Instrument, Priority

'

'

'

'

'

'

'

'

'

'

'

'

'

107.88%

'

106.88%

'

106.38%

'

'

105.25%

'

104.25%

Redemption Percentages [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption price, as percentage of principal amount outstanding, 2014 (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

103.94%

'

'

'

'

'

'

'

'

'

Redemption price, as percentage of principal amount outstanding, 2015 (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

101.97%

'

'

'

'

'

'

'

'

'

Redemption price, as percentage of principal amount outstanding, 2016 and thereafter (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

Redemption price, as percentage of principal amount outstanding, 2016 (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

103.44%

'

'

'

'

'

'

'

Redemption price, as percentage of principal amount outstanding, 2017 (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

102.29%

'

103.19%

'

'

102.63%

'

'

Redemption price, as percentage of principal amount outstanding, 2018 (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

101.15%

'

102.13%

'

'

101.75%

'

102.13%

Redemption price, as percentage of principal amount outstanding, 2020 and thereafter (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

100.00%

'

'

100.00%

'

'

Redemption price, as percentage of principal amount outstanding, 2019 (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

101.06%

'

'

100.88%

'

101.42%

Redemption price, as percentage of principal amount outstanding, 2020 and thereafter (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

100.00%

'

'

100.00%

'

'

Redemption price, as percentage of principal amount outstanding, 2020 (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.71%

Redemption price, as percentage of principal amount outstanding, 2021 and thereafter (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

Debt_Obligations_Accounts_Rece

Debt Obligations, Accounts Receivable Securitization Facility and Shelf Registration Statements (Details) (USD $)	Dec. 31, 2013	Jan. 31, 2013	Dec. 31, 2013	Jul. 31, 2013
In Millions, unless otherwise specified		Accounts Receivable Securitization Facility [Member]	Second Amendment to Accounts Receivable Securitization Facility [Member]	July 2013 Shelf [Member]
Schedule of Debt Instruments [Line Items]	'	'	'	'
Maximum borrowing capacity	'	$200	$300	'
Aggregate amount of debt or equity securities allowed under shelf agreement	$300	'	'	$800

Debt_Obligations_Debt_Reacquis

Debt Obligations, Debt Re-acquisitions Summary (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Re-acquisitions Summary [Abstract]	'	'
Loss on debt redemption	$14.70	$12.80
Unsecured Debt [Member] | Notes 6.375% Redemption Date [Member]	'	'
Debt Re-acquisitions Summary [Abstract]	'	'
Premium paid on tender of Senior Notes	6.4	0
Write-off of deferred debt issue cost	1	0
Unsecured Debt [Member] | Notes 8.25% Redemption Date [Member]	'	'
Debt Re-acquisitions Summary [Abstract]	'	'
Premium paid on tender of Senior Notes	0	8.6
Write-off of deferred debt issue cost	0	2.5
Unsecured Debt [Member] | Notes 11.25% Redemption Date [Member]	'	'
Debt Re-acquisitions Summary [Abstract]	'	'
Premium paid on tender of Senior Notes	4.1	0
Recognition of unamortized discount	2.2	0
Write-off of deferred debt issue cost	1	0
Revolving Credit Facility [Member] | Senior Secured Revolving Credit Facility due July 2015 [Member]	'	'
Debt Re-acquisitions Summary [Abstract]	'	'
Write-off of deferred debt issue cost	$0	$1.70

Partnership_Units_and_Related_2

Partnership Units and Related Matters (Details) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

In Millions, except Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2013

Feb. 10, 2014

Nov. 30, 2012

Jan. 31, 2012

Jan. 31, 2011

Aug. 31, 2010

Aug. 31, 2012

Mar. 31, 2013

Aug. 31, 2013

Subsequent Event [Member]

Shelf Offering 2010 Shelf [Member]

Shelf Offering 2010 Shelf [Member]

Shelf Offering 2010 Shelf [Member]

Shelf Offering 2010 Shelf [Member]

2012 EDA [Member]

March 2013 EDA [Member]

August 2013 EDA [Member]

Subsidiary, Sale of Stock [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'45 days

'

'

'

'

'

'

'

'

Number of common units included in public offerings (in shares)

'

'

'

'

'

'

'

'

'

'

'

'

'

1,118,147

10,925,000

4,405,000

9,200,000

7,475,000

2,420,046

4,204,751

4,529,641

Per share price on public offering (in dollars per share)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$36

$38.30

$33.67

$24.80

'

'

'

Net proceeds from public offering

'

'

'

'

'

'

'

'

'

'

'

'

'

$56.20

$378.20

$164.80

$298

$177.80

$94.80

$197.50

$225.60

General partner contributed to maintain general partner ownership percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

1.2

8

3.5

6.3

3.8

2

4.1

4.7

General partner interest (in hundredths)

'

'

'

'

'

'

'

'

'

'

'

'

'

2.00%

2.00%

2.00%

2.00%

2.00%

2.00%

2.00%

2.00%

Purchase of Common Units by Parent (in units)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,300,000

'

'

'

'

'

Purchase of Common Units by Parent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

49.8

'

'

'

'

'

Purchase price of Badlands acquisition

'

'

'

'

'

'

'

'

'

'

'

'

'

'

975.8

'

'

'

'

'

'

Aggregate amount of debt or equity securities allowed to be issued under the shelf agreement

300

'

'

'

'

'

'

'

'

'

'

'

300

'

'

'

'

'

'

'

'

Dollar amount of Common Units able to sell from Equity Distribution Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100

200

400

Date Paid or to be paid

14-Feb-14

14-Nov-13

14-Aug-13

15-May-13

14-Feb-13

14-Nov-12

14-Aug-12

15-May-12

14-Feb-12

14-Nov-11

12-Aug-11

13-May-11

'

'

'

'

'

'

'

'

'

Distributions to limited partners

84

79.4

75.8

71.7

69

59.1

57.3

55.5

53.7

49.4

48.3

47.3

'

