form8_k.htm

-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, O+iN5/NvuZPkJ3ySw0oQE7XP+oOc2eX9ufbvd0lkw7TXDjchjX8hDdkZrX++XCeh KQN4gpeofljtEk+kc3aW4A== 0001379661-10-000016.txt : 20100809 0001379661-10-000016.hdr.sgml : 20100809 20100809062319 ACCESSION NUMBER: 0001379661-10-000016 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20091231 ITEM INFORMATION: Other Events ITEM INFORMATION: Financial Statements and Exhibits FILED AS OF DATE: 20100809 DATE AS OF CHANGE: 20100809 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Targa Resources Partners LP CENTRAL INDEX KEY: 0001379661 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 651295427 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-33303 FILM NUMBER: 10999882 BUSINESS ADDRESS: STREET 1: 1000 LOUISIANA STREET 2: SUITE 4300 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: (713)584-1000 MAIL ADDRESS: STREET 1: 1000 LOUISIANA STREET 2: SUITE 4300 CITY: HOUSTON STATE: TX ZIP: 77002 8-K 1 form8_k.htm 1209 TRP LP SUPPLEMENTAL FS form8_k.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported)

August 9, 2010

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	001-33303	65-1295427
(State or other jurisdiction	(Commission	(IRS Employer
of incorporation or organization)	File Number)	Identification No.)

1000 Louisiana, Suite 4300
Houston, TX 77002
(Address of principal executive office and Zip Code)

(713) 584-1000
(Registrants’ telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01 Other Information.

On April 27, 2010, Targa Resources Partners LP (the “Partnership”) closed on its previously announced acquisition of (i) 100% of the limited partner interests in Targa Midstream Services Limited Partnership (“TMS”), (ii) 100% of the limited liability company interests in Targa Gas Marketing LLC (“TGM”), (iii) 100% of the limited and general partner interests in Targa Permian LP (“Permian”), (iv) 100% of the limited partner interests in Targa Straddle LP (“Targa Straddle”) and (v) 100% of the limited liability company interests in Targa Straddle GP LLC (“Targa Straddle GP”) for aggregate consideration of $420 million, subject to certain adjustments.

TMS, TGM, Permian, Targa Straddle and Targa Straddle GP collectively owned at closing (i) Targa Resources, Inc.’s (“Targa”) natural gas straddle business consisting of the business and operations involving the Barracuda, Lowry and Stingray plants, including the Pelican, Seahawk and Cameron gas gathering pipeline systems, all of which are wholly-owned by TMS or its subsidiaries, and the business and operations represented by its participation and ownership interests in the Bluewater, Sea Robin, Calumet, N. Terrebonne, Toca and Yscloskey plants, (ii) certain of Targa’s natural gas gathering and processing systems, processing plants and related assets including the Sand Hills processing plant and gathering system, Monahans gathering system, Puckett gathering system, a 40% ownership interest in the Wes t Seminole gathering system and a compressor overhaul facility and (iii) Targa’s natural gas marketing business (collectively, the “Business”).

The Partnership and the Business are considered entities under common control. As a result, the Partnership is providing supplemental consolidated financial statements to include the financial results of the Business for all periods presented. We are providing the following to reflect the supplemental results: Selected Financial Data, Management’s Discussion and Analysis of Supplemental Financial Condition and Results of Operations, and Supplemental Consolidated Financial Statements of Targa Resources Partners LP for the periods indicated.

In connection with the acquisition of Targa's interest in the Permian and Straddle Systems and its impact on our structure used for internal management purposes, an updated evaluation of our reportable segments was performed during the second quarter of 2010. As a result, our operations are now presented under four reportable segments: (1) Field Gathering and Processing, (2) Coastal Gathering and Processing, (3) Logistics Assets and (4) Marketing and Distribution. Prior period information in this report has been revised to conform to the 2010 reported segment presentation. See Notes 2 and 20 of Exhibit 99.3 for further information on the changes of our reportable segments.

Item 9.01 Financial Statements and Exhibits.

(a)

Not applicable

(b)

Not applicable

(c)

Not applicable

(d) Exhibits

Exhibit Number		Description

23.1 99.1		Consent of PricewaterhouseCoopers on Supplemental Consolidated Financial Statements of Targa Resources Partners LP Selected Financial Data

99.2 99.3		Management’s Discussion and Analysis of Supplemental Financial Condition and Results of Operations Supplemental Consolidated Financial Statements of Targa Resources Partners LP

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

	By: Targa Resources GP LLC,
	its general partner

Dated: August 9, 2010	By:	/s/ John Robert Sparger
		John Robert Sparger
		Senior Vice President and Chief Accounting Officer

EXHIBIT INDEX

Exhibit Number		Description

23.1 99.1		Consent of PricewaterhouseCoopers on Supplemental Consolidated Financial Statements of Targa Resources Partners LP Selected Financial Data

99.2 99.3		Management’s Discussion and Analysis of Supplemental Financial Condition and Results of Operations Supplemental Consolidated Financial Statements of Targa Resources Partners LP

EX-23.1 2 ex23_1.htm CONSENT OF PRICEWATERHOUSECOOPERS ex23_1.htm

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-149200) and Form S-3 (No. 333-165959) of Targa Resources Partners LP of our report dated March 3, 2010, except with respect to our opinions on the consolidated financial statements and internal control over financial reporting insofar as they relate to the effects of the acquisition of the Permian and Straddle Systems discussed in Note 2 and change in segment reporting discussed in Note 20, as to which the date is August 9, 2010, relating to the financial statements of Targa Resources Partners LP, and the effectiveness of internal control over financial reporting, which appears in this Current Report on Form 8-K.

/s/PricewaterhouseCoopers LLP

Houston, Texas

August 9, 2010

EX-99.1 3 ex99_1.htm SELECTED FINANCIAL DATA ex99_1.htm

Exhibit 99.1

SELECTED FINANCIAL DATA

The following table presents selected historical consolidated financial and operating data of Targa Resources Partners LP. See “Basis of Presentation” included under Note 2 to our “Supplemental Consolidated Financial Statements” contained in Exhibit 99.3 of this Form 8-K for information regarding the retrospective adjustment of our financial information for the years 2005 through 2009 as entities under common control in connection with our acquisition of the Permian and Straddle Systems from Targa Resources, Inc. We derived the summary selected historical financial data as of December 31, 2009 and 2008 and for the years ended December 31, 2009, 2008 and 2007 from our audited consolidated financial statements. The unaudited historical financial data as of December 31, 2007, 2006 and 2005 and for the yea rs ended December 31, 2006 and 2005 has been derived from our accounting records and prepared in accordance with generally accepted accounting principles in the United States and on a basis consistent with our subsequent audited consolidated financial statements. The information contained herein should be read in conjunction with our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (Exhibit 99.2) and “Supplemental Consolidated Financial Statements” (Exhibit 99.3) contained in this Form 8-K.

	Targa Resources Partners LP (1)
	Year Ended December 31,
	2009			2008			2007			2006			2005 (2)
	(In millions, except operating and price data)
Statement of operations data:
Revenues (3) (4)	$	4,391.2		$	7,837.9		$	7,103.6		$	5,952.4		$	1,848.3
Product purchases (4)		3,809.6			7,197.7			6,471.5			5,382.4			1,684.9
Gross margin (5)		581.6			640.2			632.1			570.0			163.4
Operating expenses		191.1			227.0			209.0			229.8			50.1
Operating margin (6)		390.5			413.2			423.1			340.2			113.3
Depreciation and amortization expenses		125.1			119.5			114.3			109.2			28.9
General and administrative expenses		100.6			85.4			89.8			86.8			25.5
Other		(0.7	)		5.4			(0.1	)		(0.1	)		-
Income from operations		165.5			202.9			219.1			144.3			58.9
Other income (expense):
Interest expense from affiliate		(66.6	)		(82.4	)		(81.7	)		-			-
Interest expense allocated from Parent		-			-			(19.4	)		(150.5	)		(29.8	)
Other interest income (expense), net		(52.0	)		(37.9	)		(21.5	)		(5.1	)		-
Equity in earnings of unconsolidated investment		5.0			3.9			3.5			2.8			0.4
Gain (loss) on debt repurchases		(1.5	)		13.1			-			-			(3.7	)
Gain (loss) on mark-to-market derivative instruments		(15.2	)		30.6			(61.9	)		25.3			(24.2	)
Other		0.7			12.9			(0.8	)		0.9			(0.1	)
Income before income taxes		35.9			143.1			37.3			17.7			1.5
Income tax expense		(1.2	)		(2.9	)		(2.9	)		(3.7	)		-
Net income		34.7			140.2			34.4			14.0			1.5
Less: Net income (loss) attributable to noncontrolling interest		2.2			0.3			0.1			(0.6	)		0.2
Net income attributable to Targa Resources Partners LP	$	32.5		$	139.9		$	34.3		$	14.6		$	1.3

Net income (loss) attributable to predecessor operations	$	(21.9	)	$	48.4		$	6.2
Net income attributable to general partner		10.4			7.0			0.6
Net income attributable to limited partners		44.0			84.5			27.5
Net income attributable to Targa Resources Partners LP	$	32.5		$	139.9		$	34.3

Net income per limited partner unit--basic and diluted	$	0.86		$	1.83		$	0.81
Weighted average limited partner units
outstanding--basic and diluted		51.2			46.2			34.0
Financial data:
Adjusted EBITDA (7)		335.6			357.7			328.0			255.6			84.0
Distributable cash flow (8)		187.7			177.9			157.7			26.5			54.6
Operating data:
Plant natural gas inlet, MMcf/d (9) (10)		1,578.0			1,506.7			1,917.7			1,748.1			1,070.8
Gross NGL production, MBbl/d		73.3			74.5			83.6			80.7			50.2
Natural gas sales, Bbtu/d (10)		580.6			517.7			502.0			731.9			299.9
NGL sales, MBbl/d		273.5			280.5			313.9			323.0			79.0
Condensate sales, MBbl/d		3.7			3.1			3.2			4.2			1.9
Average realized prices: (11)
Natural gas, $/MMBtu		3.85			8.19			6.48			6.39			8.27
NGL, $/gal		0.79			1.39			1.18			1.02			0.78
Condensate, $/Bbl		56.38			90.30			71.37			58.02			47.65

	Targa Resources Partners LP (1)
	Year Ended December 31,
	2009			2008			2007			2006			2005 (2)
	(In millions, except per unit data)
Balance sheet data (at year end):
Property, plant and equipment, net	$	1,983.6		$	2,022.2		$	2,031.7		$	2,050.2		$	2,109.9
Total assets		2,550.7			2,688.0			3,122.3			2,870.7			2,915.8
Long-term allocated debt, less current maturities		327.0			1,077.7			991.9			1,286.3			1,766.1
Long-term debt, less current maturities		908.4			696.8			626.3			-			-
Total equity		784.7			549.5			614.1			530.8			620.5
Cash flow data:
Net cash provided by (used in):
Operating activities	$	353.9		$	399.2		$	384.4		$	195.2		$	50.3
Investing activities		(82.9	)		(98.5	)		(95.6	)		(115.9	)		(10.6	)
Financing activities		(305.9	)		(269.7	)		(237.0	)		(74.7	)		(37.9	)
Cash dividends declared per unit		2.07			1.97			1.24			N/A			N/A

__________

(1)

The financial statements and financial information included in our Annual Report on Form 10-K for the year ended December 31, 2009 have been updated to reflect our acquisition of the Permian and Straddle Systems, a transfer of assets under common control.

(2)

Includes the results of the Permian and Straddle Systems for the period from October 31, 2005 (the date at which the assets were acquired by Targa) through December 31, 2005.

(3)

Includes business interruption insurance revenues of $12.2 million, $32.3 million, $7.3 million and $7.0 million for 2009, 2008, 2007 and 2006.

(4)

During 2009, we reclassified NGL marketing fractionation and other service fees to revenues that were originally recorded in product purchase costs. The reclassification increased revenues and product purchases for 2008, 2007, 2006 and 2005 by $28.7 million, $27.6 million, $20.3 million and $3.9 million.

(5)

Gross margin is revenues less product purchases. See “Non-GAAP Financial Measures.”

(6)

Operating margin is gross margin less operating expenses. See “Non-GAAP Financial Measures.”

(7)

Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash gain or loss related to derivative instruments. See “Non-GAAP Financial Measures.”

(8)

Distributable cash flow is net income plus depreciation and amortization and deferred taxes, adjusted for losses on mark-to-market derivative contracts, less maintenance capital expenditures. See “Non-GAAP Financial Measures.”

(9)

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

(10)

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

(11)

Average realized prices include the impact of hedging activities.

Non-GAAP Financial Measures

Gross Margin. With respect to our Natural Gas Gathering and Processing segments, we define gross margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. With respect to our Logistics Assets segment we define gross margin as total revenues, which consists primarily of service fee revenues. With respect to our Marketing and Distribution segment, we define gross margin as total revenues, which consists primarily of service fee revenues and NGL sales, less cost of sales, which consists primarily of NGL purchases and changes in inventory valuation.

Operating Margin. With respect to our Natural Gas Gathering and Processing segments, our Logistics Assets segment and our Marketing and Distribution segment, we define operating margin as gross margin less operating expense.

The GAAP measure most directly comparable to gross margin and operating margin is net income. The non-GAAP financial measures of gross margin and operating margin should not be considered as an alternative to GAAP net income. Gross margin and operating margin are not presentations made in accordance with GAAP and have important limitations as analytical tools. You 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, 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 lim itations 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. Management reviews gross margin and operating margin monthly for consistency and trend analysis. Based on this monthly analysis, management takes appropriate action to maintain positive trends or to reverse negative trends. Management uses gross margin and operating margin as important performance measures of the core profitability of our operations.

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

	Year Ended December 31,
	2009			2008			2007			2006			2005
	(In millions)
Reconciliation of gross margin and operating
margin to net income (loss):
Gross margin	$	581.6		$	640.2		$	632.1		$	570.0		$	163.4
Operating expenses		(191.1	)		(227.0	)		(209.0	)		(229.8	)		(50.1	)
Operating margin		390.5			413.2			423.1			340.2			113.3
Depreciation and amortization expenses		(125.1	)		(119.5	)		(114.3	)		(109.2	)		(28.9	)
General and administrative and other operating expenses		(99.9	)		(90.8	)		(89.7	)		(86.7	)		(25.5	)
Interest expense, net		(118.6	)		(120.3	)		(122.6	)		(155.6	)		(29.8	)
Income tax expense		(1.2	)		(2.9	)		(2.9	)		(3.7	)		-
Gain (loss) on debt repurchases		(1.5	)		13.1			-			-			(3.7	)
Gain (loss) related to mark-to-market derivative instruments		(15.2	)		30.6			(61.9	)		25.3			(24.2	)
Other, net		5.7			16.8			2.7			3.7			0.3
Net income	$	34.7		$	140.2		$	34.4		$	14.0		$	1.5

Adjusted EBITDA. We define Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization and non-cash gain or loss related to derivative instruments. 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, 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.

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.

The generally accepted accounting principles (“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 and GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You 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 comp anies.

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.

	Targa Resources Partners LP
	Year Ended December 31,
	2009			2008			2007			2006			2005
Reconciliation of net cash provided by	(In millions)
operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	353.9		$	399.2		$	384.4		$	195.2		$	50.3
Net income attributable to noncontrolling interest		(2.2	)		(0.3	)		(0.1	)		0.6			(0.2	)
Interest expense, net (1)		44.8			33.7			38.2			146.5			24.6
Gain (loss) on debt repurchases		(1.5	)		13.1			-			-			(3.7	)
Termination of commodity derivatives		-			87.4			-			-			-
Current income tax expense		0.3			0.8			0.8			-			-
Other		(2.4	)		2.8			(2.0	)		(1.0	)		(4.4	)
Changes in operating assets and liabilities which
used (provided) cash:
Accounts receivable and other assets		67.1			(766.5	)		101.5			(3.5	)		32.0
Accounts payable and other liabilities		(124.4	)		587.5			(194.8	)		(82.2	)		(14.6	)
Adjusted EBITDA	$	335.6		$	357.7		$	328.0		$	255.6		$	84.0

__________

(1)

Net of amortization of debt issuance costs of $3.8 million, $2.1 million, $1.8 million, $9.1 million and $5.2 million for 2009, 2008, 2007, 2006 and 2005 and net of amortization of interest rate swap premiums of $3.4 million, $2.1 million and $0.9 million for 2009, 2008 and 2007.

	Year Ended December 31,
Reconciliation of net income (loss) attributable to Targa	2009			2008			2007			2006			2005
Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP	$	32.5		$	139.9		$	34.3		$	14.6		$	1.3
Add:
Interest expense, net		118.6			120.3			122.6			155.6			29.8
Income tax expense		1.2			2.9			2.9			3.7			-
Depreciation and amortization expenses		125.1			119.5			114.3			109.2			28.9
Non-cash (gain) loss related to derivatives		59.1			(24.0	)		54.7			(26.8	)		24.2
Noncontrolling interest adjustment		(0.9	)		(0.9	)		(0.8	)		(0.7	)		(0.2	)
Adjusted EBITDA	$	335.6		$	357.7		$	328.0		$	255.6		$	84.0

less maintenance capital expenditures. Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others 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 can quickly compute the coverage ratio of estimated cash flows to planned 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 leve l 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).

The economic substance behind our use of distributable cash flow is to measure the ability of our assets to generate cash flow sufficient to make distributions to our investors.

The GAAP measure most directly comparable to distributable cash flow is net income. Distributable cash flow should not be considered as an alternative to GAAP net income. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You 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 compatible to similarly titled measures of other companies, thereby diminishing its utility.

We compensate for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision making processes.

	Year Ended December 31,
	2009			2008			2007			2006			2005
Reconciliation of net income attributable to Targa	(In millions)
Resources Partners LP distributable cash flow:
Net income attributable to Targa Resources Partners LP	$	32.5		$	139.9		$	34.3		$	14.6		$	1.3
Depreciation and amortization expenses		125.1			119.5			114.3			109.2			28.9
Deferred income tax expense		0.9			2.1			2.1			3.7			-
Amortization in interest expense		3.8			2.1			1.8			9.1			5.2
Loss (gain) on debt repurchases		1.5			(13.1	)		-			-			3.7
Non-cash (gain) loss related to mark-to-market derivative instruments		59.1			(24.0	)		54.7			(26.8	)		24.2
Maintenance capital expenditures		(34.6	)		(48.0	)		(49.0	)		(82.8	)		(8.7	)
Other (1)		(0.6	)		(0.6	)		(0.5	)		(0.5	)		-
Distributable cash flow	$	187.7		$	177.9		$	157.7		$	26.5		$	54.6

__________

(1)

Other includes the non-controlling interest percentage of our unconsolidated investment’s depreciation, interest expense and maintenance capital expenditures.

EX-99.2 4 ex99_2.htm MANAGEMENT'S DISCUSSION AND ANALYSIS OF SUPPLEMENTAL FINANCIAL CONDITION AND RESULTS OF OPERATIONS ex99_2.htm

Exhibit 99.2

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

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our supplemental financial statements and notes included in Exhibit 99.3.

Overview

Targa Resources Partners LP, is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”). Our common units are listed on the New York Stock Exchange under the symbol “NGLS.” In this 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. References to “TRP LP” are intended to mean and include Targa Resources Partners LP, individually, and not on a consolidated basis.

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.

We acquired from Targa its ownership interests in the following assets, liabilities and operations on the dates indicated:

February 14, 2007 – North Texas System;

October 24, 2007 – San Angelo (“SAOU”) System and Louisiana (“LOU”) System;

September 24, 2009 – Downstream Business; and

April 27, 2010 – Permian and Straddle Systems.

For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these acquisitions collectively as our “predecessors.”

Our Operations

Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”).

Concurrent with the acquisition of the Permian and Straddle Systems, we reassessed our disclosures of segment information. We now report our operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) NGL Logistics and Marketing consisting of two segments – (a) Logistics Assets and (b) Marketing and Distribution. Other includes the impact on operating income of our derivatives hedging activities. See Note 20.

