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form8_k.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): December 31, 2009

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

TABLE OF CONTENTS

Item 8.01. Other Events

Item 9.01. Financial Statements and Exhibits

EXHIBIT INDEX

Exhibit 23.1

Exhibit 99.1

Item 8.01. Other Events.

We are filing the consolidated balance sheet of Targa Resources GP LLC as of December 31, 2009, which is included as Exhibit 99.1 to this Current Report on Form 8-K. Targa Resources GP LLC is the general partner of Targa Resources Partners LP.

Item 9.01. Financial Statements and Exhibits

(d) Exhibits


Exhibit
Number		Description
Exhibit 23.1		Consent of Independent Registered Public Accounting Firm
Exhibit 99.1		Audited Consolidated Balance Sheet of Targa Resources GP LLC as of December 31, 2009

SIGNATURES

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

	TARGA RESOURCES PARTNERS LP

	By: Targa Resources GP LLC,
	its general partner

Dated: March 5, 2009	By:	/s/ John Robert Sparger
		John Robert Sparger
		Senior Vice President and Chief Accounting Officer
		(Authorized signatory and Principal Accounting Officer)

EXHIBIT INDEX


Exhibit
Number		Description
Exhibit 23.1		Consent of Independent Registered Public Accounting Firm
Exhibit 99.1		Consolidated Balance Sheet of Targa Resources GP LLC as of December 31, 2009

ex99_1.htm

Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of Targa Resources GP LLC:

In our opinion, the accompanying consolidated balance sheet presents fairly, in all material respects, the financial position of Targa Resources GP LLC and its subsidiaries (the "Company") at December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of the Company’s management; our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

As disclosed in Note 3 to the consolidated balance sheet, the Company has changed the manner in which it accounts for noncontrolling interests, effective January 1, 2009.

As disclosed in Note 12 to the consolidated balance sheet, the Company has engaged in significant transactions with other subsidiaries of its parent company, Targa Resources, Inc., a related party.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 5, 2010

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

Bbl			Barrels (equal to 42 gallons)
Btu			British thermal units, a measure of heating value
/d			per day
gal			Gallons
MMBtu			Million British thermal units
NGL(s)			Natural gas liquid(s)

Price Index Definitions

IF-Waha			Inside FERC Gas Market Report, West Texas Waha
NY-HH			NYMEX, Henry Hub Natural Gas
NY-WTI			NYMEX, West Texas Intermediate Crude Oil

TARGA RESOURCES GP LLC
CONSOLIDATED BALANCE SHEET

	December 31, 2009
	(In millions)

ASSETS
Current assets:
Cash and cash equivalents	$	60.4
Trade receivables, net of allowance of $2.2 million		328.3
Inventory		39.3
Assets from risk management activities		25.8
Other current assets		1.2
Total current assets		455.0

Property, plant and equipment, at cost		2,096.8
Accumulated depreciation		(418.3	)
Property, plant and equipment, net		1,678.5
Long-term assets from risk management activities		9.1
Investment in unconsolidated affiliate		18.5
Other assets		19.8
Total assets	$	2,180.9

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable to third parties	$	164.0
Accounts payable to affiliates		101.4
Accrued liabilities		114.2
Liabilities from risk management activities		16.3
Total current liabilities		395.9

Long-term debt payable to third parties		908.4
Long-term liabilities from risk management activities		28.9
Deferred income taxes		4.9
Other long-term liabilities		6.6

Commitments and contingencies (Note 13)

Equity:
Member's interest		10.1
Accumulated other comprehensive income (loss)		(0.8	)
Total member's equity		9.3
Noncontrolling interest		826.9
Total equity		836.2
Total liabilities and equity	$	2,180.9

See notes to consolidated balance sheet

TARGA RESOURCES GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

Note 1—Organization and Operations

Targa Resources GP LLC is a Delaware limited liability company formed in October 2006 to become the general partner of Targa Resources Partners LP. Our sole member is Targa GP Inc., an indirect wholly-owned subsidiary of Targa Resources, Inc. (“Targa”). Our primary business purpose is to manage the affairs and operations of Targa Resources Partners LP.

