Targa Resources Partners (NGLS-PA) 8-K Regulation FD Disclosure

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

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

Date of Report (Date of earliest event reported): November 16, 2010

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

Item 7.01 Regulation FD Disclosure

     On November 16, 2010, Targa Resources Corp., formerly Targa Resources Investments Inc. (“TRC”), the indirect parent of Targa Resources GP LLC, the general partner of Targa Resources Partners LP (the “Partnership”), disclosed the following information about the Partnership and its plans relating to the Partnership in an amendment to the registration statement on Form S-1 (the “S-1/A”) relating to TRC’s proposed initial public offering. The information below is excerpted from the S-1/A and updates or provides additional information from information previously disclosed by the Partnership with respect to the Partnership’s business, operations and prospects.

     As used in the information excerpted below, unless indicated otherwise: (1) “our,” “we,” “us,” “TRC,” the “Company” and similar terms refer either to TRC in its individual capacity or to TRC and its subsidiaries collectively, as the context requires, (2) the “General Partner” refers to Targa Resources GP LLC, the general partner of the Partnership, and (3) the “Partnership” refers to the Partnership in its individual capacity, to the Partnership and its subsidiaries collectively, or to the Partnership together with combined entities for predecessor periods under common control, as the context requires.

OUR DIVIDEND POLICY

General

We intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash we receive from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:

•  Federal income taxes, which we are required to pay because we are taxed as a corporation;

•  the expenses of being a public company;

•  other general and administrative expenses;

•  general and administrative reimbursements to the Partnership;

•  capital contributions to the Partnership upon the issuance by it of additional partnership securities if we choose to maintain the General Partner’s 2.0% interest;

•  reserves our board of directors believes prudent to maintain;

•  our obligation to (i) satisfy tax obligations associated with previous sales of assets to the Partnership, (ii) reimburse the Partnership for certain capital expenditures related to Versado and (iii) provide the Partnership with limited quarterly distribution support through 2011, all as described in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources;” and

•  interest expense or principal payments on any indebtedness we incur.

Based on the current distribution policy of the Partnership, expected cash to be received from the Partnership, our expected federal income tax liabilities, our expected level of other expenses and reserves that our board of directors believes prudent to maintain, we expect that our initial quarterly dividend rate will be $0.2575 per share. If the Partnership is successful in implementing its business strategy and increasing distributions to its partners, we would generally expect to increase dividends to our stockholders, although the timing and amount of any such increased dividends will not necessarily be comparable to the increased Partnership distributions. We expect to pay a pro rated dividend for the portion of the fourth quarter of 2010 that we are public in February 2011. However, we cannot assure you that any dividends will be declared or paid.

The determination of the amount of cash dividends, including the quarterly dividend referred to above, if any, to be declared and paid will depend upon our financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board of directors deems relevant. The Partnership’s debt agreements contain restrictions on the payment of distributions and prohibit the payment of distributions if the Partnership is in default. If the Partnership cannot make incentive distributions to the general partner or limited partner distributions to us, we will be unable to pay dividends on our common stock.

The Partnership’s Cash Distribution Policy

Under the Partnership’s partnership agreement, available cash is defined to generally mean, for each fiscal quarter, all cash on hand at the date of determination of available cash for that quarter less the amount of cash reserves established by the General Partner to provide for the proper conduct of the Partnership’s business, to comply with applicable law or any agreement binding on the Partnership and its subsidiaries and to provide for future distributions to the Partnership’s unitholders for any one or more of the upcoming four quarters. The determination of available cash takes into account the possibility of establishing cash reserves in some quarterly periods that the Partnership may use to pay cash distributions in other quarterly periods, thereby enabling it to maintain relatively consistent cash distribution levels even if the Partnership’s business experiences fluctuations in its cash from operations due to seasonal and cyclical factors. The General Partner’s determination of available cash also allows the Partnership to maintain

reserves to provide funding for its growth opportunities. The Partnership makes its quarterly distributions from cash generated from its operations, and those distributions have grown over time as its business has grown, primarily as a result of numerous acquisitions and organic expansion projects that have been funded through external financing sources and cash from operations.

The actual cash distributions paid by the Partnership to its partners occur within 45 days after the end of each quarter. Since second quarter 2007, the Partnership has increased its quarterly cash distribution 7 times. During that time period, the Partnership has increased its quarterly distribution by 62% from $0.3375 per common unit, or $1.35 on an annualized basis, to $0.5475 per common unit, or $2.19 on an annualized basis, based on the 2010 fourth quarter distribution management plans to recommend to the General Partner’s board of directors.

