SEC Filing | Targa Resources Corp.

View:

Download DOC

Download PDF

Download XLS

Download XBRL

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File Number: 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware		65-1295427
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1000 Louisiana St, Suite 4300, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 584-1000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No £.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer R

Accelerated filer £

Non-accelerated filer £

Smaller reporting company £

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No R.

As of April 30, 2013, there were 102,777,067 common units and 2,097,492 general partner units outstanding.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.		4

	Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012	4

	Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012	5

	Consolidated Statements of Comprehensive Income for the three months ended March 31, 2013 and 2012	6

	Consolidated Statements of Changes in Owners' Equity for the three months ended March 31, 2013 and 2012	7

	Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012	8

	Notes to Consolidated Financial Statements	9

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.		22

Item 3. Quantitative and Qualitative Disclosures About Market Risk.		40

Item 4. Controls and Procedures.		43

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.		43

Item 1A. Risk Factors.		43

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.		43

Item 3. Defaults Upon Senior Securities.		43

Item 4. Mine Safety Disclosures.		43

Item 5. Other Information.		43

Item 6. Exhibits.		44

SIGNATURES

Signatures		46

Table of Contents

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Partners LP’s (together with its subsidiaries, “we,” “us,” “our,” or “the Partnership”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking by the use of forward-looking statements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in “Part II – Other Information, Item 1A. Risk Factors.” of this Quarterly Report on Form 10-Q (“Quarterly Report”) as well as the following risks and uncertainties:

our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations;

the amount of collateral required to be posted from time to time in our transactions;

our success in risk management activities, including the use of derivative instruments to hedge commodity risks;

the level of creditworthiness of counterparties to transactions;

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;

the timing and extent of changes in natural gas, natural gas liquids (“NGL”), crude oil and other commodity prices, interest rates and demand for our services;

weather and other natural phenomena;

industry changes, including the impact of consolidations and changes in competition;

our ability to obtain necessary licenses, permits and other approvals;

the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering and processing systems, oil supplies to our gathering systems and NGL supplies to our logistics and marketing facilities and our success in connecting our facilities to transportation and markets;

our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets;

general economic, market and business conditions; and

the risks described elsewhere in “Part II – Other Information, Item 1A. Risk Factors” of this Quarterly Report, our Annual Report on Form 10-K for the year ended December 31, 2012 (“Annual Report”) and our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Part II – Other Information, Item 1A. Risk Factors.” in this Quarterly Report and in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

Table of Contents

As generally used in the energy industry and in this Quarterly Report, the identified terms have the following meanings:

Bbl	Barrels (equal to 42 U.S. gallons)
Btu	British thermal units, a measure of heating value
BBtu	Billion British thermal units
/d	Per day
/hr	Per hour
gal	U.S. gallons
GPM	Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gas
LPG	Liquefied petroleum gas
MBbl	Thousand barrels
MMBbl	Million barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
NGL(s)	Natural gas liquid(s)
NYMEX	New York Mercantile Exchange
GAAP	Accounting principles generally accepted in the United States of America
NYSE	New York Stock Exchange

Price Index Definitions
IF-NGPL MC	Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-PB	Inside FERC Gas Market Report, Permian Basin
IF-WAHA	Inside FERC Gas Market Report, West Texas WAHA
NY-WTI	NYMEX, West Texas Intermediate Crude Oil
OPIS-MB	Oil Price Information Service, Mont Belvieu, Texas

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1.

Financial Statements.

TARGA RESOURCES PARTNERS LP

CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2013			2012

	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	102.1		$	68.0
Trade receivables, net of allowances of $0.7 million and $0.7 million		427.7			514.9
Inventories		66.0			99.4
Assets from risk management activities		18.2			29.3
Other current assets		2.4			3.3
Total current assets		616.4			714.9
Property, plant and equipment		4,912.8			4,701.2
Accumulated depreciation		(1,225.1	)		(1,168.0	)
Property, plant and equipment, net		3,687.7			3,533.2
Other intangible assets, net		674.1			680.8
Long-term assets from risk management activities		3.2			5.1
Investment in unconsolidated affiliate		54.8			53.1
Other long-term assets		38.0			38.6
Total assets	$	5,074.2		$	5,025.7

LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	587.3		$	639.8
Accounts payable to Targa Resources Corp.		53.2			61.4
Liabilities from risk management activities		8.2			7.4
Total current liabilities		648.7			708.6
Long-term debt		2,450.4			2,393.3
Long-term liabilities from risk management activities		5.0			4.8
Deferred income taxes		11.6			11.2
Other long-term liabilities		49.1			47.7

Commitments and contingencies (see Note 12)

Owners' equity:
Common unitholders (102,777,067 and 100,095,989 units issued and outstanding as of March 31, 2013 and December 31, 2012)		1,703.3			1,649.5
General partner (2,097,492 and 2,042,776 units issued and outstanding as of March 31, 2013 and December 31, 2012)		48.5			45.3
Accumulated other comprehensive income		2.3			14.8
		1,754.1			1,709.6
Noncontrolling interests in subsidiaries		155.3			150.5
Total owners' equity		1,909.4			1,860.1
Total liabilities and owners' equity	$	5,074.2		$	5,025.7

See notes to consolidated financial statements.

Table of Contents

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended March 31,
	2013			2012

	(Unaudited)
	(In millions, except per unit amounts)
Revenues	$	1,397.8		$	1,645.5
Costs and expenses:
Product purchases		1,137.5			1,384.1
Operating expenses		86.1			71.6
Depreciation and amortization expenses		63.9			46.7
General and administrative expenses		34.1			32.9
Income from operations		76.2			110.2
Other income (expense):
Interest expense, net		(31.4	)		(29.4	)
Equity earnings		1.6			2.1
Other		(0.2	)		(0.1	)
Income before income taxes		46.2			82.8
Income tax expense:
Current		(0.5	)		(0.6	)
Deferred		(0.4	)		(0.4	)
		(0.9	)		(1.0	)
Net income		45.3			81.8
Less: Net income attributable to noncontrolling interests		6.4			11.7
Net income attributable to Targa Resources Partners LP	$	38.9		$	70.1

Net income attributable to general partner	$	22.8		$	14.1
Net income attributable to limited partners		16.1			56.0
Net income attributable to Targa Resources Partners LP	$	38.9		$	70.1

Net income per limited partner unit - basic	$	0.16		$	0.64
Net income per limited partner unit - diluted	$	0.16		$	0.63
Weighted average limited partner units outstanding - basic		101.8			88.1
Weighted average limited partner units outstanding - diluted		102.0			88.2

See notes to consolidated financial statements.

Table of Contents

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Three Months Ended March 31,
	2013			2012

	(Unaudited)
	(In millions)
Net income	$	45.3		$	81.8
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value		(7.6	)		15.4
Settlements reclassified to revenues		(6.6	)		(2.2	)
Interest rate swaps:
Settlements reclassified to interest expense, net		1.7			2.3
Other comprehensive income (loss)		(12.5	)		15.5
Comprehensive income		32.8			97.3
Less: Comprehensive income attributable to noncontrolling interests		6.4			11.7
Comprehensive income attributable to Targa Resources Partners LP	$	26.4		$	85.6

See notes to consolidated financial statements.

Table of Contents

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY

											Accumulated
	Limited					General					Other			Non-
	Partner					Partner					Comprehensive			controlling
	Units		Amount			Units		Amount			Income (Loss)			Interests			Total
	(Unaudited)
	(In millions, except units in thousands)

Balance December 31, 2012		100,096	$	1,649.5			2,043	$	45.3		$	14.8		$	150.5		$	1,860.1
Compensation on equity grants		13		1.7			-		-			-			-			1.7
Accrual of distribution equivalent rights		-		(0.3	)		-		-			-			-			(0.3	)
Proceeds from equity offerings		2,668		105.3			54		2.3			-			-			107.6
Distributions to noncontrolling interests		-		-			-		-			-			(3.7	)		(3.7	)
Contributions from noncontrolling interests		-		-			-		-			-			2.1			2.1
Other comprehensive loss		-		-			-		-			(12.5	)		-			(12.5	)
Net income		-		16.1			-		22.8			-			6.4			45.3
Distributions		-		(69.0	)		-		(21.9	)		-			-			(90.9	)
Balance March 31, 2013		102,777	$	1,703.3			2,097	$	48.5		$	2.3		$	155.3		$	1,909.4

Balance, December 31, 2011		84,756	$	1,221.2			1,730	$	27.2		$	(25.6	)	$	138.9		$	1,361.7
Compensation on equity grants		10		1.0			-		-			-			-			1.0
Proceeds from equity offerings		4,405		165.0			90		3.4			-			-			168.4
Contributions from Targa Resources Corp.		-		0.4			-		0.1			-			-			0.5
Distributions to noncontrolling interests		-		-			-		-			-			(10.1	)		(10.1	)
Contributions from noncontrolling interests		-		-			-		-			-			1.4			1.4
Other comprehensive income		-		-			-		-			15.5			-			15.5
Net income		-		56.0			-		14.1			-			11.7			81.8
Distributions to unitholders		-		(53.7	)		-		(12.3	)		-			-			(66.0	)
Balance March 31, 2012		89,171	$	1,389.9			1,820	$	32.5		$	(10.1	)	$	141.9		$	1,554.2

See notes to consolidated financial statements.