'

'

'

'

'

'

'

'

Distributions to general partners (Incentive)

29.5

26.9

24.6

22.1

20.1

16.1

14.4

12.7

11

8.8

7.8

6.8

'

'

'

'

'

'

'

'

'

Distributions to general partners (2%)

2.3

2.2

2

1.9

1.8

1.5

1.5

1.4

1.3

1.2

1.2

1.1

'

'

'

'

'

'

'

'

'

Total distributions to general and limited partners

$115.80

$108.50

$102.40

$95.70

$90.90

$76.70

$73.20

$69.60

$66

$59.40

$57.30

$55.20

'

'

'

'

'

'

'

'

'

Distributions per limited partner per unit (in dollars per unit)

$0.75

$0.73

$0.72

$0.70

$0.68

$0.66

$0.64

$0.62

$0.60

$0.58

$0.57

$0.56

'

'

'

'

'

'

'

'

'

Earnings_per_Limited_Partner_U2

Earnings per Limited Partner Unit (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings per Limited Partner Unit [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Net income	$115.60	$65	$32.70	$45.30	$38.60	$28.10	$54.70	$81.80	$258.60	$203.20	$245.50
Less: Net income attributable to noncontrolling interests	'	'	'	'	'	'	'	'	25.1	28.6	41
Net income attributable to Targa Resources Partners LP	'	'	'	'	'	'	'	'	233.5	174.6	204.5
Net income attributable to general partner	'	'	'	'	'	'	'	'	107.5	66.7	38
Net income attributable to limited partners	77.1	31.6	1.2	16.1	13	7.5	31.4	56	126	107.9	166.5
Net income attributable to Targa Resources Partners LP	'	'	'	'	'	'	'	'	$233.50	$174.60	$204.50
Weighted average units outstanding - basic (in shares)	'	'	'	'	'	'	'	'	105.5	90.1	84.1
Net income available per limited partner unit - basic (in dollars per share)	'	'	'	'	'	'	'	'	$1.19	$1.20	$1.98
Weighted average units outstanding (in shares)	'	'	'	'	'	'	'	'	105.5	90.1	84.1
Dilutive effect of unvested stock awards (in shares)	'	'	'	'	'	'	'	'	0.2	0.1	0.1
Weighted average units outstanding - diluted (in shares)	'	'	'	'	'	'	'	'	105.7	90.2	84.2
Net income available per limited partner unit - diluted (in dollars per share)	'	'	'	'	'	'	'	'	$1.19	$1.20	$1.98