Overview of Presentation

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial quarterly dividend of $0.2575 per share of common stock for each quarter through the quarter ending December 31, 2011. In these sections, we present three tables, including:

•  our “Unaudited Pro Forma Available Cash,” in which we present the amount of available cash we would have had available for dividends to our shareholders on a pro forma basis for the year ended December 31, 2009 and for the twelve months ended September 30, 2010; and

•  our “TRC Minimum Estimated Cash Available for Distribution for the Twelve Month Period Ending December 31, 2011” and “TRC Minimum Estimated Cash Available for Distribution for the Three Month Period Ending December 31, 2010” in which we present our estimate of the Adjusted EBITDA necessary for the Partnership to pay distributions to its partners, including us, to enable us to have sufficient cash available for distribution to fund quarterly dividends on all outstanding common shares for each quarter through the quarter ending December 31, 2011.

Targa Resources Corp. Unaudited Pro Forma Available Cash for the Year Ended December 31, 2009 and the Twelve Months Ended September 30, 2010

Our pro forma available cash for the year ended December 31, 2009 and the twelve months ended September 30, 2010 would have been sufficient to pay the initial quarterly dividend of $0.2575 per share of common stock outstanding following the completion of this offering.

Pro forma cash available for distribution includes estimated incremental general and administrative expenses we will incur as a result of being a public corporation, such as costs associated with preparation and distribution of annual and quarterly reports to shareholders, tax returns, investor relations, registrar and transfer agent fees, director compensation and incremental insurance costs, including director and officer liability insurance. We expect that these items will increase our annual general and administrative expenses by approximately $1 million.

The table below reconciles the Partnership’s historical financial results to our minimum cash available for distribution and illustrates that we would have had cash distributions on our interests in the Partnership sufficient to pay dividends to our shareholders at the initial quarterly dividend of $0.2575 per share. The table reconciles the Partnership’s historical financial results to its Adjusted EBITDA for the year ended December 31, 2009 and for the twelve months ended September 30, 2010 and then reconciles Adjusted EBITDA to pro forma cash available for distribution to all of the Partnership’s unitholders.

The Partnership’s pro forma cash available for distribution is derived from its historical financial statements included in its Current Report onForm 8-K filed with the SEC on October 4, 2010, and its Quarterly Report onForm 10-Q filed with the SEC on November 5, 2010. Under common control accounting, the Partnership’s financial results include the historical financial results of the assets acquired from us. The only pro forma adjustments to such historical financial results are to (i) present prior period interest expense based on the Partnership’s current debt balance as reflected in the pro forma cash interest expense line in the table below and (ii) current units outstanding of 75,545,409 units for all

periods presented. The pro forma cash available for distribution should not be considered indicative of our results of operations had the transactions contemplated in our unaudited pro forma condensed consolidated financial statements actually been consummated on January 1, 2009.

Targa Resources Corp.

Unaudited Pro Forma Available Cash

	Year Ended			Twelve Months
	December 31,			Ended September 30,
	2009			2010
	(In millions, except per
	share amounts)
Targa Resources Partners LP Data
Revenues	$	4,503.7		$	5,321.4
Less: Product purchases		(3,792.9	)		(4,556.2	)
Gross margin(1)		710.8			765.2
Less: Operating expenses		(234.4	)		(242.4	)
Operating margin(2)		476.4			522.8
Less:
Depreciation and amortization expenses		(166.7	)		(170.1	)
General and administrative expenses		(118.5	)		(116.6	)
Interest expense, net		(107.0	)		(107.0	)
Equity in earnings of unconsolidated investment		5.0			5.6
Loss on debt repurchases		(1.5	)		(0.8	)
Loss onmark-to-market derivative instruments		(30.9	)		7.1
Income tax expense		(1.2	)		(4.2	)
Net income attributable to noncontrolling interest		(19.3	)		(25.5	)
Other		4.4			(0.6	)
Net income attributable to Targa Resources Partners LP		40.7			110.6
Plus:
Interest expense, net		107.0			107.0
Income tax expense		1.2			4.2
Depreciation and amortization expenses		166.7			170.1
Noncash loss related to derivative instruments		92.0			15.4
Noncontrolling interest adjustment		(10.5	)		(10.3	)
Adjusted EBITDA(3)		397.1			397.0