Unless the context requires otherwise, references to “we,” “us,” or “our” are intended to mean and include the business and operations of Targa Resources GP LLC, as well as its consolidated subsidiaries, which include Targa Resources Partners LP and its consolidated subsidiaries.

References to “the Partnership” mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. The Partnership is a publicly traded Delaware limited partnership, the registered common units of which are listed on the New York Stock Exchange under the ticker symbol “NGLS.” References to “TRGP” mean Targa Resources GP, LLC, individually as the general partner of the Partnership, and not on a consolidated basis. TRGP has no independent operations and no material assets outside of its interest in the Partnership.

On September 24, 2009, the Partnership acquired Targa’s interests in Targa Downstream GP LLC, Targa LSNG GP LLC, Targa Downstream LP and Targa LSNG LP (collectively, the “Downstream Business”) in a transaction among entities under common control. See Note 4.

Note 2—Basis of Presentation

We consolidate the accounts of the Partnership and its subsidiaries into our consolidated balance sheet. Notwithstanding this consolidation, we are not liable for, and our assets are not available to satisfy, the obligations of the Partnership and/or its subsidiaries.

We categorize the midstream natural gas industry into, and describe our business with the acquisition of the Downstream Business, in, two divisions: (i) Natural Gas Gathering and Processing (also a segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and Marketing division consists of three segments: (a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale Marketing.

The Natural Gas Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. These assets are located in North Texas, Louisiana and the Permian Basin of West Texas. We are also party to natural gas processing agreements with third party plants.

The Logistics Assets segment is involved with gathering and storing mixed NGLs and fractionating, storing, and transporting finished NGLs. These assets are generally connected to and supplied, in part, by our Natural Gas Gathering and Processing segment and are predominantly located in Mont Belvieu, Texas and Western Louisiana.

The NGL Distribution and Marketing segment markets our own natural gas liquids production and purchased natural gas liquids products in selected United States markets.

The Wholesale Marketing segment includes our refinery services business and wholesale propane marketing operations. In our refinery services business, we provide liquefied petroleum gas balancing services, purchase natural gas liquids products from refinery customers and sell natural gas liquids products to various customers. Our wholesale propane marketing operations include the sale of propane and related logistics services to multi-state retailers, independent retailers and other end-users. Wholesale Marketing operates principally in the United States, and has a small marketing presence in Canada.

In preparing the accompanying consolidated balance sheet, we have reviewed, as we have determined necessary, events that have occurred after December 31, 2009, up until the issuance of the consolidated balance sheet. See Notes 9, 10 and 13.

Note 3—Significant Accounting Policies

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

Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows shall be recognized as an increase or a decrease in the carrying amount of the liability for an asset retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset.Upon settlement, AROs will be extinguished by us at either the recorded amount or we will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost. See Note 7.

Cash and Cash Equivalents. Cash and cash equivalents include all cash on hand, demand deposits and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. As of December 31, 2009, accrued liabilities included approximately $5.3 million of outstanding checks that were reclassified from cash and cash equivalents.

Concentration of Credit Risk. Financial instruments which potentially subject us to concentrations of credit risk consist primarily of trade accounts receivable and commodity derivative instruments.

Consolidation Policy. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Our consolidated balance sheet include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest.

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

Trade Accounts Receivable. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met.

Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.

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

Environmental Liabilities. Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is

probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. See Note 13.

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

Income Taxes. We are generally not subject to income taxes because our income is taxed directly to our sole member and to Targa as our indirect owner.

Texas has adopted a margin tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas. Accordingly, we have estimated our liability for this tax and it is recorded as a tax liability.

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

Noncontrolling Interest. Noncontrolling interest represents third party ownership in the net assets of our consolidated subsidiaries, the Partnership and Cedar Bayou Fractionators. For financial reporting purposes, the assets and liabilities of our majority owned subsidiary are consolidated with any third party investor’s interest shown as noncontrolling interest.

Price Risk Management (Hedging). We have designated certain downstream liquids marketing contracts that meet the definition of a derivative as normal purchases and normal sales, which are not accounted for as derivatives. All derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (“OCI”), a component of member’s equity, and reclassified to earnings when the forecasted transaction occurs.

Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Hedge ineffectiveness is measured on a quarterly basis. Any ineffective portion of the unrealized gain or loss is reclassified to earnings in the current period.

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately. See Notes 11, 12 and 15.

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

Property, Plant and Equipment. Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The estimated service lives of our functional asset groups are as follows:

	Range
Asset Group	of Years
Gas gathering systems and processing systems	5 to 20
Fractionation, terminalling and natural gas liquids storage facilities	5 to 25
Transportation assets	10 to 25
Other property and equipment	3 to 25

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

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

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

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

Unit-Based Employee Compensation. We award share-based compensation to non-management directors in the form of restricted common units, which are deemed to be equity awards. Compensation expense on restricted common units is measured by the fair value of the award at the date of grant. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. See Note 10.

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

Note 4—Acquisition of Downstream Business

On September 24, 2009, the Partnership acquired Targa’s interests in the Downstream Business for $530 million. Consideration to Targa comprised $397.5 million in cash and the issuance to Targa of 174,033 general partner units and 8,527,615 common units. The form of the transaction reflected in our consolidated balance sheet was:

Targa contributed the Downstream Business to the Partnership.

Prior to the contribution, the Downstream Business’ affiliate indebtedness payable to Targa totaled $817.3 million, inclusive of $223.0 million of accrued interest.

Immediately prior to, and in contemplation of, the contribution, $287.3 million of the Downstream Business’ affiliated indebtedness was settled through a separate capital contribution from Targa.

On the contribution date, the Downstream Business’ affiliate indebtedness payable to Targa was $530 million.

The Partnership repaid the affiliate indebtedness with: (i) $397.5 million in cash; (ii) 174,033 in general partner units with an agreed-upon value of $2.7 million; and (iii) 8,527,615 in common units with an agreed-upon value of $129.8 million.

The Partnership’s acquisition of the Downstream Business has been accounted for as a transfer of net assets between entities under common control.

Note 5—Property, Plant and Equipment

Property, plant and equipment and accumulated depreciation were as follows as of December 31, 2009:

Natural gas gathering systems	$	1,225.6
Processing and fractionation facilities		404.4
Terminalling and natural gas liquids storage facilities		238.5
Transportation assets		150.7
Other property and equipment		16.8
Land		49.8
Construction in progress		11.0
		2,096.8
Accumulated depreciation		(418.3	)
	$	1,678.5

Note 6—Investment in Unconsolidated Affiliate

As of December 31, 2009, our unconsolidated investment of $18.5 million consisted of a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast. Our equity in the net assets of GCF as of December 31, 2009 exceeded our acquisition date investment account by approximately $5.2 million.

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

Note 7—Asset Retirement Obligations

Our asset retirement obligations are included in our consolidated balance sheet as a component of other long-term liabilities. The changes in our aggregate asset retirement obligations during 2009 are as follows:

Beginning of year	$	6.2
Liabilities settled		-
Change in cash flow estimate		-
Accretion expense		0.4
End of year	$	6.6

Note 8—Long-Term Debt

Consolidated long-term debt consisted of the following as of December 31, 2009:

Senior secured revolving credit facility, variable rate, due February 2012	$	479.2
Senior unsecured notes, 8¼% fixed rate, due July 2016		209.1
Senior unsecured notes, 11¼% fixed rate, due July 2017 (1)		220.1
Total long-term debt	$	908.4
Letters of credit outstanding under senior secured revolving credit facility	$	69.2

__________

(1)

The carrying amount of the notes includes $11.2 million of unamortized original issue discount as of December 31, 2009.

Credit Agreement

On February 14, 2007, the Partnership entered into a credit agreement which provided for a five-year $500 million credit facility with a syndicate of financial institutions. On October 24, 2007, the Partnership entered into the First Amendment to Credit Agreement which allows it to request commitments under the credit agreement, as supplemented and amended, up to $1 billion. The Partnership currently has $977.5 million committed under the senior secured credit facility (“credit facility”). In October 2008, Lehman Bank defaulted on a borrowing request under the senior secured credit facility. Lehman’s commitment under the facility is $19 million and is currently unfunded, which effectively reduces the Partnership’s total commitments under its credit facility by $19 million.