Derivative_Instruments_and_Hed2

Derivative Instruments and Hedging Activities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative assets [Abstract]	'	'	'
Current assets	$2	$29.30	'
Long-term assets	3.1	5.1	'
Total derivative assets	5.1	34.4	'
Derivative Liabilities [Abstract]	'	'	'
Current liabilities	-8	-7.4	'
Long-term liabilities	-1.4	-4.8	'
Total derivative liabilities	-9.4	-12.2	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Cash flow commodity hedge deferred net gain to be reclassified within twelve months	5.6	'	'
Cash flow interest rate swaps deferred net loss to be reclassified within twelve months	2.4	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Fair value	4.3	'	'
Asset Position [Member] | Gross Presentation [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	2.6	28.2	'
Counterparties without offsetting position - assets	2.5	6.2	'
Counterparties without offsetting position - liabilities	0	0	'
Fair value	5.1	34.4	'
Asset Position [Member] | Gross Presentation [Member] | Current Position [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	1.9	23.8	'
Counterparties without offsetting position - assets	0.1	5.5	'
Counterparties without offsetting position - liabilities	0	0	'
Fair value	2	29.3	'
Asset Position [Member] | Gross Presentation [Member] | Long-term Position [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	0.7	4.4	'
Counterparties without offsetting position - assets	2.4	0.7	'
Counterparties without offsetting position - liabilities	0	0	'
Fair value	3.1	5.1	'
Asset Position [Member] | Pro Forma Net Presentation [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	0	18	'
Counterparties without offsetting position - assets	2.5	6.2	'
Counterparties without offsetting position - liabilities	0	0	'
Fair value	2.5	24.2	'
Asset Position [Member] | Pro Forma Net Presentation [Member] | Current Position [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	0	16.4	'
Counterparties without offsetting position - assets	0.1	5.5	'
Counterparties without offsetting position - liabilities	0	0	'
Fair value	0.1	21.9	'
Asset Position [Member] | Pro Forma Net Presentation [Member] | Long-term Position [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	0	1.6	'
Counterparties without offsetting position - assets	2.4	0.7	'
Counterparties without offsetting position - liabilities	0	0	'
Fair value	2.4	2.3	'
Liability Position [Member] | Gross Presentation [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	-5.6	-10.2	'
Counterparties without offsetting position - assets	0	0	'
Counterparties without offsetting position - liabilities	-3.8	-2	'
Fair value	-9.4	-12.2	'
Liability Position [Member] | Gross Presentation [Member] | Current Position [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	-4.4	-7.4	'
Counterparties without offsetting position - assets	0	0	'
Counterparties without offsetting position - liabilities	-3.6	0	'
Fair value	-8	-7.4	'
Liability Position [Member] | Gross Presentation [Member] | Long-term Position [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	-1.2	-2.8	'
Counterparties without offsetting position - assets	0	0	'
Counterparties without offsetting position - liabilities	-0.2	-2	'
Fair value	-1.4	-4.8	'
Liability Position [Member] | Pro Forma Net Presentation [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	-3	0	'
Counterparties without offsetting position - assets	0	0	'
Counterparties without offsetting position - liabilities	-3.8	-2	'
Fair value	-6.8	-2	'
Liability Position [Member] | Pro Forma Net Presentation [Member] | Current Position [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	-2.5	0	'
Counterparties without offsetting position - assets	0	0	'
Counterparties without offsetting position - liabilities	-3.6	0	'
Fair value	-6.1	0	'
Liability Position [Member] | Pro Forma Net Presentation [Member] | Long-term Position [Member]	'	'	'
Pro forma impact of reporting derivatives in the Consolidated Balance Sheet [Abstract]	'	'	'
Counterparties with offsetting position	-0.5	0	'
Counterparties without offsetting position - assets	0	0	'
Counterparties without offsetting position - liabilities	-0.2	-2	'
Fair value	-0.7	-2	'
Cash Flow Hedging [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	-5.8	76.4	-37.8
Gain (Loss) Reclassified from OCI into Income (Effective Portion)	15.1	36	-42.8
Cash Flow Hedging [Member] | Interest Expense, Net [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Reclassified from OCI into Income (Effective Portion)	-6.1	-7.9	-8.1
Cash Flow Hedging [Member] | Revenues [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Reclassified from OCI into Income (Effective Portion)	21.2	43.9	-34.7
Interest Rate Contracts [Member] | Other Income (Expense) [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Recognized in Income on Derivatives	0	0	-5
Interest Rate Contracts [Member] | Cash Flow Hedging [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	0	0	-4.4
Unrealized gain (loss) on hedges	-2.4	-8.5	'
Commodity Contracts [Member] | Revenues [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Recognized in Income on Derivatives	-0.1	0.7	1.7
Commodity Contracts [Member] | Cash Flow Hedging [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)	-5.8	76.4	-33.4
Unrealized gain (loss) on hedges	-3.7	23.1	'
Designated as Hedging Instrument [Member]	'	'	'
Derivative assets [Abstract]	'	'	'
Total derivative assets	5.1	34.3	'
Derivative Liabilities [Abstract]	'	'	'
Total derivative liabilities	-9.1	-12	'
Designated as Hedging Instrument [Member] | Commodity Contracts [Member]	'	'	'
Derivative assets [Abstract]	'	'	'
Current assets	2	29.2	'
Long-term assets	3.1	5.1	'
Derivative Liabilities [Abstract]	'	'	'
Current liabilities	-7.7	-7.2	'
Long-term liabilities	-1.4	-4.8	'
Not Designated as Hedging Instrument [Member]	'	'	'
Derivative assets [Abstract]	'	'	'
Total derivative assets	0	0.1	'
Derivative Liabilities [Abstract]	'	'	'
Total derivative liabilities	-0.3	-0.2	'
Not Designated as Hedging Instrument [Member] | Commodity Contracts [Member]	'	'	'
Derivative assets [Abstract]	'	'	'
Current assets	0	0.1	'
Derivative Liabilities [Abstract]	'	'	'
Current liabilities	($0.30)	($0.20)	'
Natural Gas [Member] | Swaps [Member] | Year 2014 [Member]	'	'	'
Derivative [Line Items]	'	'	'
Notional volumes of commodity hedges (per day)	48,050	'	'
Natural Gas [Member] | Swaps [Member] | Year 2015 [Member]	'	'	'
Derivative [Line Items]	'	'	'
Notional volumes of commodity hedges (per day)	34,551	'	'
Natural Gas [Member] | Swaps [Member] | Year 2016 [Member]	'	'	'
Derivative [Line Items]	'	'	'
Notional volumes of commodity hedges (per day)	25,500	'	'
Natural Gas Liquids [Member] | Swaps [Member] | Year 2014 [Member]	'	'	'
Derivative [Line Items]	'	'	'
Notional volumes of commodity hedges (per day)	1,125	'	'
Natural Gas Liquids [Member] | Swaps [Member] | Year 2015 [Member]	'	'	'
Derivative [Line Items]	'	'	'
Notional volumes of commodity hedges (per day)	0	'	'
Natural Gas Liquids [Member] | Swaps [Member] | Year 2016 [Member]	'	'	'
Derivative [Line Items]	'	'	'
Notional volumes of commodity hedges (per day)	0	'	'
Condensate [Member] | Swaps [Member] | Year 2014 [Member]	'	'	'
Derivative [Line Items]	'	'	'
Notional volumes of commodity hedges (per day)	2,450	'	'
Condensate [Member] | Swaps [Member] | Year 2015 [Member]	'	'	'
Derivative [Line Items]	'	'	'
Notional volumes of commodity hedges (per day)	0	'	'
Condensate [Member] | Swaps [Member] | Year 2016 [Member]	'	'	'
Derivative [Line Items]	'	'	'
Notional volumes of commodity hedges (per day)	0	'	'