	Year Ended			Twelve Months
	December 31,			Ended September 30,
	2009			2010
	(In millions, except per
	share amounts)
Adjusted EBITDA(3)		397.1			397.0
Less:
Pro forma cash interest expense(4)		(101.1	)		(101.1	)
Maintenance capital expenditures, net		(35.3	)		(40.4	)
Pro forma cash available for distribution to Partnership unitholders(5)		260.7			255.5
Partnership’s debt covenant ratios(6)
Interest coverage ratio of not less than 2.25 to 1.0		3.7	x		3.7	x
Consolidated leverage ratio of not greater than 5.5 to 1.0		3.5	x		3.6	x
Consolidated senior leverage ratio of not greater than 4.0 to 1.0		1.8	x		1.9	x
Estimated minimum cash available for distribution to Partnership unitholders
Estimated minimum cash distributions to us:
2% general partner interest		3.8			3.8
Incentive distribution rights(7)		21.4			21.4
Common units		25.5			25.5
Pro forma cash distributions to us		50.7			50.7
Pro forma cash distributions to public unitholders		139.9			139.9
Total pro forma cash distributions by the Partnership		190.6			190.6
Excess / (Shortfall)		70.1			64.9
Targa Resources Corp. Data(8)
Pro forma cash distributions to be received from the Partnership	$	50.7		$	50.7
Plus / (Less):
General and administrative expenses(9)		(5.4	)		(5.4	)
Cash interest expense(10)		(3.4	)		(3.4	)
Interest income		1.7			1.7
Minimum estimated cash available for distribution		43.6			43.6
Excess / (Shortfall)		—			—
Expected dividend per share		1.03			1.03
Total dividends paid to stockholders	$	43.6		$	43.6

(1)	Gross margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations.”
(2)	Operating margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations.”
(3)	Adjusted EBITDA is presented because we believe it provides additional information with respect to both the performance of our fundamental business activities as well as our ability to meet future debt service, capital expenditures and working capital requirements. It is a non-GAAP financial measure and is not intended to be used in lieu of the GAAP presentation of net income.

⁽⁴⁾ For the twelve months ended September 30, 2010, the Partnership’s pro forma cash interest expense includes (i) $35.0 million of interest expense related to borrowings under the revolving credit facility based on an average balance of $727.3 million at an average interest rate of 4.8% (comprised of 1% LIBOR plus a borrowing spread of 2.75% plus interest rate hedge settlement of 1.1%); (ii) $62.9 million of interest expense related to the $690 million of senior unsecured notes with a weighted average interest rate of approximately 9.1% and (iii) $3.2 million of commitment fees and letter of credit fees. After giving effect to LIBOR swaps for $300 million of the Partnership’s revolving credit facility, a 1.0% change in LIBOR would result in a change in interest expense for the period of $4.3 million.

For the twelve months ended December 31, 2009, the Partnership’s pro forma cash interest expense includes (i) $33.6 million of interest expense related to borrowings under the revolving credit facility based on an average balance of $684.5 million at an average interest rate of 4.9% (comprised of 1% LIBOR plus a spread of 2.75% plus interest rate hedge settlement of 1.2%); (ii) $62.9 million of interest expense related to the $690 million of senior unsecured notes with a weighted average interest rate of

	approximately 9.1% and (iii) $4.5 million of commitment fees and letter of credit fees. After giving effect to LIBOR swaps for $300 million of the Partnership’s revolving credit facility, a 1.0% change in LIBOR would result in a change in interest for the period of $3.9 million.
	Cash interest expense excludes $5.9 million of non-cash interest expense for both periods.
(5)	The Partnership’s pro forma cash available for distribution is presented because we believe it is used by investors to evaluate the ability of the Partnership to make quarterly cash distributions. It is a non-GAAP financial measure and is not intended to be used in lieu of the GAAP presentation of net income.
(6)	The Partnership’s credit agreement and indentures contain certain financial covenants. The Partnership’s revolving credit facility requires that, at the end of each fiscal quarter, the Partnership must maintain:

•  an interest coverage ratio, defined as the ratio of the Partnership’s consolidated adjusted EBITDA (as defined in the Amended and Restated Credit Agreement) for the four consecutive fiscal quarters most recently ended to the consolidated interest expense (as defined in the Amended and Restated Credit Agreement) for such period, of no less than 2.25 to 1.0;

•  a Consolidated Leverage Ratio, defined as the ratio of the Partnership’s consolidated funded indebtedness (as defined in the Amended and Restated Credit Agreement) to consolidated adjusted EBITDA, for the four fiscal quarters most recently ended, that is not greater than 5.5 to 1.0; and

•  a Consolidated Senior Leverage ratio, defined as the ratio of the Partnership’s consolidated funded indebtedness, excluding unsecured note indebtedness, to consolidated adjusted EBITDA, for the four fiscal quarters most recently ended, that is not greater than 4.0 to 1.0.