Table of Contents

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three months ended March 31,
	2013			2012

	(Unaudited)
	(In millions)
Cash flows from operating activities
Net income	$	45.3		$	81.8
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense		4.0			4.6
Compensation on equity grants		1.7			1.0
Depreciation and amortization expense		63.9			46.7
Accretion of asset retirement obligations		1.1			1.0
Deferred income tax expense		0.4			0.4
Equity earnings, net of distributions		(1.6	)		-
Risk management activities		(0.2	)		1.1
Gain on sale or disposition of assets		(0.1	)		-
Changes in operating assets and liabilities:
Receivables and other assets		87.9			113.9
Inventory		33.6			44.3
Accounts payable and other liabilities		(64.3	)		(148.1	)
Net cash provided by operating activities		171.7			146.7
Cash flows from investing activities
Outlays for property, plant and equipment		(203.5	)		(102.7	)
Investment in unconsolidated affiliate		-			(6.2	)
Return of capital from unconsolidated affiliate		-			0.3
Other, net		(4.6	)		0.8
Net cash used in investing activities		(208.1	)		(107.8	)
Cash flows from financing activities
Proceeds from borrowings under credit facility		325.0			145.0
Repayments of credit facility		(380.0	)		(643.0	)
Proceeds from issuance of senior notes		-			400.0
Proceeds from accounts receivable securitization facility		171.4			-
Repayments of accounts receivable securitization facility		(60.0	)		-
Costs incurred in connection with financing arrangements		(1.0	)		(4.4	)
Proceeds from equity offerings		107.6			168.4
Distributions to unitholders		(90.9	)		(66.0	)
General partner contributions		-			0.5
Contributions from noncontrolling interests		2.1			1.4
Distributions to noncontrolling interests		(3.7	)		(10.1	)
Net cash provided by (used in ) financing activities		70.5			(8.2	)
Net change in cash and cash equivalents		34.1			30.7
Cash and cash equivalents, beginning of period		68.0			55.6
Cash and cash equivalents, end of period	$	102.1		$	86.3

See notes to consolidated financial statements.

Table of Contents

TARGA RESOURCES PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

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 NYSE under the symbol “NGLS.” In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.

Targa Resources GP LLC is a Delaware limited liability company formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa. As of March 31, 2013, Targa owned a 14.3% interest in us in the form of 2,097,492 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 natural gas liquids (“NGL”) and NGL products; gathering, storing and terminaling crude oil; and storing, terminaling and selling refined petroleum products. See Note 13 for certain financial information for our business segments.

Note 2 — Basis of Presentation

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

The unaudited consolidated financial statements for the three months ended March 31, 2013 and 2012 include all adjustments which we believe are necessary for a fair presentation of the results for interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation.

Our financial results for the three months ended March 31, 2013 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2013.

Table of Contents

Note 3 — Significant Accounting Policies

Accounting Policy Updates/Revisions

The accounting policies that we follow are set forth in Note 3 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2012. Significant updates or revisions to these policies during the three months ended March 31, 2013 are shown below.

Accounts Receivable Securitization Facility

Under our Accounts Receivable Securitization Facility (the “Securitization Facility’), proceeds from the sales of certain receivables are treated as collateralized borrowings in our financial statements. All amounts outstanding under the Securitization Facility 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.

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.

Recent Accounting Pronouncements

In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarifies that ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, applies to financial instruments or derivative transactions accounted for under ASC 815. The amendments require disclosures to present both gross and net amounts of derivative assets and liabilities that are subject to master netting arrangements with counterparties. We currently present our derivative assets and liabilities gross on our statement of financial position. We have provided additional disclosures regarding the gross and net amounts of derivative assets and liabilities in Note 10 in accordance with these new standards updates.

Note 4 –Business Acquisitions

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”).

Pursuant to the Membership Interest Purchase and Sale Agreement dated November 19, 2012 (the “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 and revalued during the contingency period. 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.

Future 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. At March 31, 2013, we re-estimated the contingent consideration to be $15.6 million, an increase of $0.3 million attributable to accretion of the discount factor due to the passage of time. Our current assessment of other valuation variables and factors has not changed since the acquisition date.

Table of Contents

Our Annual Report on Form 10-K included the pro-forma schedule information for the year ended 2012. The following table presents updated 2012 pro forma information to reflect the effects of our 2013 policy decisions regarding depreciation and amortization of acquired properties and intangible assets, as described below. The following table also presents quarterly unaudited pro forma information for the three months ended March 31, 2012 for comparative purposes in this quarterly report.

	Year Ended December 31, 2012				Three Months Ended
	As reported in 10-K		Pro forma		March 31, 2012
	( In millions except per unit amounts)
Revenues	$	5,883.6	$	5,907.8	$	1,648.4
Net income		203.2		157.4		66.4
Net income attributable to limited partners		107.9		63.1		40.9

Net income per limited partner unit - Basic and diluted	$	1.20	$	0.63	$	0.41

We applied the same assumptions used in preparing the year-end pro forma schedules reported in our Annual Report on Form 10-K except for the following adjustments to conform to our current accounting policies:

depreciation expenses associated with the fair value adjustments to property, plant and equipment using straight-line method over a useful life of 15-20 years. The pro forma information included in our 2012 Form 10-K utilized a 30 year useful life;

amortization expenses associated with the fair value adjustments to definite-lived intangibles in a manner that closely resembles the expected pattern in which we benefit from services provided to customers, over a useful life of 20 years. The pro forma information included in our 2012 10-K utilized a straight-line method over a 30 year life; and

adjustment to pro forma revenues to report purchases, and sales on a net, rather than gross, basis for certain Badlands natural gas processing agreements in which we are in substance an agent rather than a principal.

Note 5 — Inventories

The components of inventories consisted of the following:

	March 31, 2013		December 31, 2012
Natural gas liquids	$	44.2	$	82.3
Materials and supplies		21.8		17.1
	$	66.0	$	99.4

Table of Contents

Note 6 — Property, Plant and Equipment and Intangible Assets

							Estimated useful lives
	March 31, 2013			December 31, 2012			(In years)
Gathering systems	$	2,048.0		$	1,975.3		5 to 20
Processing and fractionation facilities		1,262.1			1,251.6		5 to 25
Terminaling and storage facilities		502.6			462.0		5 to 25
Transportation assets		292.6			292.5		10 to 25
Other property, plant and equipment		86.7			84.6		3 to 25
Land		87.1			87.1			-
Construction in progress		633.7			548.1			-
Property, plant and equipment	$	4,912.8		$	4,701.2
Accumulated depreciation		(1,225.1	)		(1,168.0	)
Property, plant and equipment, net	$	3,687.7		$	3,533.2

Intangible assets	$	680.8		$	680.8			20
Accumulated amortization		(6.7	)		-
Intangible assets, net	$	674.1		$	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.

Customer contracts and customer relationships related to the Badlands system have an estimated economic useful life of 20 years. Amortization expense attributable to these assets is recorded using a method that closely reflects the cash flow pattern underlying the intangible asset valuation. Our estimated amortization expense for our intangible assets for each of the next five calendar years (2013-2017) is approximately $27.1 million, $61.4 million, $80.1 million, $88.3 million and $81.5 million.

Note 7 — Accounts Payable and Accrued Liabilities

The components of accounts payable and accrued liabilities consisted of the following:

	March 31, 2013		December 31, 2012
Commodities	$	383.5	$	416.8
Other goods and services		140.1		153.4
Interest		35.2		39.4
Other		28.5		30.2
	$	587.3	$	639.8

Table of Contents

Note 8 — Debt Obligations

	March 31,			December 31,
	2013			2012
Senior secured revolving credit facility, variable rate, due October 2017 (1)	$	565.0		$	620.0
Senior unsecured notes, 11¼% fixed rate, due July 2017		72.7			72.7
Unamortized discount		(2.4	)		(2.5	)
Senior unsecured notes, 7⅞% fixed rate, due October 2018		250.0			250.0
Senior unsecured notes, 6⅞% fixed rate, due February 2021		483.6			483.6
Unamortized discount		(29.9	)		(30.5	)
Senior unsecured notes, 6⅜% fixed rate, due August 2022		400.0			400.0
Senior unsecured notes, 5¼% fixed rate, due May 2023		600.0			600.0
Accounts receivable securitization facility, due January 2014 (2)		111.4			-
	$	2,450.4		$	2,393.3

Letters of credit outstanding	$	53.2		$	45.3

(1)	As of March 31, 2013, availability under our $1.2 billion senior secured revolving credit facility was $581.8 million.

