Edgar Filing: Targa Resources Corp.

form10-ka.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

Amendment No. 1

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

For the fiscal year ended December 31, 2010

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

For the transition period from to

Commission file number: 001-34991

TARGA RESOURCES CORP.

(Exact name of registrant as specified in its charter)

Delaware		20-3701075
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

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

(713) 584-1000

(Registrant’s telephone number, including area code)

Securities registered pursuant to section 12(b) of the Act:


Title of Each Class		Name of Each Exchange on Which Registered
Common Stock		New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £ No R

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No R

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R

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

Large accelerated filer £

Accelerated filer £

Non-accelerated filer R

Smaller reporting company £

(Do not check if a smaller reporting company)

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

As of June 30, 2010, the last day of the registrant’s most recently completed second quarter, the registrant’s common stock was not publicly traded. As of February 21, 2011, the aggregate market value of the registrant’s common stock, $0.001 par value, held by non-affiliates of the registrant was approximately $719.7 million (based upon the closing sale price of $31.91 per common stock on that date on The New York Stock Exchange).

As of February 25, 2011, there were 42,349,738 shares of the registrant’s common stock, $0.001 par value, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

Explanatory Note

This Amendment No. 1 to the Annual Report on Form 10-K of Targa Resources Corp. (“the Company”) for the fiscal year ended December 31, 2010 is being filed for the purpose of adding an exhibit and providing separate condensed financial information as required by Rule 5-04 of the Securities and Exchange Commission Regulation S-X. These audited financial statements, which were not available prior to the filing of our 2010 Annual Report on Form 10-K, do not update or modify in any way the consolidated results of operations, financial position, cash flows or other disclosures in our Annual Report, which are included in this Amendment No. 1. Furthermore, these financial statements do not reflect events occurring after the original filing date of our Form 10-K of February 28, 2011.

In connection with filing this Amendment No. 1, the Company is also filing currently dated certifications of the Company's principal executive officer and principal financial officer pursuant to Rules 13a-14(a) and 13a-14(b) under the Securities Exchange Act of 1934, as amended.

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Targa Resources Corp.

(Registrant)

By: /s/ Matthew J. Meloy

Matthew J. Meloy

Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)

Date: March 29, 2011

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements

Our Consolidated Financial Statements are included under Part II, Item 8 of the Annual Report. For a listing of these statements and accompanying footnotes, see "Index to Financial Statements" Page F-1 of this Annual Report.

(a)(2) Schedule I – Condensed Financial Information of Registrant - Parent Only

(a)(3) Exhibits

Number		Description
2.1**	—	Purchase and Sale Agreement, dated as of September 18, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 21, 2007 (File No. 001-33303)).
2.2	—	Amendment to Purchase and Sale Agreement, dated October 1, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)).
2.3	—	Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP, Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 29, 2009 (File No. 001-33303)).
2.4	—	Purchase and Sale Agreement, dated as of March 31, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC and Targa Midstream Holdings LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 1, 2010 (File No. 001-33303)).
2.5	—	Purchase and Sale Agreement, dated as of August 6, 2010, by and among Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 9, 2010 (File No. 001-33303)).
2.6	—	Purchase and Sale Agreement, dated September 13, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 17, 2010 (File No. 001-33303)).
3.1	—	Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).
3.2	—	Form of Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)).
3.3	—	Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
3.4	—	Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
3.5	—	First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
3.6	—	Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).
3.7	—	Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
3.8	—	Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.9	—	Amendment to Amended and Restated Certificate of Incorporation of Targa Resources, Inc.
3.10	—	Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit 3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
4.1	—	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
10.1	—	Credit Agreement, dated as of January 5, 2010 among Targa Resources, Inc., as the borrower, Deutsche Bank Trust Company Americas, as the administrative agent, Deutsche Bank Securities Inc. and Credit Suisse Securities (USA) LLC, as joint lead arrangers, Credit Suisse Securities (USA) LLC and Citadel Securities LLC, as the co-syndication agents, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Citadel Securities LLC, Banc of America Securities LLC and Barclays Capital, as joint book runners, Bank of America, N.A., Barclays Bank PLC and ING Capital LLC, as the co-documentation agents and the other lenders party thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
10.2	—	Amendment No. 1 to Credit Agreement, dated November 12, 2010 among TRI Resources Inc., as the Borrower, Deutsche Bank Trust Company Americas, Credit Suisse AG, Cayman Islands Branch, Bank of America, N.A., ING Capital LLC and Barclays Bank PLC, as Lenders, and Deutsche Bank Trust Company Americas, as Administrative Agent (incorporated by reference to Exhibit 10.94 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 16, 2010 (File No. 333-169277)).
10.3	—	Holdco Credit Agreement, dated as of August 9, 2007 among Targa Resources Investments Inc., as the borrower, Credit Suisse, as the administrative agent, Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc. and, as joint lead arrangers, Deutsche Bank Securities Inc., as the syndication agent, Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Lehman Brothers, Inc. and Merrill Lynch Capital Corporation, as joint book runners, Lehman Commercial Paper Inc. and Merrill Lynch Capital Corporation, as the co-documentation agents and the other lenders party thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).

10.4	—	Amendment No. 1 to Holdco Credit Agreement, dated January 5, 2010 among Targa Resources Investments Inc., as the Borrower, Targa Resources, Inc., as Lender, Targa Capital, LLC, as Lender, and Credit Suisse AG, Cayman Islands Brach, as Administrative Agent (incorporated by reference to Exhibit 10.92 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
10.5	—	Amended and Restated Credit Agreement, dated July 19, 2010, by and among Targa Resources Partners LP, as the borrower, Bank of America, N.A., as the administrative agent, Wells Fargo Bank, National Association and the Royal Bank of Scotland plc, as the co-syndication agents, Deutsche Bank Securities Inc. and Barclays Bank PLC, as the co-documentation agents, Banc of America Securities LLC, Wells Fargo Securities, LLC and RBS Securities Inc., as joint lead arrangers and co-book managers and the other lenders part thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Form 8-K filed on July 21, 2010 (File No. 001-33303)).
10.6	—	Targa Resources Investments Inc. Amended and Restated Stockholders’ Agreement dated as of October 28, 2005 (incorporated by reference to Exhibit 10.2 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.7	—	First Amendment to Amended and Restated Stockholders’ Agreement, dated January 26, 2006 (incorporated by reference to Exhibit 10.3 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.8	—	Second Amendment to Amended and Restated Stockholders’ Agreement, dated March 30, 2007 (incorporated by reference to Exhibit 10.4 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.9	—	Third Amendment to Amended and Restated Stockholders’ Agreement, dated May 1, 2007 (incorporated by reference to Exhibit 10.5 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.10	—	Fourth Amendment to Amended and Restated Stockholders’ Agreement, dated December 7, 2007 (incorporated by reference to Exhibit 10.6 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.11	—	Fifth Amendment to Amended and Restated Stockholders’ Agreement, dated December 1, 2009 (incorporated by reference to Exhibit 10.1 to Targa Resources, Inc.’s Current Report on Form 8-K filed December 2, 2009 (File No. 333-147066)).
10.12	—	Form of Sixth Amendment to Amended and Restated Stockholders’ Agreement (incorporated by reference to Exhibit 10.11 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
10.13+	—	Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.10 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.14+	—	First Amendment to Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.11 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.15+	—	Second Amendment to Targa Resources Investments Inc. 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.12 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.16+	—	Form of Targa Resources Investments Inc. Nonstatutory Stock Option Agreement (Non-Employee Directors) (incorporated by reference to Exhibit 10.13 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.17+	—	Form of Targa Resources Investments Inc. Nonstatutory Stock Option Agreement (Non-Director Management and Other Employees) (incorporated by reference to Exhibit 10.14 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.18+	—	Form of Targa Resources Investments Inc. Incentive Stock Option Agreement (incorporated by reference to Exhibit 10.15 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.19+	—	Form of Targa Resources Investments Inc. Restricted Stock Agreement (incorporated by reference to Exhibit 10.16 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.20+	—	Form of Targa Resources Investments Inc. Restricted Stock Agreement (relating to preferred stock option exchange for directors) (incorporated by reference to Exhibit 10.17 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.21+	—	Form of Targa Resources Investments Inc. Restricted Stock Agreement (relating to preferred stock option exchange for employees) (incorporated by reference to Exhibit 10.18 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.22+	—	Targa Resources Corp. 2010 Stock Incentive Plan (incorporated by reference to Exhibit 4.3 of Targa Resources Corp.’s Registration Statement on Form S-8 filed December 9, 2010 (File No. 333-171082)).
10.23+	—	Form of Targa Resources Corp. Restricted Stock Agreement – 2010 (incorporated by reference to Exhibit 4.4 of Targa Resources Corp.’s Registration Statement on Form S-8 filed December 9, 2010 (File No. 333-171082)).
10.24+	—	Form of Targa Resources Corp. 2011 Restricted Stock Agreement – 2011 (incorporated by reference to Exhibit 10.2 of Targa Resources Corp.’s Current Report on Form 8-K filed February 18, 2011 (File No. 001-34991)).
10.25+	—	Targa Resources Investments Inc. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.27 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)).
10.26+	—	Targa Resources Investments Inc. 2008 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.13 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)).
10.27+	—	Targa Resources Investments Inc. 2009 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.14 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 27, 2009 (File No. 001-33303)).
10.28+	—	Targa Resources Investments Inc. 2010 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.22 to Targa Resources Partners LP’s Annual Report on Form 10-K filed March 4, 2010 (File No. 001-33303)).
10.29+	—	Targa Resources Corp. 2011 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.27 to Targa Resources Partners LP’s Annual Report on Form 10-K filed February 25, 2011 (File No. 001-33303)).
10.30+	—	Targa Resources Partners LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed February 1, 2007 (File No. 333-138747)).
10.31+	—	Form of Targa Resources Partners LP Restricted Unit Grant Agreement — 2007 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 13, 2007 (File No. 001-33303)).
10.32+	—	Form of Targa Resources Partners LP Restricted Unit Grant Agreement — 2010 (incorporated by reference to Exhibit 10.15 to Targa Resources Partners LP’s Form 10-K filed March 4, 2010 (File No. 001-33303)).
10.33+	—	Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2007 (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed with the SEC on February 13, 2007 (File No. 001-33303)).
10.34+	—	Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2008 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 22, 2008 (File No. 001-33303)).
10.35+	—	Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2009 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 28, 2009 (File No. 001-33303)).

10.36+	—	Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2010 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed December 7, 2009 (File No. 001-33303)).
10.37+	—	Form of Targa Resources Partners LP Performance Unit Grant Agreement — 2011 (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 18, 2011) (File No. 001-33303)).
10.38	—	Indenture dated June 18, 2008, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Form 10-Q filed August 11, 2008 (File No. 333-147066)).
10.39	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.40	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.41	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.42	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.43	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.44	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.13 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.45	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.15 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.46	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.17 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.47	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.19 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.48	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.21 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.49	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.23 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.50	—	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.25 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.51	—	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.52	—	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.53	—	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.54	—	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).

10.55	—	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.56	—	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.57	—	Supplemental Indenture dated August 10, 2010 to Indenture dated June 18, 2008, among Targa MLP Capital, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.46 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
10.58	—	Supplemental Indenture dated September 20, 2010 to Indenture dated June 18, 2008, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
10.59	—	Supplemental Indenture dated October 25, 2010 to Indenture dated June 18, 2008, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
10.60	—	Registration Rights Agreement dated July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
10.61	—	Indenture dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
10.62	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.63	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.64	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.65	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.66	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.67	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.14 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.68	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.16 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.69	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.18 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.70	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.20 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.71	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.22 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.72	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.24 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).

10.73	—	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.26 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 9, 2009 (File No. 001-33303)).
10.74	—	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.75	—	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.76	—	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.77	—	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.78	—	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.79	—	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.80	—	Supplemental Indenture dated August 10, 2010 to Indenture dated July 6, 2009, among Targa MLP Capital, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 10.66 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)).
10.81	—	Supplemental Indenture dated September 20, 2010 to Indenture dated July 6, 2009, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
10.82	—	Supplemental Indenture dated October 25, 2010 to Indenture dated July 6, 2009, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
10.83	—	First Supplemental Indenture dated February 2, 2011 to that certain Indenture dated July 6, 2009 (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).
10.84	—	Registration Rights Agreement dated as of August 13, 2010 among the Issuers, the Guarantors and Banc of America Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)).
10.85	—	Indenture dated as of August 13, 2010 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)).
10.86	—	Supplemental Indenture dated September 20, 2010 to Indenture dated August 13, 2010, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001- 33303)).
10.87	—	Supplemental Indenture dated October 25, 2010 to Indenture dated August 13, 2010, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed November 5, 2010 (File No. 001-33303)).
10.88	—	Registration Rights Agreement dated February 2, 2011 among the Issuers, the Guarantors, Deutsche Bank Securities Inc., as representative of the several initial purchasers, and the Dealer Managers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).
10.89	—	Indenture dated February 2, 2011 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).
10.90	—	Contribution, Conveyance and Assumption Agreement, dated February 14, 2007, by and among Targa Resources Partners LP, Targa Resources Operating LP, Targa Resources GP LLC, Targa Resources Operating GP LLC, Targa GP Inc., Targa LP Inc., Targa Regulated Holdings LLC, Targa North Texas GP LLC and Targa North Texas LP (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
10.91	—	Contribution, Conveyance and Assumption Agreement, dated October 24, 2007, by and among Targa Resources Partners LP, Targa Resources Holdings LP, Targa TX LLC, Targa TX PS LP, Targa LA LLC, Targa LA PS LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)).
10.92	—	Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)).