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'
Assets from commodity derivative contracts	$5.10	$34.40	'
Liability from commodity derivative contracts	9.4	12.2	'
Badlands contingent consideration liability	0	15.3	'
Cash and cash equivalents	57.5	68	'
Senior secured revolving credit facility	395	620	'
Senior unsecured notes	2,253.50	1,945.20	'
Accounts receivable securitization facility	279.7	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'
Derivatives financial instruments, fair value, net	4.3	'	'
Derivative fair value commodity price increases 10 percent, net liability	29.9	'	'
Derivative fair value commodity price decreases 10 percent, net asset	21.3	'	'
Contingent payment	50	'	'
Commodity Derivative Contracts Liability/ (Asset) [Member]	'	'	'
Fair Value Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]	'	'	'
Beginning balance	0.6	0	-11.6
Settlements included in Revenue	-1.3	-0.1	3.7
Transfers out of Level 3	'	'	7.9
Unrealized losses included in OCI	'	0.7	'
Change in valuation of contingent liability	0	0	'
Ending balance	-0.7	0.6	0
Contingent Liability [Member]	'	'	'
Fair Value Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]	'	'	'
Beginning balance	15.3	0	0
Settlements included in Revenue	0	0	0
Transfers out of Level 3	'	'	0
Unrealized losses included in OCI	'	0	'
Change in valuation of contingent liability	-15.3	15.3	'
Ending balance	0	15.3	0
Fair Value, Inputs, Level 1 [Member]	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'
Assets from commodity derivative contracts	0	0	'
Liability from commodity derivative contracts	0	0	'
Badlands contingent consideration liability	0	0	'
Cash and cash equivalents	0	0	'
Senior secured revolving credit facility	0	0	'
Senior unsecured notes	0	0	'
Accounts receivable securitization facility	0	'	'
Fair Value, Inputs, Level 2 [Member]	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'
Assets from commodity derivative contracts	3.4	34.4	'
Liability from commodity derivative contracts	8.4	11.6	'
Badlands contingent consideration liability	0	0	'
Cash and cash equivalents	0	0	'
Senior secured revolving credit facility	395	620	'
Senior unsecured notes	2,253.50	1,945.20	'
Accounts receivable securitization facility	279.7	'	'
Fair Value, Inputs, Level 3 [Member]	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'
Assets from commodity derivative contracts	1.7	0	'
Liability from commodity derivative contracts	1	0.6	'
Badlands contingent consideration liability	0	15.3	'
Cash and cash equivalents	0	0	'
Senior secured revolving credit facility	0	0	'
Senior unsecured notes	0	0	'
Accounts receivable securitization facility	0	'	'
Carrying Value [Member]	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'
Assets from commodity derivative contracts	5.1	34.4	'
Liability from commodity derivative contracts	9.4	12.2	'
Badlands contingent consideration liability	0	15.3	'
Cash and cash equivalents	57.5	68	'
Senior secured revolving credit facility	395	620	'
Senior unsecured notes	2,230.60	1,773.30	'
Accounts receivable securitization facility	$279.70	'	'

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Plant
Related Party Transaction [Line Items]	'	'	'
Parent allocation of payroll and related costs included in operating expense	$109.70	$97.20	$87.40
Parent allocation of general and administrative expense	134.3	124	115.2
Cash distributions to Targa based on unit ownership	138.2	92.7	60.3
Contributions from Targa, net	0	1	13.2
Cost and Expenses	108.6	'	'
Amount of project cost paid	17	'	'
Number of installation of acid gas processing plants	3	'	'
Reimbursement from joint venture	0.2	'	'
GCF [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Sales	0.4	0.1	0.8
Cost and Expenses	$6.30	$1.90	$0.40

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Future non-cancelable commitments related to certain contractual obligations [Abstract]	'		'		'
Payments Due by Period Total	$41.80		'		'
Payments Due by Period 2014	9.7		'		'
Payments Due by Period 2015	9.4		'		'
Payments Due by Period 2016	9		'		'
Payments Due by Period 2017	7.7		'		'
Payments Due by Period 2018	6		'		'
Operating Leases [Member]	'		'		'
Future non-cancelable commitments related to certain contractual obligations [Abstract]	'		'		'
Payments Due by Period Total	33.9	[1]	'		'
Payments Due by Period 2014	8	[1]	'		'
Payments Due by Period 2015	7.8	[1]	'		'
Payments Due by Period 2016	7.4	[1]	'		'
Payments Due by Period 2017	6.1	[1]	'		'
Payments Due by Period 2018	4.6	[1]	'		'
Total expenses	23.3	[2]	16.1	[2]	14.2	[2]
Land Site Lease and Right-of-way [Member]	'		'		'
Future non-cancelable commitments related to certain contractual obligations [Abstract]	'		'		'
Payments Due by Period Total	7.9	[3]	'		'
Payments Due by Period 2014	1.7	[3]	'		'
Payments Due by Period 2015	1.6	[3]	'		'
Payments Due by Period 2016	1.6	[3]	'		'
Payments Due by Period 2017	1.6	[3]	'		'
Payments Due by Period 2018	1.4	[3]	'		'
Total expenses	$3.60		$3.30		$2.80
[1]	Includes minimum payments on lease obligations for office space, railcars and tractors.
[2]	Includes short-term leases for items such as compressors and equipment.
[3]	Land site lease and right-of-way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us. These agreements expire at various dates through 2099.

Significant_Risks_and_Uncertai2

Significant Risks and Uncertainties (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Significant Risks and Uncertainties [Abstract]	'	'	'
Potential loss if all counterparites default	$2.20	'	'
Potential minimum loss of individual counterparties	1	'	'
Potential maximum loss of individual counterparties	1.2	'	'
Allowance for Doubtful Accounts [Member]	'	'	'
Movement in Valuation Allowances and Reserves [Roll Forward]	'	'	'
Balance at beginning of year	0.7	2.2	7.7
Additions	0.2	0	0.5
Deductions	0	-1.5	-6
Balance at end of year	$0.90	$0.70	$2.20
Barclays PLC [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk percentage (in hundredths)	24.00%	'	'
Securities Americas LLC. [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk percentage (in hundredths)	26.00%	'	'
Bank of America Merrill Lynch [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk percentage (in hundredths)	37.00%	'	'
Customer Concentration Risk [Member] | Chevron Phillips Chemical Company LLC [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk percentage (in hundredths)	8.00%	10.00%	12.00%

Other_Operating_Expense_Detail

Other Operating Expense (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Other Operating Expense [Abstract]	'	'		'
Abandoned Project Costs	$0.70	$0		$0
Loss on sale or disposal of assets	3.9	15.6	[1]	0.2
Casualty loss	4.3	3.6		0
Miscellaneous business tax	0.7	0.7		0
Total	9.6	19.9		0.2
Loss due to write-off of investment	$15.40	'		'
[1]	Includes a $15.4 million loss due to a write-off of our investment in the Yscloskey joint interest processing plant in Southeastern Louisiana. Following Hurricane Isaac, the joint venture owners elected not to restart the plant.