Prior to the second quarter of 2010, we reported our results under four segments: (1) Natural Gas Gathering and Processing, (2) Logistics Assets, (3) NGL Distribution and Marketing and (4) Wholesale Marketing. The increased amount of Coastal Gathering and Processing assets owned by us as a result of our acquisition of the Permian and Straddle Systems, and consideration of underlying operational and economic differences between Field and Coastal gathering and processing systems led to more granular analysis of the Natural Gas Gathering and Processing results. Also, we have aggregated the previously separately reported NGL Distribution and Marketing segment and Wholesale Marketing segment into one reportable segment, Marketing and Distribution. This combined marketing segment reflects significant operational int errelationships among the Marketing and Distribution activities apparent in our current business model.

liquids and removing impurities. The Field Gathering and Processing segment’s assets are located in North Texas and the Permian Basin and the Coastal Gathering and Processing segment’s assets are located in the onshore region of the Louisiana Gulf Coast and the Gulf of Mexico.

The NGL Logistics and Marketing division is also referred to as our Downstream Business. It includes all the activities necessary to convert raw natural gas liquids into NGL products, market the finished products and provide certain value added services.

The Logistics Assets segment is involved in transporting and storing mixed NGLs and fractionating, storing, and transporting finished NGLs. 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 Western Louisiana.

The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes (1) marketing our own natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; and (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users.

Recent Events

On January 19, 2010, we completed a public offering of 5,500,000 common units representing limited partner interests in the Partnership (“common units”) under our existing shelf registration statement on Form S-3 at a price of $23.14 per common unit ($22.17 per common unit, net of underwriting discounts), providing net proceeds of $121.9 million. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 825,000 common units at $23.14 per common unit, providing net proceeds of $18.3 million. We used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under our senior secured credit facility.

On April 27, 2010, we completed the acquisition of the Permian and Straddle Systems from Targa for $420 million. See “Basis of Presentation” included under Note 2 of the “Notes to Supplemental Consolidated Financial Statements” in Exhibit 99.3 for information regarding retrospective adjustment of our financial information for the years 2007 through 2009 as entities under common control in connection with our acquisition of the Permian and Straddle Systems.

Factors That Significantly Affect Our Results

Our results of operations are substantially impacted by changes in commodity prices as well as increases and decreases in the volume of natural gas that we gather through our pipeline systems. These throughput volumes generally are driven by wellhead production, our competitive position on a regional basis and more broadly by prices and demand for natural gas and NGLs (which may be impacted by economic, political and regulatory development factors beyond our control).

Contract Mix. Our natural gas gathering and processing contract arrangements can have a significant impact on our profitability. Because of the significant volatility of natural gas and NGL prices, the contract mix of our natural gas gathering and processing segment can have a significant impact on our profitability. Negotiated contract terms are based upon a variety of factors, including natural gas quality, geographic location, the competitive environment at the time the contract is executed and customer preferences. Contract mix and, accordingly, exposure to natural gas and NGL prices may change over time as a result of changes in these underlying factors.

Set forth below is a table summarizing the contract mix of our natural gas gathering and processing division for 2009 and the potential impacts of commodity prices on operating margins:

Contract Type	Percent of Throughput		Impact of Commodity Prices
Percent-of-Proceeds		47%	Decreases in natural gas and/or NGL prices generate decreases in operating margin.
Wellhead Purchases/Keep Whole		13%	Increases in natural gas prices relative to NGL prices generate decreases in operating margin. Decreases in NGL prices relative to natural gas prices generate decreases in operating margin.
Hybrid		25%	In periods of favorable processing economics, similar to percent-of-liquids (or wellhead purchases/keep-whole in some circumstances, if economically advantageous to the processor). In periods of unfavorable processing economics, similar to fee-based.

Fee-Based		15%	No direct impact from commodity price movements.

Actual contract terms are based upon a variety of factors, including natural gas quality, geographic location, the competitive commodity and pricing environment at the time the contract is executed, and customer requirements. Our gathering and processing contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of producer preferences, competition, and changes in production as wells decline at different rates or are added, our expansion into regions where different types of contracts are more common as well as other market factors. We prefer to enter into contracts with less commodity price sensitivity including fee-based and percent-of-proceeds arrangements.

We attempt to mitigate the impact of commodity prices on our results of operations through hedging activities which can materially impact our results of operations. See “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.”

Impact of Our Hedging Activities. In an effort to reduce the variability of our cash flows we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2010 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. For additional information regarding our hedging activities, see “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.”

General and Administrative Expenses. Our Omnibus Agreement with Targa, our general partner and others addresses the reimbursement of costs incurred on our behalf and indemnification matters. Under the Omnibus Agreement (as amended), which runs through April 2013, Targa will provide general and administrative and other services to us associated with (1) our existing assets and any future Targa conveyances and (2) subject to mutual agreement, our future acquisitions from third parties.

The employees supporting our operations are employees of Targa. We reimburse Targa for the payment of certain operating expenses, including compensation and benefits of operating personnel assigned to our assets, and for the provision of various general and administrative services for our benefit. Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.

With respect to the North Texas System, Targa capped the North Texas Systems’ general and administrative expenses at $5.0 million annually through February 14, 2010. There is not a cap of expenses related to any of the other Targa conveyances. However, Targa will provide distribution support to us in the form of a reduced general and administrative expense billings, up to $8.0 million per quarter, if necessary, for a 1.0 times distribution coverage

ratio. The distribution support is in effect for the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011. No distribution support was required for the fourth quarter of 2009.

Allocated general and administrative expenses, including expenses allocated to the Downstream Business and the Permian and Straddle Business, of $84.1 million, $76.3 million and $86.2 million for 2009, 2008 and 2007 were subject to the cap contained in the Omnibus Agreement.

In addition to these allocated general and administrative expenses, we incur incremental general and administrative expenses as a result of operating as a separate publicly held limited partnership. These direct, incremental general and administrative expenses, which were approximately $16.5 million, $9.2 million and $3.6 million during 2009, 2008 and 2007, including expenses associated with our equity offerings, financing arrangements and acquisitions. These direct and incremental costs also include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, registrar and transfer agent fees and independent director compensation.

The historical financial statements of the SAOU and LOU Systems, the North Texas System, the Downstream Business and the Permian and Straddle Business include certain items that will not impact our future results of operations and liquidity including the items described below:

					Permian and
	North Texas		Downstream		Straddle
	System		Business		Systems
Original principal December 1, 2005	$	816.2	$	568.7	$	232.2
Interest accrued during 2005 and 2006		88.3		61.8		25.1
Borrowings during 2006		-		9.2		-
Parent debt contributed January 1, 2007		904.5		639.7		257.3
Additional borrowings:
For the year ended December 31, 2007		-		13.0		-
For the year ended December 31, 2008		-		3.4		-
Interest accrued prior to Targa conveyance:
For the year ended December 31, 2007 (2)		9.8		58.5		23.2
For the year ended December 31, 2008		-		59.3		23.2
For the year ended December 31, 2009		-		43.4		23.3
		9.8		161.2		69.7
Outstanding affiliate debt at conveyance date
or December 31, 2009 (1)		914.3		817.3		327.0

Payment (cash and units) (1)		665.7		530.0		-

Affiliate debt contributed at conveyance date	$	248.6	$	287.3	$	-

__________

(1)

The Permian and Straddle Systems were not conveyed to the Partnership until April 2010, at which time the entire affiliate debt balance of $332.8 million was paid as part of the transaction.

(2)

In 2007 Targa also allocated $9.6 million of interest related to the conveyance of the SAOU and LOU Systems.

Working Capital Adjustments. Prior to the contribution of the North Texas System in February 2007, and the acquisition of the SAOU and LOU Systems in October 2007, all intercompany transactions, including commodity sales and expense reimbursements, were not cash settled with the Targa, but were recorded as an adjustment to parent equity on the balance sheet. The primary intercompany transactions between the respective parent and the Predecessor Business are natural gas and NGL sales, the provision of operations and maintenance activities and the provision of general and administrative services. Prior to acquisition of the Downstream Business in September 2009, all intercompany balances related to the Downstream Business were settled with the parent as part of the

customary settlement process. Accordingly, the working capital of the Predecessor Business does not reflect any affiliate accounts payable for the personnel and services provided or paid for by the applicable parent on behalf of the Predecessor Business.

Distributions to our Unitholders

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). Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures, as well as our working capital needs.

The following table shows the distributions we paid in 2009, 2008 and 2007:

		Distributions Paid (1)										Distributions
	For the Three	Limited Partners				General Partner						per limited
Date Paid	Months Ended	Common		Subordinated (2)		Incentive			2%	Total		partner unit
		(In millions, except per unit amounts)
2009
November 14, 2009	September 30, 2009	$	31.9	$	-	$	2.6	$	0.7	$	35.2	$	0.5175
August 14, 2009	June 30, 2009		23.9		-		2.0		0.5		26.4		0.5175
May 15, 2009	March 31, 2009		18.0		5.9		1.9		0.5		26.3		0.5175
February 13, 2009	December 31, 2008		18.0		6.0		1.9		0.5		26.4		0.5175

2008
November 14, 2008	September 30, 2008	$	17.9	$	6.0	$	1.9	$	0.5	$	26.3	$	0.5175
August 14, 2008	June 30, 2008		17.8		5.9		1.7		0.5		25.9		0.5125
May 15, 2008	March 31, 2008		14.5		4.8		0.2		0.4		19.9		0.4175
February 14, 2008	December 31, 2007		13.8		4.6		0.1		0.4		18.9		0.3975

2007
November 14, 2007	September 30, 2007	$	11.1	$	3.9	$	-	$	0.3	$	15.3	$	0.3375
August 14, 2007	June 30, 2007		6.5		3.9		-		0.2		10.6		0.3375
May 15, 2007	March 31, 2007		3.3		1.9		-		0.1		5.3		0.1688

__________

(1)

On February 12, 2010, we paid a cash distribution of $0.5175 per unit on our outstanding common units. The total distribution paid was $38.8 million, with $24.8 million paid to our non-affiliated common unitholders and $10.4 million, $0.8 million and $2.8 million paid to Targa for its common unit ownership, general partner interest and incentive distribution rights.

(2)

Under the terms of our amended and restated Partnership Agreement, all 11,528,231 subordinated units converted to common units on a one-to-one basis on May 19, 2009.

General Trends and Outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural Gas Supply and Outlook. Fluctuations in energy prices can affect production rates and investments by third parties in the development of new natural gas reserves. Generally, drilling and production activity will increase as energy prices increase. The recent substantial decline in natural gas prices has led many exploration and production companies to reduce planned capital expenditures for drilling and production activities during 2010 which could lead to a decrease in the level of natural gas production in our areas of operation.

Significant Relationships. The following table lists the percentage of our consolidated sales and consolidated product purchases with our significant customers and suppliers:

	Year Ended December 31,
	2009		2008		2007
% of consolidated revenues
Chevron Phillips Chemical Company LLC		16%		20%		21%
% of product purchases
Louis Dreyfus Energy Services L.P.		11%		9%		7%

No other third party customer accounted for more than 10% of our consolidated revenues or consolidated product purchases during these periods.

Commodity Prices. Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices, primarily as a result of our percent-of-proceeds contracts. Our processing profitability is largely dependent upon pricing and market demand for natural gas, NGLs and condensate, which are beyond our control and have been volatile. Recent weak economic conditions have negatively affected the pricing and market demand for natural gas, NGLs and condensate, which caused a reduction in profitability of our processing operations. In a declining commodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to average price declines. We have attempted to mitigat e our exposure to commodity price movements by entering into hedging arrangements. For additional information regarding our hedging activities, see “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.”

Volatile Capital Markets. We are dependent on our ability to access the equity and debt capital markets in order to fund acquisitions and expansion expenditures. Global financial markets have been, and are expected to continue to be, extremely volatile and disrupted and the current weak economic conditions have recently caused a significant decline in commodity prices. As a result, we may be unable to raise equity or debt capital on satisfactory terms, or at all, which may negatively impact the timing and extent to which we execute growth plans. Prolonged periods of low commodity prices or volatile capital markets may impact our ability or willingness to enter into new hedges, fund organic growth, connect to new supplies of natural gas, execute acquisitions or implement expansion capital expenditures.

How We Evaluate Our Operations

Our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the natural gas, NGLs and condensate we sell, and the costs associated with conducting our operations, including the costs of wellhead natural gas and Y-grade that we purchase as well as operating and general and administrative costs. 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 natural gas and NGLs, and the natural gas and NGL throughput on our system are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, deman d for our products and changes in our customer mix.

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include gross margin, operating margin, operating expenses, plant inlet, gross NGL production, adjusted EBITDA and distributable cash flow, among others.

Throughput Volumes, Facility Efficiencies and Fuel Consumption. Our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our systems. This is achieved by connecting new wells, adding new volumes in existing areas of production as well as by capturing supplies currently gathered by third parties.

In addition, we seek to increase operating margins by limiting volume losses and reducing fuel consumption by increasing compression efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes of natural gas 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. This information is tracked through our processing plants to determine customer settlements 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 plants to monitor the fuel consumption and recoveries of the facilities. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis.

	Year Ended December 31,
	2009			2008			2007
	(In millions)
Reconciliation of gross margin and operating
margin to net income (loss):
Gross margin	$	581.6		$	640.2		$	632.1
Operating expenses		(191.1	)		(227.0	)		(209.0	)
Operating margin		390.5			413.2			423.1
Depreciation and amortization expenses		(125.1	)		(119.5	)		(114.3	)
General and administrative and other operating expenses		(99.9	)		(90.8	)		(89.7	)
Interest expense, net		(118.6	)		(120.3	)		(122.6	)
Income tax expense		(1.2	)		(2.9	)		(2.9	)
Gain (loss) on debt repurchases		(1.5	)		13.1			-
Gain (loss) related to mark-to-market derivative instruments		(15.2	)		30.6			(61.9	)
Other, net		5.7			16.8			2.7
Net income	$	34.7		$	140.2		$	34.4

Operating Expenses. Operating expenses are costs associated with the operation of a specific asset. Direct labor, ad valorem taxes, repair and maintenance, utilities and contract services compose the most significant portion of our operating expenses. These expenses generally remain relatively stable independent of the volumes through our systems but fluctuate depending on the scope of the activities performed during a specific period.

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.

	Year Ended December 31,
	2009			2008			2007
Reconciliation of net cash provided by	(In millions)
operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	353.9		$	399.2		$	384.4
Net income attributable to noncontrolling interest		(2.2	)		(0.3	)		(0.1	)
Interest expense, net (1)		44.8			33.7			38.2
Gain (loss) on debt repurchases		(1.5	)		13.1			-
Termination of commodity derivatives		-			87.4			-
Current income tax expense		0.3			0.8			0.8
Other		(2.4	)		2.8			(2.0	)
Changes in operating assets and liabilities which
used (provided) cash:
Accounts receivable and other assets		67.1			(766.5	)		101.5
Accounts payable and other liabilities		(124.4	)		587.5			(194.8	)
Adjusted EBITDA	$	335.6		$	357.7		$	328.0

__________

(1)

Net of amortization of debt issuance costs of $3.8 million, $2.1 million and $1.8 million and amortization of interest rate swap premiums of $3.4 million, $2.1 million and $0.9 million for 2009, 2008 and 2007.

	Year Ended December 31,
	2009			2008			2007
Reconciliation of net income attributable to Targa	(In millions)
Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP	$	32.5		$	139.9		$	34.3
Add:
Interest expense, net (1)		118.6			120.3			122.6
Income tax expense		1.2			2.9			2.9
Depreciation and amortization expense		125.1			119.5			114.3
Non-cash (gain) loss related to derivatives		59.1			(24.0	)		54.7
Noncontrolling interest adjustment		(0.9	)		(0.9	)		(0.8	)
Adjusted EBITDA	$	335.6		$	357.7		$	328.0

__________

(1)

Includes affiliate interest expense of $66.6 million, $82.4 million and $81.7 million for 2009, 2008 and 2007 and allocated interest expense of $19.4 million for 2007.

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) related to mark-to-market derivative instruments and debt repurchases, less maintenance capital expenditures (net of any reimbursements of project costs). The impact of noncontrolling interests is included in our measure. Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others 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 can quickly compute the coverage ratio of estimated cash flows to planned 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).

The economic substance behind our use of distributable cash flow is to measure the ability of our assets to generate cash flow sufficient to make distributions to our investors.

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. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You 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 compatible to similarly titled measures of other companies, thereby diminishing its utility.

	Year Ended December 31,
	2009			2008			2007
Reconciliation of net income attributable to Targa	(In millions)
Resources Partners LP distributable cash flow:
Net income attributable to Targa Resources Partners LP	$	32.5		$	139.9		$	34.3
Depreciation and amortization expense		125.1			119.5			114.3
Deferred income tax expense		0.9			2.1			2.1
Amortization in interest expense		3.8			2.1			1.8
Loss (gain) on debt repurchases		1.5			(13.1	)		-
Non-cash (gain) loss related to derivatives		59.1			(24.0	)		54.7
Maintenance capital expenditures		(34.6	)		(48.0	)		(49.0	)
Other (1)		(0.6	)		(0.6	)		(0.5	)
Distributable cash flow	$	187.7		$	177.9		$	157.7

__________

(1)

Other includes the noncontrolling interest percentage of our unconsolidated investment’s depreciation, interest expense and maintenance capital expenditures.

Results of Operations

	Year Ended December 31,									2009 vs. 2008						2008 vs. 2007
	2009			2008			2007			$ Change			% Change			$ Change			% Change
	(In millions, except
	operating and price data)
Revenues (1) (2)	$	4,391.2		$	7,837.9		$	7,103.6		$	(3,446.7	)		(44	%)	$	734.3			10	%
Product purchases (2)		3,809.6			7,197.7			6,471.5			(3,388.1	)		(47	%)		726.2			11	%
Gross margin (3)		581.6			640.2			632.1			(58.6	)		(9	%)		8.1			1	%
Operating expenses		191.1			227.0			209.0			(35.9	)		(16	%)		18.0			9	%
Operating margin (4)		390.5			413.2			423.1			(22.7	)		(5	%)		(9.9	)		(2	%)
Depreciation and amortization expenses		125.1			119.5			114.3			5.6			5	%		5.2			5	%
General and administrative expenses		100.6			85.4			89.8			15.2			18	%		(4.4	)		(5	%)
Other		(0.7	)		5.4			(0.1	)		(6.1	)		(113	%)		5.5			5,500	%
Income from operations		165.5			202.9			219.1			(37.4	)		(18	%)		(16.2	)		(7	%)
Interest expense, net		(118.6	)		(120.3	)		(122.6	)		1.7			1	%		2.3			2	%
Equity in earnings of
unconsolidated investment		5.0			3.9			3.5			1.1			28	%		0.4			11	%
Gain (loss) on debt repurchases		(1.5	)		13.1			-			(14.6	)		(111	%)		13.1			-
Gain (loss) on mark-to-market
derivative instruments		(15.2	)		30.6			(61.9	)		(45.8	)		(150	%)		92.5			149	%
Other		0.7			12.9			(0.8	)		(12.2	)		(95	%)		13.7			1,713	%
Income tax expense		(1.2	)		(2.9	)		(2.9	)		1.7			59	%		-			-
Net income		34.7			140.2			34.4			(105.5	)		(75	%)		105.8			308	%
Less: Net income attributable
to noncontrolling interest		2.2			0.3			0.1			1.9			633	%		0.2			200	%
Net income attributable
to Targa Resources Partners LP	$	32.5		$	139.9		$	34.3			(107.4	)		(77	%)		105.6			308	%
Financial and operating data:
Financial data:
Adjusted EBITDA (5)	$	335.6		$	357.7		$	328.0		$	(22.1	)		(6	%)	$	29.7			9	%
Distributable cash flow (6)		187.7			177.9			157.7			9.8			6	%		20.2			13	%
Operating data:
Plant natural gas inlet, MMcf/d (7) (8)		1,578.0			1,506.7			1,917.7			71.3			5	%		(411.0	)		(21	%)
Gross NGL production, MBbl/d		73.3			74.5			83.6			(1.2	)		(2	%)		(9.1	)		(11	%)
Natural gas sales, BBtu/d (8)		580.6			517.7			502.0			62.9			12	%		15.7			3	%
NGL sales, MBbl/d		273.5			280.5			313.9			(7.0	)		(2	%)		(33.4	)		(11	%)
Condensate sales, MBbl/d		3.7			3.1			3.2			0.6			19	%		(0.1	)		(3	%)
Average realized prices (9):
Natural gas, $/MMBtu		3.85			8.19			6.48			(4.34	)		(53	%)		1.71			26	%
NGL, $/gal		0.79			1.39			1.18			(0.60	)		(43	%)		0.21			17	%
Condensate, $/Bbl		56.38			90.30			71.37			(33.92	)		(38	%)		18.94			27	%

__________

(1)

Includes business interruption insurance revenues of $12.2 million, $32.3 million and $7.3 million for 2009, 2008 and 2007.