10.93	—	Contribution, Conveyance and Assumption Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC, Targa Midstream Holdings LLC, Targa Resources Operating LP, Targa North Texas GP LLC and Targa Resources Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
10.94	—	Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 26, 2010 (File No. 001-33303)).
10.95	—	Contribution, Conveyance and Assumption Agreement, dated September 28, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 4, 2010 (file No. 001-33303)).
10.96	—	Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
10.97	—	First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
10.98+	—	Form of Indemnification Agreement between Targa Resources Investments Inc. and each of the directors and officers thereof (incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 8, 2010 (File No. 333-169277)).
10.99+	—	Targa Resources Partners LP Indemnification Agreement for Barry R. Pearl dated February 14, 2007 (incorporated by reference to Exhibit 10.11 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
10.100+	—	Targa Resources Partners LP Indemnification Agreement for Robert B. Evans dated February 14, 2007 (incorporated by reference to Exhibit 10.12 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
10.101+	—	Targa Resources Partners LP Indemnification Agreement for Williams D. Sullivan dated February 14, 2007 (incorporated by reference to Exhibit 10.13 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
10.102	—	Amended and Restated Registration Rights Agreement dated as of October 31, 2005 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.'s Registration Statement on Form S-1/A filed November 12, 2010 (file No. 333-169277)).
21.1	—	List of Subsidiaries of Targa Resources Corp.
23.1*	—	Consent of PricewaterhouseCoopers LLP
31.1*	—	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*	—	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1*	—	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	—	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

** Pursuant to Item 601(b)(2) of Regulation S-K, the Company agrees to furnish supplementally a copy of any omotted exhibit or Schedule to the SEC upon request.

+ Management contract or compensatory plan or arrangement

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

TARGA RESOURCES CORP. AUDITED CONSOLIDATED FINANCIAL STATEMENTS

Management's Report on Internal Control Over Financial Reporting	F-2

Report of Independent Registered Public Accounting Firm	F-3

Consolidated Balance Sheets as of December 31, 2010 and December 31, 2009	F-4

Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008	F-5

Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2010, 2009 and 2008	F-6

Consolidated Statement of Changes in Owners' Equity for the Years Ended December 31, 2010, 2009 and 2008	F-7

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008	F-8

Notes to Consolidated Financial Statements	F-9
Note 1 ― Organization and Operations	F-9
Note 2 ― Basis of Presentation	F-9
Note 3 ― Out of Period Adjustment	F-9
Note 4 ― Significant Accounting Policies	F-10
Note 5 ― Inventory	F-14
Note 6 ― Property, Plant and Equipment	F-14
Note 7 ― Asset Retirement Obligation	F-14
Note 8 ― Investment in Unconsolidated Affiliates	F-15
Note 9 ― Debt Obligations	F-16
Note 10 ― Convertible Participating Preferred Stock	F-20
Note 11 ― Partner Units and Related Matters	F-20
Note 12 ― Earnings Per Share	F-22
Note 13 ― Insurance Claims	F-23
Note 14 ― Derivative Instruments and Hedging Activities	F-24
Note 15 ― Related Party Transactions	F-26
Note 16 ― Commitments and Contingencies	F-28
Note 17 ― Fair Value Measurements	F-29
Note 18 ― Income Taxes	F-31
Note 19 ― Fair Value of Financial Instruments	F-32
Note 20 ― Supplemental Cash Flow Information	F-33
Note 21 ― Segment Information	F-33
Note 22 ― Other Operating Income	F-36
Note 23 ― Significant Risks and Uncertainties	F-36
Note 24 ― Stock and Other Compensation Plans	F-39
Note 25 ― Selected Quarterly Financial Data	F-43

Schedule I - Condensed Financial Information of Registrant - Parent Only	F-44

Report of Independent Public Firm on Condensed Financial Information of Registrant - Parent Only	F-44

Parent Only - Condensed Balance Sheets as of December 31, 2010 and December 31, 2009	F-45

Parent Only - Condensed Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008	F-46

Parent Only - Condensed Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008	F-47

Parent Only - Note to Condensed Financial Statements	F-48
Note 1 - Basis of Presentation	F-48

F-1

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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

Management has used the framework set forth in the report entitled “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the internal control over financial reporting. Based on that evaluation, management has concluded that the internal control over financial reporting was effective as of December 31, 2010.

/s/ Rene R. Joyce

Rene R. Joyce

Chief Executive Officer

(Principal Executive Officer)

/s/ Matthew J. Meloy

Matthew J. Meloy

Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)

F-2

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Targa Resources Corp.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of changes in owners' equity and of cash flows present fairly, in all material respects, the financial position of Targa Resources Corp. and its subsidiaries (the "Company") at December 31, 2010 and 2009, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements 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 financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 25, 2011

F-3

Index to Financial Statements

TARGA RESOURCES CORP.
CONSOLIDATED BALANCE SHEETS

	December 31,
	2010			2009
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	188.4		$	252.4
Trade receivables, net of allowances of $7.9 million and $8.0 million		466.6			404.3
Inventory		50.4			39.4
Deferred income taxes		3.6			-
Assets from risk management activities		25.2			32.9
Other current assets		16.3			16.0
Total current assets		750.5			745.0
Property, plant and equipment, at cost		3,331.4			3,193.3
Accumulated depreciation		(822.4	)		(645.2	)
Property, plant and equipment, net		2,509.0			2,548.1
Long-term assets from risk management activities		18.9			13.8
Other long-term assets		115.4			60.6
Total assets	$	3,393.8		$	3,367.5

LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable	$	254.2		$	206.4
Accrued liabilities		335.8			304.3
Current maturities of debt		-			12.5
Deferred income taxes		-			1.4
Liabilities from risk management activities		34.2			29.2
Total current liabilities		624.2			553.8
Long-term debt, less current maturities		1,534.7			1,593.5
Long-term liabilities from risk management activities		32.8			43.8
Deferred income taxes		111.6			50.0
Other long-term liabilities		54.4			63.1

Commitments and contingencies (see Note 16)

Convertible cumulative participating series B preferred stock
(100.0 million shares authorized, none and 6.4 million shares issued and
outstanding at December 31, 2010 and December 31, 2009)		-			308.4

Owners' equity:
Targa Resources Corp. stockholders' equity:
Common stock
($0.001 par value, 300.0 million shares authorized, 42.3 million and 3.9 million
shares issued and outstanding at December 31, 2010 and December 31, 2009)		-			-
Additional paid-in capital		244.5			194.0
Accumulated deficit		(100.8	)		(85.8	)
Accumulated other comprehensive income (loss)		0.6			(20.3	)
Treasury stock, at cost		-			(0.5	)
Total Targa Resources Corp. stockholders' equity		144.3			87.4
Noncontrolling interests in subsidiaries		891.8			667.5
Total owners' equity		1,036.1			754.9
Total liabilities and owners' equity	$	3,393.8		$	3,367.5

See notes to consolidated financial statements

F-4

Index to Financial Statements

TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2010			2009			2008
	(In millions, except per share amounts)
Revenues	$	5,469.2		$	4,536.0		$	7,998.9
Costs and expenses:
Product purchases		4,687.7			3,791.1			7,218.5
Operating expenses		260.2			235.0			275.2
Depreciation and amortization expenses		185.5			170.3			160.9
General and administrative expenses		144.4			120.4			96.4
Other		(4.7	)		2.0			13.4
		5,273.1			4,318.8			7,764.4
Income from operations		196.1			217.2			234.5
Other income (expense):
Interest expense, net		(110.9	)		(132.1	)		(141.2	)
Equity in earnings of unconsolidated investments		5.4			5.0			14.0
Gain (loss) on debt repurchases (see Note 9)		(17.4	)		(1.5	)		25.6
Gain on early debt extinguishment (see Note 9)		12.5			9.7			3.6
Gain on insurance claims (see Note 13)		-			-			18.5
Gain (loss) on mark-to-market derivative instruments		(0.4	)		0.3			(1.3	)
Other income		0.5			1.2			-
Income before income taxes		85.8			99.8			153.7
Income tax (expense) benefit:
Current		10.6			(1.6	)		(1.3	)
Deferred		(33.1	)		(19.1	)		(18.0	)
		(22.5	)		(20.7	)		(19.3	)
Net income		63.3			79.1			134.4
Less: Net income attributable to noncontrolling interest		78.3			49.8			97.1
Net income (loss) attributable to Targa Resources Corp.		(15.0	)		29.3			37.3
Dividends on Series B preferred stock		(9.5	)		(17.8	)		(16.8	)
Undistributed earnings attributable to preferred shareholders		-			(11.5	)		(20.5	)
Dividends on common equivalents		(177.8	)		-			-
Net income (loss) available to common shareholders		(202.3	)		-			-
Net income (loss) available per common share	$	(30.94	)	$	-		$	-
Weighted average shares outstanding - basic and diluted		6.5			3.8			3.8

See notes to consolidated financial statements

F-5

Index to Financial Statements

TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31,
	2010			2009			2008
	(In millions)
Net income (loss) attributable to Targa Resources Corp.	$	(15.0	)	$	29.3		$	37.3
Other comprehensive income (loss) attributable to Targa Resources Corp.
Commodity hedging contracts:
Change in fair value		38.0			(49.6	)		110.9
Reclassification adjustment for settled periods		(4.0	)		(39.5	)		40.4
Interest rate hedges:
Change in fair value		(1.9	)		(7.2	)		(5.0	)
Reclassification adjustment for settled periods		1.6			8.8			0.7
Foreign currency translation adjustment		-			-			(1.8	)
Related income taxes		(12.8	)		31.1			(52.8	)
Other comprehensive income (loss) attributable to Targa Resources Corp.		20.9			(56.4	)		92.4

Comprehensive income (loss) attributable to Targa Resources Corp.		5.9			(27.1	)		129.7

Net income attributable to noncontrolling interest		78.3			49.8			97.1
Other comprehensive income (loss) attributable to
noncontrolling interest:
Commodity hedging contracts:
Change in fair value		14.5			(54.7	)		95.5
Reclassification adjustment for settled periods		(4.4	)		(30.2	)		24.7
Interest rate swaps:
Change in fair value		(18.2	)		(0.1	)		(14.0	)
Reclassification adjustment for settled periods		7.7			6.9			2.0
Other comprehensive income (loss) attributable to
noncontrolling interest		(0.4	)		(78.1	)		108.2
Comprehensive income (loss) attributable to
noncontrolling interest		77.9			(28.3	)		205.3
Total comprehensive income (loss)	$	83.8		$	(55.4	)	$	335.0

See notes to consolidated financial statements

F-6

Index to Financial Statements

TARGA RESOURCES CORP.
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY

												Accumulated
						Additional						Other									Non
	Common Stock					Paid in			Accumulated			Comprehensive			Treasury Stock						Controlling
	Shares			Amount		Capital			Deficit			Income (Loss)			Shares			Amount			Interest			Total
	(In millions, except shares in thousands)
Balance, December 31, 2007		3,653		$	-	$	230.4		$	(152.4	)	$	(56.3	)		18		$	-		$	552.4		$	574.1
Option exercises		181			-		0.8			-			-			-			-			-			0.8
Forfeiture of non-vested common stock		(27	)		-		-			-			-			-			-			-			-
Repurchases of common stock		-			-		-			-			-			70			(0.5	)		-			(0.5	)
Dividends of Series B preferred stock		-			-		(16.8	)		-			-			-			-			-			(16.8	)
Impact of equity transactions of the Partnership		-			-		(0.4	)		-			-			-			-			0.4			-
VESCO Acquisition		-			-		-			-			-			-			-			41.9			41.9
Distribution of property		-			-		-			-			-			-			-			(14.8	)		(14.8	)
Contributions		-			-		-			-			-			-			-			0.3			0.3
Dividends		-			-		-			-			-			-			-			(98.5	)		(98.5	)
Amortization of equity awards		-			-		1.2			-			-			-			-			0.3			1.5
Tax expense on vesting of common stock		-			-		(1.0	)		-			-			-			-			-			(1.0	)
Other comprehensive income		-			-		-			-			92.4			-			-			108.2			200.6
Net income		-			-		-			37.3			-			-			-			97.1			134.4
Balance, December 31, 2008		3,807			-		214.2			(115.1	)		36.1			88			(0.5	)		687.3			822.0
Option exercises		106			-		0.3			-			-			-			-			-			0.3
Forfeiture of non-vested common stock		(3	)		-		-			-			-			-			-			-			-
Repurchases of common stock		-			-		-			-			-			9			-			-			-
Impact of equity transactions of the Partnership		-			-		(2.9	)		-			-			-			-			2.9			-
Contributions		-			-		-			-			-			-			-			103.8			103.8
Dividends		-			-		-			-			-			-			-			(98.5	)		(98.5	)
Dividends on Series B preferred stock		-			-		(17.8	)		-			-			-			-			-			(17.8	)
Amortization of equity awards		-			-		0.4			-			-			-			-			0.3			0.7
Tax expense on vesting of common stock		-			-		(0.2	)		-			-			-			-			-			(0.2	)
Other comprehensive income (loss)		-			-		-			-			(56.4	)		-			-			(78.1	)		(134.5	)
Net income		-			-		-			29.3			-			-			-			49.8			79.1
Balance, December 31, 2009		3,910			-		194.0			(85.8	)		(20.3	)		97			(0.5	)		667.5			754.9
Option exercises		1,161			-		0.6			-			-			(69	)		0.3			-			0.9
Compensation on equity grants		1,906			-		13.8			-			-			-			-			-			13.8
Repurchases of common stock		-			-		-			-			-			13			(0.1	)		-			(0.1	)
Proceeds from sale of limited partner
interests in the Partnership		-			-		-			-			-			-			-			224.4			224.4
Impact of equity transactions of the Partnership		-			-		258.9			-			-			-			-			(258.9	)		-
Tax impact of equity offerings		-			-		(79.6	)		-			-			-			-			-			(79.6	)
Proceeds from Partnership Equity offerings		-			-		-			-			-			-			-			317.8			317.8
Dividends to noncontrolling interests		-			-		-			-			-			-			-			(136.9	)		(136.9	)
Dividends to common and common equivalents		-			-		(213.3	)		-			-			-			-			-			(213.3	)
Dividends on Series B preferred stock		-			-		(9.5	)		-			-			-			-			-			(9.5	)
Series B Preferred Conversion		35,356			-		79.9			-			-			-			-			-			79.9
Other comprehensive income		-			-		-			-			20.9			-			-			(0.4	)		20.5
Treasury shares retired		(41	)		-		(0.3	)		-			-			(41	)		0.3			-			-
Net income (loss)		-			-		-			(15.0	)		-			-			-			78.3			63.3
Balance, December 31, 2010		42,292		$	-	$	244.5		$	(100.8	)	$	0.6			-		$	-		$	891.8		$	1,036.1