(2)	All amounts outstanding under the Securitization Facility are reflected as long-term debt in our balance sheet to the extent that we have the ability and intent to fund the Securitization Facility’s borrowing with availability under our long-term Senior Secured Credit Facility (the “TRP Revolver”).

The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the three months ended March 31, 2013:

	Range of Interest Rates Incurred	Weighted Average Interest Rate Incurred
Senior secured revolving credit facility	1.9% - 4.5%	2.2%
Accounts receivable securitization facility	0.9%	0.9%

Compliance with Debt Covenants

As of March 31, 2013, we were in compliance with the covenants contained in our various debt agreements.

Accounts Receivable Securitization Facility

In January 2013, we entered into the Securitization Facility to provide up to $200 million of borrowing capacity at commercial paper 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.

Note 9 — Partnership Units and Related Matters

Public Offerings of Common Units

In 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 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 (“2012 EDA”) with Citigroup Global Markets Inc. (“Citigroup”) pursuant to which we may sell, at our option, up to an aggregate of $100 million of our common units through Citibank, as sales agent, under the 2012 Shelf. Settlement for sales of common units will occur on the third business day following the date on which any sales were made in return for payment of the net proceeds to us. During the three months ended 2013, we issued 2,420,046 common units under the 2012 EDA and received gross proceeds of $96.7 million pursuant to the EDA. Targa contributed $2.0 million to us to maintain its 2% general partner interest.

Table of Contents

In March 2013, we entered into a second Equity Distribution Agreement (the “2013 EDA”) with Citigroup, Deutsche Bank Securities Inc., Raymond James & Associates, Inc. and UBS Securities LLC, as our sales agents, pursuant to which we may sell, at our option, up to an aggregate of $200 million of our common units under our 2012 Shelf. During the three months ended March 31, 2013, we issued 248,252 common units and received gross proceeds of $10.7 million, pursuant to the 2013 EDA. Targa contributed $0.3 million to us 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 during the three months ended March 31, 2013.

			Distributions
			Limited		General Partner						Distributions per limited
Three Months Ended	Date Paid or to be Paid		Partners Common		Incentive		2%		Total		partner unit
					(In millions, except per unit amounts)
March 31, 2013	May 15, 2013	$	71.7	$	22.1	$	1.9	$	95.7	$	0.6975
December 31, 2012	February 14, 2013		69.0		20.1		1.8		90.9		0.6800

Subsequent Event

In April 2013, we filed with the SEC a universal shelf registration statement (the “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 2013 Shelf expires in April 2016.

Note 10 — 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 Field Gathering and Processing Operations and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing segment and the LOU business unit in 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 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.

Table of Contents

At March 31, 2013, the notional volumes of our commodity hedges for equity volumes were:

Commodity	Instrument	Unit	2013	2014	2015	2016
Natural Gas	Swaps	MMBtu/d	31,108	25,500	12,001	5,000
NGL	Swaps	Bbl/d	5,650	1,000	-	-
Condensate	Swaps	Bbl/d	1,962	1,450	-	-

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 March 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	$	18.1	$	8.1	$	29.2	$	7.2
	Long-term		3.2		5.0		5.1		4.8
Total derivatives designated as hedging instruments		$	21.3	$	13.1	$	34.3	$	12.0

Derivatives not designated as hedging instruments
Commodity contracts	Current	$	0.1	$	0.1	$	0.1	$	0.2
	Long-term		-		-		-		-
Total derivatives not designated as hedging instruments		$	0.1	$	0.1	$	0.1	$	0.2

Total current position		$	18.2	$	8.2	$	29.3	$	7.4
Total long-term position			3.2		5.0		5.1		4.8
Total derivatives		$	21.4	$	13.2	$	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
March 31, 2013	Position		Position		Position		Position
Current position
Counterparties with offsetting position	$	16.3	$	7.1	$	9.2	$	-
Counterparties without offsetting position - assets		1.9		-		1.9		-
Counterparties without offsetting position - liabilities		-		1.1		-		1.1
		18.2		8.2		11.1		1.1
Long-term position
Counterparties with offsetting position		3.2		0.9		2.3		-
Counterparties without offsetting position - assets		-		-		-		-
Counterparties without offsetting position - liabilities		-		4.1		-		4.1
		3.2		5.0		2.3		4.1
Total derivatives
Counterparties with offsetting position		19.5		8.0		11.5		-
Counterparties without offsetting position - assets		1.9		-		1.9		-
Counterparties without offsetting position - liabilities		-		5.2		-		5.2
	$	21.4	$	13.2	$	13.4	$	5.2

December 31, 2012
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		18.0		-
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 asset of $8.2 million as of March 31, 2013, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities by year as indicated by market quotes for the counterparties’ credit default swap rates. These default probabilities have been applied to the unadjusted fair values of the derivative instruments to arrive at the credit risk adjustment, which was immaterial for all periods presented.

Table of Contents

Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in natural gas, NGL and crude oil prices relative to the fixed prices set forth in the hedges 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 other comprehensive income (“OCI”) and amounts reclassified from OCI to revenue and expense for the periods indicated:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) March 31,
	2013			2012
Commodity contracts		(7.6	)		15.4
	$	(7.6	)	$	15.4

	Gain (Loss) Reclassified from OCI into Income (Effective Portion) March 31,
Location of Gain (Loss)	2013			2012
Interest expense, net	$	(1.7	)	$	(2.3	)
Revenues		6.6			2.2
	$	4.9		$	(0.1	)

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 derivatives not designated as hedging instruments was immaterial for all periods presented.

The following table shows the deferred gains (losses) included in accumulated OCI that will be reclassified into earnings through the end of 2016:

	March 31, 2013			December 31, 2012
Commodity hedges	$	8.9		$	23.1
Interest rate hedges		(6.8	)		(8.5	)

As of March 31, 2013, deferred net gains of $10.7 million on commodity hedges and deferred net losses of $5.7 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 11 for additional disclosures related to derivative instruments and hedging activities.

Table of Contents

Note 11 — Fair Value Measurements

Under generally accepted accounting principles, our consolidated balance sheet reflects 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 is 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 swap 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 asset position of $8.2 million as of March 31, 2013, are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. This asset 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 $18.7 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 $35.1 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:

the TRP Revolver and Securitization Facility are based on carrying value which approximates fair value as its interest rate is based on prevailing market rates;

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.

Table of Contents

The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included in our consolidated balance sheet at fair value and (2) supplemental fair value disclosures for other financial instruments:

	March 31, 2013
			Fair Value
	Carrying Value		Total		Level 1		Level 2		Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheet at Fair Value:
Assets from commodity derivative contracts	$	21.4	$	21.4	$	-	$	21.4	$	-
Liabilities from commodity derivative contracts		13.2		13.2		-		12.2		1.0
Badlands contingent consideration liability		15.6		15.6		-		-		15.6
Financial Instruments Recorded on Our Consolidated Balance Sheet at Carrying Value:
Cash and cash equivalents		102.1		102.1
Senior secured revolving credit facility		565.0		565.0		-		565.0		-
Senior unsecured notes		1,774.0		1,949.8		-		1,949.8		-
Accounts receivable securitization facility		111.4		111.4		-		111.4		-

	December 31, 2012
			Fair Value
	Carrying Value		Total		Level 1		Level 2		Level 3
Financial Instruments Recorded on Our Consolidated Balance Sheet at Fair Value:
Assets from commodity derivative contracts	$	34.3	$	34.3	$	-	$	34.3	$	-
Liabilities from commodity derivative contracts		12.1		12.1		-		11.5		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		68.0		68.0
Senior secured revolving credit facility		620.0		620.0		-		620.0		-
Senior unsecured notes		1,773.3		1,945.2		-		1,945.2		-

Additional Information Regarding Level 3 Fair Value Measurements

As of March 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 March 31, 2013, we had five 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.

Table of Contents

As of March 31, 2013, we had a contingent consideration liability, which was included in the preliminary valuation of the Badlands acquisition (see Note 4). The preliminary fair value was determined by a probability-based model measuring the likelihood of meeting certain volumetric measures identified in the MIPSA. Consequently, as these probability-based inputs are not observable, the entire valuation of the contingent consideration is categorized in Level 3.

The following table sets forth a reconciliation of the changes in the fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

	Commodity Derivative Contracts		Contingent Liability
Balance, December 31, 2012	$	0.6	$	15.3
Loss included in Revenue		0.4		-
Loss included in Other expense		-		0.3
Balance, March 31, 2013	$	1.0	$	15.6

The losses for the period included in earnings are attributable to the change in unrealized losses of liabilities held at the reporting dates. There have been no transfers of assets or liabilities between the three levels of the fair value hierarchy during the three months ended March 31, 2013.

Note 12 — Commitments and Contingencies

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.

Note 13 — 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 includes 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, Texas and Southwestern Louisiana.