The credit facility bears interest at the Partnership’s option, at the higher of the lender’s prime rate or the federal funds rate plus 0.5%, plus an applicable margin ranging from 0% to 1.25% dependent on the Partnership’s total leverage ratio, or LIBOR plus an applicable margin ranging from 1.0% to 2.25% dependent on the Partnership’s total leverage ratio. The credit facility is secured by substantially all of the Partnership’s assets. As of December 31, 2009, approximately $479.2 million of borrowings under the credit facility and approximately $69.2 million of letters of credit were outstanding.

The credit facility restricts the Partnership’s ability to make distributions of available cash to unitholders if a default or an event of default (as defined in the credit agreement) has occurred and is continuing. The credit facility requires the Partnership to maintain a leverage ratio (the ratio of consolidated indebtedness to consolidated EBITDA, as defined in the credit agreement) of less than or equal to 5.50 to 1.00 and a senior secured indebtedness ratio (the ratio of senior secured indebtedness to consolidated EBITDA, as defined in the credit agreement) of less than or equal to 4.50 to 1.00, each subject to certain adjustments. The credit facility also requires the Partnership to maintain an interest coverage ratio (the ratio of consolidated EBITDA to consolidated interest expense, as defined in the credit agreement) of greater than or equal to 2.25 to 1.00, determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination, as well as upon the occurrence of certain events, including the incurrence of additional permitted indebtedness. In conjunction with a material acquisition, the Partnership has the option to increase the leverage ratio to 6.00 to 1.00 and to increase the senior secured indebtedness ratio to 5.00 to 1.00 for a period of up to a year.

The credit facility matures on February 14, 2012, at which time all unpaid principal and interest is due.

8¼% Senior Notes due 2016

On June 18, 2008, the Partnership completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of 8¼% senior notes due 2016 (the “8¼% Notes”). The 8¼% Notes:

are the Partnership’s unsecured senior obligations;

rank pari passu in right of payment with the Partnership’s existing and future senior indebtedness, including indebtedness under the credit facility;

are senior in right of payment to any of the Partnership’s future subordinated indebtedness; and

are unconditionally guaranteed by the Partnership.

The 8¼% Notes are effectively subordinated to all secured indebtedness under the credit agreement, which is secured by substantially all of the Partnership’s assets, to the extent of the value of the collateral securing that indebtedness.

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

At any time prior to July 1, 2011, the Partnership may redeem up to 35% of the aggregate principal amount of the 8¼% Notes with the net cash proceeds of one or more equity offerings by the Partnership at a redemption price of 108.25% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:

(1)

at least 65% of the aggregate principal amount of the 8¼% Notes (excluding 8¼% Notes held by the Partnership) remains outstanding immediately after the occurrence of such redemption; and

(2)

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

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

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

Year	Percentage
2012		104.125%
2013		102.063%
2014 and thereafter		100.000%

During 2008, the Partnership repurchased $40.9 million face value of its outstanding 8¼% Notes in open market transactions at an aggregate purchase price of $28.3 million, including $1.5 million of accrued interest. The repurchased 8¼% Notes were retired and are not eligible for re-issue at a later date.

11¼% Senior Notes due 2017

On July 6, 2009, the Partnership 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.

The 11¼% Notes:

are the Partnership’s unsecured senior obligations;

rank pari passu in right of payment with the Partnership’s existing and future senior indebtedness, including indebtedness under the credit facility;

are senior in right of payment to any of the Partnership’s future subordinated indebtedness; and

are unconditionally guaranteed by the Partnership.

The 11¼% Notes are effectively subordinated to all indebtedness under the credit agreement, which is secured by substantially all of the Partnership’s assets, to the extent of the value of the collateral securing that indebtedness.