See notes to consolidated financial statements

F-7

Index to Financial Statements

TARGA RESOURCES CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Year Ended December 31,
	2010			2009			2008
	(In millions)
Cash flows from operating activities
Net income (loss)	$	63.3		$	79.1		$	134.4
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		9.4			10.2			9.6
Paid-in-kind interest expense		10.9			25.9			38.2
Compensation on equity grants		13.4			0.7			1.5
Depreciation and amortization expense		174.7			168.8			160.9
Asset impairment charges		10.8			1.5			-
Accretion of asset retirement obligations		3.3			2.9			1.9
Deferred income tax expense		33.1			19.1			18.0
Equity in earnings of unconsolidated investments, net of distributions		3.4			-			(9.4	)
Risk management activities		29.9			40.3			(64.5	)
Loss (gain) on sale of assets		(1.5	)		0.1			(5.9	)
Loss (gain) on debt repurchases		17.4			1.5			(25.6	)
Loss (gain) on early debt extinguishment		(12.5	)		(9.7	)		(3.6	)
Gain on property damage insurance settlement (See Note 13)		-			-			(18.5	)
Repayments of interest of Holdco loan facility		(0.9	)		(6.0	)		(4.3	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		(119.2	)		(140.1	)		600.7
Inventory		(11.4	)		19.3			72.8
Accounts payable and other liabilities		(15.6	)		122.2			(515.5	)
Net cash provided by operating activities		208.5			335.8			390.7
Cash flows from investing activities
Outlays for property, plant and equipment		(139.3	)		(99.4	)		(132.3	)
Acquisitions, net of cash acquired		-			-			(124.9	)
Proceeds from property insurance		3.5			38.8			48.3
Other		1.2			1.3			2.2
Net cash used in investing activities		(134.6	)		(59.3	)		(206.7	)
Cash flows from financing activities
Loan Facilities of Targa:
Borrowings		495.0			-			95.9
Repayments		(1,087.4	)		(589.2	)		(74.6	)
Loan Facilities of the Partnership:
Borrowings		1,593.1			806.6			435.3
Repayments		(1,057.0	)		(596.6	)		(350.6	)
Dividends to noncontrolling interest		(136.9	)		(98.5	)		(98.5	)
Proceeds from secondary offering of interests in the Partnership		224.4			-			-
Proceeds from Partnership equity offerings		317.8			103.8			0.3
Issuance of common stock		0.9			0.3			0.8
Repurchases of common stock		(0.1	)		-			(0.5	)
Dividends to common and common equivalent shareholders		(210.1	)		-			-
Dividends to preferred shareholders		(238.0	)		-			-
Costs incurred in connection with financing arrangements		(39.6	)		(13.3	)		(7.2	)
Net cash provided by (used in) financing activities		(137.9	)		(386.9	)		0.9
Net change in cash and cash equivalents		(64.0	)		(110.4	)		184.9
Cash and cash equivalents, beginning of period		252.4			362.8			177.9
Cash and cash equivalents, end of period	$	188.4		$	252.4		$	362.8

See notes to consolidated financial statements

F-8

Index to Financial Statements

TARGA RESOURCES CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 —Organization and Operations

Targa Resources Corp., formerly Targa Resources Investments Inc. (“TRC”), is a Delaware corporation formed on October 27, 2005. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended to mean our consolidated business and operations.

Note 2 – Basis of Presentation

The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2010 and 2009, and the results of our operations, comprehensive income, cash flows and changes in owners’ equity for the years ended December 31, 2010, 2009 and 2008.

We have prepared our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All significant intercompany balances and transactions have been eliminated.

We are the sole member of Targa Resources GP LLC, the managing general partner of Targa Resources Partners LP (“the Partnership”). Because we control the General Partner of the Partnership, under generally accepted accounting principles, we must reflect our ownership interest in the Partnership on a consolidated basis. Accordingly, our financial results are combined with the Partnership’s financial results in our consolidated financial statements even though the distribution or transfer of Partnership assets are limited by the terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by controlling affiliates of us are reflected in our results of operations as net income attributable to non-controlling interests and in our balance sheet equity section as noncontrolling interests in subsidiaries. Throughout these footnotes, we make a distinction where relevant between financial results of the Partnership versus those of a standalone parent and its non-partnership subsidiaries.

As of December 31, 2010, our interests in the Partnership consist of the following:

·	a 2% general partner interest, which we hold through our 100% ownership interest in the general partner of the Partnership;

·	all Incentive Distribution Rights (IDRs); and

·	11,645,659 common units of the Partnership, representing a 15.4% limited partnership interest.

In preparing the accompanying consolidated financial statements, we have reviewed events that have occurred after December 31, 2010, up until the issuance of the financial statements. See Notes 9, 11, 12and 24.

Note 3 – Out of Period Adjustment

During 2009, we recorded adjustments related to prior periods which decreased our income before income taxes for 2009 by $5.4 million. The adjustments consisted of $7.2 million related to debt issue costs that should have been expensed during 2007 and $1.8 million of revenue which should have been recorded during 2006.

Had these adjustments been previously recorded in their appropriate periods, net income attributable to Targa for the year ended December 31, 2009 would have increased by $3.4 million.

After evaluating the quantitative and qualitative aspects of these errors, we concluded that our previously issued financial statements were not materially misstated and the effect of recognizing these adjustments in 2009 financial statements was not material to the 2009 or 2007 results of operations, financial position or cash flows.

F-9

Index to Financial Statements

Note 4 —Significant Accounting Policies

Consolidation Policy. Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undivided interests in various gas processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities. Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests.

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

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

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

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

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

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

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

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

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

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

F-10

Index to Financial Statements

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

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure hedge ineffectiveness on a quarterly basis and reclassify any ineffective portion of the unrealized gain or loss to earnings in the current period.

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

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

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

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

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

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

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of operations. See Note 6.

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.

F-11

Index to Financial Statements

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

Debt Issue Costs. Costs incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt. Gains or losses on debt repurchases and debt extinguishments include any associated unamortized debt issue costs.

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 16.

Income Taxes. We account for income taxes using the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.

We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we establish a valuation allowance. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.

We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize assets for which no reserve has been established.

Non-controlling Interest. Non-controlling interest represents third party ownership in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with any third party investors’ interest shown as non-controlling interest within the equity section of the balance sheet. In the statements of operations, non-controlling interest reflects the allocation of earnings to third party investors. We account for the difference between the carrying amount of our investment in the Partnership and the underlying book value arising from issuance of common units by the Partnership, where we maintain control, as an equity transaction. If the Partnership issues common units at a price different than our carrying value per unit, we account for the premium or deficiency as an adjustment to paid-in capital.

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

·	sales of natural gas, NGLs and condensate;

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

·	NGL fractionation, terminalling and storage, transportation and treating.

F-12

Index to Financial Statements

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

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

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

Share-Based Compensation. We award share-based compensation to employees and directors in the form of restricted stock, stock options and performance unit awards. Compensation expense on restricted stock and stock options is measured by the fair value of the award as determined by management at the date of grant. Compensation expense on performance unit awards that qualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured subsequently at each reporting date through the settlement period. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. See Note 24.

Earnings per share. We account for earnings per share (EPS) in accordance with ASC 260 – Earnings per Share. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock so long as it does not have an anti-dilutive effect on EPS. Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Prior to the conversion of the Series B Preferred Stock on December 10, 2010, we used the two-class method of allocating earnings between our common and preferred class of stock outstanding for the purposes of presenting net income per share. See Note 12.

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

Accounting Pronouncements Recently Adopted

Fair Value Measurements

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

F-13

Index to Financial Statements

Note 5 —Inventory

Due to fluctuating commodity prices for natural gas liquids, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceeds their net realizable value. These non-cash adjustments are charged to product purchases in the period they are recognized, with the related cash impact in the subsequent period of sale. For 2010 and 2009, we did not recognize an adjustment to the carrying value of our NGL inventory. At December 31, 2008, we recognized $6.0 million to reduce the carrying value of NGL inventory to its net realizable value.

Note 6 – Property, Plant and Equipment

	December 31,
	2010						2009
	Targa Resources Partners LP		TRC-Non-Partnership		Targa Resources Corp-Consolidated		Targa Resources Partners LP		TRC-Non-Partnership		Targa Resources Corp-Consolidated		Range of Years
Natural gas gathering systems	$	1,630.9	$	-		1,630.9	$	1,578.0	$	-	$	1,578.0	5 to 20
Processing and fractionation facilities		961.9		6.6		968.5		949.8		6.2		956.0	5 to 25
Terminalling and natural gas liquids
storage facilities		244.7		-		244.7		238.6		8.0		246.6	5 to 25
Transportation assets		275.6		-		275.6		271.6		-		271.6	10 to 25
Other property, plant and equipment		46.8		22.6		69.4		45.3		20.9		66.2	3 to 25
Land		51.2		-		51.2		50.9		1.8		52.7		-
Construction in progress		88.4		2.7		91.1		21.3		0.9		22.2		-
	$	3,299.5	$	31.9		3,331.4	$	3,155.5	$	37.8	$	3,193.3

Note 7 – Asset Retirement Obligations

Our asset retirement obligations primarily relate to certain of the Partnership’s gas-gathering pipeline and processing facilities and are included in our consolidated balance sheets as a component of other long-term liabilities. The changes in our aggregate asset retirement obligations are as follows:

	Year Ended December 31,
	2010		2009			2008
Beginning of period	$	34.1	$	34.0		$	12.6
Liabilities incurred(1)		-		-			16.9
Liabilities settled		-		-			(0.2	)
Change in cash flow estimate(2)		0.3		(2.8	)		2.8
Accretion expense		3.3		2.9			1.9
End of period	$	37.7	$	34.1		$	34.0

________

(1)	The 2008 amount relates to our consolidation of Venice Energy Services Company, LLC (“VESCO”). See Note 8.

(2)	The change in cash flow estimate is primarily from a reassessment of abandonment cost estimates for our offshore gathering systems.

F-14

Index to Financial Statements

Note 8 – Investment in Unconsolidated Affiliates

As of December 31, 2010 and 2009, the Partnership’s unconsolidated investment consisted of a 38.8% ownership interest in Gulf Coast Fractionators LP (“GCF), included in Other long-term assets on the consolidated balance sheet.

Prior to July 31, 2008 our unconsolidated investments also included a 22.9% ownership interest in VESCO. On July 31, 2008, we acquired an additional 53.9% interest, giving us effective control under the terms of the operating agreement; therefore, we have consolidated the operations of VESCO in our financial results effective August 1, 2008.

The following table shows the activity related to our unconsolidated investments for the years indicated:

	December 31,
	2010		2009		2008
Equity in earnings of
VESCO (1)(2)	$	-	$	-	$	10.1
GCF		5.4		5.0		3.9
	$	5.4	$	5.0	$	14.0
Cash Distributions:
GCF	$	8.8	$	5.0	$	4.6

______

1)	Includes our equity earnings through July 31, 2008.

2)	Includes business interruption insurance claims of $4.1 million for 2008.

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

F-15

Index to Financial Statements

Note 9 – Debt Obligations

Our consolidated debt obligations include our obligations, the obligations of TRI Resources, Inc. (“TRI”) and the Partnership’s obligations.

	December 31,
	2010			2009
Long-term debt:
Obligations of Targa:
TRC Holdco loan facility, variable rate, due February 2015 (1)	$	89.3		$	385.4
TRI Senior secured revolving credit facility, variable rate, due July 2014 (2)		-			-
TRI Senior secured term loan facility, variable rate, due October 2012		-			62.2
TRI Senior unsecured notes, 8½% fixed rate, due November 2013		-			250.0
Obligations of the Partnership: (3)
Senior secured revolving credit facility, variable rate, due July 2015 (4)		765.3			-
Senior secured revolving credit facility, variable rate, due February 2012		-			479.2
Senior unsecured notes, 8¼% fixed rate, due July 2016		209.1			209.1
Senior unsecured notes, 11¼% fixed rate, due July 2017		231.3			231.3
Unamortized discounts, net of premiums		(10.3	)		(11.2	)
Senior unsecured notes, 7⅞% fixed rate, due October 2018		250.0			-
Total debt		1,534.7			1,606.0
Current maturities of TRI debt		-			(12.5	)
Total long-term debt	$	1,534.7		$	1,593.5
Irrevocable standby letters of credit:
Letters of credit outstanding under the TRI senior secured synthetic letter of credit facilities	$	-		$	9.5
Letters of credit outstanding under senior secured revolving credit facilities of the Partnership		101.3			108.4
	$	101.3		$	117.9

___________

(1)	Quarterly, we make an election to pay interest when due or refinance the interest as part of our long-term debt.

(2)	As of December 31, 2010, availability under TRI’s senior secured revolving credit facility was $75.0 million.

(3)	While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.

(4)	As of December 31, 2010, availability under the Partnership’s senior secured revolving credit facility was $233.4 million.