Table of Contents

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 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:

	Three Months Ended March 31, 2013
	Field		Coastal
	Gathering		Gathering				Marketing				Corporate
	and		and		Logistics		and				and
	Processing		Processing		Assets		Distribution		Other		Eliminations			Total
Revenues
Sales of commodities	$	38.1	$	69.6	$	32.9	$	1,136.5	$	6.6	$	-		$	1,283.7
Fees from midstream services		20.2		8.8		47.1		38.0		-		-			114.1
		58.3		78.4		80.0		1,174.5		6.6		-			1,397.8
Intersegment revenues
Sales of commodities		273.0		151.9		0.9		110.5		-		(536.3	)		-
Fees from midstream services		0.9		-		36.6		6.4		-		(43.9	)		-
		273.9		151.9		37.5		116.9		-		(580.2	)		-
Revenues	$	332.2	$	230.3	$	117.5	$	1,291.4	$	6.6	$	(580.2	)	$	1,397.8
Operating margin	$	53.8	$	23.5	$	56.3	$	34.0	$	6.6	$	-		$	174.2
Other financial information:
Total assets	$	2,854.7	$	416.3	$	1,210.7	$	436.9	$	21.4	$	134.2		$	5,074.2
Capital expenditures	$	96.1	$	6.5	$	103.7	$	-	$	-	$	0.6		$	206.9

	Three Months Ended March 31, 2012
	Field		Coastal
	Gathering		Gathering				Marketing				Corporate
	and		and		Logistics		and				and
	Processing		Processing		Assets		Distribution		Other		Eliminations			Total
Revenues
Sales of commodities	$	45.4	$	59.8	$	45.7	$	1,417.2	$	1.4	$	-		$	1,569.5
Fees from midstream services		10.9		3.7		38.7		22.7		-		-			76.0
		56.3		63.5		84.4		1,439.9		1.4		-			1,645.5
Intersegment revenues
Sales of commodities		317.4		220.0		-		132.0		-		(669.4	)		-
Fees from midstream services		0.3		0.1		24.0		9.3		-		(33.7	)		-
		317.7		220.1		24.0		141.3		-		(703.1	)		-
Revenues	$	374.0	$	283.6	$	108.4	$	1,581.2	$	1.4	$	(703.1	)	$	1,645.5
Operating margin	$	73.0	$	46.3	$	43.0	$	26.1	$	1.4	$	-		$	189.8
Other financial information:
Total assets	$	1,661.1	$	422.5	$	823.0	$	507.9	$	49.5	$	123.1		$	3,587.1
Capital expenditures	$	26.2	$	2.0	$	60.1	$	9.1	$	-	$	0.6		$	98.0

Table of Contents

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

	Three Months Ended March 31,
	2013		2012
Sales of commodities
Natural gas sales	$	255.3	$	202.9
NGL sales		963.5		1,290.2
Condensate sales		27.1		29.0
Petroleum products		31.3		45.5
Derivative activities		6.5		1.9
		1,283.7		1,569.5
Fees from midstream services
Fractionating and treating fees		29.7		26.9
Storage, terminaling, transportation and export fees		60.2		30.5
Gas gathering and processing fees		18.5		8.6
Other		5.7		10.0
		114.1		76.0
Total revenues	$	1,397.8	$	1,645.5

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

	Three Months Ended March 31,
	2013			2012
Reconciliation of operating margin to net income:
Operating margin	$	174.2		$	189.8
Depreciation and amortization expense		(63.9	)		(46.7	)
General and administrative expense		(34.1	)		(32.9	)
Interest expense, net		(31.4	)		(29.4	)
Income tax expense		(0.9	)		(1.0	)
Other, net		1.4			2.0
Net income	$	45.3		$	81.8

Table of Contents

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2012 (“Annual Report”), as well as the unaudited consolidated financial statements and Notes hereto included in this Quarterly Report on Form 10-Q.

Overview

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 are listed on the NYSE under the symbol “NGLS.” In this Quarterly Report, unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries.

Targa Resources GP LLC (the “general partner”) 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.

Our Operations

We are a leading provider of midstream natural gas, NGLs, terminaling and crude oil gathering services in the United States. 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.

Table of Contents

Other contains the results of our commodity hedging activities included in operating margin.

2013 Developments

On January 1, 2013, we assumed operational control of the Badlands assets and commenced integration activities. We anticipate rapid growth of volumes and build-out of the Badlands system throughout 2013 and 2014. As these assets are still in a start-up phase, the results of our Badlands operations were not material to the overall consolidated results of operations for the three months ended March 31, 2013. Badland operational results are included as part of the Field Gathering and Processing segment.

The Badlands 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 during the contingency period. 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 the thresholds.

In January 2013, we entered into a Securitization Facility that provides up to $200 million of borrowing capacity at commercial paper rates plus a margin through January 2014. Under this Securitization Facility, one of our consolidated subsidiaries (TLMT) sells or contributes receivables, without recourse, to another of its consolidated subsidiaries (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. 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. Total funding under this Securitization Facility as of March 31, 2013 was $111.4 million.

During the three months ended March 31, 2013, we issued 2,668,298 common units and received gross proceeds of $107.4 million, pursuant to our 2012 and 2013 EDAs. Targa contributed $2.3 million to maintain its 2% general partner interest. Based upon market conditions and our capital needs, at our option, we can sell additional common units up to an aggregate amount of $192.6 million under these agreements.

Recent Accounting Pronouncements

Table of Contents

How We Evaluate Our Operations

Our profitability is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the crude oil, natural gas, NGLs and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of crude oil, wellhead natural gas and mixed NGLs that we purchase as well as operating and general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.

Our profitability is also impacted by fee-based revenues. Our growth strategy, based on expansion of existing facilities as well as third-party acquisitions of businesses and assets, is resulting in an increasing percentage of assets that generate fee-based revenues. Fixed fees for services such as fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities.

Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures — gross margin, operating margin, adjusted EBITDA and distributable cash flow.

Throughput Volumes, Facility Efficiencies and Fuel Consumption

Our profitability is impacted by our ability to add new sources of natural gas supply and crude oil to offset the natural decline of existing volumes from oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third-parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, typically connected by third-party transportation, to our Downstream Business’ fractionation facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities. Our recently acquired assets in the Bakken Shale should allow us to participate in the infrastructure build-out in return for fee-based revenue to gather crude oil or gather and process natural gas, from the wellhead to various takeaway options. There is a significant amount of uncommitted acreage in proximity to our system, which should provide further opportunities to enhance medium and long-term growth in the Bakken Shale.

In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of the facilities. Similar tracking is performed for our crude oil gathering and logistics assets. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.

Table of Contents

Operating Expenses

Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, generally remain relatively stable and independent of the volumes through our systems but fluctuate depending on the scope of the activities performed during a specific period.

Capital Expenditures

We closely monitor the capital projects associated with growth and maintenance projects. We analyze return on investment before a capital project is approved, closely monitor the spending throughout the development of the project and evaluate ensuing operational performance versus capital investment economic analysis. We have seen a substantial increase in our total capital spent over the last three years and currently have significant internal growth projects that we closely monitor.

Gross Margin

We define gross margin as revenues less purchases. It is impacted by volumes and commodity prices as well as by our contract mix and hedging program. We define Gathering and Processing gross margin as total operating revenues from (1) the sale of natural gas, condensate and NGLs (2) natural gas and crude oil gathering and service fee revenues and (3) settlement gains and losses on commodity hedges, less product purchases, which consist primarily of producer payments and other natural gas purchases. Logistics Assets gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees, NGL and natural gas sales, less cost of sales, which consists primarily of NGL and natural gas purchases, transportation costs and changes in inventory valuation.

Operating Margin

We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by us and by external users of our financial statements, including investors and commercial banks, to assess:

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Table of Contents

Adjusted EBITDA

We define Adjusted EBITDA as net income before: interest; income taxes; depreciation and amortization; gains or losses on debt repurchases and redemptions, early debt extinguishments and asset disposals; non-cash risk management activities related to derivative instruments; and changes in the fair value of the Badlands acquisition contingent consideration. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others.

The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.

Adjusted EBITDA is a non-GAAP financial measure. The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Distributable Cash Flow

We define distributable cash flow as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash losses (gains) on mark-to-market derivative contracts, debt repurchases and redemptions, early debt extinguishments and asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs), and changes in the fair value of the Badlands acquisition contingent consideration. This measure includes any impact of noncontrolling interests.

Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by the board of directors of our general partner) to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratio of estimated cash flows to cash distributions. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder).

Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Partners LP. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Partners LP. It has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Table of Contents

Non-GAAP Financial Measures

The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated:

	Three Months Ended March 31,
	2013			2012
	(In millions)
Reconciliation of gross margin and operating margin to net income:
Gross margin	$	260.3		$	261.4
Operating expenses		(86.1	)		(71.6	)
Operating margin		174.2			189.8
Depreciation and amortization expenses		(63.9	)		(46.7	)
General and administrative expenses		(34.1	)		(32.9	)
Interest expense, net		(31.4	)		(29.4	)
Income tax expense		(0.9	)		(1.0	)
Gain on sale or disposal of assets		0.1			-
Other, net		1.3			2.0
Net income	$	45.3		$	81.8

	Three Months Ended March 31,
	2013			2012
	(In millions)
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	171.7		$	146.7
Net income attributable to noncontrolling interests		(6.4	)		(11.7	)
Interest expense, net (1)		27.4			24.8
Current income tax expense		0.5			0.6
Other (2)		(3.8	)		(4.9	)
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivable and other assets		(121.5	)		(158.2	)
Accounts payable and other liabilities		64.3			148.1
Adjusted EBITDA	$	132.2		$	145.4

(1)	Net of amortization of debt issuance costs, discount and premium included in interest expense of $4.0 million and $4.6 million for the three months ended March 31, 2013 and 2012.

(2)

Includes equity earnings from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations, amortization of stock-based compensation, gain on sale or disposal of assets, and changes in the contingent consideration associated with the Badlands acquisition.

Table of Contents

	Three Months Ended March 31,
	2013			2012
	(In millions)
Reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP	$	38.9		$	70.1
Add:
Interest expense, net		31.4			29.4
Income tax expense		0.9			1.0
Depreciation and amortization expenses		63.9			46.7
Gain on sale or disposal of assets		(0.1	)		-
Change in contingent consideration		0.3			-
Risk management activities		(0.2	)		1.0
Noncontrolling interests adjustment (1)		(2.9	)		(2.8	)
Adjusted EBITDA	$	132.2		$	145.4

(1)	Noncontrolling interest portion of depreciation and amortization expenses.

	Three Months Ended March 31,
	2013			2012
	(In millions)
Reconciliation of net income attributable to Targa Resources Partners LP to distributable cash flow:
Net income attributable to Targa Resources Partners LP	$	38.9		$	70.1
Depreciation and amortization expenses		63.9			46.7
Deferred income tax expense		0.4			0.4
Amortization in interest expense		4.0			4.6
Gain on sale or disposal of assets		(0.1	)		-
Risk management activities		(0.2	)		1.0
Maintenance capital expenditures		(21.7	)		(16.5	)
Other (1)		0.3			(0.6	)
Targa Resources Partners LP distributable cash flow	$	85.5		$	105.7

(1)	Includes reimbursements of certain environmental maintenance capital expenditures by Targa, the noncontrolling interest portion of maintenance capital expenditures, depreciation and amortization expenses and changes in the fair value of the Badlands acquisition contingent consideration.

Table of Contents

Results of Operations

The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2013 and 2012 (in millions, except operating statistics and price amounts):

	Three Months Ended March 31,
	2013			2012			2013 vs. 2012
Revenues	$	1,397.8		$	1,645.5		$	(247.7	)	(15	%)
Product purchases		1,137.5			1,384.1			(246.6	)	(18	%)
Gross margin (1)		260.3			261.4			(1.1	)	(0	%)
Operating expenses		86.1			71.6			14.5		20	%
Operating margin (2)		174.2			189.8			(15.6	)	(8	%)
Depreciation and amortization expenses		63.9			46.7			17.2		37	%
General and administrative expenses		34.1			32.9			1.2		4	%
Income from operations		76.2			110.2			(34.0	)	(31	%)
Interest expense, net		(31.4	)		(29.4	)		(2.0	)	7	%
Equity earnings		1.6			2.1			(0.5	)	(24	%)
Other		(0.2	)		(0.1	)		(0.1	)	(100	%)
Income tax expense		(0.9	)		(1.0	)		0.1		10	%
Net income		45.3			81.8			(36.5	)	(45	%)
Less: Net income attributable to noncontrolling interests		6.4			11.7			(5.3	)	(45	%)
Net income attributable to Targa Resources Partners LP	$	38.9		$	70.1		$	(31.2	)	(45	%)

Financial and operating data:

Financial data:
Adjusted EBITDA (3)	$	132.2		$	145.4		$	(13.2	)	(9	%)
Distributable cash flow (4)		85.5			105.7			(20.2	)	(19	%)
Capital expenditures		206.9			98.0			108.9		111	%

Operating data:
Crude oil gathered, MBbl/d		31.5			-			31.5		-
Plant natural gas inlet, MMcf/d (5)(6)		2,079.1			2,232.7			(153.6	)	(7	%)
Gross NGL production, MBbl/d		133.3			132.3			1.0		1	%
Export volumes, MBbl/d		44.8			22.1			22.7		103	%
Natural gas sales, BBtu/d (6)		849.7			860.5			(10.8	)	(1	%)
NGL sales, MBbl/d		281.3			279.1			2.2		1	%
Condensate sales, MBbl/d		3.4			3.1			0.3		10	%

(1)	Gross margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”

(2)	Operating margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”

(3)

Adjusted EBITDA is net income before: interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and debt redemptions, early debt extinguishments and asset disposals, non-cash risk management activities related to derivative instruments and changes in the fair value of the Badlands acquisition contingent consideration. This is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”

(4)

Distributable cash flow is income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash losses (gains) on mark-to-market derivative contracts, debt repurchases, debt redemptions, early debt extinguishments, asset disposals, less maintenance capital expenditures (net of any reimbursements of project costs) and changes in the fair value of the Badlands acquisition contingent consideration. This is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”

(5)	Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(6)	Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

Table of Contents

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Revenues, including the impacts of hedging, decreased due to impact of lower realized prices on NGLs and condensate ($317.0 million) and lower natural gas and NGL volumes ($8.8 million), partially offset by the impact of higher realized prices on natural gas ($51.2 million), higher fee-based and other revenues ($25.1 million) and higher volumes of condensate ($1.8 million).

Consolidated gross margin was essentially flat, as the favorable margin effects of volumes expansions were mitigated by falling NGL and condensate prices. Operating expenses increased primarily due to the system expansions in our Field Gathering and Processing segment and higher maintenance costs. See “—Results of Operations – By Reportable Segment” for additional information regarding changes in the components of operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses was primarily due to the acquisition of Badlands properties and intangible assets, system expansions and other assets placed in service during the last twelve months.

General and administrative expenses increased primarily due to compensation and benefits.

The increase in interest expense was the result of higher borrowings ($6.2 million) offset by higher capitalized interest ($4.3 million) as a result of increased spending on major capital projects.

The decrease in net income attributable to noncontrolling interests reflects the impact of lower earnings at our non-wholly owned Upstream consolidated subsidiaries, primarily at our Versado and VESCO joint ventures.

Results of Operations—By Reportable Segment

Our operating margins by reportable segment are:

		Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other		Total
Three Months Ended:		(In millions)
March 31, 2013	$	53.8	$	23.5	$	56.3	$	34.0	$	6.6	$	174.2
March 31, 2012		73.0		46.3		43.0		26.1		1.4		189.8

Table of Contents

Gathering and Processing Segments

Field Gathering and Processing

	Three Months Ended March 31,
	2013		2012		2013 vs. 2012

	($ in millions)
Gross margin	$	91.5	$	102.3	$	(10.8	)	(11	%)
Operating expenses		37.7		29.3		8.4		29	%
Operating margin	$	53.8	$	73.0	$	(19.2	)	(26	%)
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
Sand Hills		152.3		145.7		6.6		5	%
SAOU		139.2		115.3		23.9		21	%
North Texas System		260.8		224.5		36.3		16	%
Versado		160.7		169.9		(9.2	)	(5	%)
Badlands		15.9		-		15.9		-
		728.9		655.4		73.5		11	%
Gross NGL production, MBbl/d
Sand Hills		17.4		17.0		0.4		2	%
SAOU		20.6		18.2		2.4		13	%
North Texas System		29.0		24.9		4.1		16	%
Versado		19.4		19.0		0.4		2	%
Badlands		1.6		-		1.6		-
		88.0		79.1		8.9		11	%
Crude oil gathered, MBbl/d		31.5		-		31.5		-
Natural gas sales, BBtu/d (3)		339.2		313.3		25.9		8	%
NGL sales, MBbl/d		70.8		65.0		5.8		9	%
Condensate sales, MBbl/d		2.9		2.9		-		0	%
Average realized prices (4):
Natural gas, $/MMBtu		3.12		2.57		0.55		21	%
NGL, $/gal		0.72		1.06		(0.34	)	(32	%)
Condensate, $/Bbl		85.66		99.23		(13.57	)	(14	%)

(1)

Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

(2)	Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(3)	Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(4)	Average realized prices exclude the impact of hedging activities presented in Other.

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

The decrease in gross margin was primarily driven by lower NGL and condensate sales prices, partially offset by system volume increases and higher natural gas prices. The increase in plant inlet volumes were largely attributable to new well connects, which increased system volumes. Volumes at Sand Hills and Versado were impacted by operational issues.

The increase in operating expenses was primarily due to expanded operations and higher system maintenance and repair costs.