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

At any time prior to July 15, 2012, the Partnership may redeem up to 35% of the aggregate principal amount of the 11¼% Notes with the net cash proceeds of certain equity offerings by the Partnership at a redemption price of 111.25% of the principal amount, plus accrued and unpaid interest to the redemption date, provided that:

(1) at least 65% of the aggregate principal amount of the 11¼% Notes (excluding 11¼% Notes held by the Partnership) remains outstanding immediately after the occurrence of such redemption; and

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

At any time prior to July 15, 2013, the Partnership may also redeem all or a part of the 11¼% Notes at a redemption price equal to 100% of the principal amount of the 11¼% Notes redeemed plus the applicable premium as defined in the indenture as of, and accrued and unpaid interest to, the date of redemption.

On or after July 15, 2013, the Partnership may redeem all or a part of the 11¼% Notes at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest on the 11¼% Notes redeemed, if redeemed during the twelve-month period beginning on July 15 of each year indicated below:

Year	Percentage
2013		105.625%
2014		102.813%
2015 and thereafter		100.000%

The 11¼% Notes are subject to a registration rights agreement dated as of July 6, 2009. Under the registration rights agreement, the Partnership is required to file by July 7, 2010 a registration statement with respect to any 11¼% Notes that are not freely transferable without volume restrictions by holders of the 11¼% Notes that are not affiliates of the Partnership. If the Partnership fails to do so, additional interest will accrue on the principal amount of the 11¼% Notes. We have determined that the payment of additional interest is not probable. As a result, the Partnership has not recorded a liability for any contingent obligation.

During 2009, the Partnership repurchased $18.7 million face value of its outstanding 11¼% Notes in open market transactions at an aggregated purchase price of $18.9 million plus accrued interest of $0.3 million. The repurchased 11¼% Notes were retired and are not eligible for re-issue at a later date.

Compliance with Debt Covenants

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

Note 9—Equity

As of December 31, 2009, member’s equity consisted of the capital account of Targa GP Inc. and its proportionate share of the accumulated OCI of the Partnership.

Noncontrolling interest represents third-party and Targa ownership interests in the Partnership and Cedar Bayou Fractionators. As of December 31, 2009, the components of noncontrolling interest were:

Non-affiliate public unitholders of the Partnership	$	844.0
Targa Resources, Inc.		19.9
Accumulated other comprehensive income (loss)		(37.0	)
Noncontrolling interest	$	826.9

General. In accordance with the Partnership Agreement, the Partnership must distribute all of its available cash to unitholders of record on the applicable record date, as determined by the general partner within 45 days after the end of each quarter.

Under the quarterly incentive distribution provisions, generally we are entitled to 13% of amounts distributed in excess of $0.3881 per unit, 23% of the amounts distributed in excess of $0.4219 per unit and 48% of amounts distributed in excess of $0.50625 per unit. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.3375 per unit, plus arrearages.

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

Unit Offering

On August 12, 2009, the Partnership completed a unit offering under its shelf registration statement of 6,900,000 common units, representing limited partner interests in the Partnership, at a price of $15.70 per common unit. Net proceeds generated by the offering were $105.3 million, after deducting underwriting discounts, commissions and estimated offering expenses, and including TRGP’s proportionate capital contribution of $2.2 million. The proceeds were used to reduce borrowings of the Partnership’s credit facility by $103.5 million.

Units Issued Relating to Acquisition

Subsequent Event. On January 19, 2010, the Partnership completed a public offering of 5,500,000 common units representing limited partner interests in the Partnership units under its 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, the Partnership 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 the Partnership’s credit facility.

Note 10—Accounting for Unit-Based Compensation

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

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

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

At December 31, 2009, the aggregate fair value of performance units expected to vest was $23.5 million. The remaining recognition period for the unrecognized compensation cost is approximately three and a half years.

During 2009 and 2008, we also made equity-based awards of 32,000 and 16,000 restricted common units of the Partnership (4,000 and 2,000 restricted common units of the Partnership to each of the Partnership’s and Targa Investments’ non-management directors) under its (“Incentive Plan”). The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date. As of December 31, 2009 there were 41,993 unvested restricted common units outstanding under this plan.

The following table summarizes our unit-based awards for 2009 (in units and dollars):

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

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

Note 11—Derivative Instruments and Hedging Activities

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, as well as changes in interest rates.