The following table shows the range of interest rates paid and weighted average interest rate paid on our variable-rate debt obligations during the year ended December 31, 2010:

	Range of interest	Weighted average
	rates paid	interest rate paid
TRC Holdco loan facility	3.3% to 5.4%	5.0%
Senior secured term loan facility of TRI, due 2014	5.8% to 6.0%	5.9%
Senior secured revolving credit facility of the Partnership	1.2% to 5.0%	2.3%

Compliance with Debt Covenants

As of December 31, 2010, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.

F-16

Index to Financial Statements

TRC Holdco Loan Facility

During the year ended December 31, 2010, we completed transactions that have been recognized in our consolidated financial statements as a debt extinguishment, and recognized a pretax gain of $36.8 million. The transactions, executed by us, were payments of $269.3 million to acquire $306.1 million of outstanding borrowings (including accrued interest of $23.1 million) under our Holdco credit agreement (“Holdco debt”) and write offs of associated debt issue costs totaling $2.0 million. After this transaction, we removed all of the debt covenants associated with the TRC Holdco Loan Facility, as we have cumulatively repurchased over 50% of the original principal of the Holdco debt.

On November 3, 2010, we amended our Holdco agreement to name our wholly-owned subsidiary, Targa Resources Inc. (“TRI”), as guarantor to our obligations under the credit agreement. The operations and assets of the Partnership continue to be excluded as guarantors of the Holdco debt.

During the year ended December 31, 2009, we completed a transaction that has been recognized in our consolidated financial statements as a debt extinguishment, and recognized a pretax gain of $24.5 million, net of debt issue costs of $0.7 million. The transactions, executed by TRI, were payments of $39.3 million to acquire $64.5 million of outstanding borrowings (including accrued interest of $6.0 million) under our Holdco debt. We wrote-off $0.7 million of associated debt issuance costs.

Interest on borrowings are payable, at our option, either (i) entirely in cash, (ii) entirely by increasing the principal amount of the outstanding borrowings or (iii) 50% cash and 50% by increasing the principal amount of the outstanding borrowings.

Borrowings outstanding under the credit facility bear interest at a rate equal to an applicable rate plus, at our option, either (i) a base rate determined by reference to the higher of (1) the prime rate of Credit Suisse or (2) the federal funds rate plus 0.5% or (ii) LIBOR as determined by reference to the costs of funds for dollar deposits for the interest period relevant to such borrowing adjusted for certain statutory reserves. At December 31, 2010, the applicable rate for borrowings under the credit facility was 4% with respect to base rate borrowings and 5% with respect to LIBOR borrowings.

Principal amounts outstanding under the credit facility are due and payable in February 2015. We may prepay all of part of the principal amount outstanding, at our option, at 101% of the principal amount outstanding until August 9, 2011, then at 100% of the principal amount outstanding.

TRI Senior Secured Credit Agreement

On January 5, 2010 TRI entered into a senior secured credit agreement (the “credit agreement”) providing senior secured financing of $600.0 million, consisting of:

$500.0 million senior secured term loan facility; and

•	$100.0 million senior secured revolving credit facility (the “credit facility”).

The entire amount of our credit facility is available for letters of credit and includes a limited borrowing capacity for borrowings on same-day notice referred to as swing line loans. Our available capacity under this facility is currently $75 million. TRI is the borrower under this facility.

Borrowings under the credit agreement bear interest at a rate equal to an applicable margin, plus at our option, either (a) a base rate determined by reference to the higher of (1) the prime rate of Deutsche Bank, (2) the federal funds rate plus 0.5%, and (3) solely in the case of term loans, 3%, or (b) LIBOR as determined by reference to the higher of (1) the British Bankers Association LIBOR Rate and (2) solely in the case of term loans, 2%.

In addition to paying interest on outstanding principal under the senior secured credit facilities, TRI is required to pay other fees. TRI is required to pay a commitment fee equal to 0.5% of the current unutilized commitments. The commitment fee rate may fluctuate based upon TRI’s leverage ratios. TRI is also required to pay a fronting fee equal to 0.25% on outstanding letters of credit.

F-17

Index to Financial Statements

The credit agreement requires TRI to prepay loans outstanding under the senior secured term loan facility, subject to certain exceptions, with:

•	50% of our annual excess cash flow (which percentage will be reduced to 25% if our total leverage ratio is no more than 3.00 to 1.00 and to 0% if our total leverage ratio is no more than 2.50 to 1.00);

•	up to 100% of the net cash proceeds of all non-ordinary course asset sales, transfers or other dispositions of property, subject to our consolidated leverage ratio; and

•	100% of the net cash proceeds of any incurrence of debt, other than debt permitted under the credit agreement.

During the year ended December 31, 2010, our term loan facility was paid in full, the available capacity of the revolving credit facility was reduced to $75.0 million and the full amount is available for borrowing as of December 31, 2010.

All obligations under the credit agreement and certain secured hedging arrangements are unconditionally guaranteed, subject to certain exceptions, by each of TRI’s existing and future domestic restricted subsidiaries, referred to, collectively, as the guarantors. TRI has pledged the following assets, subject to certain exceptions, as collateral:

•	the capital stock and other equity interests held by TRI or any guarantor; and

•	a security interest in, and mortgages on, TRI’s and its guarantors’ tangible and intangible assets.

The credit agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, TRI’s ability to incur additional indebtedness (including guarantees and hedging obligations); create liens on assets; enter into sale and leaseback transactions; engage in mergers or consolidations; sell assets; pay dividends and make distributions or repurchase capital stock and other equity interests; make investments, loans or advances; make capital expenditures; repay, redeem or repurchase certain indebtedness; make certain acquisitions; engage in certain transactions with affiliates; amend certain debt and other material agreements; change TRI’s lines of business; and impose certain restrictions on restricted subsidiaries that are not guarantors, including restrictions on the ability of such subsidiaries that are not guarantors to pay dividends.

The credit agreement requires TRI to maintain certain specified maximum total leverage ratios and certain specified minimum interest coverage ratios. In each case we are required to comply with certain limitations, including minimum cash consideration requirements.

On January 5, 2010, concurrent with the execution of the credit agreement, TRI borrowed $500.0 million on the term loan facility net of a $5.0 million discount. There was no initial funding on the revolving credit line. The proceeds from the term loan were used to:

•	complete the cash tender offer and consent solicitation for all $250.0 million of TRI’s outstanding 8 ½% senior notes due 2013;

•	repay the outstanding balance of $62.2 million on TRI’s existing senior secured term loan due 2012;

•	purchase $164.2 million in face value of the Holdco Notes for $131.4 million ; and

•	fund working capital and pay fees and expenses under the credit agreement.

During the year ended December 31, 2010, TRI incurred a gain on early debt extinguishments of $12.5 million from the write-off of debt issue costs related to the repayments of TRI’s term loan, and the purchase of the Holdco Notes as discussed above.

During 2009, TRI repaid substantially all of its senior secured term loan facility and recognized a $14.8 million loss on early debt extinguishment consisting of the write-off of debt issue costs related to the facility.

During 2009, TRI also incurred a loss on debt repurchases of $17.4 million comprising $10.9 million of premiums paid and $6.5 million from the write-off of debt issue costs related to the repurchase of TRI’s 8½% senior notes discussed above. The premiums paid were included as a cash outflow from a financing activity in the Statement of Cash Flows.

F-18

Index to Financial Statements

Senior Secured Credit Facility of the Partnership

On July 19, 2010, the Partnership entered into an Amended and Restated Credit Agreement that replaced the Partnership’s existing variable rate Senior Secured Credit Facility with a new variable rate Senior Secured Credit Facility due July 2015. The amended and restated Senior Secured Credit Facility increases available commitments to the Partnership to $1.1 billion from $958.5 million and allows the Partnership to request increases in commitments up to an additional $300 million.

The Partnership incurred a charge of $0.8 million related to a partial write-off of debt issue costs associated with this amended and restated credit facility related to a change in syndicate members. The remaining balance in debt issue costs of $4.7 million is being amortized over the life of the amended and restated credit facility.

The Partnership’s amended and restated credit facility bears interest at LIBOR plus an applicable margin ranging from 2.25% to 3.5% dependent on the Partnership’s consolidated funded indebtedness to consolidated adjusted EBITDA ratio. The Partnership’s new credit facility is secured by substantially all of the Partnership’s assets. As of December 31, 2010, availability under the Partnership’s Senior Secured Revolving Credit Facility was $233.4 million, after giving effect to $101.3 million in outstanding letters of credit.

The Partnership’s senior secured credit facility restricts its ability to make distributions of available cash to unitholders if a default or an event of default (as defined in its senior secured credit agreement) has occurred and is continuing. The senior secured credit facility requires the Partnership to maintain a consolidated funded indebtedness to consolidated adjusted EBITDA of less than or equal to 5.50 to 1.00. The Partnership’s senior secured credit facility also requires it to maintain an interest coverage ratio (the ratio of its consolidated EBITDA to its consolidated interest expense, as defined in its senior secured 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.

Senior Unsecured Notes of the Partnership

The Partnership has three issues of unsecured senior notes. On June 18, 2008, the Partnership privately placed $250 million in aggregate principal amount of 8¼% senior notes due 2016 (the “8¼% Notes”). On July 6, 2009, the Partnership privately placed $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. On August 13, 2010 the Partnership privately placed $250 million in aggregate principal amount of 7⅞% senior notes due 2018 (the “7⅞% Notes”).

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

Interest on the 8¼% Notes accrues at the rate of 8¼% per annum and is payable semi-annually in arrears on January 1 and July 1. 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. Interest on the 7⅞% Notes accrues at the rate of 7⅞% per annum and is payable semi-annually in arrears on April 15 and October 15, commencing on April 15, 2011.

The Partnership may redeem up to 35% of the aggregate principal amount each of our series of notes, at any time prior to July 1, 2011 for the 8¼% Notes (July 15, 2012 for the 11¼% Notes, and October 15, 2013 for the 7⅞% Notes), with the net cash proceeds of one or more equity offerings. The Partnership must pay a redemption price of 108.25% of the principal amount for the 8¼% Notes (111.25% for the 11¼% Notes, and 107.875% for the 7⅞ Notes), plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:

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

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

F-19

Index to Financial Statements

The Partnership may also redeem all or a part of each of the series of notes, on or after July 1, 2012 for the 8¼% Notes (July 15, 2013 for the 11¼% Notes, October 15, 2014 for the 7⅞ Notes) at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidated damages, if any, on the notes redeemed, if redeemed during the twelve-month period beginning on July 1 for the 8¼% Notes (July 15 for the 11¼% Notes, October 15 for the 7⅞% Notes) of each year indicated below:

8¼% Notes		11¼% Notes		7⅞% Notes
Year	Redemption %	Year	Redemption %	Year	Redemption %
2012	104.125%	2013	105.625%	2014	103.938%
2013	102.063%	2014	102.813%	2015	101.969%
2014 and thereafter	100.000%	2015 and thereafter	100.000%	2016 and thereafter	100.000%

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

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

Subsequent Events. On February 2, 2011, the Partnership closed on a private placement of $325 million in aggregate principal amount of 6⅞% Senior Notes due 2021 (“the 6⅞% Notes”) resulting in net proceeds of $319.3 million.

On February 4, 2011 the Partnership exchanged $158.6 million under an exchange offer to holders of its 11¼% Notes due 2017 for $158.6 million principal amount 6⅞% Notes due 2021. In conjunction with the exchange the Partnership paid a premium in cash of $28.6 million. The debt covenants related to the remaining $72.7 million of face value 11¼% Notes due 2017 were removed as the Partnership received sufficient consents in connection with the exchange offer to amend the indenture.

Note 10 – Convertible Participating Preferred Stock

The holders of the Series B stock accrued dividends at an annual rate of 6% of the accreted value of the stock (purchase price plus unpaid dividends, compounded quarterly) until December 10, 2010, at which time we completed our IPO and all of our Series B stock converted to common stock based (a) a conversion ratio of one share of our Series B stock to 4.92 shares of our Common Stock plus (b) the accreted value per share of the Series B stock divided by the IPO price after deducting underwriter discounts and commissions.

Cash dividends on the Series B stock were payable when declared by our Board of Directors, subject to restrictions under our debt agreements. During the year ended 2010, we paid dividends of $238 million to the Series B preferred shareholders and an additional $177.8 million to common equivalent shareholders. The common equivalent shareholders are the holders of the Series B stock that participate ratably in such common dividend in proportion to the number of shares of common stock that were issuable upon the conversion of the shares of Series B stock.

Note 11 – Partnership Units and Related Matters

On January 19, 2010, the Partnership completed a public offering of 5,500,000 common units representing limited partner interests in the Partnership (“common units”) under its existing shelf registration statement on Form S-3 (“Registration Statement”) 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, providing net proceeds of $18.3 million. In addition, we contributed $3.0 million for 129,082 general partner units to maintain our 2% general partner interest. The Partnership used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under its senior secured credit facility.

F-20

Index to Financial Statements

On April 14, 2010, Targa LP Inc., a wholly-owned subsidiary of ours, closed on a secondary public offering of 8,500,000 common units of the Partnership at $27.50 per common unit. Proceeds from this offering, after underwriting discounts and commission were $224.4 million before expenses associated with the offering. This offering also triggered a mandatory prepayment on our senior secured credit agreement of $3.2 million related to TRI’s senior secured revolving credit facility and $105.6 million on TRI’s senior secured term loan facility.

On April 27, 2010, we completed the sale of our interests in the Permian Business and Straddle Assets to the Partnership for $420.0 million, effective April 1, 2010. This sale triggered a mandatory prepayment on TRI’s senior secured credit agreement of $152.5 million, which was paid on April 27, 2010. As part of the closing of the sale of our Permian Business and Straddle Assets, we amended our Omnibus Agreement with the Partnership, to continue to provide general and administrative and other services to the Partnership through April 2013.