Table of Contents

Coastal Gathering and Processing

	Three Months Ended March 31,
	2013		2012		2013 vs. 2012
	($ in millions)
Gross margin	$	34.0	$	56.7	$	(22.7	)	(40	%)
Operating expenses		10.5		10.4		0.1		1	%
Operating margin	$	23.5	$	46.3	$	(22.8	)	(49	%)
Operating statistics (1):
Plant natural gas inlet, MMcf/d (2),(3)
LOU (4)		341.6		194.9		146.7		75	%
Coastal Straddles		474.5		839.5		(365.0	)	(43	%)
VESCO		534.1		543.0		(8.9	)	(2	%)
		1,350.2		1,577.4		(227.2	)	(14	%)
Gross NGL production, MBbl/d
LOU		9.0		8.1		0.9		11	%
Coastal Straddles		13.4		17.6		(4.2	)	(24	%)
VESCO		22.9		27.5		(4.6	)	(17	%)
		45.3		53.2		(7.9	)	(15	%)
Natural gas sales, BBtu/d (3)		275.1		282.0		(6.9	)	(2	%)
NGL sales, MBbl/d		41.4		47.3		(5.9	)	(12	%)
Condensate sales, MBbl/d		0.5		0.3		0.2		67	%
Average realized prices:
Natural gas, $/MMBtu		3.45		2.62		0.83		32	%
NGL, $/gal		0.84		1.16		(0.32	)	(28	%)
Condensate, $/Bbl		110.44		127.86		(17.42	)	(14	%)

(1)	Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume during the quarter and the denominator is the number of calendar days during the quarter.

(2)	Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(3)	Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

(4)	Includes volumes from the Big Lake processing plant acquired in July 2012.

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

The decrease in gross margin was primarily due to lower realized NGL and condensate sales prices, less favorable frac spread and lower throughput volumes. The decrease in plant inlet volumes was largely attributable to the decline in offshore and off-system supply volumes and the impact of the Yscloskey, Calumet and other third-party plant shutdowns in 2012, partially offset by the addition of the Big Lake plant. Lower natural gas sales volumes reflected decreased sales to other reportable segments for resale, partially offset by an increase in demand from industrial customers. VESCO’s NGL production was constrained by damage to one of the two third-party pipelines that provide NGL takeaway capacity.

Operating expenses were flat as higher system maintenance and repair costs at LOU and Lowry were offset by the impact of the Yscloskey and Calumet plant shutdowns.

Table of Contents

Logistics and Marketing Segments

Logistics Assets

	Three Months Ended March 31,
	2013		2012		2013 vs. 2012
	($ in millions)
Gross margin	$	86.5	$	64.4	$	22.1		34	%
Operating expenses		30.2		21.4		8.8		41	%
Operating margin	$	56.3	$	43.0	$	13.3		31	%
Operating statistics (1):
Fractionation volumes, MBbl/d		258.0		293.7		(35.7	)	(12	%)
LSNG treating volumes, MBbl/d		25.7		19.1		6.6		35	%
Benzene treating volumes, MBbl/d		20.9		17.0		3.9		23	%

(1)	Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

The increase in gross margin was primarily due to increased export and storage activity, higher fractionation and treating revenues, and increased petroleum logistics activities, partially offset by lower fractionation volumes. Export volumes, which benefit both the Logistics Assets and the Marketing and Distribution segments, averaged 44.8 MBbl/d for the three months ended March 31, 2013, nearly double 2012 volumes. Storage fees increased due to higher rates and new customers. Higher fractionation fees and contractual capacity reservation fees more than offset the impact of lower fractionation supply volumes that resulted from ethane rejection and pipeline operating issues at facilities not operated by the Partnership. Treating fees increased due to higher hydrotreating and de-pentanizer volumes. Terminaling gross margin improved as a result of increased crude oil throughput for the three months ended 2013 and the start up of the renewable fuels project at the Sound Terminal.

Operating expenses increased primarily due to higher fuel, labor and maintenance costs and lower system product gains.

Table of Contents

Marketing and Distribution

	Three Months Ended March 31,
	2013		2012		2013 vs. 2012
	($ in millions)
Gross margin	$	44.8	$	35.4	$	9.4		27	%
Operating expenses		10.8		9.3		1.5		16	%
Operating margin	$	34.0	$	26.1	$	7.9		30	%
Operating statistics (1):
Natural gas sales, BBtu/d		882.1		1,023.5		(141.4	)	(14	%)
NGL sales, MBbl/d		283.6		282.7		0.9		0.3	%
Average realized prices:
Natural gas, $/MMBtu		3.34		2.60		0.74		28	%
NGL realized price, $/gal		0.92		1.21		(0.29	)	(24	%)

(1)	Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Despite flat NGL and lower natural gas sales volumes, gross margin increased due to higher LPG export activity, higher wholesale propane margins driven by colder weather, additional gasoline blending demand and increased truck and barge utilization.

Operating expenses increased primarily due to higher truck operating expense as a result of increased truck utilization, and increased distribution expense.

Other

	Three Months Ended March 31,
	2013		2012		2013 vs. 2012
	(In millions)
Gross margin	$	6.6	$	1.4	$	5.2
Operating margin	$	6.6	$	1.4	$	5.2

Other contains the financial effects of our hedging program on operating margin. It typically represents the cash settlements on our derivative contracts. Other also includes deferred gains or losses on previously terminated or de-designated hedge contracts that are reclassified to revenues upon the occurrence of the underlying physical transactions.

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 price associated with a portion of our expected (i) natural gas equity volumes in Field Gathering and Processing Operations and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing as well as in the LOU portion of the Coastal Gathering and Processing Operations that result from its percent of proceeds processing arrangements by entering into derivative instruments.

Table of Contents

The following table provides a breakdown of our hedge revenue by product:

	Three Months Ended March 31,
	2013			2012			2013 vs. 2012

	(In millions)
Natural gas	$	3.3		$	8.6		$	(5.3	)
NGL		3.5			(5.5	)		9.0
Crude oil		(0.2	)		(1.7	)		1.5
	$	6.6		$	1.4		$	5.2

Because we are essentially forward selling a portion of our plant equity volumes, these hedge positions will move favorably in periods of falling prices and unfavorably in periods of rising prices.

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing our indebtedness and meeting our collateral requirements, will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include weather, commodity prices (particularly for natural gas and NGLs), and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under the TRP Revolver, borrowings under the Securitization Facility, the issuance of additional common units and access to debt markets. The capital markets continue to experience volatility. Our exposure to current credit conditions includes our credit facility, cash investments and counterparty performance risks. We continually monitor our liquidity and the credit markets, as well as events and circumstances surrounding each of the lenders to the TRP Revolver.

As of April 25, 2013, our liquidity consisted of the following:

		April 25, 2013

		(In millions)
Cash on hand		$	25.0
Total availability under the TRP Revolver			1,200.0
Total availability under the Securitization Facility			147.7
			1,372.7
Less:	Outstanding borrowings under the TRP Revolver		(525.0	)
	Outstanding borrowings under the Securitization Facility		(147.7	)
	Outstanding letters of credit under the TRP Revolver		(50.7	)
	Total liquidity	$	649.3

We may issue additional equity or debt securities to assist us in meeting future liquidity and capital spending requirements.

In 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 million of debt or equity securities, the 2012 Shelf. The 2012 Shelf expires in August 2015. In August 2012, we entered into the 2012 EDA, pursuant to which we may sell, at our option, up to an aggregate of $100 million of our common units through Citigroup, as our sales agent, under the 2012 Shelf. In March 2013, we entered into the 2013 EDA, pursuant to which we may sell, at our option, up to an aggregate of $200 million of our common units through Citigroup, Deutsche Bank Securities Inc., Raymond James & Associates, Inc. and UBS Securities LLC, as our sales agents, under the 2012 Shelf.

Table of Contents

In January 2013, we entered into a Securitization Facility that provides up to $200 million of borrowing capacity at commercial paper rates plus a margin through January 2014. Under this Securitization Facility, one of our consolidated subsidiaries (TLMT) sells or contributes receivables, without recourse, to another of our consolidated subsidiaries (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. 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 April 2013, we filed with the SEC a universal shelf registration statement, the 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 2013 Shelf expires in April 2016.

Risk Management

We evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all of our commodity derivatives with major financial institutions or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operation. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas equity volumes through 2016 and our NGL and condensate equity volumes through 2014. See “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.” The current market conditions may also impact our ability to enter into future commodity derivative contracts.

Our risk management position has moved from a net asset position of $22.2 million at December 31, 2012 to a net asset position of $8.2 million at March 31, 2013. Aggregate forward prices for commodities are below the fixed prices we currently expect to receive on those derivative contracts, creating this net asset position. Consequently, our expected future receipts on derivative contracts are greater than our expected future payments. We account for derivatives that mitigate commodity price risk as cash flow hedges. Changes in fair value are deferred in OCI until the underlying hedged transactions settle.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced with receivables from NGL customers offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (1) our cash position; (2) liquids inventory levels and their valuation, which we closely manage; and (3) changes in the fair value of the current portion of derivative contracts.