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Cash: [Abstract]	'		'		'
Interest paid, net of capitalized interest (1)	$119.10	[1]	$92.50	[1]	$92.70	[1]
Income taxes paid, net of refunds	2.3		2.3		2.5
Non-cash: [Abstract]	'		'		'
Deadstock inventory transferred to property, plant and equipment	30.4		3		0.7
Badlands acquisition contingent consideration	0		15.3		0
Accrued distribution equivalent rights	1.7		0.5		0.1
Change in capital accruals	-0.4		-34.4		-4.8
Transfers from materials and supplies to property, plant and equipment	20.5		0		0
Change in ARO estimate	1.4		-1		1.2
Interest capitalized on expansion projects	$28		$13.60		$3.40
[1]	Interest capitalized on expansion projects was $28.0 million, $13.6 million and $3.4 million for the years ended December 31, 2013, 2012 and 2011.

Compensation_Plans_Details

Compensation Plans (Details) (USD $)	0 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Jan. 14, 2014	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Compensation expenses recognized	'	$6		$3.60		$1.50
Vesting percentage of IPO stock awards over 24 months (in hundredths)	'	60.00%		'		'
Vesting percentage of IPO stock awards over 36 months (in hundredths)	'	40.00%		'		'
Stock repurchased from employees (in shares)	'	169,159		197,731		'
Stock repurchase price (in dollars per share)	'	$79.01		$47.88		'
Defined contribution plan [Abstract]	'	'		'		'
Description of 401(k) plan	'	'Targa has a 401(k) plan whereby it matches 100% of up to 5% of an employeebs contribution (subject to certain limitations in the plan).B Targa also contributes an amount equal to 3% of each employeebs eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. Targa made contributions to the 401(k) plan totaling $9.6 million, $8.7 million, and $7.8 million during 2013, 2012 and 2011.		'		'
Employer matching contribution percent (in hundredths)	'	100.00%		'		'
Maximum annual contribution per employee percent (in hundredths)	'	5.00%		'		'
Contribution per employee percent (in hundredths)	'	3.00%		'		'
Contributions to defined contribution plan	'	9.6		8.7		7.8
Performance Awards Equity Settled [Member]	'	'		'		'
Share based compensation arrangements [Roll Forward]	'	'		'		'
Unit outstanding, beginning of year (in shares)	552,198	307,620		135,870		0
Granted (in shares)	111,745	244,578		171,750		135,870
Units outstanding, end of year (in shares)	'	552,198		307,620		135,870
Liabilities recognized [Abstract]	'	'		'		'
To be recognized in future periods	'	16.3		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Outstanding, beginning of period (in dollars per share)	$42.01	$38.40		$33.94		$0
Granted (in dollars per share)	'	$46.54		$41.94		$33.94
Outstanding, end of period (in dollars per share)	'	$42.01		$38.40		$33.94
Compensation expenses recognized	'	5.5		3.1		1
Unrecognized compensation expenses	'	16.3		'		'
Weighted average recognition period for the unrecognized compensation cost	'	'2 years		'		'
Performance Awards Cash Settled [Member]	'	'		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Compensation expenses recognized	'	21.9		14.2		13.3
Weighted average recognition period for the unrecognized compensation cost	'	'1 year 9 months 18 days		'		'
Fair value of units vested during the period	'	25.2		22.2		5.5
Director Grants [Member]	'	'		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Compensation expenses recognized	'	0.5		0.5		0.5
Fair value of units vested during the period	'	0.7		1		1
Restricted Stock [Member]	'	'		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Recognized tax benefits	'	1.6		1.3		'
Restricted Stock [Member] | Long Term Incentive Plan 2010 Plan [Member]	'	'		'		'
Liabilities recognized [Abstract]	'	'		'		'
To be recognized in future periods	'	3.3		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Compensation expenses recognized	'	6.3		13.7		13.4
Unrecognized compensation expenses	'	3.3		'		'
Weighted average recognition period for the unrecognized compensation cost	'	'1 year 7 months 6 days		'		'
Restricted Stock Units (RSUs) [Member] | Long Term Incentive Plan 2010 Plan [Member]	'	'		'		'
Liabilities recognized [Abstract]	'	'		'		'
To be recognized in future periods	'	3.6		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Compensation expenses recognized	'	0.4		0		0
Unrecognized compensation expenses	'	3.6		'		'
Weighted average recognition period for the unrecognized compensation cost	'	'2 years 9 months 18 days		'		'
Accrued Dividends Settled [Member]	'	'		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Fair value of units vested during the period	'	2.4		2		0
Partnership Long-term Incentive Plan [Member]	'	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'		'		'
Total units authorized (in shares)	'	1,680,000		'		'
Vesting period	'	'3 years		'		'
Share based compensation arrangements [Roll Forward]	'	'		'		'
Unit outstanding, beginning of year (in shares)	'	569,623		'		'
Granted (in shares)	'	152,170		'		'
Vested and paid (in shares)	'	-305,853		'		'
Forfeited (in shares)	'	-3,650		'		'
Units outstanding, end of year (in shares)	'	412,290		'		'
Calculated fair market value as of December 31, 2013	'	28.6		'		'
Liabilities recognized [Abstract]	'	'		'		'
Current liability	'	8.7		'		'
Long-term liability	'	5.9		'		'
Liability as of December 31, 2013	'	14.6		'		'
To be recognized in future periods	'	14		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Unrecognized compensation expenses	'	14		'		'
Partnership Long-term Incentive Plan [Member] | Long Term Incentive Plan 2010 Plan [Member]	'	'		'		'
Share based compensation arrangements [Roll Forward]	'	'		'		'
Unit outstanding, beginning of year (in shares)	'	306,253		'		'
Granted (in shares)	'	0		'		'
Vested and paid (in shares)	'	-305,853		'		'
Forfeited (in shares)	'	-400		'		'