On August 13, 2010, the Partnership completed an offering of 6,500,000 of its common units under the Registration Statement at a price of $24.80 per common unit ($23.82 per common unit, net of underwriting discounts) providing net proceeds to the Partnership of approximately $154.8 million. Pursuant to the exercise of the underwriters’ overallotment option, the Partnership sold an additional 975,000 common units, providing net proceeds of approximately $23.2 million. In addition, we contributed $3.8 million for 152,551 general partner units to maintain a 2% general partner interest. The Partnership used the net proceeds from this offering to reduce borrowings under its senior secured credit facility.

On August 25, 2010, we completed the sale to the Partnership of our 63% equity interest in Versado, effective August 1, 2010, for $247.2 million in the form of $244.7 million in cash and $2.5 million in partnership interests represented by 89,813 common units and 1,833 general partner units. The sale triggered a mandatory prepayment of $91.3 million under TRI’s senior secured credit facility. Under the terms of the Versado Purchase and Sale Agreement, Targa will reimburse the Partnership for future maintenance capital expenditures required pursuant to our New Mexico Environmental Department settlement agreement, of which our share is currently estimated at $19.0 million, to be incurred through 2011.

On September 28, 2010, we completed the sale to the Partnership of our Venice Operations, which includes Targa’s 76.8% interest in Venice Energy Services Company, L.L.C. (“VESCO”), for aggregate consideration of $175.6 million, effective September 1, 2010. The sale triggered a mandatory prepayment of $73.5 million under TRI’s senior secured credit facility.

The net impact of our sale of assets to the Partnership resulted in an increase to additional paid-in capital of $243 million and a corresponding reduction of the non-controlling interest in these assets.

The following table lists the Partnership’s distributions declared and paid in the years ended December 31, 2010 and 2009:

		Distributions Paid										Distributions
	For the Three	Limited Partners				General Partner						per limited
Date Paid	Months Ended	Common		Subordinated		Incentive			2%	Total		partner unit
		(In millions, except per unit amounts)
2010
November 12, 2010	September 30, 2010	$	40.6	$	-	$	4.6	$	0.9	$	46.1	$	0.5375
August 13, 2010	June 30, 2010		35.9		-		3.5		0.8		40.2		0.5275
May 14, 2010	March 31, 2010		35.2		-		2.8		0.8		38.8		0.5175
February 12, 2010	December 31, 2009		35.2		-		2.8		0.8		38.8		0.5175

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

As part of our sale of the Downstream Business to the Partnership in 2009, we agreed to provide distribution support to the Partnership through the fourth quarter of 2011, in the form of a reduction in the reimbursement for general and administrative expense that we allocate to the Partnership if necessary for a 1.0 times distribution coverage, at a distribution level of the Partnership’s at the time of the sale of the Downstream Business of $0.5175 per limited partner unit, subject to a maximum support of $8.0 million in any quarter. No distribution support has been necessary through the fourth quarter of 2010.

F-21

Index to Financial Statements

Subsequent Events. On January 24, 2011, the Partnership completed a public offering of 8,000,000 common units representing limited partner interests in the Partnership (“common units”) under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of underwriting discounts), providing net proceeds of $259.3 million. Pursuant to the exercise of the underwriters’ overallotment option, the Partnership sold an additional 1,200,000 common units, providing net proceeds of $38.9 million. In addition, we contributed $6.3 million for 187,755 general partner units to maintain our 2% interest in the Partnership.

On February 14, 2011, the Partnership paid a cash distribution of $0.5475 per common unit on our outstanding common units. The total distribution paid was $53.5 million, with $40.0 million paid to the Partnership’s non-affiliated common unitholders and $6.4 million, $1.1 million and $6.0 million paid to us for our common unit ownership, general partner interest and incentive distribution rights.

Note 12 – Earnings per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of restricted stock awards and stock options. Diluted EPS also includes the assumed conversion of the Series B Convertible Participating Preferred Stock for periods prior to December 10, 2010.

Prior to the conversion of the Series B Preferred Stock to common stock on December 10, 2010, net income after the impact of preferred dividends was allocated according to the preferred stock agreement. The terms of the preferred stock agreement stipulated that common shareholders are not entitled to any dividends, unless approved with written consent of a majority of the outstanding preferred stockholders, until the preferred holders recapture the carrying value of their preferred securities which includes accreted dividends. For 2008 and 2009, there was no net income available to common shareholders as the preferred shareholders are entitled to all undistributed earnings. As such, there were no earnings per share to our common shareholders during 2008 and 2009. For 2010, there was no allocation to preferred shareholders as the Company was in a loss position and the preferred shareholders do not participate in losses under the terms of the preferred stock agreement.

For each of the periods presented below, all of the potentially dilutive securities were excluded from the calculation of diluted EPS as they were anti-dilutive.

The following table reflects the weighted average of outstanding securities that were excluded from the diluted calculation of net income (loss) available to common shareholders as the effect of including such securities would have been anti-dilutive (in thousands).

	Years Ended December 31,
	2010	2009	2008
	(in thousands)
Restricted Stock - 2010 Stock Incentive Plan (1)	1,350.0	-	-
Restricted Stock - 2005 Incentive Compensation Plan (2)	10.6	488.9	1,518.6
Stock Options - 2005 Incentive Compensation Plan (3)	1,470.0	2,313.1	2,341.5
Conversion of Series B Preferred Stock (4)	33,322.5	31,515.3	31,515.3

________

(1)	In connection with the IPO in December 2010, the Company issued 1,350,000 shares of restricted stock under the 2010 Stock Incentive Plan to employees. At December 31, 2010, all of these shares were unvested.

(2)	Amounts represent the weighted average number of unvested shares outstanding for each year.

(3)	Amounts represent the weighted average number of unexercised stock options outstanding for each year. Prior to the closing of the IPO in December 2010, all outstanding options were either exercised or cashed out. As of December 31, 2010, there are no outstanding stock options.

(4)

Amounts in 2009 and 2008 represent the assumed conversion of the Series B Preferred Stock into common shares as of January 1 for each year. During 2010, in connection with the closing of the IPO, 6,409,697 shares of Series B Convertible Participating Preferred Stock, plus accreted value, were converted into 35,356,698 shares of common stock. Beginning on December 10, 2010, these shares are included in the calculation of weighted average shares outstanding – basic and diluted. The amount included in the table above for 2010 represents the weighted average shares for the period from January 1, 2010 through December 9, 2010 (based on the actual number of shares converted on December 10, 2010).

Subsequent event. On February 21, 2011, we paid a cash dividend of $0.0616 per share of our outstanding common stock. The total dividend paid was $2.6 million. This dividend was pro-rated to give effect to a partial quarter following our IPO.

F-22

Index to Financial Statements

Note 13 – Insurance Claims

Hurricanes Katrina and Rita

Hurricanes Katrina and Rita affected certain Gulf Coast facilities in 2005. The final purchase price allocation of our acquisition from Dynegy in October 2005 included an $81.1 million receivable for insurance claims related to property damage caused by Hurricanes Katrina and Rita. The insurance claim process was completed with respect to Hurricanes Katrina and Rita for property damage and business interruption insurance, which resulted in an $18.5 million gain recorded in 2008. This amount was reported in the other income line in the other income (expense) section of our Consolidated Statement of Operations.

Hurricanes Gustav and Ike

Certain Louisiana and Texas facilities sustained damage and had disruption to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During 2010 and 2009, the estimate was reduced by $3.3 million and $3.7 million to give effect to higher insurance recoveries and lower out of pocket costs. These amounts were reported in the Other line in the costs and expenses section of our Consolidated Statements of Operations.

During the year ended December 31, 2010, expenditures related to the hurricanes were $0.3 million. During the year ended December 31, 2009, expenditures related to the hurricanes included $35.9 million for repairs and $7.6 million capitalized as improvements.

Total business interruption proceeds related to Hurricanes Gustav and Ike recorded as revenues during 2010 and 2009 were $5.5 million and $19.5 million, respectively. No hurricane-related business interruption proceeds were received during 2008. We were entitled to receive all post dropdown insurance proceeds under the terms of the Purchase and Sale Agreements with the Partnership. These amounts were reported in the revenues line on our Consolidated Statements of Operations.

F-23

Index to Financial Statements

Note 14 – Derivative Instruments and Hedging Activities

Commodity Hedges

In an effort to reduce the variability of cash flows, the Partnership has hedged the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (floors).

The hedges generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. The NGL hedges cover baskets of ethane, propane, normal butane, iso-butane and natural gasoline based upon our expected equity NGL composition, as well as specific NGL hedges of ethane and propane. This strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, the NGL hedges are based on published index prices for delivery at Mont Belvieu and the natural gas hedges are based on published index prices for delivery at Mid-Continent, WAHA and Permian Basin (El Paso), which closely approximate our 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, which approximates the prices received for condensate. This necessarily exposes the Partnership to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying West Texas condensate equity volumes.

Hedge ineffectiveness has been immaterial for all periods.

At December 31, 2010, the notional volumes of our commodity hedges were:

Commodity	Instrument	Unit	2011	2012	2013	2014
Natural Gas	Swaps	MMBtu/d	30,100	23,100	8,000	-
NGL	Swaps	Bbl/d	8,550	6,700	3,400	-
NGL	Floors	Bbl/d	253	294	-	-
Condensate	Swaps	Bbl/d	1,100	950	800	700

Interest Rate Swaps

As of December 31, 2010, the Partnership had $765.3 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:

		Notional		Fair
Period	Fixed Rate	Amount		Value
		($ in millions)
2011	3.52%	$	300	$	(7.8	)
2012	3.40%		300		(7.5	)
2013	3.39%		300		(4.0	)
2014	3.39%		300		(0.8	)
				$	(20.1	)

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.

F-24

Index to Financial Statements

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

	Asset Derivatives					Liability Derivatives
	Balance	Fair Value as of				Balance	Fair Value as of
	Sheet	December 31,				Sheet	December 31,
	Location	2010		2009		Location	2010		2009
Derivatives designated as hedging instruments
Commodity contracts	Current assets	$	24.8	$	31.6	Current liabilities	$	25.5	$	20.7
	Current assets		18.9		11.7	Long-term liabilities		20.5		39.1

Interest rate contracts	Current assets		-		0.2	Current liabilities		7.8		8.0
	Long-term assets		-		1.9	Long-term liabilities		12.3		4.7
Total derivatives designated as hedging instruments		$	43.7	$	45.4		$	66.1	$	72.5

Derivatives not designated as hedging instruments
Commodity contracts	Current assets	$	0.4	$	1.1	Current liabilities	$	0.9	$	0.5
	Long-term assets		-		0.2	Long-term liabilities		-		-
Total derivatives not designated as hedging instruments		$	0.4	$	1.3		$	0.9	$	0.5
Total derivatives		$	44.1	$	46.7		$	67.0	$	73.0

The fair value of derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets.

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

	Gain (Loss)
	Recognized in OCI on
Derivatives in	Derivatives (Effective Portion)
Cash Flow Hedging	Year Ended December 31,
Relationships	2010			2009			2008
Interest rate contracts	$	(20.1	)	$	(7.3	)	$	(19.0	)
Commodity contracts		52.5			(104.3	)		206.4
	$	32.4		$	(111.6	)	$	187.4

	Gain (Loss)
	Reclassified from OCI into
Location of Gain (Loss)	Income (Effective Portion)
Reclassified from	Year Ended December 31,
OCI into Income	2010			2009			2008
Interest expense, net	$	(9.3	)	$	(15.7	)	$	(2.7	)
Revenues		8.4			69.7			(65.1	)
	$	(0.9	)	$	54.0		$	(67.8	)

F-25

Index to Financial Statements

Our earnings are also affected by the use of the mark-to-market method of accounting for our derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheets and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. During 2010, 2009 and 2008, we recorded the following mark-to-market gains (losses):

		Amount of Gain (Loss) Recognized
		in Income on Derivatives
Derivatives	Location of Gain (Loss)	Year Ended
Not Designated as	Recognized in Income	December 31,
Hedging Instruments	on Derivatives	2010	2009	2008
Commodity contracts	Other income (expense)	$(0.4)	$0.3	$(1.3)

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

	Year Ended December 31,
	2010			2009			2008
Unrealized gain (loss) on commodity hedges, before tax	$	4.5		$	(29.4	)	$	59.6
Unrealized gain (loss) on commodity hedges, net of tax		2.7			(18.3	)		39.3
Unrealized gain (loss) on interest rate swaps, before tax		(3.4	)		(3.1	)		(4.7	)
Unrealized gain (loss) on interest rate swaps, net of tax		(2.1	)		(1.9	)		(3.1	)

As of December 31, 2010, deferred net losses of $3.9 million on commodity hedges and $7.5 million on interest rate swaps recorded in OCI are expected to be reclassified to revenue and interest expense, respectively, during the next twelve months.

In July 2008, we paid $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. Prior to the terminations, these swaps were designated as hedges. During the years ended December 31, 2010, 2009 and 2008 deferred net losses of $29.6 million, $40.0 million and $20.8 million were reclassified from OCI as a non-cash reduction of revenue.

In May 2008 we entered into certain NGL derivative contracts with Lehman Brothers Commodity Services, Inc., a subsidiary of Lehman Brothers Holdings Inc. (“Lehman”). Due to Lehman’s bankruptcy filing, it is unlikely that we will receive full or partial payment of any amounts that may become owed to us under these contracts. Accordingly, we discontinued hedge accounting treatment for these contracts in July 2008. Deferred losses of $0.2 million and $0.3 million will be reclassified to revenues during 2011 and 2012 when the forecasted transactions related to these contracts are expected to occur. During 2008, we recognized a non-cash mark-to-market loss on derivatives of $1.3 million to adjust the fair value of the Lehman derivative contracts to zero. In October 2008, we terminated the Lehman derivative contracts.