Commodity Price Risk. A majority of the revenues from our natural gas gathering and processing business are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes, as payment for services. The prices of natural gas and NGLs are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and the Parnership enters into commodity derivative transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

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, the Partnership 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, the Partnership typically receives an agreed upon fixed price for a specified notional quantity of natural gas or NGL and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since the Partnership receives from its 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 the Partnership’s expected natural gas and NGL equity volumes. The Partnership utilizes purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. the Partnership’s commodity hedges may expose us to the risk of financial loss in certain circumstances. The Partnership’s hedging arrangements provide us protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market prices rise above the prices at which the Partnership has hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.

We have tailored the Parnership’s hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The Partnership’s NGL hedges cover baskets of ethane, propane, normal butane, iso-butane 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. Additionally, the Partnership’s NGL hedges are based on published index prices for delivery at Mont Belvieu and our natural gas hedges are based on published index prices for delivery at Columbia Gulf, Houston Ship Channel, Mid-Continent and Waha, which closely approximate its actual NGL and natural gas delivery points. The Partnership hedges a portion of its condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.

At December 31, 2009, the notional volumes of the Partnership’s commodity hedges were:

Commodity	Instrument	Unit	2010		2011		2012		2013
Natural Gas	Swaps	MMBtu/d		16,494		14,000		10,000		4,000
NGL	Swaps	Bbl/d		5,607		4,000		2,700		-
NGL	Floors	Bbl/d		-		199		231		-
Condensate	Swaps	Bbl/d		501		350		200		200

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our variable rate borrowings under the Partnership’s credit facility. To the extent that interest rates increase, our interest expense for our revolving debt will also increase. As of December 31, 2009, the Partnership had borrowings of approximately $479.2 million outstanding under its credit facility. In an effort to reduce the variability of its cash flows, the Partnership has 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 the Partnership’s 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 sheet. Accordingly, unrealized gains and losses relating to our portion of the interest rate swaps are recorded in OCI until the interest expense on the related debt is recognized in earnings.

Credit Risk. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to the Partnership 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 the Partnership’s counterparties decline, its 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 the Partnership’s exposure related to its counterparties regarding 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.

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

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair Value		Balance Sheet	Fair Value
	Location	2009		Location	2009
Derivatives designated as hedging instruments
Commodity contracts	Current assets	$	24.5	Current liabilities	$	7.8
	Long term assets		7.0	Long term liabilities		24.2

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

Derivatives not designated as hedging instruments
Commodity contracts	Current assets		1.1	Current liabilities		0.5
	Long term assets		0.2	Long term liabilities		-
Total derivatives not designated
as hedging instruments			1.3			0.5

Total derivatives		$	34.9		$	45.2

Interest Rate Swaps

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

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

Period	Fixed Rate		Notional Amount	Fair Value
2010		3.67%	$300 million	$	(7.8	)
2011		3.52%	300 million		(5.1	)
2012		3.40%	300 million		(0.6	)
2013		3.39%	300 million		1.6
01/01 - 4/24/2014		3.39%	300 million		1.3
				$	(10.6	)

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

The fair value of derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices and interest rates based on those observed in underlying markets. These contracts may expose the Partnership to the risk of financial loss in certain circumstances.

See Notes 12 and 15 for additional disclosures related to derivative instruments and hedging activities.

Note 12—Related-Party Transactions

Targa Resources, Inc.

Reimbursement of Operating and General and Administrative Expense. The Omnibus Agreement, as amended, addresses the reimbursement to Targa for costs incurred on the Partnership’s behalf and indemnification matters. Any or all of the provisions of this agreement, other than the indemnification provisions described in Note 13, are terminable by Targa at its option if TRGP is removed without cause and units held by Targa and its affiliates are not voted in favor of that removal. The Omnibus Agreement will terminate in the event of a change of control of the Partnership or us.

Under the Omnibus Agreement, the Partnership reimburses Targa for the payment of certain operating expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for its benefit.

Pursuant to these arrangements, Targa performs centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. The Partnership reimburses Targa for the direct expenses to provide these services as well as other direct expenses it incurs on the Partnership’s behalf, such as compensation of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits.