Units outstanding, end of year (in shares)	'	0		'		'
Partnership Long-term Incentive Plan [Member] | Long Term Incentive Plan 2011 Plan [Member]	'	'		'		'
Share based compensation arrangements [Roll Forward]	'	'		'		'
Unit outstanding, beginning of year (in shares)	'	122,550		'		'
Granted (in shares)	'	3,000		'		'
Vested and paid (in shares)	'	0		'		'
Forfeited (in shares)	'	-680		'		'
Units outstanding, end of year (in shares)	'	124,870		'		'
Calculated fair market value as of December 31, 2013	'	10.6		'		'
Liabilities recognized [Abstract]	'	'		'		'
Current liability	'	8.7		'		'
Long-term liability	'	0		'		'
Liability as of December 31, 2013	'	8.7		'		'
To be recognized in future periods	'	1.9		'		'
Vesting date	'	30-Jun-14		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Unrecognized compensation expenses	'	1.9		'		'
Partnership Long-term Incentive Plan [Member] | Long Term Incentive Plan 2012 Plan [Member]	'	'		'		'
Share based compensation arrangements [Roll Forward]	'	'		'		'
Unit outstanding, beginning of year (in shares)	'	140,820		'		'
Granted (in shares)	'	3,200		'		'
Vested and paid (in shares)	'	0		'		'
Forfeited (in shares)	'	-1,560		'		'
Units outstanding, end of year (in shares)	'	142,460		'		'
Calculated fair market value as of December 31, 2013	'	10.4		'		'
Liabilities recognized [Abstract]	'	'		'		'
Current liability	'	0		'		'
Long-term liability	'	4.9		'		'
Liability as of December 31, 2013	'	4.9		'		'
To be recognized in future periods	'	5.5		'		'
Vesting date	'	30-Jun-15		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Unrecognized compensation expenses	'	5.5		'		'
Partnership Long-term Incentive Plan [Member] | Long Term Incentive Plan 2013 Plan [Member]	'	'		'		'
Share based compensation arrangements [Roll Forward]	'	'		'		'
Unit outstanding, beginning of year (in shares)	'	0		'		'
Granted (in shares)	'	145,970		'		'
Vested and paid (in shares)	'	0		'		'
Forfeited (in shares)	'	-1,010		'		'
Units outstanding, end of year (in shares)	'	144,960		'		'
Calculated fair market value as of December 31, 2013	'	7.6		'		'
Liabilities recognized [Abstract]	'	'		'		'
Current liability	'	0		'		'
Long-term liability	'	1		'		'
Liability as of December 31, 2013	'	1		'		'
To be recognized in future periods	'	6.6		'		'
Vesting date	'	30-Jun-16		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Unrecognized compensation expenses	'	6.6		'		'
Partnership Long-term Incentive Plan [Member] | Director Grants [Member]	'	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'		'		'
Vesting period	'	'3 years		'		'
Share based compensation arrangements [Roll Forward]	'	'		'		'
Unit outstanding, beginning of year (in shares)	0	4,500		19,831		39,074
Granted (in shares)	8,740	12,780		9,980		10,600
Vested and paid (in shares)	'	-17,280		-25,311		-29,843
Units outstanding, end of year (in shares)	'	0		4,500		19,831
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Outstanding, beginning of period (in dollars per share)	$0	$23.51		$16.31		$16.12
Granted (in dollars per share)	'	$39.33		$38.72		$33.53
Vested and paid (in dollars per share)	'	$35.21		$23.86		$22.18
Outstanding, end of period (in dollars per share)	'	$0		$23.51		$16.31
Units granted to non-management directors, per director (in units)	1,748	'		'		'
TRC Stock Incentive Plan [Member] | Restricted Stock [Member]	'	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'		'		'
Vesting period	'3 years	'		'		'
Share based compensation arrangements [Roll Forward]	'	'		'		'
Unit outstanding, beginning of year (in shares)	203,973	711,030		1,434,220		1,350,000	[1]
Granted (in shares)	22,017	30,623	[2]	91,090	[2]	84,220	[2]
Vested and paid (in shares)	'	-534,940	[3]	-805,350	[3]	'
Forfeited (in shares)	'	-2,740		-8,930		'
Units outstanding, end of year (in shares)	'	203,973		711,030		1,434,220
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Outstanding, beginning of period (in dollars per share)	$41.05	$25.95		$22.67		$22	[1]
Granted (in dollars per share)	'	$57.59	[2]	$42.50	[2]	$33.39	[2]
Vested and paid (in dollars per share)	'	$22	[3]	$22	[3]	'
Forfeited (in dollars per share)	'	$27.28		$23.99		'
Outstanding, end of period (in dollars per share)	'	$41.05		$25.95		$22.67
Fair value of units vested during the period	'	$42.20	[4]	$40.30	[4]	$0	[4]
TRC Stock Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member]	'	'		'		'
Share based compensation arrangements [Roll Forward]	'	'		'		'
Unit outstanding, beginning of year (in shares)	'	0		'		'
Granted (in shares)	'	55,790		'		'
Forfeited (in shares)	'	-240		'		'
Units outstanding, end of year (in shares)	'	55,550		'		'
Weighted Average Grant Date Fair Value [Abstract]	'	'		'		'
Granted (in dollars per share)	'	$69.90		'		'
Forfeited (in dollars per share)	'	$67.07		'		'
Outstanding, end of period (in dollars per share)	'	$69.92		'		'
TRC Incentive Plan [Member] | Restricted Stock [Member]	'	'		'		'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'		'		'
Total units authorized (in shares)	'	5,000,000		'		'
[1]	These awards were issued in conjunction with the Targa IPO and vest over a three year period at 60% in 2012 and the remaining 40% in 2013.
[2]	These awards will cliff vest at the end of three years.
[3]	Awards vested in 2013 and 2012 were 40% and 60% of the awards issued in conjunction with the Targa IPO, net of forfeitures. Targa repurchased 169,159 and 197,731 shares from employees at $79.01 and $47.88 per share in 2013 and 2012 to satisfy the employeesb minimum statutory tax withholdings on the vested awards. The repurchased shares are recorded in treasury stock at cost.
[4]	Targa recognized $1.6 million and $1.3 million in tax benefits for 2013 and 2012 that were associated with the vesting of the 40% and 60% restricted stock related to Targa IPO.