See Note 15, Note 17 and Note 23 for additional disclosures related to derivative instruments and hedging activity.

Note 15—Related Party Transactions

Relationship with Warburg Pincus LLC

Chansoo Joung and Peter Kagan, two of our directors, are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. During 2010, 2009 and 2008, we purchased $41.5 million, $9.7 million and $4.8 million of product from Broad Oak.

Peter Kagan is also a director of Antero Resources Corporation (“Antero”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Antero. We purchased $0.1 million, $0.5 million, and $64.4 million of product from Antero during the year ended December 31, 2010, 2009, and 2008. These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.

F-26

Index to Financial Statements

Relationships with Bank of America (“BofA”)

Equity. Prior to December 10, 2010, BofA was considered a beneficial owner of more than 5% of our common stock. Upon our initial public offering, BofA was reduced its ownership below 5%.

Financial Services. An affiliate of BofA is a lender and an agent under the Partnership’s senior credit facility with commitments of $72 million. BofA and its affiliates have engaged, and may in the future engage, in other commercial and investment banking transactions with us or the Partnership in the ordinary course of their business. They have received, and expect to receive, customary compensation and expense reimbursement for these commercial and investment banking transactions.

Commodity Hedges. The Partnership has previously entered into various commodity derivative transactions with BofA. As of December 31, 2010, the Partnership has no open positions with BofA. During 2010, 2009 and 2008, the Partnership received from (paid to) BofA $1.9 million, $24.2 million and ($30.5) million in commodity derivative settlements.

Commercial Relationships. The Partnership’s product sales and product purchases with BofA were:

	Year Ended
	December 31,
	2010		2009		2008
Included in revenues	$	26.0	$	36.7	$	97.0
Included in costs and expenses		3.7		1.0		5.1

Relationships with Sequent Energy Management, EOG Resources Inc., and Intercontinental Exchange, Inc.

Charles Crisp, one our directors, is also a director of AGL Resources Inc. (“AGL”), EOG Resources Inc. (“EOG”) and Intercontinental Exchange Inc. (“Intercontinental”). Sequent Energy Management (“Sequent”) is a subsidiary of AGL. The following schedule shows the transactions with each of these related parties.

	Sales								Purchases
	Year Ended, December 31,								Year Ended, December 31,
	2010			2009			2008		2010		2009		2008
Sequent	$	14.3		$	11.7		$	-	$	27.4	$	5.0	$	-
EOG		(1	)		(1	)		-		10.0		5.6		13.1
Intercontinental		-			-			-		0.2		0.2		0.2

________

(1)	Less than $0.1 million

These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.

F-27

Index to Financial Statements

Transactions with Unconsolidated Affiliates

For the years indicated, our natural gas and NGL sales and purchases with our unconsolidated affiliates were:

	December 31,
	2010		2009		2008
Included in revenues
GCF	$	0.3	$	0.2	$	0.5
VESCO(1)		-		-		0.7
	$	0.3	$	0.2	$	1.2
Included in costs and expenses
GCF	$	1.1	$	1.4	$	3.5
VESCO(1)		-		-		178.1
	$	1.1	$	1.4	$	181.6

_______

(1)	For 2008, our commercial transactions with VESCO are reflected through July 31, 2008. As a result of acquiring an additional ownership in VESCO, and we have consolidated the operations of VESCO in our financial results from August 1, 2008.

Note 16 – 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:

	Payment Due by Period
	Total		2011		2012		2013		2014		2015		Thereafter
Partnership:
Operating lease and service contract (1)	$	36.7	$	10.6	$	8.4	$	3.8	$	2.7	$	2.6	$	8.6
Capacity and terminalling payments (2)		12.9		6.6		4.7		1.6		-		-		-
Land site lease and right-of-way (3)		20.4		1.3		1.2		1.2		1.1		1.0		14.6
TRC:
Operating leases (4)		15.3		2.5		2.1		2.2		2.2		2.2		4.1
	$	85.3	$	21.0	$	16.4	$	8.8	$	6.0	$	5.8	$	27.3

______

(1)	Includes minimum lease payment obligations associated with gas processing plant site leases, railcar leases, and office space leases.

(2)	Consists of capacity payments for firm transportation contracts.

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

(4)	Includes minimum lease payment obligations associated with corporate operations.

The following table shows the above mentioned expenses of the Partnership:

	Year Ended December 31,
	2010			2009			2008
Operating leases		$	13.5		$	13.7		$	14.7
Capacity payments			8.6			9.6			6.7
Land site lease and right-of-way			2.8			2.3			4.0

F-28

Index to Financial Statements

Environmental

For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Environmental reserves do not reflect management’s assessment of any insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.

Our environmental liability at December 31, 2010 and December 31, 2009 was $1.6 million and $3.2 million. Our December 31, 2010 liability consisted of $0.2 million for gathering system leaks and $1.4 million for ground water assessment and remediation.

In May 2007, the New Mexico Environmental Department (“NMED”) alleged air emissions violations at the Eunice, Monument and Saunders gas processing plants operated by Targa Midstream Services Limited Partnership and owned by Versado Gas Processors, LLC (“Versado”), which were identified in the course of an inspection of the Eunice plant conducted by the NMED in August 2005.

In January 2010, Versado settled the alleged violations with NMED for a penalty of approximately $1.5 million. As part of the settlement, Versado agreed to install two acid gas injection wells, additional emission control equipment and monitoring equipment. We estimate the total cost to complete these projects to be approximately $33.4 million, of which $4.0 million has already been paid. The Partnership is responsible for its 63% pro-rata ownership percentage of the total costs of the projects. Under the terms of the Versado Purchase and Sale Agreement, we must reimburse the Partnership for the cost of these compliance investments.

Legal Proceedings

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

On December 8, 2005, WTG Gas Processing, L.P. (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa and two 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 SAOU 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. In October 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. In February 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety. In January 2011, the Texas Supreme Court denied the WTG’s petition for review of the lower courts’ judgment and WTG filed a motion for rehearing with the Texas Supreme Court requesting the court reconsider its denial to review WTG’s appeal. We have agreed to indemnify the Partnership for any claim or liability arising out of the WTG suit.

Except as provided above, neither we nor the Partnership is a party to any other legal proceedings other than legal proceedings arising in the ordinary course of our business. The Partnership is a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business.

Note 17 — Fair Value Measurements

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

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

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

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

F-29

Index to Financial Statements

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

The following tables present the fair value of our financial assets and liabilities according to the fair value hierarchy. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

	December 31, 2010

	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	44.1	$	-	$	43.9	$	0.2
Assets from interest rate derivatives		-		-		-		-
Total assets	$	44.1	$	-	$	43.9	$	0.2
Liabilities from commodity derivative contracts	$	46.9	$	-	$	35.1	$	11.8
Liabilities from interest rate derivatives		20.1		-		20.1		-
Total liabilities	$	67.0	$	-	$	55.2	$	11.8

	December 31, 2009
	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	44.6	$	-	$	44.6	$	-
Assets from interest rate derivatives		2.1		-		2.1		-
Total assets	$	46.7	$	-	$	46.7	$	-
Liabilities from commodity derivative contracts	$	60.3	$	-	$	46.6	$	13.7
Liabilities from interest rate derivatives		12.7		-		12.7
Total liabilities	$	73.0	$	-	$	59.3	$	13.7

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

	Commodity Derivative Contracts
	2010			2009			2008
Balance at January 1	$	(13.7	)	$	148.2		$	(124.2	)
Unrealized gains included in OCI		2.6			(57.1	)		149.6
Purchases		-			-			81.1
Settlements included in Income		(0.5	)		(35.0	)		41.7
Transfers out of Level 3 (1)		-			(69.8	)		-
Balance at December 31	$	(11.6	)	$	(13.7	)	$	148.2

_________

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

For all periods indicated in the above table, all Level 3 derivative instruments were designated as cash flow hedges, and, as such, all changes in their fair value are reflected in Other Comprehensive Income. Therefore, there are no unrealized gains or losses reflected in revenues or other income (expense) with respect to Level 3 derivative instruments.

F-30

Index to Financial Statements

Note 18—Income Taxes

Our provisions for income taxes for the periods indicated are as follows:

	Year Ended December 31,
	2010			2009		2008
Current expense (benefit)	$	(10.6	)	$	1.6	$	1.3
Deferred expense		33.1			19.1		18.0
	$	22.5		$	20.7	$	19.3

Our deferred income tax assets and liabilities at December 31, 2010 and 2009 consist of differences related to the timing of recognition of certain types of costs as follows:

	December 31,
	2010			2009
Deferred tax assets:
Net operating loss	$	-		$	60.1
Property, Plant and Equipment		-			6.3
Risk management contracts		48.3			-
Other		13.1			3.6
Tax credits		-			16.8
Deferred tax assets before valuation allowance		61.4			86.8
Valuation allowance		(3.5	)		-
		57.9			86.8
Deferred tax liabilities:
Investments(1)		(145.8	)		(132.8	)
Risk management contracts		-			(5.4	)
Property, Plant and Equipment		(23.6	)		-
		(169.4	)		(138.2	)
Net deferred tax liability	$	(111.5	)	$	(51.4	)

Federal	$	(106.6	)	$	(60.2	)
Foreign		0.5			0.5
State		(5.4	)		8.3
	$	(111.5	)	$	(51.4	)
Balance sheet classification of deferred tax assets (liabilities):
Current asset	$	3.6		$	-
Long-term asset (valuation allowance)		(3.5	)
Current liability		-			(1.4	)
Long-term liability		(111.6	)		(50.0	)
	$	(111.5	)	$	(51.4	)

______

(1)	Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of the assets and liabilities of our wholly-owned partnerships and equity method investments.

As a result of dropdown transactions in 2009 and 2010, differences related to the date of income recognition for book and tax occurred. While these are temporary differences, the reversal of these differences will not be recognized until we sell the units of the Partnership. Therefore, the tax effect of these differences is recorded as a valuation allowance of $3.5 million in deferred taxes, as a component of other long term assets for 2010.

As of December 31, 2010, for federal income tax purposes, both regular tax net operating losses (“NOLs”) and alternative minimum tax NOLs were fully utilized.

F-31

Index to Financial Statements

Set forth below is reconciliation between our income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision in the accompanying consolidated statements of operations for the periods indicated:

	Years Ending
	December 31,
Income tax reconciliation:	2010			2009			2008
Income before income taxes	$	85.8		$	99.8		$	153.7
Less: Net income attributable to noncontrolling interest		(78.3	)		(49.8	)		(97.1	)
Income attributable to TRC before income taxes		7.5			50.0			56.6
Federal statutory income tax rate		35%			35%			35%
U.S. federal income tax provision at statutory rate		2.6			17.5			19.8
State income taxes, net of federal tax benefit (1)		13.4			1.8			1.2
Valuation allowance		3.0			-			-
Other, net		3.5			1.4			(1.7	)
Income Tax Provision	$	22.5		$	20.7		$	19.3

________

(1)	For 2010, primarily consists of the write-off of an $11.9 million Texas margin tax credit.

We have not identified any uncertain tax positions. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipate any adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves for uncertain income tax positions have been recorded.

On April 14, 2010, we closed on a secondary public offering of 8,500,000 common units of the Partnership. The direct tax effect of the change in ownership interest in the Partnership as a result of the secondary public offering was recorded as a reduction in shareholders’ equity of $79.1 million, an increase in current tax liability of $41.9 million and an increase in deferred tax liability of $37.2 million. There was no tax impact on consolidated net income as a result of the secondary public offering.

On April 27, 2010, we sold our interests in the Permian and Straddle Systems to the Partnership. On September 28, 2010, we sold our interests in the Venice Operations to the Partnership. Under applicable accounting principles, the tax consequences of transactions with common control entities are not to be reflected in pre-tax income. Consequently, there was no tax impact on consolidated pre-tax net income as a result of the sale of the Permian and Straddle Systems and the Venice Operations. The tax effect of these sales was recorded as an increase in other long term assets of $64.7 million, to be amortized over the remaining life of the underlying assets, an increase in current tax liability of $94.9 million, a decrease in deferred tax liability of $27.5 million and an increase in current tax expense of $2.7 million.

Note 19—Fair Value of Financial Instruments

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

The carrying value of the senior secured revolving 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 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.

F-32

Index to Financial Statements

The carrying amounts and fair values of our other financial instruments are as follows as of the dates indicated:

	December 31, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Holdco loan facility (1)	$	89.3	$	86.8	$	385.4	$	278.9
Senior secured term loan facility, due 2012 (2)		-		-		62.2		61.9
Senior unsecured notes, 8½% fixed rate (3)		-		-		250.0		259.2
Senior unsecured notes of the Partnership, 8¼% fixed rate		209.1		219.4		209.1		206.5
Senior unsecured notes of the Partnership, 11¼% fixed rate		231.3		265.0		231.3		253.5
Senior unsecured notes of the Partnership, 7 7/8% fixed rate		250.0		259.7		-		-

________

(1)	For the fair value of the Holdco loan facility, since we cannot obtain an indicative quote from external sources, we are using the value of the November 2010 purchases that we made at 97.18% of face value.

(2)	The carrying amount of the debt as of December 31, 2009 approximates the fair value as the variable rate is periodically reset to prevailing market rates.

(3)	The fair value as of December 31, 2009 represents the value of the last trade of the year which occurred on December 9, 2009. On January 5, 2010 we paid $264.7 million to complete a cash tender offer for all outstanding aggregate principal amount plus accrued interest of $3.8 million.