Contracts with Affiliates

Sales to and purchases from affiliates.The Partnership routinely conducts business with other subsidiaries of Targa. The related-party transactions result primarily from purchases and sales of natural gas and purchases of NGL products.

Natural Gas Purchase Agreements. During 2007, the North Texas, SAOU and LOU Systems entered into natural gas purchase agreements at a price based on Targa Gas Marketing LLC’s (“TGM”) sale price for such natural gas, less TGM’s costs and expenses associated therewith. These agreements have an initial term of 15 years and automatically extend for a term of five years, unless the agreements are otherwise terminated by either party. Furthermore, either party may elect to terminate the agreements if either party ceases to be an affiliate of Targa. In

addition, Targa manages the SAOU and LOU Systems’ natural gas sales to third parties under contracts that remain in the name of the Targa Texas Field Services and Targa Louisiana Field Services.

NGL Product Purchase Agreements. On September 24, 2009, Targa Liquids Marketing and Trade, a Delaware general partnership and indirectly, wholly-owned subsidiary of the Partnership (“Targa Liquids”), entered into product purchase agreements with Targa Midstream Services Limited Partnership, a Delaware limited partnership and indirectly wholly-owned subsidiary of Targa (“TMSLP”), and Targa Permian LP, a Delaware limited partnership and indirectly, wholly-owned subsidiary of Targa (“Targa Permian”), pursuant to which Targa Liquids will purchase all volumes of NGLs that are owned or controlled by TMSLP and Targa Permian and not otherwise committed for sale to a third party, at a price based on the prevailing market price less transportation, fractionation and certain other fees. The product purchase agreements will have an initial term of 15 years and will automatically extend for a term of five years. Furthermore, either party may elect to terminate the agreement if either party ceases to be an affiliate of Targa. Each product purchase agreement is effective as of September 1, 2009.

Allocation of Costs. The employees supporting the Partnership’s operations are employees of Targa. Our consolidated balance sheet is affected by costs allocated to the Partnership by Targa for centralized general and administrative services performed by Targa, as well as depreciation of assets utilized by Targa’s centralized general and administrative functions. Costs allocated to the Partnership were based on identification of Targa’s resources which directly benefit the Partnership and the Partnership’s proportionate share of costs based on its estimated usage of shared resources and functions. All of the allocations were based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if the Partnership had been operated as a stand-alone entity.

Relationships with Warburg Pincus LLC

Chansoo Joung and Peter Kagan, two of the directors of Targa, are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom the Partnership buys natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. As of December 31, 2009, our payable balance with Broad Oak was $1.6 million.

Relationships with Bank of America

Equity

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

Financial Services

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

Hedging Arrangements

The Partnership has entered into various commodity derivative transactions with BofA. The following table shows its open commodity derivatives with BofA as of December 31, 2009:

Period

Commodity

Daily Volumes

Average Price

Index

Jan 2010 - Dec 2010

Natural Gas

3,289

MMBtu

7.39

per MMBtu

IF-WAHA

Jan 2010 - Jun 2010

Natural Gas

663

MMBtu

8.16

per MMBtu

NY-HH

Jan 2010 - Dec 2010

Condensate

181

Bbl

69.28

per Bbl

NY-WTI

As of December 31, 2009, the fair value of these open positions was an asset of $0.9 million.

Commercial Relationships

The Partnership has executed NGL sales and purchase transactions on the spot market with BofA.

Note 13—Commitments and Contingencies

Certain property and equipment is leased under non-cancelable leases that require fixed monthly rental payments and expire at various dates through 2099. Transportation contracts require us to make payments for capacity and expire at various dates through 2013. Surface and underground access for gathering, processing, and distribution assets that are located on property not owned by us is obtained through right-of-way agreements, which require annual rental payments and expire at various dates through 2099. Future non-cancelable commitments related to certain contractual obligations are presented below:

	Payments Due by Period
	Total		2010		2011		2012		2013		2014		Thereafter
Operating lease obligations (1)	$	38.0	$	8.9	$	6.5	$	6.2	$	3.3	$	2.6	$	10.5
Capacity payments (2)		2.7		2.0		0.7		-		-		-		-
Right-of-way		11.4		0.9		0.8		0.8		0.7		0.5		7.7
	$	52.1	$	11.8	$	8.0	$	7.0	$	4.0	$	3.1	$	18.2

__________

(1)

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

(2)

Consist of capacity payments for firm transportation contracts.