Segment_Information_Details

Segment Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
									Segment
Segment Reporting [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Number of divisions	'	'	'	'	'	'	'	'	2	'	'
Number of reportable segments per division	'	'	'	'	'	'	'	'	2	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	$5,975.10	$5,529	$6,726.10
Fees from midstream services	'	'	'	'	'	'	'	'	579.2	354.6	261
Revenues	2,159.90	1,556.90	1,441.60	1,397.80	1,526.80	1,392.90	1,318.40	1,645.50	6,556.20	5,883.60	6,987.10
Operating margin	'	'	'	'	'	'	'	'	801.5	691.7	661.1
Other financial information:	'	'	'	'	'	'	'	'	'	'	'
Total assets	5,971.40	'	'	'	5,025.70	'	'	'	5,971.40	5,025.70	3,658
Capital expenditures	'	'	'	'	'	'	'	'	1,034.50	616.7	333.5
Business acquisitions	'	'	'	'	'	'	'	'	0	996.2	156.5
Total Outside Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	5,975.10	5,529	6,726.10
Fees from midstream services	'	'	'	'	'	'	'	'	579.2	354.6	261
Business interruption insurance	'	'	'	'	'	'	'	'	1.9	'	'
Revenues	'	'	'	'	'	'	'	'	6,556.20	5,883.60	6,987.10
Total Intersegment Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	0	0	0
Fees from midstream services	'	'	'	'	'	'	'	'	0	0	0
Revenues	'	'	'	'	'	'	'	'	0	0	0
Field Gathering and Processing [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	1,525	1,364.20	1,641.90
Operating margin	'	'	'	'	'	'	'	'	270.5	231.2	287.9
Other financial information:	'	'	'	'	'	'	'	'	'	'	'
Total assets	3,200.70	'	'	'	2,797.90	'	'	'	3,200.70	2,797.90	1,666.20
Capital expenditures	'	'	'	'	'	'	'	'	557.8	222.1	167.5
Business acquisitions	'	'	'	'	'	'	'	'	'	970.4	0
Field Gathering and Processing [Member] | Total Outside Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	188.8	172.7	184.9
Fees from midstream services	'	'	'	'	'	'	'	'	112.8	39.5	27.5
Business interruption insurance	'	'	'	'	'	'	'	'	1.1	'	'
Revenues	'	'	'	'	'	'	'	'	302.7	212.2	212.4
Field Gathering and Processing [Member] | Total Intersegment Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	1,218.90	1,150.70	1,428.40
Fees from midstream services	'	'	'	'	'	'	'	'	3.4	1.3	1.1
Revenues	'	'	'	'	'	'	'	'	1,222.30	1,152	1,429.50
Coastal Gathering and Processing [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	981.8	965.4	1,298.80
Operating margin	'	'	'	'	'	'	'	'	85.4	115.1	174.3
Other financial information:	'	'	'	'	'	'	'	'	'	'	'
Total assets	383.8	'	'	'	414.1	'	'	'	383.8	414.1	427.5
Capital expenditures	'	'	'	'	'	'	'	'	20.6	9.4	12.8
Business acquisitions	'	'	'	'	'	'	'	'	'	25.8	0
Coastal Gathering and Processing [Member] | Total Outside Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	305	240.6	325.7
Fees from midstream services	'	'	'	'	'	'	'	'	33.4	23.6	19.8
Business interruption insurance	'	'	'	'	'	'	'	'	0.2	'	'
Revenues	'	'	'	'	'	'	'	'	338.6	264.2	345.5
Coastal Gathering and Processing [Member] | Total Intersegment Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	642.2	701.1	952.9
Fees from midstream services	'	'	'	'	'	'	'	'	1	0.1	0.4
Revenues	'	'	'	'	'	'	'	'	643.2	701.2	953.3
Logistics Assets [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	536.9	463.4	263.5
Operating margin	'	'	'	'	'	'	'	'	282.3	188.3	123.1
Other financial information:	'	'	'	'	'	'	'	'	'	'	'
Total assets	1,503.60	'	'	'	1,100.90	'	'	'	1,503.60	1,100.90	775.4
Capital expenditures	'	'	'	'	'	'	'	'	444.7	359	147.4
Business acquisitions	'	'	'	'	'	'	'	'	'	0	156.5
Logistics Assets [Member] | Total Outside Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	140.5	184.4	43.2
Fees from midstream services	'	'	'	'	'	'	'	'	216	170.7	130
Business interruption insurance	'	'	'	'	'	'	'	'	0	'	'
Revenues	'	'	'	'	'	'	'	'	356.5	355.1	173.2
Logistics Assets [Member] | Total Intersegment Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	3.9	1.8	1
Fees from midstream services	'	'	'	'	'	'	'	'	176.5	106.5	89.3
Revenues	'	'	'	'	'	'	'	'	180.4	108.3	90.3
Marketing and Distribution [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	6,045.40	5,608.10	6,966.80
Operating margin	'	'	'	'	'	'	'	'	141.9	116	113.4
Other financial information:	'	'	'	'	'	'	'	'	'	'	'
Total assets	756.1	'	'	'	548.6	'	'	'	756.1	548.6	650.5
Capital expenditures	'	'	'	'	'	'	'	'	6.3	12.3	3.5
Business acquisitions	'	'	'	'	'	'	'	'	'	0	0
Marketing and Distribution [Member] | Total Outside Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	5,319.30	4,890.20	6,209.90
Fees from midstream services	'	'	'	'	'	'	'	'	217.1	120.9	83.8
Business interruption insurance	'	'	'	'	'	'	'	'	0.6	'	'
Revenues	'	'	'	'	'	'	'	'	5,537	5,011.10	6,293.70
Marketing and Distribution [Member] | Total Intersegment Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	478.6	565	636.5
Fees from midstream services	'	'	'	'	'	'	'	'	29.8	32	36.6
Revenues	'	'	'	'	'	'	'	'	508.4	597	673.1
Other Segment [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	21.4	41.1	-37.6
Operating margin	'	'	'	'	'	'	'	'	21.4	41.1	-37.6
Other financial information:	'	'	'	'	'	'	'	'	'	'	'
Total assets	5.1	'	'	'	34.4	'	'	'	5.1	34.4	51.9
Capital expenditures	'	'	'	'	'	'	'	'	0	0	0
Business acquisitions	'	'	'	'	'	'	'	'	'	0	0
Other Segment [Member] | Total Outside Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	21.4	41.1	-37.6
Fees from midstream services	'	'	'	'	'	'	'	'	0	0	0
Business interruption insurance	'	'	'	'	'	'	'	'	0	'	'
Revenues	'	'	'	'	'	'	'	'	21.4	41.1	-37.6
Other Segment [Member] | Total Intersegment Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	0	0	0
Fees from midstream services	'	'	'	'	'	'	'	'	0	0	0
Revenues	'	'	'	'	'	'	'	'	0	0	0
Corporate And Elimination [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Revenues	'	'	'	'	'	'	'	'	-2,554.30	-2,558.60	-3,146.30
Operating margin	'	'	'	'	'	'	'	'	0	0	0
Other financial information:	'	'	'	'	'	'	'	'	'	'	'
Total assets	122.1	'	'	'	129.8	'	'	'	122.1	129.8	86.5
Capital expenditures	'	'	'	'	'	'	'	'	5.1	13.9	2.3
Business acquisitions	'	'	'	'	'	'	'	'	'	0	0
Corporate And Elimination [Member] | Total Outside Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	0.1	0	0
Fees from midstream services	'	'	'	'	'	'	'	'	-0.1	-0.1	-0.1
Business interruption insurance	'	'	'	'	'	'	'	'	0	'	'
Revenues	'	'	'	'	'	'	'	'	0	-0.1	-0.1
Corporate And Elimination [Member] | Total Intersegment Revenues [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	-2,343.60	-2,418.60	-3,018.80
Fees from midstream services	'	'	'	'	'	'	'	'	-210.7	-139.9	-127.4
Revenues	'	'	'	'	'	'	'	'	($2,554.30)	($2,558.50)	($3,146.20)