Note 20 — Supplemental Cash Flow Information

Supplemental cash flow information was as follows for the periods indicated:

	Year Ended
	December 31,
	2010		2009		2008
Cash:
Interest paid	$	90.8	$	82.4	$	94.2
Income taxes paid (1)		92.6		6.5		1.6

Non-cash
Inventory line-fill transferred to property, plant and equipment		0.4		9.8		-
Like-kind exchange of property, plant and equipment		-		-		5.8
Paid-in-kind interest refinanced to Holdco principal		10.9		25.9		38.2
Conversion of series B preferred stock (accretive value)		79.9		-		-
Settlement of Partnership notes		-		-		14.1
Distribution of property to noncontrolling interest		-		-		14.8
Distribution of property to common shareholders		3.2		-		-

________

(1)

During 2010, cash tax payments of $92.6 million were made to the Internal Revenue Service and various states in connection with taxable gains recognized upon Targa’s sale of the Permian Business and Straddle Assets, its interests in the Venice Operations and its secondary public offering of 8,500,000 common units of the Partnership. Under applicable accounting principles, the income tax consequences of these transactions are generally deferred and recognized over time. For income tax purposes, the tax consequences must be recognized in 2010 when the dispositions were completed.

Note 21 – Segment Information

The Partnership’s operations are presented under four segments: (1) Field Gathering and Processing, (2) Coastal Gathering and Processing, (3) Logistics Assets and (4) Marketing and Distribution. The financial results of our hedging activities are reported in Other.

The Natural Gas Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. The Field Gathering and Processing segment assets are located in North Texas and the Permian Basin of Texas and New Mexico and the Coastal Gathering and Processing segment assets are located in the onshore and near offshore region of the Louisiana Gulf Coast and the Gulf of Mexico.

F-33

Index to Financial Statements

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 Southwestern 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; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to us from our Gathering and Processing segments and the purchase and resale of natural gas in selected United States markets.

Other contains the results of our derivatives and hedging transactions. Eliminations of inter-segment transactions are reflected in the eliminations column.

Our segment information is shown in the following tables. With the conveyance of all of our remaining operating assets to the Partnership in September 2010, all operating assets are now owned by the Partnership. We have segregated the following segment information between Partnership and Non-partnership activities. Partnership activities have been presented on a common control accounting basis which reflects the dropdown transactions as if they occurred in prior periods similar to a pooling of interests. The Non-Partnership results include activities related to certain assets and liabilities contractually excluded from the dropdown transactions and certain historical hedge activities that could not be reflected under GAAP in the Partnership common control results.

	Year Ended December 31, 2010
	Partnership
	Field		Coastal
	Gathering		Gathering				Marketing				Corporate
	and		and		Logistics		and				and			TRC Non-
	Processing		Processing		Assets		Distribution		Other		Eliminations			Partnership		Consolidated
Revenues	$	211.6	$	446.6	$	84.5	$	4,713.5	$	4.0	$	-		$	9.0	$	5,469.2
Intersegment revenues		1,084.4		755.7		88.0		494.8		-		(2,422.9	)		-		-
Revenues	$	1,296.0	$	1,202.3	$	172.5	$	5,208.3	$	4.0	$	(2,422.9	)	$	9.0	$	5,469.2
Operating margin	$	236.6	$	107.8	$	83.8	$	80.5	$	4.0	$	-		$	8.6	$	521.3
Other financial information:
Total assets	$	1,623.4	$	451.5	$	471.9	$	519.9	$	44.1	$	75.6		$	207.4	$	3,393.8
Capital expenditure	$	67.8	$	6.9	$	66.3	$	2.7	$	-	$	-		$	3.5	$	147.2

F-34

Index to Financial Statements

	Year Ended December 31, 2009
	Partnership
	Field		Coastal
	Gathering		Gathering				Marketing				Corporate
	and		and		Logistics		and				and			TRC Non-
	Processing		Processing		Assets		Distribution		Other		Eliminations			Partnership		Consolidated
Revenues	$	191.7	$	392.0	$	76.7	$	3,797.1	$	46.3	$	-		$	32.2	$	4,536.0
Intersegment revenues		780.1		525.0		79.5		337.4		-		(1,722.0	)		-		-
Revenues	$	971.8	$	917.0	$	156.2	$	4,134.5	$	46.3	$	(1,722.0	)	$	32.2	$	4,536.0
Operating margin	$	183.2	$	89.7	$	74.3	$	83.0	$	46.3	$	-		$	33.4	$	509.9
Other financial information:
Total assets	$	1,668.2	$	489.0	$	414.4	$	442.3	$	46.8	$	92.0		$	214.8	$	3,367.5
Capital expenditure	$	53.4	$	14.0	$	15.8	$	16.0	$	-	$	-		$	2.7	$	101.9

	Year Ended December 31, 2008
	Partnership
	Field		Coastal
	Gathering		Gathering				Marketing					Corporate
	and		and		Logistics		and					and			TRC Non-
	Processing		Processing		Assets		Distribution		Other			Eliminations			Partnership			Consolidated
Revenues	$	415.9	$	781.2	$	69.1	$	6,797.5	$	(33.6	)	$	-		$	(31.2	)	$	7,998.9
Intersegment revenues		1,530.8		736.4		103.4		619.5		-			(2,990.1	)		-			-
Revenues	$	1,946.7	$	1,517.6	$	172.5	$	7,417.0	$	(33.6	)	$	(2,990.1	)	$	(31.2	)	$	7,998.9
Operating margin	$	385.4	$	105.4	$	40.1	$	41.3	$	(33.6	)	$	-		$	(33.4	)	$	505.2
Other financial information:
Total assets		1,725.7	$	522.4	$	421.5	$	356.9	$	202.1		$	120.0		$	293.2		$	3,641.8
Capital expenditure		82.7		13.1		37.2		4.2		-			-			8.3			145.5

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

	Year Ended December 31,
	2010		2009		2008
Natural gas sales	$	1,076.5	$	809.4	$	1,590.3
NGL sales		4,115.3		3,365.3		6,148.4
Condensate sales		95.1		95.5		131.5
Fractionating and treating fees		55.8		61.2		66.8
Storage and terminalling fees		40.1		41.0		33.0
Transportation fees		33.8		43.4		39.2
Gas processing fees		32.1		24.0		22.0
Hedge settlements		9.1		69.7		(65.1	)
Business interruption insurance		6.0		21.5		32.9
Other		5.4		4.6		(0.1	)
	$	5,469.2	$	4,536.0	$	7,998.9

F-35

Index to Financial Statements

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

	Year Ended December 31,
	2010			2009			2008
Reconciliation of operating margin to net income
Operating margin	$	521.3		$	509.9		$	505.2
Depreciation and amortization expense		(185.5	)		(170.3	)		(160.9	)
General and administrative expense		(144.4	)		(120.4	)		(96.4	)
Interest expense, net		(110.9	)		(132.1	)		(141.2	)
Income tax expense		(22.5	)		(20.7	)		(19.3	)
Other, net		5.3			12.7			47.0
Net income	$	63.3		$	79.1		$	134.4

Note 22 – Other Operating Income

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

	Year Ended December 31,
	2010			2009			2008
Abandoned project costs	$	0.1		$	5.5		$	-
Casualty loss (gain) adjustment (see Note 13)		(3.3	)		(3.6	)		19.3
Loss (gain) on sale of assets (1)		(1.5	)		0.1			(5.9	)
	$	(4.7	)	$	2.0		$	13.4

________

(1)	For 2008, $5.8 million gain on sale of assets was due to a like-kind exchange. See Note 20.

Note 23 – Significant Risks and Uncertainties

Our primary business objective is to increase our available cash for dividends to our stockholders by assisting the Partnership in executing its business strategy. We may facilitate the Partnership’s growth through various forms of financial support, including, but not limited to, modifying the Partnership’s IDRs, exercising the Partnership’s IDR reset provision contained in its partnership agreement, making loans, making capital contributions in exchange for yielding or non-yielding equity interests or providing other financial support to the Partnership, if needed, to support its ability to make distributions. In addition, we may acquire assets that could be candidates for acquisition by the Partnership, potentially after operational or commercial improvement or further development.

Nature of the Partnership’s Operations in Midstream Energy Industry

The Partnership operates in the midstream energy industry. Its business activities include gathering, transporting, processing, fractionating and storage of natural gas, NGLs and crude oil. The Partnership’s 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.

The Partnership’s 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 the Partnership’s results of operations, cash flows and financial position.

F-36

Index to Financial Statements

The principal market risks are exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, as well as changes in interest rates. The fair value of commodity and interest rate derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. These contracts may expose the Partnership to the risk of financial loss in certain circumstances. The Partnership’s hedging arrangements provide it protection on its hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they are hedged, the Partnership will receive less revenue on the hedged volumes than it would receive in the absence of hedges.

Commodity Price Risk. A majority of the revenues from the natural gas gathering and processing business are derived from percent-of-proceeds contracts under which the Partnership receives 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. The Partnership monitors these risks and enters into commodity derivative transactions designed to mitigate the impact of commodity price fluctuations on its business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

In an effort to reduce the variability of our cash flows the Partnership has hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2010 through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of 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 pays 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 actual equity volumes, the Partnership typically limits its use of swaps to hedge the prices of less than its 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 it to the risk of financial loss in certain circumstances. Hedging arrangements provide it protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges. See Note 14.

Interest Rate Risk. The Partnership is exposed to changes in interest rates, primarily as a result of variable rate borrowings 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 variable rate debt is effectively fixed for the term of each agreement. See Note 14.

Counterparty Risk – Credit and Concentration

Derivative Counterparty Risk

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

The Partnership has master netting agreements with most of its hedge counterparties. These netting arrangements allow it to net settle asset and liability positions with the same counterparties. As of December 31, 2010, the Partnership had $25.8 million in liabilities to offset the default risk of counterparties with which it also had asset positions of $38.4 million as of that date.

F-37

Index to Financial Statements

The 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 it to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of the counterparties decline, the 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, the Partnership may sustain a loss and its cash receipts could be negatively impacted.

As of December 31, 2010, affiliates of Barclays, Credit Suisse and British Petroleum (“BP”) accounted for 62%, 13% and 12%, respectively, of the Partnership’s net counterparty credit exposure related to commodity derivative instruments. Barclays, Credit Suisse and BP are major financial institutions or corporations each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

Customer Credit Risk

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

	Year Ended December 31,
	2010			2009			2008
Balance at beginning of year	$	8.0		$	9.2		$	0.9
Additions		-			-			8.3
Deductions		(0.1	)		(1.2	)		-
Balance at end of year	$	7.9		$	8.0		$	9.2

Significant Commercial Relationships

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

		Year Ended December 31,
		2010	2009	2008
% of consolidated revenues
	Chevron Phillips Chemical Company LLC	10%	15%	19%
% of product purchases
	Louis Dreyfus Energy Services L.P.	10%	11%	9%

All transactions in the above table were associated with the Marketing and Distribution segment.

Casualty or Other Risks

Targa maintains coverage in various insurance programs, which provides us with property damage, business interruption and other coverages which are customary for the nature and scope of our operations. The financial impact of storm events such as Hurricanes Katrina and Rita, and more recently Hurricanes Gustav and Ike, as well as the current economic environment, have affected many insurance carriers, and may affect their ability to meet their obligation or trigger limitations in certain insurance coverages. At present, there is no indication of any of our insurance carriers being unable or unwilling to meet their coverage obligations.

Management believes that Targa has adequate insurance coverage, although insurance will 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, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.

F-38

Index to Financial Statements

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

Note 24 – Stock and Other Compensation Plans

2005 Incentive Compensation Plan

Stock Option Plans

Under Targa’s 2005 Incentive Compensation Plan (“the Plan”), options to purchase a fixed number of shares of its stock may be granted to our employees, directors and consultants. Generally, options granted under the Plan have a vesting period of four years and remain exercisable for ten years from the date of grant.

The fair value of each option granted was estimated on the date of grant using a Black-Scholes option pricing model, which incorporates various assumptions for 2010, 2009 and 2008, including (i) expected term of the options of ten years, (ii) a risk-free interest rate of 3.9% for 2010 and 3.6% for 2009 and 2008, (iii) expected dividend yield of 0%, and (iv) expected stock price volatility on TRC’s common stock of 39.4% for 2010 and 25.5% for 2009 and 2008. Our selection of the risk-free interest rate was based on published yields for United States government securities with comparable terms. Because TRC was a non-public company until December 10, 2010, its expected stock price volatility was estimated based upon the historical price volatility of the Dow Jones U.S. Pipelines Index over a period equal to the expected average term of the options granted. The calculated fair value of options granted during the year ended December 31, 2010, and 2008 was $4.09, and $3.01 per share. There were no options granted in 2009.

We recognized compensation expense associated with stock options of $0.2 million, $0.1 million and $0.2 million during 2010, 2009 and 2008.

The following table shows stock option activity for the periods indicated:

	Number of			Weighted Average
	Options (1)			Exercise Price (2)
Outstanding at December 31, 2009		2,215,442		$	17.04
Granted		46,018			7.22
Exercised		(1,189,863	)		0.67
Rescinded		(987,629	)		24.87
Cashed out		(59,002	)		1.90
Forfeited		(24,966	)		25.51
Outstanding at December 31, 2010		-

_______

(1)	The number of options was adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03.

(2)	The weighted average prices were adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03.

The aggregated intrinsic value of stock options exercised in 2010, 2009 and 2008 was $3.4 million, $0.2 million, and $0.5 million.

Concurrent with the IPO, unexercised in-the-money stock options were cashed out, resulting in $1.2 million of additional compensation expense in 2010. Unexercised out-of-the-money stock options were rescinded. As such, there are no outstanding stock options at December 31, 2010.