(2)

(3)

Gross margin is revenues less product purchases. See “How We Evaluate Our Operations.”

(4)

Operating margin is gross margin less operating expenses. See “How We Evaluate Our Operations.”

(5)

Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash gain or loss related to derivative instruments. See “How We Evaluate Our Operations.”

(6)

Distributable cash flow is net income plus depreciation and amortization and deferred taxes, adjusted for losses on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures. See “How We Evaluate Our Operations.”

(7)

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

(8)

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

(9)

Average realized prices include the impact of hedging activities.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Revenues decreased $3,478.9 million due to lower realized prices and a $20.1 million reduction in business interruption proceeds, partially offset by a $39.7 million increase due to higher sales volumes and a $12.6 million increase of non-commodity revenues.

The decrease in gross margin reflects lower commodity prices, lower NGL production and lower business interruption proceeds, partially offset by higher natural gas and condensate sales volumes, higher fee revenues and the positive impact of our hedge activity.

For information regarding period to period changes in our gross margins, see “Results of Operations—By Segment”.

Depreciation and amortization increased primarily due to a 4% increase in our property, plant and equipment balance for 2009 compared to 2008.

General and administrative expense increased for 2009 compared to 2008 primarily due to increases in compensation related expenses, professional services, allocated corporate level expenses and insurance expenses.

Interest expense decreased for 2009 compared to 2008 primarily due to lower average outstanding debt during 2009. See “Liquidity and Capital Resources” for information regarding our outstanding debt obligations.

Loss on debt repurchases for 2009 relates to open market repurchases of our 11¼% Senior Notes due 2017.

Our loss on mark-to-market derivative instruments for 2009 compared to a gain for 2008 was primarily due to the treatment of commodity hedges related to the Permian System that were allocated to us through common control accounting. These hedges did not qualify for hedge accounting and therefore the change in fair value of these instruments was recorded in earnings using the mark-to market method. The use of mark-to-market accounting caused non-cash earnings volatility due to changes in the underlying commodity price indices. During 2009, we recorded mark-to-market losses, compared to 2008, when we recorded mark-to-market gains due to these changes in commodity price indices.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Revenues increased $1,231.4 million due to higher commodity prices, a $31.7 million increase in non-commodity revenues and a $25.0 million increase in business interruption proceeds, partially offset by a $553.8 million decrease due to volume changes.

The increase in gross margin reflects higher commodity prices and increased natural gas sales volumes, fee revenues and business interruption proceeds, partially offset by lower NGL and condensate sales volumes.

For information regarding period to period changes in our gross margins, see “Results of Operations—By Segment”.

Depreciation and amortization increased primarily due to a 5% increase in our property, plant and equipment balance for 2008 compared to 2007.

General and administrative expense decreased for 2008 compared to 2007, primarily due to decreases in allocated corporate level expenses and insurance expenses; partially offset by increases in compensation related expenses and professional services.

Interest expense decreased for 2008 compared to 2007, primarily from lower average outstanding debt during 2008. See “Liquidity and Capital Resources” for information regarding our outstanding debt obligations.

Gain on debt repurchases for 2008 relates to open market repurchases of our 8¼% Senior Notes due 2016.

Our gain on mark-to-market derivative instruments for 2008 compared to the loss for 2007 was primarily due to the treatment of commodity hedges related to the Permian System that were allocated to us through common control accounting. These hedges did not qualify for hedge accounting and therefore the change in fair value of these instruments was recorded in earnings using the mark-to market method. The use of mark-to-market accounting caused non-cash earnings volatility due to changes in the underlying commodity price indices. During 2008, we recorded mark-to-market gains, compared to 2007, when we recorded mark-to-market losses due to these changes in commodity price indices.

Results of Operations—By Segment

Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation. For all operating statistics presented, the numerator is the total volume or sales for the period and the denominator is the number of calendar days for the period.

Field Gathering and Processing Segment

The following table provides summary financial data regarding results of operations in our Field Gathering and Processing segment for the periods indicated:

	Year Ended December 31,									2009 vs. 2008						2008 vs. 2007
	2009			2008			2007			$ Change			% Change			$ Change			% Change
	($ in millions)
Gross margin (1)	$	185.2		$	329.6		$	278.9		$	(144.4	)		(44	%)	$	50.7			18	%
Operating expenses		(55.8	)		(62.0	)		(56.9	)		(6.2	)		(10	%)		5.1			9	%
Operating margin (2)	$	129.4		$	267.6		$	222.0			(138.2	)		(52	%)		45.6			21	%
Operating statistics (3):
Plant natural gas inlet, MMcf/d		383.2			373.0			389.9			10.2			3	%		(16.9	)		(4	%)
Gross NGL production, MBbl/d		47.6			46.5			45.9			1.1			2	%		0.6			1	%
Natural gas sales, BBtu/d		169.3			208.6			196.5			(39.3	)		(19	%)		12.1			6	%
NGL sales, MBbl/d		39.5			38.2			38.4			1.3			3	%		(0.2	)		(1	%)
Condensate sales, MBbl/d		2.5			2.8			3.0			(0.3	)		(11	%)		(0.2	)		(7	%)
Average realized prices:
Natural gas, $/MMBtu		3.34			7.63			6.17			(4.29	)		(56	%)		1.46			24	%
NGL, $/gal		0.70			1.19			1.04			(0.49	)		(41	%)		0.15			14	%
Condensate, $/Bbl		55.98			84.52			62.79			(28.54	)		(34	%)		21.73			35	%

__________

(1)

(2)

Gross margin is revenues less product purchases.

Operating margin is gross margin less operating expenses.

(3)

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

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Gross Margin. The decrease in gross margin for 2009 compared to 2008 is attributable to a decrease in commodity sales prices and a decrease in natural gas sales volumes due to a decrease in purchases from affiliates for resale.

Operating Expenses. The decrease in operating expenses for 2009 compared to 2008 was primarily the result of higher commodity prices and the impact of those prices on supply costs, lube oil, fuel costs, utility costs and contract services.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Gross Margin. The increase in gross margin for 2008 compared to 2007 is attributable to an increase in commodity sales volumes and an increase in natural gas sales volumes due to a lower proportion of take-in-kind volumes and increased marketing activity.

Operating Expenses. The increase in operating expenses for 2008 compared to 2007 was primarily the result of increases in system maintenance, repairs and supplies, chemicals and lubricants, environmental expenses, utilities expenses and ad valorem taxes partially offset by decreases in compensation and benefit costs.

Coastal Gathering and Processing Segment

The following table provides summary financial data regarding results of operations in our Coastal Gathering and Processing segment for the periods indicated:

	Year Ended December 31,									2009 vs. 2008						2008 vs. 2007
	2009			2008			2007			$ Change			% Change			$ Change			% Change
	($ in millions)
Gross margin (1)	$	91.3		$	122.3		$	119.1		$	(31.0	)		(25	%)	$	3.2			3	%
Operating expenses		(28.8	)		(25.7	)		(28.7	)		3.1			12	%		(3.0	)		(10	%)
Operating margin (2)	$	62.5		$	96.6		$	90.4			(34.1	)		(35	%)		6.2			7	%
Operating statistics (3):
Plant natural gas inlet, MMcf/d (4)		1,194.8			1,133.7			1,527.8			61.1			5	%		(394.1	)		(26	%)
Gross NGL production, MBbl/d		25.7			28.0			37.6			(2.3	)		(8	%)		(9.6	)		(26	%)
Natural gas sales, BBtu/d		258.4			239.4			244.1			19.0			8	%		(4.7	)		(2	%)
NGL sales, MBbl/d		26.9			28.5			36.3			(1.6	)		(6	%)		(7.8	)		(21	%)
Condensate sales, MBbl/d		1.4			1.4			1.4			-			-			-			-
Average realized prices:
Natural gas, $/MMBtu		4.04			8.97			6.83			(4.93	)		(55	%)		2.14			31	%
NGL, $/gal		0.79			1.39			1.09			(0.60	)		(43	%)		0.30			27	%
Condensate, $/Bbl		52.78			89.48			73.02			(36.70	)		(41	%)		16.46			23	%

__________

(1)

(2)

Gross margin is revenues less product purchases.

Operating margin is gross margin less operating expenses.

(3)

(4)

The majority of Straddle System volumes are gathered on third party offshore pipeline systems and delivered to the plant inlets.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Gross Margin. The decrease in gross margin for 2009 compared to 2008 is attributable to a decrease in commodity sales prices, partially offset by an increase in natural gas sales volumes primarily due to increased sales demand to our industrial customers and affiliates; and a decrease in NGL sales due to the straddle plants recovering after hurricanes Gustav and Ike in 2008.

Operating Expenses. Operating expenses increased for 2009 compared to 2008 primarily due increases in compensation and benefits costs, system maintenance repairs and supplies, chemicals and lubricants, and environmental expenses due to the straddle plants recovering after hurricanes Gustav and Ike in 2008; partially offset by decreases in utilities expenses.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Gross Margin. The increase in gross margin for 2008 compared to 2007 is attributable to an increase in commodity sales prices, partially offset by a decrease in commodity sales volumes which were primarily the result of straddle plants shut down during third and fourth quarter of 2008 due to hurricanes Gustav and Ike.

Operating Expenses. Operating expenses decreased for 2008 compared to 2007 primarily due to decreases in compensation and benefit costs, system maintenance, repairs and supplies and utilities expenses, primarily as a result of straddle plants shut down during third and fourth quarter of 2008 due to hurricanes Gustav and Ike.

Logistics Assets Segment

The following table provides summary financial data regarding results of operations of our Logistics Assets segment for the periods indicated:

	Year Ended December 31,									2009 vs. 2008						2008 vs. 2007
	2009			2008			2007			$ Change			% Change			$ Change		% Change
	($ in millions)
Gross margin (1)	$	156.2		$	172.5		$	134.5		$	(16.3	)		(9	%)	$	38.0		28	%
Operating expenses		(81.9	)		(132.4	)		(101.7	)		(50.5	)		(38	%)		30.7		30	%
Operating margin (2)	$	74.3		$	40.1		$	32.8			34.2			85	%		7.3		22	%
Operating statistics:
Fractionation volumes, MBbl/d		217.2			212.2			209.2			5.0			2	%		3.0		1	%
Treating volumes, MBbl/d (3)		21.9			20.7			9.1			1.2			6	%		11.6		127	%

__________

(1)

Gross margin consists of fee revenue and business interruption proceeds.

(2)

Operating margin is gross margin less operating expenses.

(3)

Consists of the volumes treated in our low sulfur natural gasoline (“LSNG”) unit.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Operating Margin. The increase in operating margin for 2009 compared to 2008 is primarily the result of the Mont Belvieu cogeneration unit in operation beginning in the third quarter of 2009, overall fractionation fee improvement due to new contracts, increased barge terminalling activity due to recovery of operations after hurricane repairs, take-or-pay revenue realized in 2009 and slightly higher volumes.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Operating Margin. The increase in operating margin for 2008 compared to 2007 is primarily the result of a full year of commercial operations at our LSNG unit in 2008 compared to six months of operations in 2007, additional terminalling activity involving a new common carrier connection and overall fractionation fee improvement.

Marketing and Distribution Segment

The following table provides summary financial data regarding results of operations of our Marketing and Distribution segment for the periods indicated:

	Year Ended December 31,									2009 vs. 2008						2008 vs. 2007
	2009			2008			2007			$ Change			% Change			$ Change			% Change
	($ in millions)
Gross margin (1)	$	128.9		$	98.8		$	140.3		$	30.1			30	%	$	(41.5	)		(30	%)
Operating expenses		(45.9	)		(57.5	)		(54.9	)		(11.6	)		(20	%)		2.6			5	%
Operating margin (2)	$	83.0		$	41.3		$	85.4			41.7			101	%		(44.1	)		(52	%)
Operating statistics:
Natural gas sales, BBtu/d		510.3			417.4			389.8			92.9			22	%		27.6			7	%
NGL sales, MBbl/d		276.1			284.0			316.3			(7.9	)		(3	%)		(32.3	)		(10	%)
Average realized prices:
Natural gas, $/MMBtu		3.65			7.81			6.38			(4.16	)		(53	%)		1.43			22	%
NGL realized price, $/gal		0.80			1.40			1.19			(0.60	)		(43	%)		0.22			18	%

__________

(1)(2)

Gross margin is revenues less product purchases.

Operating margin is gross margin less operating expenses.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Gross Margin. The increase in gross margin for 2009 compared to 2008 was primarily due to higher margins on inventory sales, higher margins from overall higher market prices and improved margins on NGL sales at staged inventory locations, and increased terminal income; partially offset by decreased refinery services margins due to the expiration of certain refinery supply agreements, the expiration of a barge contract, decreased truck utilization and decreased proceeds from business interruption claims.

Operating Expenses. Operating expenses decreased for 2009 compared to 2008 primarily due to reduced barge and truck utilization and lower ad valorem taxes, partially offset by increased terminal operating expenses.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Gross Margin. The decrease in gross margin for 2008 compared to 2007 was primarily due to lower margins on inventory sales and lower margins on NGL sales at staged inventory locations; partially offset by improved barge transport revenue due to increased spot activity, increased truck utilization, increased refinery services margins and increased proceeds from business interruption claims.

Operating Expenses. Operating expenses increased for 2008 compared to 2007 primarily due to increased barge and truck utilization.

Other

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

During 2009, the settlement of our commodity derivatives resulted in $41.3 million in additional net receipts from our hedge counterparties, which were recorded as increases to gross margin from hedge settlements during the year. During 2008, the settlement of our commodity derivatives resulted in additional net payments of $32.4 million to our hedge counterparties, which were recorded as reductions of gross margin from hedge settlements during the year. Cash receipts or payments on our hedge settlements are due to the contracted price of our hedge contracts falling above or below the market prices of the commodity settled.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

During 2008 and 2007, the settlement of our commodity derivatives resulted in additional net payments of $32.4 million and $7.5 million to our hedge counterparties, which were recorded as reductions of gross margin from hedge settlements during the year. Cash payments on our hedge settlements are due to the contracted price of our hedge contracts falling below the market prices of the commodity settled.

Insurance Claims

Hurricanes Katrina and Rita affected certain of our Gulf Coast facilities in 2005. Our final purchase allocation for these assets in October 2005 included a $52.2 million receivable for insurance claims related to property damage caused by Katrina and Rita. During 2008, our cumulative receipts exceeded such amount, and we recognized a gain of $11.5 million, which is shown in the Supplemental Consolidated Statement of Operations as other income. The insurance claim process is now complete with respect to Katrina and Rita for property damage and business interruption insurance.

Certain of our Louisiana and Texas facilities sustained damage and had disruptions to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded an $11.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During 2009, we reduced the estimate by $0.7 million. During 2009, we incurred expenditures related to the hurricanes amounting to $30.4 million for previously accrued repair costs and $7.4 million capitalized for improvements to the facilities.

During 2009, 2008 and 2007, we recognized revenue from business interruption insurance of:

	Year Ended December 31,
	2009		2008		2007
	(In millions)
Coastal Gathering and Processing	$	9.8	$	13.6	$	2.6
Logistics Assets		1.9		1.8		-
Marketing and Distribution		0.5		16.9		4.7
	$	12.2	$	32.3	$	7.3

Business interruption insurance receipts recognized as revenue during 2009 relate primarily to the 2008 hurricanes; amounts recognized during 2008 and 2007 relate primarily to Hurricanes Katrina and Rita from the 2005 hurricane season. Under the terms of the Downstream and the Permian and Straddle acquisition agreements, Targa retained the right to receive any future insurance proceeds from claims associated with Gustav and Ike.

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness, to meet our collateral requirements, or to pay our distributions 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, including weather, commodity prices, particularly for natural gas and NGLs, and our 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 our credit facility, the issuance of additional equity and access to debt markets. The capital markets continue to experience volatility. Many financial institutions have or have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposures to the current credit conditions include our credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

Current market conditions also elevate the concern over 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 and natural gas prices are also volatile and have recently declined significantly. In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity derivative contracts for a portion of our estimated equity volumes through 2013. 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. In the event of a continued global recession, commodity prices may stay depressed or fall further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.

As of December 31, 2009, we had liquidity of $431.3 million, including $60.4 million of available cash and $370.9 million of available borrowings under our credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we will continue to monitor events and circumstances surrounding each of the other twenty three lenders in our credit facility. To date, other than the Lehman Bank default, we have experienced no disruptions in our ability to access funds committed under our credit facility. However, we cannot predict with any certainty the impact to us of any further disruptions in the credit environment.

Our cash generated from operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures, with remaining amounts being distributed to Targa during its period of ownership and to our unitholders since our IPO. Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow and borrowings available under our senior secured credit facilities should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, long-term indebtedness obligations, collateral requirements and minimum quarterly cash distributions for at least the next twelve months.

We intend to make cash distributions to our unitholders and our general partner in an amount at least equal to the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures. Historically, we have relied on internally generated cash flows for these purposes. See “Factors That Significantly Affect Our Results—Distributions to our Unitholders” for a table that shows the distributions w e declared paid in 2009 and 2008.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received by our customers or paid to our suppliers can also cause fluctuations in working capital because we settl e with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.

Prior to the contribution of the North Texas System in February 2007, the acquisition of the SAOU and LOU Systems in October 2007 and the acquisition of the Downstream Business in September 2009, all intercompany transactions, including expense reimbursements, were not cash settled with Targa, but were recorded as an adjustment to parent equity on the balance sheet. The primary transactions between Targa and us are natural gas and NGL sales, the provision of operations and maintenance activities and the provision of general and administrative services. As a result of this accounting treatment, our working capital did not reflect any affiliate accounts receivable for intercompany commodity sales or any affiliate accounts payable for the personnel and services provided by or

paid for by our parent prior to the acquisition of the North Texas System and the subsequent acquisition of the SAOU and LOU Systems.

As of December 31, 2009, we had a positive working capital balance of $46.2 million.

The Partnership is obligated to make minimum quarterly cash distributions to unitholders from available cash, as defined in the partnership agreement. As of December 31, 2009, such minimum amounts payable to non-Targa unitholders total approximately $56.1 million annually.

Cash Flow

The following table summarizes cash flow provided by or used in operating activities, investing activities and financing activities for the periods indicated:

	Year Ended December 31,									2009 vs. 2008						2008 vs. 2007
	2009			2008			2007			$ Change			% Change			$ Change		% Change
	(In millions)
Net cash provided by (used in):
Operating activities	$	353.9		$	399.2		$	384.4		$	(45.3	)		(11	%)	$	14.8		4	%
Investing activities		(82.9	)		(98.5	)		(95.6	)		(15.6	)		(16	%)		2.9		3	%
Financing activities		(305.9	)		(269.7	)		(237.0	)		36.2			13	%		32.7		14	%

Operating Activities

The decrease in net cash provided by operating activities for 2009 compared to 2008 was primarily due to changes in operating assets and liabilities, which provided $57.3 million in cash during 2009, compared to providing $179.0 million in cash during 2008, partially offset by an $87.4 million payment during 2008 to terminate certain out-of-the-money commodity derivatives.

The increase in net cash provided by operating activities for 2008 compared to 2007 was primarily due to changes in operating assets and liabilities, which provided $179.0 million in cash during 2008, compared to providing $93.4 million in cash during 2007, partially offset by an $87.4 million payment during 2008 to terminate certain out-of-the-money commodity derivatives.

Investing Activities

The decrease in net cash used in investing activities for 2009 compared to 2008 was primarily due to lower capital additions during 2009 compared to 2008.

The increase in net cash used in investing activities for 2008 compared to 2007 is primarily due to increased capital additions during 2008, primarily from increased expenditures related to gathering system expansion projects begun in the third quarter of 2008, partially offset by asset sale proceeds.