For the three months ended March 31, 2013, our working capital decreased $38.6 million, primarily due a decrease in net commodity receivables of $46.2 million, a decrease of inventory of $33.4 million related to seasonal draw-downs of propane inventory and lower inventory pricing, and a decrease in the net current risk management position of $11.9 million, partially offset by a $34.1 million increase in cash, $10.6 million increase in other current assets and a $8.2 million decrease in affiliate payable.

Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow, borrowings available under the TRP Revolver and the Securitization Facility and proceeds from equity offerings and debt offerings should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and minimum quarterly cash distributions for at least the next twelve months.

Table of Contents

A portion of our capital resources may be utilized in the form of letters of credit to satisfy certain counterparty credit requirements. While our credit ratings have improved over time, these letters of credit reflect our non-investment grade status, as assigned to us by Moody’s Investors Service, Inc. and Standard & Poor’s Corporation, and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. As of March 31, 2013, we had $53.2 million in letters of credit outstanding.

Cash Flow

The following table and discussion summarize our consolidated cash flows provided by or used in operating activities, investing activities and financing activities:

	Three Months Ended March 31,
	2013			2012			2013 vs. 2012
	(In millions)
Net cash provided by (used in):
Operating activities	$	171.7		$	146.7		$	25.0		17	%
Investing activities		(208.1	)		(107.8	)		(100.3	)	93	%
Financing activities		70.5			(8.2	)		78.7		(960	%)

Cash Flow from Operating Activities

Our Consolidated Statement of Cash Flows included in our historical consolidated financial statements employs the traditional indirect method of presenting cash flows from operating activities. Under the indirect method, net cash provided by operating activities is derived by adjusting our net income for non-cash items related to operating activities. An alternative GAAP presentation employs the direct method in which the actual cash receipts and outlays comprising cash flow are presented.

The following table displays our operating cash flows using the direct method as a supplement to the presentation in our financial statements:

	Three Months Ended March 31,
	2013			2012			2013 vs. 2012
	(In millions)
Cash flows from operating activities:
Cash received from customers	$	1,474.7		$	1,763.4		$	(288.7	)
Cash received from (paid to) derivative counterparties		6.4			2.7			3.7
Cash outlays for:
Product purchases		(1,150.4	)		(1,475.6	)		325.2
Operating expenses		(88.4	)		(71.6	)		(16.8	)
General and administrative expenses		(38.8	)		(41.8	)		3.0
Cash distributions from equity investment		-			2.0			(2.0	)
Interest paid, net of amounts capitalized (1)		(31.4	)		(32.4	)		1.0
Income taxes paid		-			0.1			(0.1	)
Other cash receipts (payments)		(0.4	)		(0.1	)		(0.3	)
Net cash provided by operating activities	$	171.7		$	146.7		$	25.0

(1)	Net of capitalized interest paid of $6.1 million and $1.8 million included in investing activities for the three months ended March 31, 2013 and 2012.

Lower commodity liquid prices, partially offset by higher natural gas prices, were the primary factors in the changes in cash from customers, cash from derivative contracts, and cash paid for purchases. For the three months ended March 31, 2013 and 2012, our derivative settlements were a net cash inflow. Cash received related to derivative counterparties reflects lower aggregate commodity prices compared to the higher aggregate fixed prices we received on those derivative contracts.

Table of Contents

Cash Flow from Investing Activities

The increase in net cash used in investing activities was primarily due to an increase in current capital expansion projects of $103.7 million, increased maintenance capital expenditures of $5.2 million, and an increase in other of $5.4 million primarily related to materials and supply inventory purchases for Badlands, partially offset by a change in accruals of $8.1 million.

Cash Flow from Financing Activities

The increase in net cash provided by financing activities was primarily due to an increase in long-term debt net borrowings of $154.4 million, partially offset by a decrease in proceeds from the issuance of common units of $60.8 million and an increase in distributions to owners of $17.8 million.

Our primary financing activities that occurred during the three months ended March 31, 2013 were:

net proceeds from the sale of common units under the 2012 and 2013 EDAs of $105.3 million;

related general partner contributions to maintain 2% general partner ownership of $2.3 million; and

net proceeds from the Securitization Facility of $111.4 million.

Distributions to our Unitholders

We distribute all available cash from our operating surplus. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 8 and Note 9 of the “Consolidated Financial Statements” included in this Quarterly Report.

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). As of March 31, 2013, such annual minimum amount would have been approximately $141.6 million. In every quarter since the fourth quarter of 2007, we have paid quarterly distributions greater than the minimum quarterly distribution rate. The quarterly distribution per limited partner unit to be paid in May 2013 for the first quarter of 2013 is $0.6975 per limited partner unit.

The following table details the distributions declared and/or paid for the three months ended March 31, 2013 and December 31, 2012:

			Distributions
			Limited								Distributions
Three Months	Date Paid or to be		Partners		General Partner						per limited
Ended	Paid		Common		Incentive		2%		Total		partner unit
					(In millions, except per unit amounts)
March 31, 2013	May 15, 2013	$	71.7	$	22.1	$	1.9	$	95.7	$	0.6975
December 31, 2012	February 14, 2013		69.0		20.1		1.8		90.9		0.6800

Capital Requirements

Our capital requirements relate to capital expenditures which are classified as expansion expenditures, maintenance expenditures or business acquisitions. Expansion capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets. Maintenance capital expenditures are those expenditures that are necessary to maintain the gas supply and service capability of our existing assets including the replacement of system components and equipment which are worn, obsolete or completing its useful life, and expenditures to remain in compliance with environmental laws and regulations.

Table of Contents

	Three Months Ended March 31,
	2013				2012
Capital expenditures	(In millions)
Expansion (1)		$	185.2			$	81.5
Maintenance			21.7				16.5
Gross additions to property, plant and equipment			206.9				98.0
Change in capital project payables and accruals			(3.4	)			4.7

Cash outlays for capital projects		$	203.5			$	102.7

(1)

Excludes our investment in Gulf Coast Fractionators, which is accounted for as an equity investment. Cash calls for expansion are reflected in Investment in unconsolidated affiliate in cash flows from investing activities on our Consolidated Statements of Cash Flows in our Consolidated Financial Statements

We estimate that our total growth capital expenditures for 2013 will be approximately $1.0 billion on a gross basis, and maintenance capital expenditures net to our interest will be approximately $75 million. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that over time we will invest significant amounts of capital to grow and acquire assets. Future expansion capital expenditures may vary significantly based on investment opportunities. We expect to fund future capital expenditures with funds generated from our operations, borrowings under the TRP Revolver and proceeds from issuances of additional common units and debt offerings.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are set forth in Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report. During the three months ended March 31, 2013, we established our policies related to the amortization and useful lives of the intangible assets related to the Badlands acquisition.

Intangible assets arose from producer dedications under long-term contracts and customer relationships associated with business acquisitions. The fair value of these acquired intangible assets was determined at the date of acquisitions 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.

Table of Contents

Item 3.

Quantitative and Qualitative Disclosures About Market Risk.

For an in-depth discussion of market risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interest rates, as well as nonperformance by our customers. We do not use risk sensitive instruments for trading purposes.

Commodity Price Risk

A significant portion of our revenues 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 fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. 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.

The primary purpose of our commodity risk management activities is to manage the exposure to commodity price risk and reduce volatility in our operating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of March 31, 2013, we have hedged the commodity prices associated with a portion of our expected (i) natural gas equity volumes in Field Gathering and Processing Operations and (ii) NGL and condensate equity volumes predominately in Field Gathering and Processing Operations as well as in the LOU portion of the Coastal Gathering and Processing Operations, that results from percent of proceeds processing arrangements. We hedge a higher percentage of our expected equity volumes in the current year compared to future years, in which we hedge incrementally lower percentages of expected equity volumes. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay 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 our 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) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering into similar derivative transactions using swaps, collars, purchased puts (or floors) or other derivative instruments as market conditions permit.

We have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. Our NGL hedges cover specific NGL products based upon our expected equity NGL composition. We believe this strategy 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’ fair values are based on published index prices for delivery at various locations which closely approximate the actual natural gas and NGL delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.

These commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. Our principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges, 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. Absent federal regulations resulting from the Dodd-Frank Wall Street Reform and Consumer Protection Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the put transaction.

Table of Contents

For all periods presented we have entered into hedging arrangements for a portion of our forecasted equity volumes. During the three months ended March 31, 2013 and 2012, our operating revenues were increased by net hedge adjustments on commodity derivative contracts of $6.6 million, and $1.4 million.