In connection with our extraordinary special distribution of dividends to our common and common equivalent shareholders (Note 10), in April 2010, we reduced the strike price on all of our outstanding options by $5.63. All unvested options were deemed to have immediately vested in May 2010. The weighted average exercise prices in the table above were adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03, and the reduced strike prices for options exercised, rescinded, and cashed out after the strike price was reduced in May 2010. There were no options granted or forfeited after May 2010. This reduction is considered an award modification for accounting purposes; therefore, we re-determined the fair value of the options immediately following the reduction. The modification did not result in any additional compensation expense.

F-39

Index to Financial Statements

Non-vested (Restricted) Common Stock

Restricted stock awards entitle recipients to exchange restricted common shares for unrestricted common shares (at no cost to them) once the defined vesting period expires, subject to certain forfeiture provisions. The restrictions on the non-vested shares generally lapse four years from the date of grant.

Conversion of Vested Restricted Common Stock

Concurrent with the IPO in December 2010, all vested restricted common shares converted to unrestricted common stock in the Company. The following table provides a summary of our non-vested restricted common stock awards for the periods indicated:

	Year Ended			Weighted Average
	December 31, 2010 (1)			Grant-Date Fair Value (2)
Outstanding at beginning of period		25,091		$	3.40
Granted		30,198			7.22
Vested		(55,289	)		5.49
Outstanding at end of period		-

_______

(1)	The number of restricted stock was adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03.

(2)	The weighted average prices were adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03.

The following table presents weighted average fair value of shares granted and total fair value of shares vested during the periods indicated.

	Year Ended December 31,
	2010		2009		2008
Weighted average fair value of shares granted (per share) (1)	$	7.22	$	-	$	7.02
Total fair value of shares vested (in millions)		0.3		2.4		16.6

_______

(1)	The weighted average prices were adjusted to reflect the IPO reverse stock split with the conversion rate of 2.03.

During 2010, 2009 and 2008, we recognized $0.2 million, $0.3 million and $1.0 million of compensation expense associated with the vesting of restricted stock.

2010 TRC Stock Incentive Plan

In connection with our IPO in December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan (“TRC Plan”) for employees, consultants and non-employee directors of the Company. The TRC Plan allows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as incentive options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted in conjunction with Options or Phantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock awards (“Phantom Stock Awards”), (vi) bonus stock awards, (vii) performance awards, or (viii) any combination of such awards (collectively referred to a “Awards”).

On December 6, 2010, we awarded 556,514 bonus stock awards to our executive management team which vested upon the closing of our IPO on December 10, 2010. Total compensation expense associated with these awards in 2010 was $12.2 million. The compensation expense was calculated based on the fair value of the stock of $22 per share at grant date.

On December 6, 2010, we granted to executive management and certain employees 1,350,000 Restricted Stock Awards. These awards vest over a three year period at 60% in 24 months and the remaining 40% in 36 months. There are no restrictions on the shares once the vesting requirement is met. Total compensation expense associated with these awards in 2010 was $1.1 million. We expect to incur an additional $28.6 million of expense related to the restricted awards over the next three years. The compensation expense was calculated based on the fair value of the stock of $22 per share at grant date.

F-40

Index to Financial Statements

Subsequent Event. In February 2011, our Compensation Committee (the “Committee”) made awards to our executive management for the 2011 compensation cycle of 33,140 restricted common shares under TRC’s Plan that will vest three years from the grant date and 68,030 equity-settled performance units under the Partnership’s LTIP that will vest in June 2014. The settlement value of these performance unit awards will be determined using the formula adopted for the performance unit awards granted in December 2009.

Non-Employee Director Grants and Incentive Plan related to the Partnership’s Common Units

In connection with the Partnership’s IPO in February 2007, we adopted a long-term incentive plan (“LTIP”) for employees, consultants and directors of the Partnership or its affiliates who perform services for us or our affiliates. The LTIP provides for the grant of cash-settled performance units which are linked to the performance of the Partnership’s common units and may include distribution equivalent rights (“DERs”). The LTIP is administered by the compensation committee of our board of directors. Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit.

Each vested performance unit will entitle the grantee to a cash payment equal to the then value of a Partnership common unit, including DERs. The amount vesting under such awards is based on the total return per common unit of the Partnership through the end of the performance period multiplied by the vesting percentage determined from the Partnership’s ranking in a defined peer group.

The following table summarizes the LTIP units for the year ended 2010:

	Program Year
	2007 Plan			2008 Plan			2009 Plan			2010 Plan			Total
Unit outstanding January 1, 2010		275,400			135,800			534,900			90,403			1,036,503
Granted		-			-			-			219,597			219,597
Vested and paid		(275,400	)		-			-			-			(275,400	)
Forfeited		-			(2,000	)		(7,400	)		(3,000	)		(12,400	)
Units outstanding December 31, 2010		-			133,800			527,500			307,000			968,300

Calculated fair market value as of December 31, 2010				$	5,176,263		$	20,113,575		$	13,621,590		$	38,911,428
Liabilities recognized as of December 31, 2010:
Current				$	4,276,430		$	-		$	-		$	4,276,430
Long-term					-			10,145,414			3,434,471			13,579,885

To be recognized in future periods					899,833			9,968,161			10,187,119			21,055,113

Vesting date				June 2011			June 2012			June 2013

Because the performance units require cash settlement, they have been accounted for as liabilities in our financial statements. During 2010, we paid $9.1 million for vested LTIP units.

During 2010, we changed the fair value measurement model from a Black-Scholes option pricing model to a Monte Carlo simulation model. We considered the Monte Carlo simulation model to be more appropriate for LTIP valuation purposes than our previous method because it directly incorporates the peer group ranking market conditions.

Prior to the change, the fair value of a performance unit was 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. The market condition was indirectly incorporated into the valuation based on our point-in-time ranking versus peers at the measurement date.

F-41

Index to Financial Statements

With the Monte Carlo simulation model, the fair value of a performance unit is the sum of: (i) the simulated share price of multiple correlated assets incorporated with peer ranking; and (ii) the estimated value of expected DERs. The simulated stock price was estimated using the Monte Carlo simulation with discount rate of 7.17% and expected volatility of 33.8%.

The remaining weighted average recognition period for the unrecognized compensation cost is approximately two years. During 2010, 2009 and 2008 we recognized compensation expense of $13.9 million, $10.5 million and $0.1 million related to the performance units.

Director Grants

During 2010 and 2009, Targa Resources GP LLC, the Partnership’s general partner, also made equity-based awards of 15,750 and 32,000 of the Partnership’s restricted common units (2,250 and 4,000 of its restricted common units to each of the Partnership’s and our non-management directors) under its Incentive Plan. The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date. During 2010, 2009 and 2008, the Partnership recognized compensation expense of $0.4 million, $0.3 million and $0.3 million related to these awards with an offset to common equity. The Partnership estimates that the remaining fair value of $0.2 million will be recognized in expense over approximately one year. As of December 31, 2010 there were 39,074 unvested restricted common units outstanding under this plan.

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

	Year Ended			Weighted-average
	December 31, 2010			Grant-Date Fair Value
Outstanding at beginning of year	$	41,993		$	12.88
Granted		15,750			23.51
Vested		(18,669	)		15.06
Outstanding at end of year		39,074			16.12

The weighted average grant-date fair value of the unit-based awards for the years ended 2010, 2009 and 2008 were $16.12, $12.88 and $22.12.

Subsequent event. On February 14, 2011, the Partnership’s general partner made equity based awards of 10,600 of the Partnership’s restricted common units (2,120 restricted common units under to each of the Partnership’s 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.

Other Compensation Plans

We have a 401(k) plan whereby we match 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan). We also contribute an amount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. We made contributions to the 401(k) plan totaling $7.2 million, $6.6 million, and $8.4 million during 2010, 2009, and 2008.

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Index to Financial Statements

Note 25—Selected Quarterly Financial Data (Unaudited)

Our results of operations by quarter for the years ended December 31, 2010 and 2009 were as follows:

	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter			Total
	(In millions, except per share amounts)
Year Ended December 31, 2010:
Revenues	$	1,483.6		$	1,240.0		$	1,218.3		$	1,527.3			$	5,469.2
Gross margin		185.9			182.3			186.2			227.1				781.5
Operating income		54.8			48.5			43.2			49.6				196.1
Net income (loss)		35.9			7.4			(4.2	)		24.2				63.3
Net income (loss) attributable to Targa Resources Corp.		21.9			(11.5	)		(17.4	)		(8.0	)			(15.0	)
Net income (loss) available to common shareholders (1)	$	-		$	(191.8	)	$	(19.0	)	$	(9.0	)		$	(202.3	)
Net income (loss) per common
share - basic and diluted	$	-		$	(48.10	)	$	(3.77	)	$	(0.68	)		$	(30.94	)

Year Ended December 31, 2009:
Revenues	$	1,005.6		$	1,013.8		$	1,125.7		$	1,390.9			$	4,536.0
Gross margin		155.9			174.9			189.4			224.7				744.9
Operating income		25.4			48.5			50.1			93.2				217.2
Net income (loss)		(0.4	)		20.5			10.5			48.5				79.1
Net income (loss) attributable to Targa Resources Corp.		1.3			12.2			(0.5	)		16.3				29.3
Net income (loss) available to common shareholders	$	(3.0	)	$	-		$	(5.1	)	$	-			$	-
Net income (loss) per common
share - basic and diluted	$	(0.81	)	$	-		$	(3.77	)	$	-			$	-

________

(1)	We paid dividends of $177.8 million to Series B Preferred shareholders during the second quarter of 2010, which reduces the net income available to common shares.

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SCHEDULE 1

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

Report of Independent Registered Public Accounting Firm on Financial Statement Schedule

To the Board of Directors and Stockholders

of Targa Resources Corp:

Our audits of the consolidated financial statements referred to in our report dated February 25, 2011 appearing in the Form 10-K of Targa Resources Corp. (which report and consolidated financial statements are included in this Form 10-K/A) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K/A. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

/s/PricewaterhouseCoopers LLP

Houston, Texas

February 25, 2011

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Index to Financial Statements

TARGA RESOURCES CORP.
PARENT ONLY
CONDENSED BALANCE SHEET

	December 31,
	2010		2009
	(In millions)
ASSETS
Current assets	$	-		$	-
Long-term debt issue costs		0.6			2.8
Deferred income taxes		12.5			16.0
Investment in consolidated subsidiaries		223.2			762.4
Total assets	$	236.3		$	781.2

LIABILITIES AND STOCKHOLDERS' EQUITY
Accrued current liabilities	$	2.7		$	-
Long-term debt		89.3			385.4

Commitments and contingencies

Convertible cumulative participating series B preferred stock		-			308.4

Targa Resources Corp. stockholders' equity		144.3			87.4
Total liabilities and stockholders' equity	$	236.3		$	781.2

See accompanying note to condensed financial statements

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Index to Financial Statements

TARGA RESOURCES CORP.
PARENT ONLY
CONDENSED STATEMENT OF OPERATIONS

	Year Ended December 31,
	2010			2009			2008
	(In millions, except per share amounts)
Equity in net income (loss) of consolidated subsidiaries	$	(16.3	)	$	30.9		$	51.8
General and administrative expenses		(20.5	)		(0.2	)		(0.5	)
Gain on sale of assets		1.1
Income (loss) from operations		(35.7	)		30.7			51.3

Other income (expense):
Gain on debt extinguishment		35.2			24.5			16.1
Interest expense		(11.2	)		(26.6	)		(37.9	)
Income (loss) before income taxes		(11.7	)		28.6			29.5
Deferred income tax (expense) benefit		(3.3	)		0.7			7.8
Net income (loss) attributable to Targa Resources Corp.		(15.0	)		29.3			37.3
Dividends on Series B preferred stock		(9.5	)		(17.8	)		(16.8	)
Undistributed earnings attributable to preferred shareholders		-			(11.5	)		(20.5	)
Dividends on common equivalents		(177.8	)		-			-
Net income (loss) available to common shareholders	$	(202.3	)	$	-		$	-
Net income (loss) available per common share	$	(30.94	)	$	-		$	-
Weighted average shares outstanding - basic and diluted		6.5			3.8			3.8

See accompanying note to condensed financial statements

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Index to Financial Statements

TARGA RESOURCES CORP.
PARENT ONLY
CONDENSED STATEMENT OF CASH FLOWS

	Year Ended December 31,
	2010			2009			2008
				(In millions)
Net cash used in operating activities	$	(4.4	)	$	(6.2	)	$	(7.5	)

Investing activities
Distribution and return of advances from consolidated subsidiaries		721.0			39.2			69.3
Net cash provided by investing activities		721.0			39.2			69.3

Financing activities:
Issuance of common stock		0.9			0.3			0.8
Repurchase of common stock		(0.1	)		-			(0.5	)
Repurchase of long-term debt		(269.3	)		(33.3	)		(62.1	)
Dividends to preferred shareholders		(210.1	)		-			-
Dividends to common and common equivalent shareholders		(238.0	)		-			-
Net cash used in financing activities		(716.6	)		(33.0	)		(61.8	)

Net increase (decrease) in cash and cash equivalents		-			-			-
Cash and cash equivalents - beginning of year		-			-			-
Cash and cash equivalents - end of year	$	-		$	-		$	-

See accompanying note to condensed financial statements

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Index to Financial Statements

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT –

TARGA RESOURCES CORP.

NOTE TO CONDENSED FINANCIAL STATEMENTS

Note 1 – Basis of Presentation

The condensed financial statements represent the financial information required by Rule 5-04 of the Securities and Exchange Commission Regulation S-X for Targa Resources Corp.

In the condensed financial statements, Targa’s investments in consolidated subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the consolidated subsidiaries are recorded in the balance sheets. The income (loss) from operations of the consolidated subsidiaries is reported as equity in income (loss) of consolidated subsidiaries.

A substantial amount of Targa’s operating, investing and financing activities are conducted by its affiliates. The condensed financial statements should be read in conjunction with Targa’s consolidated financial statements, which begin on page F-3 of this Annual Report.

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