The following table lists gross additions to property, plant and equipment, cash flows used in property, plant and equipment additions and the difference, which is primarily settled accruals and non-cash additions:

	Year Ended December 31,
	2009			2008			2007
	(In millions)
Gross additions to property, plant and equipment	$	86.4		$	112.8		$	99.2
Non-cash additions to property, plant and equipment		(9.8	)		(5.8	)		0.2
Change in accruals		6.4			(8.3	)		(1.5	)
Cash expenditures	$	83.0		$	98.7		$	97.9

Financing Activities

The increase in net cash used in financing activities for 2009 compared to 2008 is primarily due to repayment of affiliated debt associated with our purchase of the Downstream Business; partially offset by a net increase in debt, equity offering proceeds from our public offering of 6,900,000 common units in August 2009, and a net decrease in distributions to Targa.

The increase in net cash used in financing activities for 2008 compared to 2007 is primarily due to net proceeds from equity offerings in 2007, a decrease in debt, increased distributions to unitholders and a repurchase of senior notes in 2008; partially offset by the repayment of affiliated indebtedness in 2007, proceeds from our issuance of senior notes in 2008, and a net decrease in distributions to Targa.

Capital Requirements

The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A significant portion of the cost of constructing new gathering lines to connect to our gathering system is generally paid for by the natural gas producer. However, we expect to make significant expenditures during the next year for the construction of additional natural gas gathering and processing infrastructure and to enhance the value of our natural gas logistics and marketing assets.

We categorize our capital expenditures as either: (i) maintenance expenditures or (ii) expansion expenditures. Maintenance expenditures are those expenditures that are necessary to maintain the service capability of our existing assets including the replacement of system components and equipment which is worn, obsolete or completing its useful life, the addition of new sources of natural gas supply to our systems to replace natural gas production declines and expenditures to remain in compliance with environmental laws and regulations. Expansion 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.

	Year Ended December 31,
	2009		2008		2007
	(In millions)
Capital expenditures:
Expansion	$	51.8	$	64.8	$	50.2
Maintenance		34.6		48.0		49.0
	$	86.4	$	112.8	$	99.2

Our planned capital expenditures for 2010 are approximately $130 million with maintenance capital expenditures accounting for approximately 25%. Included in the planned capital expenditures for 2010 is the expansion of our facility at Cedar Bayou. 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. Expansion capital expenditures may vary significantly based on investment opportunities.

Credit Facilities and Long-Term Debt

As of December 31, 2009, we had outstanding loans of $479.2 million and approximately $370.9 million of availability under our senior secured revolving credit facility. See “Debt Obligations” included under Note 10 to our “Supplemental Consolidated Financial Statements” in Exhibit 99.3 for a discussion of our credit agreements.

On September 24, 2009, in association with our purchase of the Downstream Business, the entire balance of affiliated indebtedness payable to Targa (by Targa Downstream LP and Targa LSNG LP) was settled with Targa via capital contributions made by Targa and repayments by us.

Description of 8¼% Senior Notes. On June 18, 2008, we completed the private placement under Rule 144 A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of our 8¼% senior

unsecured notes due 2016 (the “8¼% Notes”). In connection with the issuance of the 8¼% Notes, we entered into an indenture (the “2008 Indenture”) governing the terms of the 8¼% Notes.

The 8¼% Notes will mature on July 15, 2016 and interest is payable on the 8¼% Notes semi-annually in arrears on each January 1 and July 1. The 8¼% Notes are guaranteed on a senior unsecured basis by certain of our subsidiaries.

The 2008 Indenture restricts our ability to make distributions to unitholders if we are in default or an event of default (as defined in the 2008 Indenture) exists. It also restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase, equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 8¼% Notes are rated investment grade by both Moody’s Investors Ser vice, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the 2008 Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.

Description of 11¼% Senior Notes. On July 6, 2009, we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. Proceeds from the 11¼% Notes were used to repay borrowings under our senior secured revolving credit facility. In connection with the issuance of the 11¼% Notes, we entered into an indenture (the “2009 Indenture&# 8221;) governing the terms of the 11¼% Notes.

The 11¼% Notes will mature on July 1, 2017 and interest is payable on the 11¼% Notes semi-annually in arrears on each January 15 and July 15. The 11¼% Notes are guaranteed on a senior unsecured basis by certain of our subsidiaries.

The 2009 Indenture restricts our ability to make distributions to unitholders if we are in default or an event of default (as defined in the 2009 Indenture) exists. It also restricts our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase, equity interests (only if such distributions do not meet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 11¼% Notes are rated investment grade by both Moody’s Investors Se rvice, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the 2009 Indenture) has occurred and is continuing, many of such covenants will terminate and we and our subsidiaries will cease to be subject to such covenants.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements as defined by the Securities and Exchange Commission. See “Contractual Obligations” below and “Commitments and Contingencies” included under Note 17 to our “Supplemental Consolidated Financial Statements” in Exhibit 99.3 for a discussion of our commitments and contingencies, some of which are not recognized in the consolidated balance sheets under GAAP.

Contractual Obligations

Following is a summary of our contractual cash obligations over the next several fiscal years, as of December 31, 2009:

	Payments Due By Period
			Less Than						More Than
Contractual Obligations (1)	Total		1 Year		1-3 Years		4-5 Years		5 Years
	(In millions)
Debt obligations (2)	$	1,246.6	$	-	$	806.2	$	-	$	440.4
Interest on debt obligations (3)		397.1		76.1		143.7		86.5		90.8
Operating lease obligations (4)		38.0		8.9		12.7		5.9		10.5
Capacity payments (5)		2.7		2.0		0.7		-		-
Land site lease and right-of-way		20.4		1.4		2.6		2.2		14.2
Asset retirement obligation		15.4		-		-		-		15.4
Purchase order commitments		4.6		4.6		-		-		-
	$	1,724.8	$	93.0	$	965.9	$	94.6	$	571.3

__________

(1)

Contractual obligations exclude current and long-term unrealized losses on derivative instruments included in the consolidated balance sheet as those amounts represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in either cash payments or cash receipts; therefore, it is not possible to estimate the timing or amounts of potential future obligations.

(2)

Represents our scheduled future maturities of consolidated debt obligations for the periods indicated. See “Debt Obligations” included under Note 10 to our “Supplemental Consolidated Financial Statements” in Exhibit 99.3 for information regarding our debt obligations.

(3)

Represents interest expense on our debt obligations based on interest rates as of December 31, 2009 and the scheduled future maturities of those debt obligations.

(4)

Include minimum lease payment obligations associated with site leases and railcar leases.

(5)

Consist of capacity payments for firm transportation contracts.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates. The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and est imates.

Property, Plant and Equipment. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Our property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we place our assets in-service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively. Examples of such circumstances include:

changes in energy prices;

changes in competition;

changes in laws and regulations that limit the estimated economic life of an asset;

changes in technology that render an asset obsolete;

changes in expected salvage values; and

changes in the forecast life of applicable resources basins, if any.

As of December 31, 2009, the net book value of our property, plant and equipment was $2.0 billion and we recorded $125.1 million in depreciation expense for 2009. The weighted average life of our long-lived assets is approximately 20 years. If the useful lives of these assets were found to be shorter than originally estimated, depreciation expense may increase, liabilities for future asset retirement obligations may be insufficient and impairments in carrying values of tangible and intangible assets may result. For example, if the depreciable lives of our assets were reduced by 10%, we estimate that depreciation expense would increase by $13.9 million per year, which would result in a corresponding reduction in our operating income. In addition, if an assessment of impairment resulted in a reduction of 1% of our long-lived assets, our operating income would decrease by $19.8 million per year. There have been no material changes impacting estimated useful lives of the assets.

Revenue Recognition. Revenues for a period reflect collections to the report date, plus any uncollected revenues reported for the period, which are reflected as accounts receivable in the balance sheet. As of December 31, 2009, our balance sheet reflects total accounts receivable from third parties of $387.8 million. We have recorded an allowance for doubtful accounts as of December 31, 2009 of $7.9 million.

Our exposure to uncollectible accounts receivable relates to the financial health of our counterparties. We and our indirect parent, Targa, 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 uncollectibility resulted in a 1% reduction of our third party accounts receivable, our annual operating income would decrease by $3.9 million.

Price Risk Management (Hedging). Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. To reduce the volatility of our cash flows, we have entered into (i) derivative financial instruments related to a portion of our equity volumes to manage the purchase and sales prices of commodities and (ii) interest rate financial instruments to fix the interest rate on our variable debt. We are exposed to the credit risk of our counterparties in these derivative financial instruments. We also monitor NGL inventory levels with a view to mitigating losses related to downward price exposure.

Our cash flow is affected by the derivative financial instruments we enter into to the extent these instruments are settled by (i) making or receiving a payment to/from the counterparty or (ii) making or receiving a payment for entering into a contract that exactly offsets the original derivative financial instrument. Typically a derivative financial instrument is settled when the physical transaction that underlies the derivative financial instrument occurs.

One of the primary factors that can affect our operating results each period is the price assumptions we use to value our derivative financial instruments, which are reflected at their fair values in the balance sheet. The relationship between the derivative financial instruments and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the derivative financial instrument and on an ongoing basis. Hedge accounting is discontinued prospectively when a derivative financial instrument becomes ineffective. Gains and losses deferred in other comprehensive income related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction wi ll not occur, deferred gains or losses on the derivative financial instrument are reclassified to earnings immediately.

The estimated fair value of our derivative financial instruments was a liability of $18.5 million as of December 31, 2009, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities by year for each counterparty’s traded credit default swap transactions. These default probabilities have been applied to the unadjusted fair values of the derivative financial instruments to arrive at the credit risk adjustment, which aggregates to less than $0.1 million as of December 31, 2009. We and our indirect parent, Targa, have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of

counterparties. If a financial instrument counterparty were to declare bankruptcy, we would be exposed to the loss of fair value of the financial instrument transaction with that counterparty. Ignoring our adjustment for credit risk, if a bankruptcy by financial instrument counterparty impacted 10% of the fair value of commodity-based financial instruments, we estimate that our operating income would decrease by $1.9 million per year.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see “Significant Accounting Policies” included under Note 4 to our “Supplemental Consolidated Financial Statements” in Exhibit 99.3.

Quantitative and Qualitative Disclosures About Market Risk

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, 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 majority 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 hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of December 31, 2009, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2010 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGL and we pay the hedge counterparty a floating price for that same quantity based upon publishe d 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) to hedge additional expected equity commodity volumes without creating volumetric risk. We intend to continue to manage our exposure to commodity prices in the future by entering into similar hedge transactions using swaps, collars, purchased puts (or floors) or other hedge 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 baskets of ethane, propane, normal butane, isobutane and natural gasoline 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 NGL hedges fair values are based on published index prices for delivery at Mont Belvieu through 2012, except for the price of isobutane in 2012, which is based on the ending 2011 pricing. Our natural gas hedges fair values are based on published index prices for delivery at Waha and Mid-Continent, which closely approximate our actual NGL and natural gas 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.

Our 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. 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 create credit exposure to us for our counterparties.

During 2009, 2008 and 2007, we entered into hedging arrangements for a portion of our forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). During 2009, 2008 and 2007, our operating revenues were increased (decreased) by net hedge adjustments of $45.8 million, ($33.7) million and ($1.0) million.

As of December 31, 2009, our commodity derivative arrangements were as follows:

Natural Gas

Instrument		Price		MMBtu per day
Type	Index	$/MMBtu		2010		2011		2012		2013		Fair Value
												(In millions)
Derivatives designated as hedging instruments
Swap	IF-WAHA		6.56		16,657		-		-		-	$	5.7
Swap	IF-WAHA		6.20		-		15,500		-		-		0.4
Swap	IF-WAHA		6.48		-		-		9,120		-		0.7
Swap	IF-WAHA		5.59		-		-		-		4,000		(0.9	)
					16,657		15,500		9,120		4,000

Swap	IF-PB		5.42		680		-		-		-		-
Swap	IF-PB		5.42		-		680		-		-		(0.1	)
Swap	IF-PB		5.54		-		-		1,360		-		(0.3	)
Swap	IF-PB		5.54		-		-		-		1,360		(0.3	)
					680		680		1,360		1,360

Swap	IF-NGPL MC		8.86		5,685		-		-		-		6.7
Swap	IF-NGPL MC		7.34		-		2,750		-		-		1.2
Swap	IF-NGPL MC		7.18		-		-		2,750		-		0.9
					5,685		2,750		2,750		-

					23,022		18,930		13,230		5,360

Derivatives not designated as hedging instruments
Basis Swap	Jan 2010-May 2011, Rec IF-CGT, Pay NYMEX less $0.12, 20,000 MMBtu/d												0.8
Fuel cost swap	Jan 2010-May 2011, Rec IF_CGT, Pay $5.96, 226 MMBtu/d												-
												$	14.8

NGL

Instrument		Price		Barrels per day
Type	Index	$/gal		2010		2011		2012		2013		Fair Value
												(In millions)
Derivatives designated as hedging instruments
Swap	OPIS_MB		0.57		7,081		-		-		-	$	3.7
Swap	OPIS_MB		0.54		-		4,924		-		-		(13.3	)
Swap	OPIS_MB		0.51		-		-		3,250		-		(8.0	)
Total Swaps					7,081		4,924		3,250		-

Floor	OPIS_MB		1.44		-		223		-		-		1.2
Floor	OPIS_MB		1.43		-		-		259		-		1.6
Total Floors					-		223		259		-

Total Sales					7,081		5,147		3,509		-
												$	(14.9	)

Condensate

Instrument		Price		Barrels per day
Type	Index	$/Bbl		2010		2011		2012		2013		Fair Value
												(In millions)
Derivatives designated as hedging instruments
Swap	NY-WTI		71.38		690		-		-		-	$	(2.7	)
Swap	NY-WTI		76.87		-		566		-		-		(1.8	)
Swap	NY-WTI		72.60		-		-		308		-		(1.5	)
Swap	NY-WTI		73.93		-		-		-		308		(1.6	)
Total Swaps					690		566		308		308

Total Sales					690		566		308		308
												$	(7.6	)

These contracts may expose us to the risk of financial loss in certain circumstances. 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.

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 either readily available in public markets or are quoted by counterparties to these contracts. These inputs are observable for the asset or liability, either directly or indirectly, for the full term of the commodity swaps and options.

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of variable rate borrowings under our senior secured revolving credit facility. To the extent that interest rates increase, interest expense for our revolving debt will also increase. As of December 31, 2009, we had borrowings of $479.2 million outstanding under our senior secured revolving credit facility. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement and ineffectiveness is required to be measured each reporting period. The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by counterparty for classification in our consolidated balance sheets. Accordingly, unrealized gains and losses relating to the interest rate

swaps are recorded in accumulated other comprehensive income (“OCI”) until the interest expense on the related debt is recognized in earnings.

As of December 31, 2009 we had the following open interest rate swaps:

			Notional	Fair
Expiration Date	Fixed Rate		Amount	Value
				(In millions)
2010		3.67%	$300 million	$	(7.8	)
2011		3.52%	300 million		(5.1	)
2012		3.40%	300 million		(0.6	)
2013		3.39%	300 million		1.6
1/1 - 4/24/2014		3.39%	300 million		1.3
				$	(10.6	)

We have designated all interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the interest rate swaps are deferred in OCI until the interest expense on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying interest rate, after taking into account our interest rate swaps, would increase our annual interest expense by $1.8 million.

Credit Risk. We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to us at the reporting date. At such times, these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.

As of December 31, 2009, affiliates of Goldman Sachs and Bank of America ("BofA") accounted for 93% and 5% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs and BofA are major financial institutions, each possessing investment grade credit ratings, based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

EX-99.3 5 ex99_3.htm SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS OF TRP LP ex99_3.htm

Exhibit 99.3

Supplemental Consolidated Financial Statements of Targa Resources Partners LP

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Targa Resources GP LLC, the general partner of Targa Resources Partners LP (“the Partnership”), is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed 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.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

The management of Targa Resources GP LLC has used the framework set forth in the report entitled “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the Partnership’s internal control over financial reporting. Based on that evaluation, management has concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2009.

The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2009 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 2.

/s/ Rene R. Joyce

Rene R. Joyce

Chief Executive Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Executive Officer)

/s/ Jeffrey J. McParland

Jeffrey J. McParland

Executive Vice President and Chief Financial Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Financial Officer)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Targa Resources Partners LP:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of changes in owners' equity and of cash flows present fairly, in all material respects, the financial position of Targa Resources Partners LP and its subsidiaries (the "Partnership") at December 31, 2009 and 2008 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2 009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our audits (which were integrated audits in 2009 and 2008). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 16 to the consolidated financial statements, the Partnership has engaged in significant transactions with its parent company, Targa Resources, Inc. and its subsidiaries, related parties.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with autho rizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 3, 2010, except with respect to our opinions on the consolidated financial statements and internal control over financial reporting insofar as it relates to the effects of the acquisition of the Permian and Straddle Systems discussed in Note 2 and change in segment reporting discussed in Note 20, as to which the date is August 9, 2010.

TARGA RESOURCES PARTNERS LP
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS

	December 31,
	2009			2008
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	60.4		$	95.3
Trade receivables, net of allowances of $7.9 million and $9.2 million		387.8			287.7
Inventory		39.1			72.2
Assets from risk management activities		28.2			99.7
Other current assets		1.6			1.0
Total current assets		517.1			555.9
Property, plant and equipment, at cost		2,488.5			2,402.3
Accumulated depreciation		(504.9	)		(380.1	)
Property, plant and equipment, net		1,983.6			2,022.2
Long-term assets from risk management activities		10.9			77.1
Investment in unconsolidated affiliate		18.5			18.5
Other long-term assets		20.6			14.3
Total assets		2,550.7			2,688.0
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable to third parties	$	173.5		$	141.8
Accounts payable to affiliates		57.9			14.1
Accrued liabilities		217.4			163.6
Liabilities from risk management activities		22.1			11.7
Deferred income taxes		-			0.3
Total current liabilities		470.9			331.5
Long-term debt payable to third parties		908.4			696.8
Long-term debt payable to Targa Resources, Inc.		327.0			1,077.7
Long-term liabilities from risk management activities		35.5			9.7
Deferred income taxes		5.8			4.1
Other long-term liabilities		18.4			18.7

Commitments and contingencies (see Note 17)

Owners' equity:
Common unitholders (61,639,846 and 34,652,000 units issued and
outstanding as of December 31, 2009 and 2008)		850.5			769.9
Subordinated unitholders (0 and 11,528,231 units issued and
outstanding as of December 31, 2009 and 2008)		-			(85.2	)
General partner (1,257,957 and 942,455 units issued and outstanding
as of December 31, 2009 and 2008)		10.1			5.6

Net parent investment		(51.5	)		(227.1	)
Accumulated other comprehensive income (loss)		(37.8	)		72.2
		771.3			535.4
Noncontrolling interest in subsidiary		13.4			14.1
Total owners' equity		784.7			549.5
Total liabilities and owners' equity	$	2,550.7		$	2,688.0

See notes to supplemental consolidated financial statements

TARGA RESOURCES PARTNERS LP
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2009			2008			2007
	(In millions, except per unit data)
Revenues from third parties	$	4,375.2		$	7,787.2		$	7,081.9
Revenues from affiliates		16.0			50.7			21.7
Total operating revenues		4,391.2			7,837.9			7,103.6
Product purchases from third parties		3,488.3			6,779.6			6,158.6
Product purchases from affiliates		321.3			418.1			312.9
Operating expenses		191.1			227.0			209.0
Depreciation and amortization expenses		125.1			119.5			114.3
General and administrative expenses		100.6			85.4			89.8
Other operating (income) expense		(0.7	)		5.4			(0.1	)
Income from operations		165.5			202.9			219.1
Other income (expense):
Interest expense from affiliate		(66.6	)		(82.4	)		(81.7	)
Interest expense allocated from Parent		-			-			(19.4	)
Other interest expense, net		(52.0	)		(37.9	)		(21.5	)
Equity in earnings of unconsolidated investment		5.0			3.9			3.5
Gain (loss) on debt repurchases		(1.5	)		13.1			-
Gain (loss) on mark-to-market derivative instruments		(15.2	)		30.6			(61.9	)
Other		0.7			12.9			(0.8	)
Income before income taxes		35.9			143.1			37.3
Income tax expense:
Current		(0.3	)		(0.8	)		(0.8	)
Deferred		(0.9	)		(2.1	)		(2.1	)
		(1.2	)		(2.9	)		(2.9	)
Net income		34.7			140.2			34.4
Less: Net income attributable to noncontrolling interest		2.2			0.3			0.1
Net income attributable to Targa Resources Partners LP	$	32.5		$	139.9		$	34.3