As of March 31, 2013, we had the following derivative instruments, which will settle during the years ending below:

Natural Gas
Instrument		Price		MMBtu/d
Type	Index	$/MMBtu		2013		2014		2015			2016		Fair Value
													(in millions)
Swap	IF-WAHA		4.55		13,289		-		-			-		$	1.9
Swap	IF-WAHA		3.73		-		10,880		-			-			(1.6	)
Swap	IF-WAHA		3.95		-		-		5,236			-			(0.5	)
Swap	IF-WAHA		4.27		-		-		-			2,236			-
Total Swaps					13,289		10,880		5,236			2,236
Swap	IF-PB		4.60		11,681		-		-			-			1.9
Swap	IF-PB		3.68		-		8,966		-			-			(1.3	)
Swap	IF-PB		3.93		-		-		4,276			-			(0.4	)
Swap	IF-PB		4.25		-		-		-			1,808			-
Total Swaps					11,681		8,966		4,276			1,808
Swap	IF-NGPL MC		4.14		6,138		-		-			-			0.2
Swap	IF-NGPL MC		3.52		-		5,654		-			-			(1.1	)
Swap	IF-NGPL MC		3.76		-		-		2,489			-			(0.3	)
Swap	IF-NGPL MC		4.16		-		-		-			956			-
Total Swaps					6,138		5,654		2,489			956
Total					31,108		25,500		12,001			5,000
														$	(1.2	)

NGL
Instrument		Price		Gal/d
Type	Index	$/Gal			2013		2014	Fair Value
								(in millions)
Swap	OPIS-MB		1.05		5,650		-	$	9.1
Swap	OPIS-MB		1.21		-		1,000		3.7
Total					5,650		1,000
								$	12.8

Condensate
Instrument		Price		Bbl/d
Type	Index	$/Bbl			2013		2014	Fair Value
								(in millions)
Swap	NY-WTI		93.27		1,962		-	$	(1.9	)
Swap	NY-WTI		89.80		-		1,450		(1.5	)
Total					1,962		1,450
								$	(3.4	)

Table of Contents

These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls).

We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. We determine the value of our derivative contracts utilizing 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. For the contracts that have inputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those contracts which we are unable to obtain quoted prices for at least 90% of the full term of the commodity swap and options, the valuations are classified as Level 3 within the fair value hierarchy. See Note 11 to the “Consolidated Financial Statements” in this Quarterly Report for more information regarding classifications within the fair value hierarchy.

Interest Rate Risk

We are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRP Revolver and the Securitization Facility. As of March 31, 2013, we do not have any interest rate hedges. However, we may in the future enter into interest rate hedges intended to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRP Revolver and the Securitization Facility will also increase. As of March 31, 2013, we had $676.4 million in variable rate borrowings under the TRP Revolver and the Securitization Facility. A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact our annual interest expense by $6.8 million.

Counterparty Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Should the creditworthiness of one or more of the 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 March 31, 2013, affiliates of Wells Fargo Bank N.A. (“Wells Fargo”), Bank of America Merrill Lynch (“BAML”), Barclays PLC (“Barclays”), Natixis Securities Americas LLC (“Natixis”) and Credit Suisse Group AG (“Credit Suisse”) accounted for 34%, 18%, 15%, 11% and 10% of our counterparty credit exposure related to commodity derivative instruments. Wells Fargo, BAML, Barclays, Natixis and Credit Suisse 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.

We have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectible accounts resulted in a 1% reduction of our third-party accounts receivable, annual operating income would decrease by $4.4 million in the year of the assessment.

Table of Contents

Item 4.

Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this Quarterly Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2013, our disclosure controls and procedures were designed at the reasonable assurance level and, as of the end of the period covered by this Quarterly Report, our disclosure controls and procedures are effective at the reasonable assurance level to provide that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and (ii) accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow for timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the three months ended March 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1.

Legal Proceedings.

The information required for this item is provided in Note 12 – Commitments and Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.

Item 1A.

Risk Factors.

For an in-depth discussion of our risk factors, see “Item 1A. Risk Factors.” in our Annual Report. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

Not applicable.

Item 3.

Defaults Upon Senior Securities.

Not applicable.

Item 4.

Mine Safety Disclosures.

Not applicable.

Item 5.

Other Information.

Not applicable.

Table of Contents

Item 6.

Exhibits

Number		Description

3.1		Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).

3.2		Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).

3.3		Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).

3.4		First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8- K filed February 16, 2007 (File No. 001-33303)).

3.5		Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).

3.6		Amendment No. 2, dated May 25, 2012, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed May 25, 2012 (File No. 001-33303)).

3.7		Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).

10.1		Receivables Purchase Agreement, dated January 10, 2013, by and among Targa Receivables LLC, Targa Resources Partners LP, as initial Servicer, the various conduit purchasers from time to time party thereto, the various committed purchasers from time to time party thereto, the various purchaser agents from time to time party thereto, the various LC participants from time to time party thereto and PNC Bank, National Association as Administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 14, 2013 (File No. 001-33303)).

10.2		Purchase and Sale Agreement, dated January 10, 2013, between the originators from time to time party thereto as Originators and Targa Receivables LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 14, 2013 (File No. 001-33303)).

12.1*		Computation of Ratio of Earnings to Fixed Charges.

31.1*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1***		First Amendment to Membership Interest and Sale Agreement, dated December 20, 2012, by and among Targa Resources Partners LP, Saddle Butte Pipeline LLC, Saddle Butte Fort Berthold Gathering, LLC and Saddle Butte Assets, LLC (incorporated by reference to Exhibit 99.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 4, 2013 (File No. 001-33303)).

Table of Contents

101.INS**		XBRL Instance Document

101.SCH**		XBRL Taxonomy Extension Schema Document

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB**		XBRL Taxonomy Extension Label Linkbase Document

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

*		Filed herewith
**		Furnished herewith
***		Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted exhibit or Schedule to the SEC upon request

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Targa Resources Partners LP
	(Registrant)

	By:	Targa Resources GP LLC,
		its general partner

Date: May 3, 2013	By:	/s/ Matthew J. Meloy
		Matthew J. Meloy
		Senior Vice President, Chief Financial Officer and Treasurer
		(Authorized Officer and Principal Financial Officer)

ex12_1.htm

Exhibit 12.1

Targa Resources Partners, LP

Computation of Ratio of Earnings to Fixed Charges

	Years Ended December 31,															Three Months Ended March 31,
	2012			2011			2010			2009			2008			2013			2012

Pre-tax income (loss) from continuing operations	$	207.4		$	249.8		$	138.0		$	8.4		$	238.1		$	46.2		$	82.8

Fixed charges:

Interest expense and amortization of debt issuance costs		116.8			107.7			110.9			159.8			156.1			31.4			29.4
Capitalized interest		13.6			3.4			1.3			0.7			0.6			6.1			1.8
Operating lease payments		5.4			4.7			4.6			4.5			4.8			1.9			1.1
Total fixed charges		135.8			115.8			116.8			165.0			161.5			39.4			32.3
Amortization of capitalized interest		0.7			0.2			0.1			0.1			0.1			0.3			0.1
Equity earnings in unconsolidated investment		(1.9	)		(8.8	)		(5.4	)		(5.0	)		(14.0	)		(1.6	)		(2.1	)
Distributions from unconsolidated investment		2.3			8.3			8.7			5.1			4.6			-			2.3
Capitalized interest		(13.6	)		(3.4	)		(1.3	)		(0.7	)		(0.6	)		(6.1	)		(1.8	)
Pre-tax income from continuing operations plus fixed charges	$	330.6		$	361.9		$	256.9		$	172.9		$	389.7		$	78.1		$	113.6

Ratio of earnings to fixed charges		2.4			3.1			2.2			1.0			2.4			2.0			3.5
Deficiency	$	-		$	-		$	-		$	-		$	-		$	-		$	-

ex31_1.htm

Exhibit 31.1

CERTIFICATION

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Joe Bob Perkins, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 3, 2013

By: /s/ Joe Bob Perkins

Name: Joe Bob Perkins

Title: Chief Executive Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Executive Officer)

ex31_2.htm

Exhibit 31.2

CERTIFICATION

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Matthew J. Meloy, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “registrant”);

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 3, 2013

By: /s/ Matthew J. Meloy

Name: Matthew J. Meloy

Title: Senior Vice President, Chief Financial Officer and Treasurer

of Targa Resources GP LLC, the general partner of Targa Resources Partners LP

(Principal Financial Officer)

ex32_1.htm

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “Partnership”) for the three months ended March 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Joe Bob Perkins, as Chief Executive Officer of Targa Resources GP LLC, the general partner of the Partnership, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By: /s/ Joe Bob Perkins

Name: Joe Bob Perkins

Title: Chief Executive Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

Date: May 3, 2013

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

ex32_2.htm

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “Partnership”) for the three months ended March 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Matthew J. Meloy , as Chief Financial Officer of Targa Resources GP LLC, the general partner of the Partnership, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By: /s/ Matthew J. Meloy

Name: Matthew J. Meloy

Title: Senior Vice President, Chief Financial Officer and Treasurer

of Targa Resources GP LLC, the general partner of

Targa Resources Partners LP

Date: May 3, 2013