Segment_Information_Revenues_b

Segment Information, Revenues by Product and Service and Reconciliation of Operating Margin to Net Income (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue from External Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	$5,975.10	$5,529	$6,726.10
Fees from midstream services	'	'	'	'	'	'	'	'	579.2	354.6	261
Business interruption insurance	'	'	'	'	'	'	'	'	1.9	0	0
Revenues	2,159.90	1,556.90	1,441.60	1,397.80	1,526.80	1,392.90	1,318.40	1,645.50	6,556.20	5,883.60	6,987.10
Reconciliation of operating margin to net income	'	'	'	'	'	'	'	'	'	'	'
Operating margin	'	'	'	'	'	'	'	'	801.5	691.7	661.1
Depreciation and amortization expense	'	'	'	'	'	'	'	'	-271.6	-197.3	-178.2
General and administrative expense	'	'	'	'	'	'	'	'	-143.1	-131.6	-127.8
Interest expense, net	'	'	'	'	'	'	'	'	-131	-116.8	-107.7
Income tax expense	'	'	'	'	'	'	'	'	-2.9	-4.2	-4.3
Other, net	'	'	'	'	'	'	'	'	5.7	-38.6	2.4
Net income	115.6	65	32.7	45.3	38.6	28.1	54.7	81.8	258.6	203.2	245.5
Natural Gas Sales [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from External Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	1,224.70	926.9	1,120.70
NGL Sales [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from External Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	4,470.90	4,265.70	5,496.90
Condensate Sales [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from External Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	121.8	114.1	103
Petroleum Products [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from External Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	136	180.1	43.1
Derivative Activities [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from External Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Sale of commodities	'	'	'	'	'	'	'	'	21.7	42.2	-37.6
Fractionating and Treating Fees [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from External Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Fees from midstream services	'	'	'	'	'	'	'	'	152	115.6	86.7
Storage, Terminaling, Transportation and Export Fees [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from External Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Fees from midstream services	'	'	'	'	'	'	'	'	275.5	159.2	110.4
Gathering and Processing [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from External Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Fees from midstream services	'	'	'	'	'	'	'	'	114.1	45	33.1
Other [Member]	'	'	'	'	'	'	'	'	'	'	'
Revenue from External Customer [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Fees from midstream services	'	'	'	'	'	'	'	'	$37.60	$34.80	$30.80

Selected_Quarterly_Financial_D2

Selected Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Selected Quarterly Financial Data (Unaudited) [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Revenues	$2,159.90	$1,556.90	$1,441.60	$1,397.80	$1,526.80	$1,392.90	$1,318.40	$1,645.50	$6,556.20	$5,883.60	$6,987.10
Gross margin	355.1	297.1	265.2	260.3	259.6	239.9	243.8	261.4	1,177.70	1,004.70	'
Operating income	146.8	91	63.2	76.2	85.9	61.3	85.5	110.2	377.2	342.9	354.9
Net income	115.6	65	32.7	45.3	38.6	28.1	54.7	81.8	258.6	203.2	245.5
Net income allocable to limited partners	$77.10	$31.60	$1.20	$16.10	$13	$7.50	$31.40	$56	$126	$107.90	$166.50
Net income (loss) per limited partner [Abstract]	'	'	'	'	'	'	'	'	'	'	'
unit - basic (in dollars per share)	$0.70	$0.30	$0.01	$0.16	$0.14	$0.08	$0.35	$0.64	$1.19	$1.20	'
unit - diluted (in dollars per share)	$0.70	$0.30	$0.01	$0.16	$0.14	$0.08	$0.35	$0.63	$1.19	$1.20	'