Net income (loss) attributable to predecessor operations	$	(21.9	)	$	48.4		$	6.2
Net income attributable to general partner		10.4			7.0			0.6
Net income allocable to limited partners		44.0			84.5			27.5
Net income attributable to Targa Resources Partners LP	$	32.5		$	139.9		$	34.3

Net income per limited partner unit - basic and diluted	$	0.86		$	1.83		$	0.81
Weighted average limited partner units outstanding - basic and diluted		51.2			46.2			34.0

See notes to supplemental consolidated financial statements

TARGA RESOURCES PARTNERS LP
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2009			2008			2007
	(In millions)

Net income	$	34.7		$	140.2		$	34.4
Other comprehensive income (loss):
Commodity hedging contracts:
Change in fair value		(72.6	)		129.9			(105.6	)
Reclassification adjustment for settled periods		(45.7	)		33.7			1.0
Related income taxes		-			-			0.3
Interest rate hedges:
Change in fair value		(2.1	)		(19.0	)		(1.7	)
Reclassification adjustment for settled periods		10.4			2.7			(0.2	)
Foreign currency translation adjustment		-			(1.8	)		1.9
Other comprehensive income (loss)		(110.0	)		145.5			(104.3	)
Comprehensive income (loss)		(75.3	)		285.7			(69.9	)
Less: Comprehensive income attributable to noncontrolling interest		2.2			0.3			0.1
Comprehensive income (loss) attributable to Targa Resources Partners LP	$	(77.5	)	$	285.4		$	(70.0	)

See notes to supplemental consolidated financial statements

TARGA RESOURCES PARTNERS LP
SUPPLEMENTAL CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY

										Accumulated
										Other
	Limited Partners						General			Comprehensive			Net Parent			Noncontrolling
	Common			Subordinated			Partner			Income (Loss)			Investment			Interest			Total
	(In millions)
Balance, December 31, 2006	$	-		$	-		$	-		$	31.3		$	425.4		$	13.4		$	470.1
Contribution from Parent, net		-			-			-			(0.3	)		194.8			-			194.5
Book value of net assets transferred
under common control		-			(83.7	)		(4.1	)		-			(642.0	)		-			(729.8	)
Issuance of units to public (including underwriter
over-allotment), net of offering and other costs		771.8			-			8.4			-			-			-			780.2
Amortization of equity awards		0.2			-			-			-			-			-			0.2
Distributions to unitholders		(20.9	)		(9.7	)		(0.6	)		-			-			-			(31.2	)
Net income		19.1			8.4			0.6			-			6.2			0.1			34.4
Other comprehensive loss		-			-			-			(104.3	)		-			-			(104.3	)
Balance, December 31, 2007		770.2			(85.0	)		4.3			(73.3	)		(15.6	)		13.5			614.1
Amortization of equity awards		0.3			-			-			-			-			-			0.3
Distributions to unitholders		(64.0	)		(21.3	)		(5.7	)		-			-			-			(91.0	)
Distribution to Parent		-			-			-			-			(259.9	)		-			(259.9	)
Contribution from noncontrolling interest		-			-			-			-			-			0.3			0.3
Net income (loss)		63.4			21.1			7.0			-			48.4			0.3			140.2
Other comprehensive income		-			-			-			145.5			-			-			145.5
Balance, December 31, 2008		769.9			(85.2	)		5.6			72.2			(227.1	)		14.1			549.5
Issuance of common units:
Equity offering		103.1			-			2.2			-			-			-			105.3
Acquisition related		129.8			-			2.7			-			-			-			132.5
Contribution (distribution) under common control		(7.7	)		-			(0.2	)		-			7.2			-			(0.7	)
Distributions to Parent		-			-			-			-			(97.0	)		(2.6	)		(99.6	)
Settlement of affiliated indebtedness		-			-			-			-			287.3			-			287.3
Distributions to noncontrolling interest		-			-			-			-			-			(0.3	)		(0.3	)
Amortization of equity awards		0.3			-			-			-			-			-			0.3
Other comprehensive loss		-			-			-			(110.0	)		-			-			(110.0	)
Conversion of subordinated units		(97.6	)		97.6			-			-			-			-			-
Net income (loss)		44.5			(0.5	)		10.4			-			(21.9	)		2.2			34.7
Distributions to unitholders		(91.8	)		(11.9	)		(10.6	)		-			-			-			(114.3	)
Balance, December 31, 2009	$	850.5		$	-		$	10.1		$	(37.8	)	$	(51.5	)	$	13.4		$	784.7

See notes to supplemental consolidated financial statements

TARGA RESOURCES PARTNERS LP
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2009			2008			2007
	(In millions)
Cash flows from operating activities
Net income	$	34.7		$	140.2		$	34.4
Adjustments to reconcile net income to net cash
provided by operating activities:
Amortization in interest expense		3.8			2.1			1.8
Amortization in general and administrative expense		0.3			0.4			0.2
Interest expense on affiliate indebtedness		66.6			82.4			81.7
Depreciation and other amortization expense		125.1			119.5			114.3
Accretion of asset retirement obligations		1.2			1.0			0.8
Deferred income tax expense		0.9			2.1			2.1
Equity in earnings of unconsolidated investments, net
of distributions		-			0.8			0.4
Risk management activities		62.5			(109.3	)		55.6
Loss (gain) on debt repurchases		1.5			(13.1	)		-
Gain on sale of assets		-			(5.9	)		(0.2	)
Changes in operating assets and liabilities:
Receivables and other assets		(90.4	)		691.1			(72.9	)
Inventory		23.3			75.4			(28.6	)
Accounts payable and other liabilities		124.4			(587.5	)		194.8
Net cash provided by operating activities		353.9			399.2			384.4
Cash flows from investing activities
Outlays for property, plant and equipment		(83.0	)		(98.7	)		(97.9	)
Other, net		0.1			0.2			2.3
Net cash used in investing activities		(82.9	)		(98.5	)		(95.6	)
Cash flows from financing activities
Proceeds from borrowings under credit facility		569.2			185.3			721.3
Repayments of credit facility		(577.6	)		(323.8	)		(95.0	)
Proceeds from issuance of senior notes		237.4			250.0			-
Repurchases of senior notes		(18.9	)		(26.8	)		-
Increase in affiliated indebtedness		-			3.4			13.0
Repayment of affiliated indebtedness		(397.5	)		-			(665.7	)
Proceeds from equity offerings		103.1			-			777.5
Distributions to unitholders		(114.3	)		(91.0	)		(31.2	)
General partner contributions		2.2			-			-
Costs incurred in connection with public offerings		-			(0.1	)		(4.6	)
Costs incurred in connection with financing arrangements		(9.6	)		(7.1	)		(7.5	)
Parent distributions		(99.6	)		(259.9	)		(944.8	)
Contribution from (distribution to) noncontrolling interest		(0.3	)		0.3			-
Net cash used in financing activities		(305.9	)		(269.7	)		(237.0	)
Net change in cash and cash equivalents		(34.9	)		31.0			51.8
Cash and cash equivalents, beginning of year		95.3			64.3			12.5
Cash and cash equivalents, end of year	$	60.4		$	95.3		$	64.3

See notes to supplemental consolidated financial statements

TARGA RESOURCES PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS

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

Targa Resources Partners LP, together with its subsidiaries, is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”). Our common units are listed on the New York Stock Exchange under the symbol “NGLS.” In this 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. References to “TRP LP” are intended to mean and include Targa Resources Partners LP, individually, and not on a consolidated basis.

Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”). We report our results of operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) NGL Logistics and Marketing consisting of two segments – (a) Logistics Assets and (b) Marketing and Distribution.

Our gathering and processing assets are located in the Fort Worth Basin/Bend Arch in North Texas, the Permian Basin in West Texas and the onshore and offshore coastal regions of Louisiana.

Our NGL logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana, with terminals and transportation assets across the U.S. See Note 20.

Targa Resources GP LLC is a Delaware single-member limited liability company, formed in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa. As of December 31, 2009, Targa and its subsidiaries own a 33.89% interest in the Partnership in the form of 1,257,957 general partner units and 20,055,846 common units.

Targa sold or conveyed its ownership interests in the following assets, liabilities and operations to us on the dates indicated:

February 14, 2007 – North Texas System;

October 24, 2007 – San Angelo (“SAOU”) System and Louisiana (“LOU”) System;

September 24, 2009 – Downstream Business (See Note 5); and

April 27, 2010 – Permian and Straddle Systems (See Note 5).

For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these conveyances collectively as our “predecessors.”

Note 2—Basis of Presentation

We have prepared these supplemental consolidated financial statements to update the financial statements and financial information included in our Annual Report on Form 10-K for the year ended December 31, 2009 to reflect our acquisition of the Permian and Straddle Systems, a transfer of assets under common control.

We have prepared the supplemental consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial results of our

predecessors may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessors had been operated as unaffiliated entities.

We have prepared the separate financial results of our predecessors from the records maintained by Targa and eliminated all significant intercompany transactions. We have included allocations of corporate general and administrative expense, interest expense and the financial effects of certain commodity derivative contracts. Transactions among us and other Targa operations have been identified in these supplemental consolidated financial statements as transactions among affiliates. See Note 16. All of the allocations are not necessarily indicative of the costs and expenses that would have resulted had we been operated as stand-alone entities.

We are required by GAAP to record the conveyances described in Note 1 based on Targa historical amounts, assuming that the acquisitions occurred at the date they qualified as entities under common control (October 31, 2005) following the acquisition of the SAOU and LOU System. We recognize the difference between our acquisition cost and the Targa basis in the net assets as an adjustment to owners’ equity. We have retrospectively adjusted the financial statements, footnotes and other financial information presented for any period affected by common control accounting to reflect the results of the combined entities.

The retrospective adjustment resulted in all the footnotes and other financial information being updated to reflect the acquisition, including: Acquisitions under Common Control (Note 5), Property, Plant and Equipment (Note 7), Debt Obligations (Note 10), Insurance Claims (Note 12), Derivative Instruments and Hedging Activities (Note 15), Related-Party Transactions (Note 16), Fair Value Measurements (Note 19), Segment Information (Note 20), Other Operating Income (Note 21), and Selected Quarterly Financial Data (Note 24).

Note 3—Out of Period Adjustment

During 2009, we recorded an adjustment related to prior periods which increased our revenue, income before income taxes and net income for 2009 by $1.8 million. The adjustment related to natural gas sales transactions which occurred during 2006. After evaluating the quantitative and qualitative aspects of the error, we concluded that our previously issued financial statements were not materially misstated and the effect of recognizing the adjustment in the 2009 financial statements was not material to our results of operations, financial position or cash flows.

Note 4—Significant Accounting Policies

Consolidation Policy. Our supplemental consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest. Noncontrolling interest represents third party ownership in the net assets of our consolidated subsidiary, Cedar Bayou Fractionators (“CBF”). For financial reporting purposes, the assets and liabilities of CBF are consolidated in whole with any third party investor’s share of net assets reported as a component of owners’ equity. In the statements of operations and comprehensive income, noncontrolling interest reflects the third party investor’s share of CBF earnings and other comprehensive income. Distributions to, and contributions from, the third party investor are report ed as adjustments to the noncontrolling interest owners’ equity.

We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests.

We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee.

Cash and Cash Equivalents. Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and are subject to an insignificant risk of changes in value.

Allowance for Doubtful Accounts. Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding each party’s ability

to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.

Inventory. Our product inventories consist primarily of NGLs. Most product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating season requirements of our customers. Product inventories are valued at the lower of cost or market using the average cost method.

Product Exchanges. Exchanges of NGL products are executed to satisfy timing and logistical needs of the exchanging parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, a price differential may be billed or owed. The price differential is recorded as either accounts receivable or accrued liabilities.

Gas Processing Imbalances. Quantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthly as inventory or as a payable using weighted average prices as of the time the imbalance was created. Inventory imbalances receivable are valued at the lower of cost or market; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.

Derivative Instruments. We employ derivative instruments to manage the volatility of cash flows due fluctuating energy prices and interest rates. All derivative instruments not qualifying for the normal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend on whether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain downstream liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales which, under GAAP, are not accounted for as derivatives.

If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transaction occurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. As such, we include the cash flows from commodity derivative instruments in revenues and from interest rate derivative instruments in interest expense.

If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. The ultimate gain or loss on the derivative transaction upon settlement is also recognized as a component of other income and expense.

Targa has allocated to us a portion of our predecessor’s cash flows under its corporate wide hedging program. All of these derivatives are recorded on the balance sheets at fair value. As we were not a direct party to those hedge transactions, we do not apply hedge accounting. Therefore, changes in the unrealized fair value of these allocated hedges are recognized currently on a mark-to-market basis in earnings as a component of other income and expense. Upon the conveyance of the predecessor’s business, we will legally incorporate these cash flow hedges into our hedge accounting program either by executing a new hedge in our name or obtaining a hedge contract novation from the counterparty to the Targa hedge.

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing

basis. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the unrealized gain or loss to earnings in the current period.

We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.

For balance sheet classification purposes, we analyze the fair values of the derivative contracts on a deal by deal basis.

Property, Plant and Equipment. Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets.

Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component.

Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs.

We capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs. Upon disposition or retirement of property, plant and equipment, any gain or loss is charged to operations.

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determina tion of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of operations.

Asset retirement obligations (“AROs”). AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. We depreciate the capitalized ARO using the straight-line method over the period during which the related long-lived asset is expected to provide benefits. After the initial period of ARO recognition, we revise the ARO to reflect the passage of time or revisions to the amounts of estimated cash flows or their timing.

Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. We record these changes as a period cost called accretion expense. Changes resulting from revisions to the timing or the amount of estimated future asset retirement costs increase or decrease the carrying amounts of the ARO asset and liability. Upon settlement, we will recognize a gain or loss to the extent that the settlement cost differs from the recorded ARO amount. See Note 9.

Debt Issue Costs. Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt.

Revenue Recognition. Our primary types of sales and service activities reported as operating revenues include:

sales of natural gas, NGLs and condensate;

natural gas processing, from which we generate revenues through the compression, gathering, treating, and processing of natural gas; and

NGL fractionation, terminalling and storage, transportation and treating.

We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured.

For processing services, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we keep the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on a percent-of-liquids bas is or a fee basis, depending on market conditions. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above. These contracts can be either index-based or fixed price contracts.

We generally report revenues gross in our consolidated statements of operations. Except for fee-based contracts, we act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership.

Environmental Liabilities. Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. See Note 17.

Unit-Based Employee Compensation. We award share-based compensation to non-management directors in the form of restricted common units, which are deemed to be equity awards. Compensation expense on restricted common units is measured by the fair value of the award at the date of grant. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. See Note 14.

Comprehensive Income. Comprehensive income includes net income and other comprehensive income (“OCI”), which includes unrealized gains and losses on derivative instruments that are designated as hedges, and currency translation adjustments.

Income Taxes. We are not subject to federal income taxes. For federal income tax purposes our earnings or losses are included in the tax returns of our individual partners. However, we are subject to a Texas margin tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas.

Net Income per Limited Partner Unit. Net income attributable to Targa Resources Partners LP is allocated to the general partner and the limited partners (common unitholders) in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted average number of outstanding limited partner units during the period.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net income per limited partner unit.

We compute earnings per unit using the two-class method. The two-class method requires that securities that meet the definition of a participating security be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that wou ld prevent it from distributing all of the earnings for a particular period.

The two-class method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights of the general partner, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed our aggregate distributions for such period, the two-class method does not have any impact on our calculation of earnings per limited partner unit. We have no dilutive securities, therefore basic and diluted net income per unit are the same.

Use of Estimates. When preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management must make estimates and assumptions based on information available at the time. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities as of the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of finan cial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative costs (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results, therefore, could differ materially from estimated amounts.

Accounting Pronouncements Recently Adopted

Financial Accounting Standards Board (“FASB”) Codification

In June 2009, FASB issued the FASB Accounting Standards Codification (the “Codification” or “ASC”) as the source of authoritative GAAP recognized by FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. As of the effective date, the Codification supersedes all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification has become non-authoritative.

FASB no longer issues new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASUs”). FASB will not consider ASUs as authoritative in their own right. They will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on changes in the Codification.

Fair Value Measurements

In September 2006, FASB issued guidance regarding fair value measurement that defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. This guidance applies to previous accounting guidance that requires or permits fair value measurements, and accordingly, does not require

any new fair value measurements. The guidance was initially effective as of January 1, 2008, but in February 2008, FASB delayed until periods beginning after November 15, 2008 the effective date for applying the guidance to nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. We adopted the guidance as of January 1, 2008 with respect to financial assets and liabilities within its scope and the impact was not material to our financial statements. As of January 1, 2009, nonfinancial assets and nonfinancial liabilities were also required to be measured at fair value. The adoption of these additional provisions did not have a material impact on our financial statements. See Note 19.

In April 2009, FASB issued guidance for determining fair values when there is no active market or where the price inputs being used represent distressed sales. Specifically, it reaffirms the need to use judgment to ascertain if a formerly active market has become inactive and in determining fair values when markets have become inactive. We adopted the guidance as of June 30, 2009. There have been no material financial statement implications relating to our adoption.

In April 2009, FASB issued guidance that requires disclosures of fair value for any financial instruments not currently reflected at fair value on the balance sheets for all interim periods. We adopted these provisions as of June 30, 2009. There have been no material financial statement implications relating to this adoption. See Note 18.

In January 2010, FASB issued guidance that requires additional disclosures about fair value measurements including transfers in and out of Levels 1 and 2 and a higher level of disaggregation for the different types of financial instruments. For the reconciliation of Level 3 fair value measurements, information about purchases, sales, issuances and settlements should be presented separately. This guidance is effective for annual and interim reporting periods beginning after December 15, 2009 for most of the new disclosures and for periods beginning after December 15, 2010 for the new Level 3 disclosures. Comparative disclosures are not required in the first year the disclosures are required. Our adoption did not have a material impact on our consolidate d financial statements.

Business Combinations

In December 2007, FASB issued guidance that requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed and requires the acquirer to disclose certain information related to the nature and financial effect of the business combination. It also establishes principles and requirements for how an acquirer recognizes any noncontrolling interest in the acquiree and the goodwill acquired in a business combination. This guidance was effective on a prospective basis for business combinations for which the acquisition date is on or after January 1, 2009. For any business combination that takes place subsequent to January 1, 2009, this guidance ma y have a material impact on our financial statements. The nature and extent of any such impact will depend upon the terms and conditions of the transaction. This guidance did not apply to our acquisitions of the Downstream Business or the Permian and Straddle Systems as they represent transfers of net assets between entities under common control.

In April 2009, FASB issued guidance that amends and clarifies application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This update is effective for assets and liabilities arising from contingencies in business combinations for which the acquisition date is on or after January 1, 2009. There have been no material financial statement implications relating to the adoption of this update.

Other

In December 2007, FASB issued guidance that requires all entities to report noncontrolling interests in subsidiaries as a separate component of equity in the consolidated statement of financial position, to clearly identify consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated statement of income, and to provide sufficient disclosure that clearly identifies and distinguishes between the interest of the parent and the interests of noncontrolling owners. It also establishes accounting and reporting standards for changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. We adopted these amended provisions effective January 1, 2009, which required retrospective reclassification of ou r consolidated financial statements for all periods presented in this filing. As a result of

adoption, we have reclassified our noncontrolling interest (formerly minority interest) on our consolidated balance sheets, from a component of liabilities to a component of equity and have also reclassified net income attributable to noncontrolling interest on our consolidated statements of operations, to below net income for all periods presented. Furthermore, we have displayed the portion of other comprehensive income that is attributable to the noncontrolling interest within our consolidated statements of comprehensive income.

