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 interrelationships among 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

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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.

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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

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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

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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.

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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 mitigate 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, demand 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.

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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.

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 expenses.

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

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	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.

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 companies.

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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.

	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

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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.

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
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.

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Results of Operations

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. The following table summarizes the key components of our results of operations for the periods indicated:

	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) 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 $28.7 million and $27.6 million.

(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.”

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(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.

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.

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.

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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.

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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) 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.

(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.

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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.

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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.

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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.

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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 we 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 settle 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

18

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

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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

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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 Service, 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”) 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 Service, 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.

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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 estimates.

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;

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· 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 will 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

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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 published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) 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

24

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

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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

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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.