Environmental

Under the Omnibus Agreement described in Note 12, Targa indemnified us for three years from February 14, 2007 against certain potential environmental claims, losses and expenses associated with the operation of the North Texas System occurring before such date that were not reserved on the books of the North Texas System. Targa’s maximum liability for this indemnification obligation will not exceed $10.0 million and Targa will not have any obligation under this indemnification until our aggregate losses exceed $250,000. We have indemnified Targa against environmental liabilities related to the North Texas System arising or occurring after February 14, 2007.

Legal Proceedings

We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against us. We believe all such matters are without merit or involve amounts which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows, except for the items more fully described below.

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

Subsequent event. On February 23, 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.

Note 14—Fair Value of Financial Instruments

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

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

The carrying value of the credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt. The carrying amounts and fair values of the Partnership’s other financial instruments as of December 31, 2009 are as follows:

	Carrying		Fair
	Amount		Value
Senior unsecured notes, 8¼% fixed rate	$	209.1	$	206.5
Senior unsecured notes, 11¼% fixed rate (1)		220.1		253.5

_______

(1)

The carrying amount of the 11¼% Notes includes $11.2 million of unamortized original issue discount as of December 31, 2009.

Note 15—Fair Value Measurements

We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The Partnership’s derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain customers. We determine the value of these derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold. We have categorized the inputs for these contracts as Level 2 or Level 3.

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2009. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	31.5	$	-	$	31.5	$	-
Assets from interest rate derivatives		2.1		-		2.1		-
Total assets	$	33.6	$	-	$	33.6	$	-
Liabilities from commodity derivative contracts	$	32.0	$	-	$	21.9	$	10.1
Liabilities from interest rate derivatives		12.7		-		12.7		-
Total liabilities	$	44.7	$	-	$	34.6	$	10.1

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

	Commodity Derivative Contracts
Balance, December 31, 2008	$	123.3
Unrealized losses included in OCI		(37.7	)
Purchases		-
Terminations		-
Settlements		(31.4	)
Transfers out of Level 3 (1)		(64.3	)
Balance, December 31, 2009	$	(10.1	)

________

(1)

During 2009, we reclassified certain of the Partnership’s NGL derivative contracts from Level 3 (unobservable inputs in which little or no market data exist) to Level 2 as we were able to obtain directly observable inputs other than quoted prices in active markets.

Note 16—Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

We operate in the midstream energy industry. Our business activities include gathering, transporting, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by (i) changes in the commodity prices of these hydrocarbon products and (ii) changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

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

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

Counterparty Risk with Respect to Financial Instruments

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

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

Casualty or Other Risks

Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverages which are customary for the nature and scope of our operations.

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

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

A portion of the insurance costs described above is allocated to us by Targa through the allocation methodology as prescribed in the Omnibus Agreement described in Note 12.

Under the Omnibus Agreement, Targa has also indemnified the Partnership for losses attributable to rights-of-way, certain consents or governmental permits, pre-closing litigation relating to the North Texas System and income taxes attributable to pre-closing operations that were not reserved on the books of the North Texas System as of February 14, 2007. Targa does not have any obligation under these indemnifications until the Partnership’s aggregate losses exceed $250,000. The Partnership has indemnified Targa for all losses attributable to the post-closing operations of the North Texas System. Targa’s obligations under this additional indemnification will survive for three years from February 14, 2007, except that the indemnification for income tax liabilities will terminate upon the expiration of the applicable statutes of limitations.

ex23_1.htm

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-149200) and Form S-3 (No. 333-159678) of Targa Resources Partners LP of our report dated March 5, 2010, relating to the consolidated balance sheet of Targa Resources GP LLC, which appears in this Current Report on Form 8-K.

/s/PricewaterhouseCoopers LLP

Houston, Texas

March 5, 2010