In March 2008, FASB issued guidance as to how a master limited partnership (“MLP”) should allocate and present earnings per unit using the two-class method when the MLP’s partnership agreement contains incentive distribution rights. Under the two-class method, current period earnings are allocated to the partners according to the distribution formula for available cash set forth in the MLP’s partnership agreement. Our adoption of this guidance on January 1, 2009, did not impact our consolidated financial position, results of operations or cash flows, or our basic and diluted net income per unit.

In June 2008, FASB issued guidance that requires us to retrospectively adjust our earnings per unit data that result in us recognizing unvested unit-based payment awards as participating units in our basic earnings per unit calculation. Our adoption of this guidance on adopted January 1, 2009 did not have a material impact on our computation of basic can diluted net income per unit.

In May 2009, FASB issued guidance that establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This guidance sets forth (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. It is effective for interim and annual periods ended after June 15, 2009 and should be applied prospectively. Our adoption did not have a material impact on our financial statements.

In June 2009, the SEC Staff issued guidance that amends or rescinds portions of the SEC staff’s interpretive guidance included in the Staff Accounting Bulletin Series in order to make the relevant interpretive guidance consistent with the ASC. Our adoption did not have a material impact on our consolidated financial statements.

In December 2009, the FASB amended consolidation guidance for variable interest entities (“VIEs”). VIEs are entities whose equity investors do not have sufficient equity capital at risk such that the entity cannot finance its own activities. When a business has a controlling financial interest in a VIE, the assets, liabilities and profit or loss of that entity must be included in consolidation. A business enterprise must consolidate a VIE when that enterprise has a variable interest that will cover most of the entity’s expected losses and/or receive most of the entity’s anticipated residual return. The new guidance, among other things, eliminates the scope exception for qualifying special-purpose entities, amends certain guidance for d etermining whether an entity is a VIE, expands the list of events that trigger reconsideration of whether an entity is a VIE, requires a qualitative rather than a quantitative analysis to determine the primary beneficiary of a VIE, requires continuous assessments of whether a company is the primary beneficiary of a VIE and requires enhanced disclosures about a company’s involvement with a VIE. This guidance is effective for us on January 1, 2010 and early adoption is prohibited. At December 31, 2009, we had not identified any interests which qualified as VIEs and our adoption of this new guidance is not expected to have a material impact on our financial statements.

Note 5—Acquisitions under Common Control

On September 24, 2009, we acquired Targa’s interests in the Downstream Business for $530.0 million in the form of $397.5 million in cash and $132.5 million in partnership interests represented by 174,033 general partner units and 8,527,615 common units. This consideration was used to repay $530.0 million of affiliated indebtedness. Targa contributed the remaining $287.3 million of affiliated indebtedness as a capital contribution. See Note 10.

On April 27, 2010, we acquired Targa’s interests in its Permian and Straddle Systems for $420.0 million, effective April 1, 2010. We financed this acquisition substantially through borrowings under our senior secured revolving credit facility. The total consideration was used to repay outstanding affiliated indebtedness of $332.8 million, with the remaining $87.2 million reported as a parent distribution.

The following tables present the impact of combining the Permian and Straddle Systems on our supplemental consolidated financial position and supplemental consolidated results of operations for the dates and periods indicated:

	December 31, 2009
	Historical		Permian
	Targa		and						Targa
	Resources		Straddle						Resources
	Partners LP		Systems			Eliminations			Partners LP
Current assets	$	455.0	$	112.0		$	(49.9	)	$	517.1
Property, plant and equipment, net		1,678.5		305.1			-			1,983.6
Other assets		47.4		2.6			-			50.0
Total assets	$	2,180.9	$	419.7		$	(49.9	)	$	2,550.7

Current liabilities	$	395.9	$	124.9		$	(49.9	)	$	470.9
Long-term debt		908.4		327.0			-			1,235.4
Other long-term liabilities		40.4		19.3			-			59.7

Owners of Targa Resources Partners LP		822.8		-			-			822.8
Net parent investment		-		(51.5	)					(51.5	)
Noncontrolling interest in subsidiary		13.4		-			-			13.4
Total owners' equity		836.2		(51.5	)		-			784.7
Total liabilities and owners' equity	$	2,180.9	$	419.7		$	(49.9	)	$	2,550.7

	December 31, 2008
	Historical			Permian
	Targa			and						Targa
	Resources			Straddle						Resources
	Partners LP			Systems			Eliminations			Partners LP
Current assets	$	496.2		$	68.4		$	(8.7	)	$	555.9
Property, plant and equipment, net		1,719.1			303.1			-			2,022.2
Other assets		99.5			10.4			-			109.9
Total assets	$	2,314.8		$	381.9		$	(8.7	)	$	2,688.0

Current liabilities	$	271.8		$	68.4		$	(8.7	)	$	331.5
Long-term debt		1,470.7			303.8			-			1,774.5
Other long-term liabilities		19.2			13.3			-			32.5

Owners of Targa Resources Partners LP		762.5			-			-			762.5
Net parent investment		(223.5	)		(3.6	)		-			(227.1	)
Noncontrolling interest in subsidiary		14.1			-			-			14.1
Total owners' equity		553.1			(3.6	)		-			549.5
Total liabilities and owners' equity	$	2,314.8		$	381.9		$	(8.7	)	$	2,688.0

	Year Ended December 31, 2009
	Historical			Permian
	Targa			and						Targa
	Resources			Straddle						Resources
	Partners LP			Systems			Eliminations			Partners LP
Revenues	$	4,095.6		$	1,035.9		$	(740.3	)	$	4,391.2
Costs and expenses:
Product purchases		3,585.6			937.0			(713.0	)		3,809.6
Operating expenses		185.1			33.3			(27.3	)		191.1
Depreciation and amortization expenses		101.2			23.9			-			125.1
General and administrative expenses and other		78.1			21.8			-			99.9
		3,950.0			1,016.0			(740.3	)		4,225.7
Income from operations		145.6			19.9			-			165.5
Other income (expense):
Interest expense		(95.4	)		(23.2	)		-			(118.6	)
Other income (expense)		5.0			(16.0	)		-			(11.0	)
Income tax expense		(1.0	)		(0.2	)		-			(1.2	)
Net income (loss)		54.2			(19.5	)		-			34.7
Less: Net income attributable to noncontrolling interest		2.2			-			-			2.2
Net income (loss) attributable to Targa Resources Partners LP	$	52.0		$	(19.5	)	$	-		$	32.5

Net loss attributable to predecessor operations	$	(2.4	)	$	(19.5	)	$	-		$	(21.9	)
Net income allocable to partners		54.4			-			-			54.4

	Year Ended December 31, 2008
	Historical			Permian
	Targa			and						Targa
	Resources			Straddle						Resources
	Partners LP			Systems			Eliminations			Partners LP
Revenues	$	7,502.1		$	1,793.9		$	(1,458.1	)	$	7,837.9
Costs and expenses:
Product purchases		6,950.8			1,645.7			(1,398.8	)		7,197.7
Operating expenses		254.0			32.3			(59.3	)		227.0
Depreciation and amortization expenses		97.8			21.7			-			119.5
General and administrative expenses and other		67.7			23.1			-			90.8
		7,370.3			1,722.8			(1,458.1	)		7,635.0
Income from operations		131.8			71.1			-			202.9
Other income (expense):
Interest expense		(97.1	)		(23.2	)		-			(120.3	)
Other income		17.4			43.1			-			60.5
Income tax expense		(2.4	)		(0.5	)		-			(2.9	)
Net income		49.7			90.5			-			140.2
Less: Net income attributable to noncontrolling interest		0.3			-			-			0.3
Net income attributable to Targa Resources Partners LP	$	49.4		$	90.5		$	-		$	139.9

Net income (loss) attributable to predecessor operations	$	(42.1	)	$	90.5		$	-		$	48.4
Net income allocable to partners		91.5			-			-			91.5

	Year Ended December 31, 2007
	Historical			Permian
	Targa			and						Targa
	Resources			Straddle						Resources
	Partners LP			Systems			Eliminations			Partners LP
Revenues	$	6,843.7		$	1,532.4		$	(1,272.5	)	$	7,103.6
Costs and expenses:
Product purchases		6,302.0			1,396.8			(1,227.3	)		6,471.5
Operating expenses		219.6			34.6			(45.2	)		209.0
Depreciation and amortization expenses		93.5			20.8			-			114.3
General and administrative expenses and other		63.7			26.0			-			89.7
		6,678.8			1,478.2			(1,272.5	)		6,884.5
Income from operations		164.9			54.2			-			219.1
Other expense:
Interest expense		(99.4	)		(23.2	)		-			(122.6	)
Other expense		(27.8	)		(31.4	)		-			(59.2	)
Income tax expense		(2.5	)		(0.4	)		-			(2.9	)
Net income (loss)		35.2			(0.8	)		-			34.4
Less: Net income attributable to noncontrolling interest		0.1			-			-			0.1
Net income (loss) attributable to Targa Resources Partners LP	$	35.1		$	(0.8	)	$	-		$	34.3

Net income (loss) attributable to predecessor operations	$	7.0		$	(0.8	)	$	-		$	6.2
Net income allocable to partners		28.1			-			-			28.1

Note 6—Inventory

Due to fluctuating commodity prices for natural gas liquids, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceeds their net realizable value. These non-cash adjustments are charged to product purchases in the period they are recognized, with the related cash impact in the subsequent period of sale. For 2009, we did not recognize an adjustment to the carrying value of our NGL inventory. As of December 31, 2008 and 2007, we recognized $6.0 million and $0.2 million to reduce the carrying value of NGL inventory to its net realizable value.

Note 7—Property, Plant and Equipment

Property, plant and equipment, at cost, and the related estimated useful lives of the assets were as follows as of the dates indicated:

	December 31,				Estimated useful lives
	2009		2008		(In years)
Gathering systems	$	1,437.2	$	1,384.1	5 to 20
Processing and fractionation facilities		555.7		515.4	5 to 25
Terminalling and natural gas liquids storage facilities		238.5		221.9	5 to 25
Transportation assets		165.5		159.3	10 to 25
Other property, plant and equipment		26.4		23.7	3 to 25
Land		50.0		50.0	-
Construction in progress		15.2		47.9	-
	$	2,488.5	$	2,402.3

Note 8—Investment in Unconsolidated Affiliate

Our unconsolidated investment consists of a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”).

The following table shows the activity related to our unconsolidated investment in GCF for the years indicated:

	Year Ended December 31,
	2009			2008			2007
Beginning of period	$	18.5		$	19.2		$	19.6
Equity in earnings		5.0			3.9			3.5
Cash distributions		(5.0	)		(4.6	)		(3.9	)
End of period	$	18.5		$	18.5		$	19.2

Our allocated cost basis of GCF at our acquisition date was less than our partnership equity balance by approximately $5.2 million. This basis difference is being amortized over the estimated useful life of the underlying fractionating assets (25 years) on a straight-line basis, and is included as a component of our equity in earnings of unconsolidated investments.

Pursuant to the Purchase and Sales Agreement of the Downstream Business acquisition, Targa is entitled to receive cumulative distributions made after September 23, 2009 of up to $4.6 million. As of December 31, 2009, Targa was entitled to $2.3 million of GCF future distributions.

Note 9—Asset Retirement Obligations

Our asset retirement obligations are included in our consolidated balance sheets as a component of other long-term liabilities. The changes in our aggregate asset retirement obligations are as follows:

	Year Ended December 31,
	2009		2008			2007
Beginning of period	$	14.2	$	10.8		$	9.9
Liabilities settled		-		(0.2	)		-
Change in cash flow estimate		-		2.6			0.1
Accretion expense		1.2		1.0			0.8
End of period	$	15.4	$	14.2		$	10.8

Note 10—Debt Obligations

Consolidated debt obligations consisted of the following as of the dates indicated:

	December 31,
	2009			2008
Targa Resources Partners LP:
Senior secured revolving credit facility, variable rate, due February 2012	$	479.2		$	487.7
Senior unsecured notes, 8¼% fixed rate, due July 2016		209.1			209.1
Senior unsecured notes, 11¼% fixed rate, due July 2017		231.3			-
Unamortized discounts, net of premiums		(11.2	)		-
Targa Downstream LP:
Note payable to Parent, 10% fixed rate, due December 2011 (including
accrued interest of $0 and $175,343)		-			744.0
Targa LSNG LP:
Note payable to Parent, 10% fixed rate, due December 2011 (including
accrued interest of $0 and $4,281)		-			29.9
Targa Permian LP:
Note payable to Parent, 10% fixed rate, due December 2011 (including
accrued interest of $36,246 and $24,164)		170.2			158.1
Targa Straddle LP:
Note payable to Parent, 10% fixed rate, due December 2011 (including
accrued interest of $33,408 and $22,272)		156.8			145.7
	$	1,235.4		$	1,774.5

Letters of credit issued	$	108.4		$	123.7

Credit Agreement

On February 14, 2007, we entered into a credit agreement which provided for a five-year $500 million credit facility with a syndicate of financial institutions. On October 24, 2007, we entered into the First Amendment to Credit Agreement which allows us to request commitments under the credit agreement, as supplemented and amended, up to $1 billion. In October 2008, Lehman Bank defaulted on a borrowing request under our senior secured credit facility. Lehman’s commitment under the facility is $19.0 million and is currently unfunded which effectively reduces our total commitments under our credit facility by $19.0 million. Including the Lehman commitment, we currently have $977.5 million committed under the senior secured credit facility, leaving an additional $22.5 million of available comm itments.

The credit facility bears interest at our option, at (1) the higher of the lender’s prime rate or the federal funds rate plus 0.5%, plus an applicable margin ranging from 0% to 1.25% dependent on our total leverage ratio, or (2) LIBOR plus an applicable margin ranging from 1.0% to 2.25% dependent on our total leverage ratio. Our credit facility is secured by substantially all of our assets. During 2009 we paid interest on this variable rate obligation ranging from 1.2% to 4.5% resulting in a weighted average interest rate of 1.7%. As described in Note 15, we have executed interest rate derivative contracts to fix the interest rate on this variable rate obligation.

Our senior secured credit facility restricts our ability to make distributions of available cash to unitholders if a default or an event of default has occurred and is continuing. The senior secured credit facility requires us to maintain a leverage ratio (the ratio of consolidated indebtedness to our consolidated EBITDA) of less than or equal to 5.50 to 1.00 and a senior secured indebtedness ratio (the ratio of senior secured indebtedness to consolidated EBITDA) of less than or equal to 4.50 to 1.00, each subject to certain adjustments. The senior secured credit facility also requires us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated

interest expense) of greater than or equal to 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, as well as upon the occurrence of certain events, including the incurrence of additional permitted indebtedness. In conjunction with a material acquisition, we have the option to increase the leverage ratio to 6.00 to 1.00 and to increase the senior secured indebtedness ratio to 5.00 to 1.00 for a period of up to a year.

Senior Unsecured Notes

We have two issues of unsecured senior notes under Rule 144A and Regulation S of the Securities Act of 1933. On June 18, 2008, we privately placed $250 million in aggregate principal amount at par value of 8¼% senior notes due 2016 (the “8¼% Notes”). On July 6, 2009, we privately placed $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million.

These notes are unsecured senior obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under our credit facility. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by us. These notes are effectively subordinated to all secured indebtedness under our credit agreement, which is secured by substantially all of our assets, to the extent of the value of the collateral securing that indebtedness.

Interest on the 8¼% Notes accrues at the rate of 8¼% per annum and is payable semi-annually in arrears on January 1 and July 1, commencing on January 1, 2009. Interest on the 11¼% Notes accrues at the rate of 11¼% per annum and is payable semi-annually in arrears on January 15 and July 15, commencing on January 15, 2010.

We may redeem up to 35% of the aggregate principal amount of the 8¼% Notes at any time prior to July 1, 2011 (July 15, 2013 for the 11¼% Notes), with the net cash proceeds of one or more equity offerings. We must pay a redemption price of 108.25% of the principal amount (111.25% for the 11 ¼% Notes), plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:

(1)

at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of such redemption; and

(2)

the redemption occurs within 90 days of the date of the closing of such equity offering.

We may also redeem all or a part of the 8¼% Notes at any time prior to July 1, 2012 (July 15, 2013 for the 11¼% Notes) at a redemption price equal to 100% of the principal amount of the notes redeemed plus the applicable premium as defined in the indenture agreement as of, and accrued and unpaid interest and liquidated damages, if any, to the date of redemption.

We may also redeem all or a part of the 8¼% Notes on or after July 1, 2012 (July 15, 2013 for the 11¼% Notes) at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidated damages, if any, on the notes redeemed, if redeemed during the twelve-month period beginning on July 1 (July 15 for the 11¼% Notes) of each year indicated below:

8¼% Notes			11¼% Notes
Year	Redemption %		Year	Redemption %
2012		104.125%	2013	105.625%
2013		102.063%	2014	102.813%
2014 and thereafter		100.000%	2015 and thereafter	100.000%

During 2008, we repurchased $40.9 million face value of our outstanding 8¼% Notes in open market transactions at an aggregate purchase price of $28.3 million, including $1.5 million of accrued interest. We recognized a gain on the debt repurchases of $13.1 million associated with the purchased notes. The repurchased 8¼% Notes were retired and are not eligible for re-issue at a later date.

During 2009, we repurchased $18.7 million face value ($17.8 million carrying value) of our outstanding 11¼% Notes in open market transactions at an aggregated purchase price of $18.9 million plus accrued interest of $0.3 million. We recognized a loss on the debt repurchases of $1.5 million, including $0.4 million in debt issue costs associated with the repurchased notes. The repurchased 11¼% Notes were retired and are not eligible for re-issue at a later date.

The 11¼% Notes are subject to a registration rights agreement dated as of July 6, 2009. Under the registration rights agreement, we are required to file by July 7, 2010 a registration statement with respect to any 11¼% Notes that are not freely transferable without volume restrictions by holders of the 11¼% Notes that are not affiliates of ours. If we fail to do so, additional interest will accrue on the principal amount of the 11¼% Notes. We have determined that the payment of additional interest is not probable. As a result, we have not recorded a liability for any contingent obligation. Any subsequent accruals of a liability or payments made under this registration rights agreement will be charged to earnings as interest expense in the period they are recognized or paid.

Compliance with Debt Covenants

As of December 31, 2009, the Partnership was in compliance with the covenants contained in our various debt agreements.

Affiliated Indebtedness

The contribution of the Permian and Straddle Systems has been treated as a transfer between entities under common control and periods prior to the transfer have been adjusted to present comparative information. On January 1, 2007, Targa contributed to us affiliated indebtedness applicable each of these predecessor businesses. We include the financial effects of this affiliated indebtedness in our consolidated financial statements prepared on common control accounting basis. The following table summarizes the financial effects of this affiliated indebtedness:

					Permian and
	North Texas		Downstream		Straddle
	System		Business		Systems
Original principal December 1, 2005	$	816.2	$	568.7	$	232.2
Interest accrued during 2005 and 2006		88.3		61.8		25.1
Borrowings during 2006		-		9.2		-
Parent debt contributed January 1, 2007		904.5		639.7		257.3
Additional borrowings:
For the year ended December 31, 2007		-		13.0		-
For the year ended December 31, 2008		-		3.4		-
Interest accrued prior to Targa conveyance:
For the year ended December 31, 2007 (2)		9.8		58.5		23.2
For the year ended December 31, 2008		-		59.3		23.2
For the year ended December 31, 2009		-		43.4		23.3
		9.8		161.2		69.7
Outstanding affiliate debt at conveyance date
or December 31, 2009 (1)		914.3		817.3		327.0

Payment (cash and units) (1)		665.7		530.0		-

Affiliate debt contributed at conveyance date	$	248.6	$	287.3	$	-

__________

(1)

The Permian and Straddle Systems were not conveyed to the Partnership until April 2010, at which time the entire affiliate debt balance of $332.8 million was paid as part of the transaction. See Note 5.

(2)

In 2007 Targa also allocated $9.6 million of interest related to the conveyance of the SAOU and LOU Systems.

The stated 10% interest rate in the formal debt arrangement was not indicative of prevailing external rates of interest including that incurred under our credit facility which is secured by substantially all of our assets. Using the weighted average rates incurred under Targa’s outstanding borrowings, pro forma affiliated interest expense would have been reduced by $33.9 million, $22.2 million and $14.1 million for the years ended December 31, 2009, 2008 and 2007. The pro forma interest expense adjustment for the Downstream Business and Permian and Straddle Systems acquisitions has been calculated by applying the weighted average rates of 4.9%, 7.3% and 8.3% that Targa incurred under its outstanding borrowings for the periods indicated. The pro forma interest adjustment for the North Texas System acquisition has been calculated by applying the weighted average r ate of 6.9% that we incurred under our credit facility for the period from January 1, 2007 to February 13, 2007.

Note 11—Partnership Equity and Distributions

General. 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.

Conversion of Subordinated Units. Under the terms of our amended and restated Partnership Agreement, all 11,528,231 subordinated units converted to common units on a one-for-one basis on May 19, 2009. The conversion had no impact upon our calculation of earnings per unit since the subordinated units were included in the basic and diluted earnings per unit calculation.

Public Offering of Common Units. On August 12, 2009, we completed a unit offering under our shelf registration statement of 6,900,000 common units representing limited partner interests in us at a price of $15.70 per common unit. Net proceeds of the offering were $105.3 million, after deducting underwriting discounts, commissions and offering expenses, and including the general partner’s proportionate capital contribution of $2.2 million. We used a portion of the proceeds to repay $103.5 million of outstanding borrowings under our senior secured revolving credit facility.

Distributions. Distributions will generally be made 98% to the common unitholders and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.3375 per unit, plus arrearages.

Under the quarterly incentive distribution provisions, generally our general partner is entitled to 13% of amounts distributed in excess of $0.3881 per unit, 23% of the amounts distributed in excess of $0.4219 per unit and 48% of amounts distributed in excess of $0.50625 per unit. Our general partner interest received no incentive distributions prior to the fourth quarter of 2007.

The following table shows the amount of cash distributions we paid to date:

		Distributions Paid										Distributions
	For the Three	Limited Partners				General Partner						per limited
Date Paid	Months Ended	Common		Subordinated		Incentive			2%	Total		partner unit
		(In millions, except per unit amounts)
2009
November 14, 2009	September 30, 2009	$	31.9	$	-	$	2.6	$	0.7	$	35.2	$	0.5175
August 14, 2009	June 30, 2009		23.9		-		2.0		0.5		26.4		0.5175
May 15, 2009	March 31, 2009		18.0		5.9		1.9		0.5		26.3		0.5175
February 13, 2009	December 31, 2008		18.0		6.0		1.9		0.5		26.4		0.5175

2008
November 14, 2008	September 30, 2008	$	17.9	$	6.0	$	1.9	$	0.5	$	26.3	$	0.5175
August 14, 2008	June 30, 2008		17.8		5.9		1.7		0.5		25.9		0.5125
May 15, 2008	March 31, 2008		14.5		4.8		0.2		0.4		19.9		0.4175
February 14, 2008	December 31, 2007		13.8		4.6		0.1		0.4		18.9		0.3975

2007
November 14, 2007	September 30, 2007	$	11.1	$	3.9	$	-	$	0.3	$	15.3	$	0.3375
August 14, 2007	June 30, 2007		6.5		3.9		-		0.2		10.6		0.3375
May 15, 2007	March 31, 2007		3.3		1.9		-		0.1		5.3		0.1688

Subsequent Events. On January 19, 2010, we completed a public offering of 5,500,000 common units representing limited partner interests in the Partnership (“common units”) under our existing shelf registration statement on Form S-3 at a price of $23.14 per common unit ($22.17 per common unit, net of underwriting discounts), providing net proceeds of $121.9 million. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 825,000 common units at $23.14 per common unit, providing net proceeds of $18.3 million. We used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under our senior secured credit facility.

On February 12, 2010, we paid a cash distribution of $0.5175 per unit on our outstanding common units to unitholders of record on February 3, 2010, for the three months ended December 31, 2009. The total distribution paid was $38.8 million, with $24.8 million paid to our non-affiliated common unitholders and $10.4 million, $0.8 million and $2.8 million paid to Targa for its common unit ownership, general partner interest and incentive distribution rights.

Note 12—Insurance Claims

We recognize income from business interruption insurance in our consolidated statements of operations as a component of revenues from third parties in the period that a proof of loss is executed and submitted to the insurers for payment. For 2009, income from business interruption insurance resulting from the effects of Hurricane Ike was $11.7 million. For 2008 and 2007, income from business interruption insurance resulting from the effects of Hurricanes Katrina and Rita was $31.7 million and $7.3 million. In addition, we received $0.5 million and $0.6 million during 2009 and 2008 as a result of fire damage at a third-party plant related to our Marketing and Distribution segment.

Hurricanes Katrina and Rita

Hurricanes Katrina and Rita affected certain of our gulf coast facilities in 2005. Our final purchase allocation for these assets in October 2005 included a $52.2 million receivable for insurance claims related to property damage caused by Katrina and Rita. During 2008, our cumulative receipts exceeded such amount, and we recognized a gain of $11.5 million, which is shown in the Supplemental Consolidated Statement of Operations as other income. The

insurance claim process is now complete with respect to Katrina and Rita for property damage and business interruption insurance.

Hurricanes Gustav and Ike

Under common control accounting, we must include the effects of insurance claims on predecessor operations in our retrospectively adjusted financial statements. However, as part of the Downstream and the Permian and Straddle acquisition agreements, Targa retained the right to receive any future insurance proceeds from claims associated with Gustav and Ike.

Note 13—Revenue Reclassification

During 2009, we reclassified NGL marketing fractionation and other service fees to revenues that were originally recorded in product purchase costs. The reclassification increased revenues and product purchases for 2008 and 2007 by $28.6 million and $27.6 million. This reclassification had no impact on our income from operations, net income, financial position or cash flows.

Note 14—Accounting for Unit-Based Compensation

In 2007, the parent of Targa, Targa Resources Investments Inc. (“Targa Investments”), adopted a Long-Term Incentive Plan (“LTIP”) for employees, consultants and directors of us and our affiliates who perform services for Targa Investments or its affiliates. The LTIP provides for the grant of cash-settled performance units, which are linked to the performance of our common units and may include distribution equivalent rights (“DERs”). The LTIP is administered by the compensation committee of the board of directors of Targa Investments. Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit.

Grants outstanding under Targa Investments’ LTIP were 275,400 under the 2007 program, 135,800 under the 2008 program, 534,900 units under the 2009 program and 90,403 units under the 2010 program. During 2009, there were forfeitures under the LTIP of 12,025 units. Grants under the 2007, 2008, 2009 and 2010 programs are payable in August 2010, July 2011, June 2012 and June 2013. Each vested performance unit will entitle the grantee to a cash payment equal to the then value of a Partnership common unit, including DERs. The amount of cash payments on awarded performance units is based on the total return per our common unit through the end of the performance period, relative to the total return of a defined peer group.

Because the performance units require cash settlement, they have been accounted for as liabilities by Targa. The fair value of a performance unit is the sum of: (i) the closing price of one of our common units on the reporting date; (ii) the fair value of an at-the-money call option on a performance unit with a grant date equal to the reporting date and an expiration date equal to the last day of the performance period; and (iii) estimated DERs. The fair value of the call options was estimated using a Black-Scholes option pricing model with a dividend yield of 8.5%, and with risk-free rates and volatilities of 0.3% and 42% under the 2007 program, 0.8% and 61% under the 2008 program, 1.4% and 61% under the 2009 program and 1.4% and 52% under the 2010 program.

At December 31, 2009, the aggregate fair value of performance units expected to vest was $23.5 million. The remaining recognition period for the unrecognized compensation cost is approximately three and a half years. During 2009, 2008 and 2007 Targa recognized compensation expense of $10.5 million, $0.1 million and $2.7 million related to the performance units. Based on Targa’s allocation methodology, we recognized allocated general and administrative expenses related to the performance units of $6.6 million, $0.1 million and $1.9 million for 2009, 2008 and 2007.

During 2009 and 2008, Targa Resources GP LLC, the general partner of the Partnership, also made equity-based awards of 32,000 and 16,000 restricted common units of the Partnership (4,000 and 2,000 restricted common units of the Partnership to each of the Partnership’s and Targa Investments’ non-management directors) under its (“Incentive Plan”). The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date. During 2009 and 2008, we recognized compensation expense of $0.3 million related to these awards with an offset to common equity. We estimate that the remaining fair value of $0.2 million will be recognized in expense over approximately two years. As of December 31, 200 9 there were 41,993 unvested restricted common units outstanding under this plan.

The following table summarizes our unit-based awards for each of the periods indicated (in units and dollars):

	Year Ended
	December 31, 2009
Outstanding at beginning of year		26,664
Granted		32,000
Vested		(16,671	)
Outstanding at end of year		41,993
Weighted average grant date fair value per share	$	12.88

Subsequent Event. On January 22, 2010, TRGP made equity-based awards of 2,250 restricted common units (15,750 total restricted common units) of the Partnership to each of ours and Targa Investments’ non-management directors under the Incentive Plan. The awards will settle with the delivery of common units and are subject to three year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date.

Note 15—Derivative Instruments and Hedging Activities

Commodity Hedges

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 baskets of ethane, propane, normal butane, iso-butane and natural gasoline based upon our expected equity NGL composition, as well as specific NGL hedges of ethane and propane. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, our NGL hedges are based on published index prices for delivery at Mont Belvieu and our natural gas hedges are based on published index prices for delivery at Columbia Gulf, Houston Ship Channel, Mid-Continent and Waha, which closely approximate our actual NGL and natural gas 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. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with our underlying West Texas condensate equity volumes.

At December 31, 2009, the notional volumes of our commodity hedges were:

Commodity	Instrument	Unit	2010		2011		2012		2013
Natural Gas	Swaps	MMBtu/d		23,022		18,930		13,230		5,360
NGL	Swaps	Bbl/d		7,081		4,924		3,250		-
NGL	Floors	Bbl/d		-		223		259		-
Condensate	Swaps	Bbl/d		690		566		308		308

Interest Rate Swaps

As of December 31, 2009, we had $479.2 million outstanding under our credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in

market interest rates we have entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:

			Notional	Fair
Expiration Date	Fixed Rate		Amount	Value
2010		3.67%	$300 million	$	(7.8	)
2011		3.52%	300 million		(5.1	)
2012		3.40%	300 million		(0.6	)
2013		3.39%	300 million		1.6
01/01 - 04/24/2014		3.39%	300 million		1.3
				$	(10.6	)

All interest rate swaps and interest rate basis swaps have been designated as cash flow hedges of variable rate interest payments on borrowings under our credit facility.

The following schedules reflect the fair values of derivative instruments in our financial statements:

	Asset Derivatives					Liability Derivatives
	Balance	Fair Value as of				Balance	Fair Value as of
	Sheet	December 31,				Sheet	December 31,
	Location	2009		2008		Location	2009		2008
Derivatives designated as hedging instruments
Commodity contracts	Current assets	$	24.5	$	88.2	Current liabilities	$	7.8	$	-
	Long-term assets		7.0		68.3	Long-term liabilities		24.2		0.1

Interest rate contracts	Current assets		0.2		-	Current liabilities		8.0		8.0
	Long-term assets		1.9		-	Long-term liabilities		4.7		9.6
Total derivatives designated
as hedging instruments			33.6		156.5			44.7		17.7

Derivatives not designated as hedging instruments
Commodity contracts	Current assets		1.1		3.6	Current liabilities		0.6		3.7
	Long-term assets		0.3		-	Long-term liabilities		-		-

Allocated commodity contracts	Current assets		2.4		7.9	Current liabilities		5.7		-
	Long-term assets		1.7		8.8	Long-term liabilities		6.6		-
Total derivatives not designated
as hedging instruments			5.5		20.3			12.9		3.7

Total derivatives		$	39.1	$	176.8		$	57.6	$	21.4

The fair value of 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.

Our earnings are also affected by the use of the mark-to-market method of accounting for derivative financial 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 sheets and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction affects earnings. 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. During 2009, 2008 and 2007, we recorded mark-to-market gains (losses) of ($15.2) million, $30.6 million and ($61.9) million.

The following tables reflect amounts reclassified from OCI to revenue and expense:

	Amount of Gain (Loss)
	Reclassified from OCI into
Location of Gain (Loss)	Income (Effective Portion)
Reclassified from	Year Ended December 31,
OCI into Income	2009			2008			2007
Interest expense, net	$	(10.4	)	$	(2.7	)	$	0.2
Revenues		45.7			(33.7	)		(1.0	)
	$	35.3		$	(36.4	)	$	(0.8	)

	Amount of Gain (Loss)
	Recognized in Income on
Location of Gain (Loss)	Derivatives (Ineffective Portion)
Reclassified from	Year Ended December 31,
OCI into Income	2009			2008		2007
Interest expense, net	$	-		$	-	$	-
Revenues		(0.1	)		-		-
	$	(0.1	)	$	-	$	-

	Gain (Loss)
	Recognized in OCI on
Derivatives in	Derivatives (Effective Portion)
Cash Flow Hedging	Year Ended December 31,
Relationships	2009			2008			2007
Interest rate contracts	$	(2.1	)	$	(19.0	)	$	(1.7	)
Commodity contracts		(72.6	)		129.9			(105.6	)
	$	(74.7	)	$	110.9		$	(107.3	)

		Amount of Gain (Loss) Recognized
Derivatives Not	Location of Gain (Loss)	in Income on Derivatives
Designated as Hedging	Recognized in Income	Year Ended December 31,
Instruments	on Derivatives	2009			2008			2007
Realized gain (loss) on allocated commodity contracts	Other income (expense)	$	(24.9	)	$	45.3		$	(24.7	)
Unrealized gain (loss) on allocated commodity contracts	Other income (expense)		9.7			(14.7	)		(37.2	)
		$	(15.2	)	$	30.6		$	(61.9	)

The following table shows the unrealized gains (losses) included in OCI:

	Year Ended December 31,
	2009			2008			2007
	(In millions)
Unrealized net gains (losses) on commodity hedges	$	(28.7	)	$	89.6		$	(74.0	)
Unrealized net losses on interest rate hedges	$	(9.2	)	$	(17.6	)	$	(1.2	)

Hedge ineffectiveness of $0.1 million was recorded in 2009. There were no adjustments for hedge ineffectiveness related to commodity hedges for 2008 or 2007. There were no adjustments for hedge ineffectiveness related to interest rate hedges for 2009, 2008 or 2007.

As of December 31, 2009, deferred net losses of $10.1 million on commodity hedges and $7.8 million on interest rate hedges recorded in OCI are expected to be reclassified to expense during the next twelve months.

In July 2008, we paid $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. Prior to the terminations, these swaps were designated as hedges. Deferred losses of $27.9 million will be reclassified from OCI as a non-cash reduction of revenue during 2010 when the hedged forecasted sales transactions occur. During 2009 and 2008, deferred losses of $38.8 million and $20.8 million related to the terminated swaps were reclassified from OCI as a non-cash reduction to revenue. We also entered into new natural gas and NGL commodity swaps at then current market prices that match the production volumes of the terminated swaps through 2010.

In May 2008 we entered into certain NGL derivative contracts with Lehman Brothers Commodity Services Inc., a subsidiary of Lehman Brothers Holdings Inc. (“Lehman”). Due to Lehman’s bankruptcy filing, it is unlikely that we will receive full or partial payment of any amounts that may become owed to us under these contracts. Accordingly, we discontinued hedge accounting treatment for these contracts in July 2008. Deferred losses of $0.1 million and $0.3 million will be reclassified from OCI to revenues during 2011 and 2012 when the forecasted transactions related to these contracts are expected to occur. During 2008, we recognized a non-cash mark-to-market loss on derivatives of $1.0 million to adjust the fair value of the Lehman derivative contracts to zero. In October 2008, we terminated the Lehman derivative contracts.

See Note 4, Note 16, Note 19 and Note 23 for additional disclosures related to derivative instruments and hedging activities.

Note 16—Related-Party Transactions

Targa Resources, Inc.

On February 14, 2007, as part of the North Texas conveyance, we entered into an Omnibus Agreement with Targa, our general partner and others that addressed the reimbursement of our general partner for costs incurred on our behalf and indemnification matters. In conjunction with subsequent Targa asset conveyances, the parties amended the Omnibus Agreement to run through April 2013 and to have Targa provide general and administrative and other services to us associated with (1) our existing assets and any future Targa conveyances and (2) subject to mutual agreement, our future acquisitions from third parties. Targa, at its option, may terminate any or all of the provisions of this agreement, other than the indemnification provisions described in Note 17, if our general partner is removed without cause and the units held by our general partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will terminate in the event of a change of control of us or our general partner.

Reimbursement of Operating and General and Administrative Expense

Pursuant to the Omnibus Agreement with respect to the North Texas System, Targa capped the North Texas Systems’ general and administrative expenses at $5.0 million annually through February 14, 2010. There is not a cap of expenses related to any of the other Targa conveyances. However, Targa will provide distribution support to us in the form of a reduced general and administrative expense billings, up to $8.0 million per quarter, if necessary, for a 1.0 times distribution coverage ratio. The distribution support is in effect for the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011. No distribution support was required for the fourth quarter of 2009. We filed the Omnibus Agreement, as amended, with the SEC.

Centralized Cash Management

Prior to the Targa conveyances of assets, the excess cash from these subsidiaries was held in separate bank accounts and swept to a centralized account under Targa. Beginning with the contribution of these systems to us, our consolidated subsidiaries’ bank accounts have been maintained under our separate centralized cash management system.

Contracts with Affiliates

Sales to and purchases from affiliates. We routinely conduct business with other subsidiaries of Targa. The related-party transactions result primarily from purchases and sales of natural gas and purchases of NGL products. Prior to February 14, 2007, all of our expenditures were paid through Targa, resulting in intercompany transactions. Prior to February 14, 2007, settlement of these intercompany transactions was through adjustments to partners’ capital accounts. After each acquisition all intercompany transactions with the acquired assets were settled in cash.

Allocations of long-term debt, debt issue costs, interest rate swaps and interest expense. The allocated debt, debt issue costs and interest rate swaps for the North Texas System and the Downstream Business were settled through deemed partner contributions of $846.3 million and $478.7 million on January 1, 2007. On October 23, 2007, the allocated debt, debt issue costs and interest rate swaps related to the SAOU and LOU Systems were settled through a deemed partner contribution of $179.6 million.

The following table summarizes transactions with Targa and Targa affiliates. Management believes these transactions are executed on terms that are fair and reasonable.

	Year Ended December 31,
	2009		2008		2007
Cash
Sales to affiliates	$	16.0	$	50.7	$	21.7
Purchases from affiliates		321.3		418.1		312.9
Parent allocation of payroll and related
costs included in operating expense		54.0		53.8		59.8
Parent allocation of general and administrative expense		84.1		76.3		86.2
Cash distributions to Targa based on unit ownership		32.9		27.0		10.4
Distributions to Targa, net		99.6		259.9		944.8
Noncash
Unit distributions to Targa		132.5		-		-
Settlement of affiliated indebtedness		287.3		-		248.6
Parent allocation of interest expense		-		-		19.4
Parent contribution of affiliate debt		-		-		257.3
Affiliate interest expense accrued		66.6		82.4		81.7
Parent allocation of debt		-		-		284.8
Parent allocation of debt issue costs		-		-		9.7

For the period from January 1, 2007 up to the date of conveyance, deemed net capital distributions from us were:

	Year Ended December 31,
	2009		2008		2007
North Texas System (through February 13, 2007)	$	-	$	-	$	0.5
SAOU and LOU Systems (through October 23, 2007)		-		-		133.6
Downstream Business (through September 23, 2009)		71.2		166.1		(26.0	)
Permian and Straddle Systems		28.3		93.8		97.3

Transactions with GCF

For the years 2009, 2008 and 2007, transactions with GCF which were included in revenues totaled $0.2 million, $0.5 million and $4.5 million. For the same periods, transactions included in costs and expenses were $1.4 million, $3.5 million and $3.3 million. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Relationships with Warburg Pincus LLC

Chansoo Joung and Peter Kagan, two of the directors of Targa, are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. We purchased $9.7 million and $4.8 million of product from Broad Oak during 2009 and 2008. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Relationships with Bank of America ("BofA")

Equity

An affiliate of BofA is an equity investor in Targa Investments, which indirectly owns our general partner.

Financial Services

BofA is a lender and an administrative agent under our senior secured credit facility.

Hedging Arrangements

We have entered into various commodity derivative transactions with BofA. The following table shows our open commodity derivatives with BofA as of December 31, 2009:

Period

Commodity

Daily Volumes

Average Price

Index

Jan 2010 - Dec 2010

Natural Gas

3,289

MMBtu

7.39

per MMBtu

IF-WAHA

Jan 2010 - Jun 2010

Natural Gas

663

MMBtu

8.16

per MMBtu

NY-HH

Jan 2010 - Dec 2010

Condensate

181

BBl

69.28

per Bbl

NY-WTI

As of December 31, 2009, the fair value of these open positions was an asset of $0.9 million. During 2009, 2008 and 2007, we received from (paid to) BofA $33.5 million, ($22.0) million and $6.9 million in commodity derivative settlements.

Commercial Relationships

We have executed NGL sales and purchase transactions on the spot market with BofA. For the years 2009, 2008 and 2007, sales to BofA which were included in revenues totaled $0.5 million, $4.4 million and $18.1 million. For the same periods, purchases from BofA were $0.3 million, $0.8 million and $9.4 million.

Note 17—Commitments and Contingencies

Future non-cancelable commitments related to certain contractual obligations are presented below:

	Payments Due by Period
	Total		2010		2011		2012		2013		2014		Thereafter
Operating leases (1)	$	38.0	$	8.9	$	6.5	$	6.2	$	3.3	$	2.6	$	10.5
Capacity payments (2)		2.7		2.0		0.7		-		-		-		-
Land site lease and right-of-way (3)		20.4		1.4		1.3		1.3		1.2		1.0		14.2
	$	61.1	$	12.3	$	8.5	$	7.5	$	4.5	$	3.6	$	24.7

__________

(1)

Include minimum lease payment obligations associated with gas processing plant site leases and railcar leases.

(2)

Consist of capacity payments for firm transportation contracts.

(3)

Provide for surface and underground access for gathering, processing, and distribution assets that are located on property not owned by us; agreements expire at various dates through 2099.

Total expenses related to operating leases, capacity payments and land site lease and right-of-way agreements were:

	Year Ended December 31,
	2009		2008		2007
Operating leases	$	10.7	$	11.3	$	13.1
Capacity payments		3.4		3.1		2.9
Land site lease and right-of-way		3.5		4.6		4.0

Environmental

Under the Omnibus Agreement, as amended, Targa indemnified us for pre-closing environmental claims related to our acquisitions for a period of two years from the dates of the acquisitions, except for the North Texas System, which was for a period of three years.

Our environmental liabilities not covered by the Omnibus Agreement are for ground water assessment and remediation and such reserves were less than $0.1 million as of December 31, 2009.

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 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, except for the items more fully described below.

On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc. and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU System from ConocoPhillips and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October&# 160;2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal. On February 3, 2009, the parties presented oral arguments to the 14th Court of Appeals in Houston, Texas. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.

Subsequent event. On February 23, 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety.

Note 18—Fair Value of Financial Instruments

We have determined the estimated fair values of our assets and liabilities classified as financial instruments using available market information and valuation methodologies described below. We apply considerable judgment when interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value.

The carrying value of the senior secured revolving credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The carrying value of the notes payable to Parent at December 31, 2009 and 2008 approximates their fair value as they were settled at their stated amount at the time of conveyance of the affected assets. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt as of the dates indicated in the following table:

	As of December 31,
	2009				2008
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior unsecured notes, 8¼% fixed rate	$	209.1	$	206.5	$	209.1	$	128.3
Senior unsecured notes, 11¼% fixed rate		231.3		253.5		-		-

Note 19—Fair Value Measurements

We categorize the inputs to the fair value of our financial assets and liabilities using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:

Level 1 – observable inputs such as quoted prices in active markets;

Level 2 – inputs other than quoted prices in active markets that are either directly or indirectly observable; and

Level 3 – unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain customers. 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. 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 following tables present the fair value of our financial assets and liabilities according to the fair value hierarchy. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

As of December 31, 2009	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	37.0	$	-	$	37.0	$	-
Assets from interest rate derivatives		2.1		-		2.1		-
Total assets	$	39.1	$	-	$	39.1	$	-
Liabilities from commodity derivative contracts	$	44.9	$	-	$	33.2	$	11.7
Liabilities from interest rate derivatives		12.7		-		12.7		-
Total liabilities	$	57.6	$	-	$	45.9	$	11.7

As of December 31, 2008	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	176.8	$	-	$	42.5	$	134.3
Assets from interest rate derivatives		-		-		-		-
Total assets	$	176.8	$	-	$	42.5	$	134.3
Liabilities from commodity derivative contracts	$	3.9	$	-	$	3.9	$	-
Liabilities from interest rate derivatives		17.5		-		17.5		-
Total liabilities	$	21.4	$	-	$	21.4	$	-

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
Balance, December 31, 2007	$	(94.7	)
Unrealized gains (losses) included in OCI		99.1
Included in earnings		46.1
Purchases		2.9
Terminations		77.8
Settlements		3.1
Balance, December 31, 2008		134.3
Unrealized gains (losses) included in OCI		(37.7	)
Included in earnings		(19.4	)
Settlements		(31.0	)
Transfers out of Level 3 (1)		(57.9	)
Balance, December 31, 2009	$	(11.7	)

________

(1)

During 2009, we reclassified certain of our NGL derivative contracts from Level 3 (unobservable inputs in which little or no market data exist) to Level 2.

Note 20—Segment Information

In connection with the April 2010 acquisition of Targa’s interest in the Permian and Straddle Systems and its impact on our structure used for internal management purposes, an updated evaluation of our reportable segments was performed during the second quarter of 2010. As a result, our operations are now presented under four reportable segments: (1) Field Gathering and Processing, (2) Coastal Gathering and Processing, (3) Logistics Assets and

(4) Marketing and Distribution. Prior period information in this report has been revised to conform to the 2010 reported segment presentation.

Prior to the second quarter of 2010, we reported our results under four segments: (1) Natural Gas Gathering and Processing, (2) Logistics Assets, (3) NGL Distribution and Marketing and (4) Wholesale Marketing. The increase in our Coastal Gathering and Processing businesses as a result of our acquisition of the Permian and Straddle Systems, and consideration of underlying operational and economic differences between Field and Coastal gathering and processing systems led to more granular analysis of the Natural Gas Gathering and Processing results. Also, we have aggregated the previously separately reported NGL Distribution and Marketing segment and Wholesale Marketing segment into one reportable segment, Marketing and Distribution. This combined marketing segment reflects significant operational interrelationships am ong the Marketing and Distribution activities apparent in our current business model.

The Natural Gas 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 natural gas liquids and removing impurities. The Field Gathering and Processing segment assets are located in North Texas and the Permian Basin and the Coastal Gathering and Processing segment assets are located in the onshore region of the Louisiana Gulf Coast and the Gulf of Mexico.

The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes (1) marketing our own natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied petroleum gas 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; and (4) marketing natural gas available to us from our Gathering and Processing segments and the purchase and resale of natural gas in selected United States markets.

Our reportable segment information is shown in the following tables:

	Year Ended December 31, 2009
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other		Eliminations			Total
Revenues from third parties	$	72.3	$	387.8	$	76.7	$	3,797.1	$	41.3	$	-		$	4,375.2
Revenues from affiliates		-		-		-		16.0		-		-			16.0
Intersegment revenues		621.1		366.4		79.5		321.4		-		(1,388.4	)		-
Revenues	$	693.4	$	754.2	$	156.2	$	4,134.5	$	41.3	$	(1,388.4	)	$	4,391.2
Operating margin	$	129.4	$	62.5	$	74.3	$	83.0	$	41.3	$	-		$	390.5
Other financial information:
Total assets	$	1,290.9	$	272.1	$	395.9	$	442.4	$	39.1	$	110.3		$	2,550.7
Capital expenditures	$	42.0	$	12.6	$	15.8	$	16.0	$	-	$	-		$	86.4

	Year Ended December 31, 2008
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other			Eliminations			Total
Revenues from third parties	$	176.7	$	776.3	$	69.1	$	6,797.5	$	(32.4	)	$	-		$	7,787.2
Revenues from affiliates		-		-		-		50.7		-			-			50.7
Intersegment revenues		1,204.6		691.2		103.4		568.8		-			(2,568.0	)		-
Revenues	$	1,381.3	$	1,467.5	$	172.5	$	7,417.0	$	(32.4	)	$	(2,568.0	)	$	7,837.9
Operating margin	$	267.6	$	96.6	$	40.1	$	41.3	$	(32.4	)	$	-		$	413.2
Other financial information:
Total assets	$	1,334.2	$	278.6	$	402.9	$	356.9	$	176.8		$	138.6		$	2,688.0
Capital expenditures	$	62.1	$	9.3	$	37.2	$	4.2	$	-		$	-		$	112.8

	Year Ended December 31, 2007
	Field Gathering and Processing		Coastal Gathering and Processing		Logistics Assets		Marketing and Distribution		Other			Eliminations			Total
Revenues from third parties	$	127.7	$	578.2	$	53.5	$	6,330.0	$	(7.5	)	$	-		$	7,081.9
Revenues from affiliates		-		-		-		21.7		-			-			21.7
Intersegment revenues		1,008.4		691.7		81.0		370.2		-			(2,151.3	)		-
Revenues	$	1,136.1	$	1,269.9	$	134.5	$	6,721.9	$	(7.5	)	$	(2,151.3	)	$	7,103.6
Operating margin	$	222.0	$	90.4	$	32.8	$	85.4	$	(7.5	)	$	-		$	423.1
Other financial information:
Total assets	$	1,363.2	$	339.7	$	384.1	$	931.3	$	12.2		$	91.8		$	3,122.3
Capital expenditures	$	46.6	$	17.6	$	34.2	$	0.8	$	-		$	-		$	99.2

The following table shows our revenues by product and services for each period presented:

	Year Ended December 31,
	2009		2008			2007
Natural gas sales	$	789.0	$	1,549.1		$	1,169.4
NGL sales		3,299.8		6,028.9			5,715.2
Condensate sales		76.5		106.1			81.8
Fractionation & Treating fees		58.5		66.8			52.6
Storage & Terminalling fees		40.9		33.0			30.2
Transportation fees		43.4		39.6			34.1
Gas processing fees		18.2		18.1			18.8
Hedge Settlements		45.7		(33.7	)		(1.0	)
Business interruption insurance		12.2		32.3			7.3
Other		7.0		(2.3	)		(4.8	)
	$	4,391.2	$	7,837.9		$	7,103.6

The following table is a reconciliation of operating margin to net income for each period presented:

	Year Ended December 31,
	2009			2008			2007
Reconciliation of operating margin to net income (loss):
Operating margin	$	390.5		$	413.2		$	423.1
Depreciation and amortization expense		(125.1	)		(119.5	)		(114.3	)
General and administrative expense		(100.6	)		(85.4	)		(89.8	)
Interest expense, net		(118.6	)		(120.3	)		(122.6	)
Income tax expense		(1.2	)		(2.9	)		(2.9	)
Other, net		(10.3	)		55.1			(59.1	)
Net income (loss)	$	34.7		$	140.2		$	34.4

Note 21—Other Operating Income

Our other operating (income) expense consists of the following items for the periods indicated:

	Year Ended December 31,
	2009			2008			2007
Casualty loss	$	(0.7	)	$	11.3		$	-
Gain on sale of assets		-			(5.9	)		(0.1	)
	$	(0.7	)	$	5.4		$	(0.1	)

Note 22—Supplemental Cash Flow Information

The following table provides supplemental cash flow information for each period presented:

	Year Ended December 31,
	2009		2008		2007
Cash:
Interest paid	$	27.0	$	29.3	$	15.5
Non-cash:
Net settlement of allocated indebtedness and debt issue costs		287.3		-		941.5
Net contribution of affiliated receivables		-		-		184.5
Non-cash long-term debt allocation of payments from Parent		-		-		(419.3	)
Debt issue costs allocated from Parent		-		-		(9.7	)
Like-kind exchange of property, plant and equipment		-		5.8		-
Inventory line-fill transferred to property, plant and equipment		9.8		-		(0.2	)
Issuance of Common Units in Downstream Acquisition		129.8		-		-
Issuance of General Partner Units in Downstream Acquisition		2.7		-		-

Note 23—Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

We operate in the midstream energy industry. Our business activities include gathering, transporting, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by (i) changes in the commodity prices of these hydrocarbon products and (ii) changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate

and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

Our profitability could be impacted by a decline in the volume of natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and condensate handled by our facilities.

A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, as well as changes in interest rates. The fair value of our commodity and interest rate 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. These contracts may expose us to the risk of financial loss in certain circumstances. 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.

Commodity Price Risk. A majority of the revenues from our natural gas gathering and processing business are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes, as payment for services. The prices of natural gas and NGLs are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into commodity derivative 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.

In an effort to reduce the variability of our cash flows we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2010 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGL 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 adv ance 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) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market 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.

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our variable rate borrowings under our credit facility. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement.

Counterparty Risk – Credit and Concentration

Derivative Counterparty Risk

Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.

We have master netting agreements with most of our hedge counterparties. These netting agreements allow us to net settle asset and liability positions with the same counterparties. As of December 31, 2009, we had $7.4 million in liabilities to offset the default risk of counterparties with which we also had asset positions of $25.9 million as of that date.

Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to us at the reporting date. At such times, these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.

As of December 31, 2009, affiliates of Goldman Sachs and Bank of America (“BofA”) accounted for 93% and 5% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs and BofA are major financial institutions, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

Customer Credit Risk

We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met. The following table summarizes the activity affecting our allowance for bad debts:

	Year Ended December 31,
	2009			2008		2007
Balance at beginning of year	$	9.2		$	0.9	$	0.8
Additions		-			8.3		0.2
Deductions		(1.3	)		-		(0.1	)
Balance at end of year	$	7.9		$	9.2	$	0.9

Significant Commercial Relationships

We are exposed to concentration risk when a significant customer or supplier accounts for a significant portion of our business activity. The following table lists the percentage of our consolidated sales or purchases with customers and suppliers which accounted for more than 10% of our consolidated revenues and consolidated product purchases for the periods indicated:

	Year Ended December 31,
	2009		2008		2007
% of consolidated revenues
Chevron Phillips Chemical Company LLC		16%		20%		21%
% of product purchases
Louis Dreyfus Energy Services L.P.		11%		9%		7%

Casualty or Other Risks

Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverages which are customary for the nature and scope of our operations. A portion of the insurance costs described above is allocated to us by Targa through the allocation methodology as prescribed in the Omnibus Agreement described in Note 16.

Management believes that Targa has adequate insurance coverage, although insurance may not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Targa may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.

If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations.

Under the Omnibus agreement described in Note 16, Targa has also indemnified us for pre-closing claims attributable to rights-of-way, certain consents or governmental permits, for a period of one to two years from our acquisitions (the North Texas System was three years). Targa has also indemnified us for certain pre-closing legal proceedings. Targa’s indemnification of any potential income tax issues attributable to pre-closing operations for each of our acquisitions terminate upon the expiration of the applicable statutes of limitations under the Omnibus Agreement, as amended.

Note 24—Selected Quarterly Financial Data (Unaudited)

Our results of operations by quarter for the years ended December 31, 2009 and 2008, as adjusted to reflect the consideration of common control accounting as discussed in Note 2, were as follows:

	First			Second			Third		Fourth
	Quarter			Quarter			Quarter		Quarter		Total
	(In millions, except per unit amounts)
Year Ended December 31, 2009:
Revenues	$	985.5		$	979.1		$	1,083.9	$	1,342.7	$	4,391.2
Operating income		17.2			34.4			45.1		68.8		165.5
Net income (loss)		(7.3	)		(4.1	)		7.8		38.3		34.7
Net income (loss) per limited partner unit--basic and diluted	$	(0.09	)	$	0.10		$	0.17	$	0.56	$	0.86

Year Ended December 31, 2008:
Revenues	$	2,162.3		$	2,235.4		$	2,309.3	$	1,130.9	$	7,837.9
Operating income		63.4			95.4			16.5		27.6		202.9
Net income		19.4			26.9			23.0		70.9		140.2
Net income per limited partner unit--basic and diluted	$	0.50		$	0.54		$	0.31	$	0.48	$	1.83

As discussed in Note 3, we recorded an adjustment in the third quarter of 2009 related to prior period natural gas transactions which increased revenues, operating income, and net income by $1.8 million.

The following table reconciles the previously reported amounts to those shown above:

	As Reported						Permian
	Targa						and						Targa
	Resources			Downstream			Straddle						Resources
	Partners LP			Business			Systems			Eliminations			Partners LP
	(In millions, except per unit amounts)
	First Quarter 2009
Revenues	$	239.0		$	764.4		$	214.7		$	(232.6	)	$	985.5
Operating income		7.4			11.3			(1.5	)		-			17.2
Net loss		(2.1	)		(3.3	)		(1.9	)		-			(7.3	)
Net loss per limited partner unit - basic and diluted	$	(0.09	)	$	-		$	-		$	-		$	(0.09	)

	Second Quarter 2009
Revenues	$	240.7		$	779.5		$	216.5		$	(257.6	)	$	979.1
Operating income		16.7			16.0			1.7			-			34.4
Net income (loss)		6.5			2.8			(13.4	)		-			(4.1	)
Net income per limited partner unit - basic and diluted	$	0.10		$	-		$	-		$	-		$	0.10

	Historical		Permian
	Targa		and						Targa
	Resources		Straddle						Resources
	Partners LP		Systems			Eliminations			Partners LP
	(In millions, except per unit amounts)
	Third Quarter 2009
Revenues	$	1,008.5	$	263.1		$	(187.7	)	$	1,083.9
Operating income		39.4		5.7			-			45.1
Net income (loss)		10.9		(3.1	)		-			7.8
Net income per limited partner unit--basic and diluted	$	0.17	$	-			-		$	0.17

	Fourth Quarter 2009
Revenues	$	1,254.8	$	341.6		$	(253.7	)	$	1,342.7
Operating income		54.8		14.0			-			68.8
Net income (loss)		39.4		(1.1	)		-			38.3
Net income per limited partner unit--basic and diluted	$	0.56	$	-			-		$	0.56

	Historical		Permian
	Targa		and						Targa
	Resources		Straddle						Resources
	Partners LP		Systems			Eliminations			Partners LP
	(In millions, except per unit amounts)
	First Quarter 2008
Revenues	$	2,085.3	$	460.8		$	(383.8	)	$	2,162.3
Operating income		45.2		18.2			-			63.4
Net income (loss)		22.8		(3.4	)		-			19.4
Net income per limited partner unit--basic and diluted	$	0.50	$	-			-		$	0.50

	Second Quarter 2008
Revenues	$	2,128.3	$	574.6		$	(467.5	)	$	2,235.4
Operating income		67.9		27.5			-			95.4
Net income (loss)		45.0		(18.1	)		-			26.9
Net income per limited partner unit--basic and diluted	$	0.54	$	-			-		$	0.54

	Third Quarter 2008
Revenues	$	2,222.5		$	492.7	$	(405.9	)	$	2,309.3
Operating income		(7.4	)		23.9		-			16.5
Net income (loss)		(38.1	)		61.1		-			23.0
Net income per limited partner unit--basic and diluted	$	0.31		$	-		-		$	0.31

	Fourth Quarter 2008
Revenues	$	1,066.0		$	265.8	$	(200.9	)	$	1,130.9
Operating income		26.1			1.5		-			27.6
Net income		20.0			50.9		-			70.9
Net income per limited partner unit--basic and diluted	$	0.48		$	-		-		$	0.48

During 2009, we reclassified NGL marketing fractionation and other service fees to revenues that were originally recorded in product purchase costs. This reclassification had no impact on our income from operations, net income, financial position or cash flows. The following table reflects the adjustments made:

	Adjustments
First Quarter 2008	$	5.8
Second Quarter 2008		8.1
Third Quarter 2008		7.6
Fourth Quarter 2008		7.1
First Quarter 2009		3.7
Second Quarter 2009		10.2
Third Quarter 2009		4.7

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