	In addition, the indentures relating to the Partnership’s senior notes require that the Partnership have a fixed charge coverage ratio for the most recently ended four fiscal quarters of not less than 1.75 to 1.0 in order to make distributions, subject to certain exceptions. This ratio is approximately equal to the interest coverage ratio described above. As indicated in the table, the Partnership’s pro forma EBITDA would have been sufficient to permit cash distributions under the terms of its credit agreement and indentures.
(7)	Our incentive distributions are based on the Partnership’s 75,545,409 outstanding common units as of November 1, 2010 and the Partnership’s fourth quarter 2010 quarterly distribution of $0.5475 per unit, or $2.19 per unit on an annualized basis, that management plans to recommend to the General Partner’s board of directors.
(8)	We will have no debt outstanding under TRI’s revolving credit facility, and accordingly, we have not presented credit ratios for this facility in the table. Pursuant to the terms of this facility at the end of each fiscal quarter, TRI must maintain:

•  an interest coverage ratio, defined as the ratio of our consolidated adjusted EBITDA (as defined in the revolving credit agreement) for the four consecutive fiscal quarters most recently ended to the consolidated interest expense (as defined in the revolving credit agreement) for such period, of no less than 1.5 to 1.0;

•  a Consolidated Leverage Ratio, defined as the ratio of our consolidated funded indebtedness (as defined in the revolving credit agreement) to consolidated adjusted EBITDA, for the four fiscal quarters most recently ended, that is not greater than 5.75 to 1.0 and becomes more restrictive over time.

(9)	General and administrative expenses include $1 million of incremental public company expenses.
(10)	Following this offering and excluding debt of the Partnership, our only outstanding debt will be the Holdco Loan under which we have the election to pay interest in cash or in kind. We have assumed that we will pay interest in cash at an assumed interest rate of LIBOR plus a spread of 3.0%. The Holdco Loan agreement has no restrictive covenants which would impact our ability to pay dividends.

TRC Minimum Estimated Cash Available for Distribution for the Twelve Month Period Ending December 31, 2011

Set forth below is a forecast of the “TRC Minimum Estimated Cash Available for Distribution” that supports our belief that we expect to generate sufficient cash flow to pay a quarterly dividend of $0.2575 per common share on all of our outstanding common shares for the twelve months ending December 31, 2011, based on assumptions we believe to be reasonable.

Our minimum estimated cash available for distribution reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending December 31, 2011. The assumptions disclosed under “— Assumptions and Considerations” below are those that we believe are significant to our ability to generate such minimum estimated cash available for distribution. We believe our actual results of operations and cash flows for the twelve months ending December 31, 2011 will be sufficient to generate our minimum

estimated cash available for distribution for such period; however, we can give you no assurance that such minimum estimated cash available for distribution will be achieved. There will likely be differences between our minimum estimated cash available for distribution for the twelve months ending December 31, 2011 and our actual results for such period and those differences could be material. If we fail to generate the minimum estimated cash available for distribution for the twelve months ending December 31, 2011, we may not be able to pay cash dividends on our common shares at the initial dividend rate stated in our cash dividend policy for such period.

Our minimum estimated cash available for distribution required to pay dividends to all our outstanding shares of common stock at the estimated annual initial dividend rate of $1.03 per share is approximately $43.6 million. Our minimum estimated cash available for distribution is comprised of cash distributions from our limited and general partnership interests in the Partnership, including the IDRs, less general and administrative expenses, less cash interest expense, if any, less federal income taxes, less capital contributions to the Partnership and less reserves established by our board of directors. Substantially all of our cash flow will be generated from our limited and general partnership interests in the Partnership. In order for our minimum estimated cash available for distribution to be approximately $43.6 million, we estimate that the Partnership must have minimum estimated cash available for distribution for the twelve months ending December 31, 2011 of $190.6 million, which would be sufficient to fund the Partnership’s recommended distribution for the quarter ended December 31, 2010 of $2.19 per common unit on an annualized basis.

In order for the Partnership to have minimum estimated cash available for distribution of $190.6 million, we estimate that it must generate Adjusted EBITDA of at least $403.5 million for the twelve months ending December 31, 2011 after giving effect to a $58.8 million cash reserve. As set forth in the table below and as further explained under “—Assumptions and Considerations,” we believe the Partnership will produce minimum estimated cash available for distribution of $190.6 million for the twelve months ending December 31, 2011.

We do not as a matter of course make public projections as to future operations, earnings or other results. However, management has prepared the minimum estimated cash available for distribution and assumptions set forth below to substantiate our belief that we will have sufficient cash available to pay the estimated annual dividend rate to our stockholders for the twelve months ending December 31, 2011. The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate the minimum estimated cash available for distribution necessary for us to have sufficient cash available for distribution to pay the estimated annual dividend rate to all of our stockholders for the twelve months ending December 31, 2011. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information. The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has neither examined, compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP reports included in this prospectus relate to our historical financial information. Such reports do not extend to the prospective financial information of the Partnership or us and should not be read to do so.

We are providing the minimum estimated cash available for distribution and related assumptions for the twelve months ending December 31, 2011 to supplement our pro forma and historical financial statements in support of our belief that we will have sufficient available cash to allow us to pay cash dividends on all of our outstanding shares of common stock for each quarter in the twelve month period ending December 31, 2011 at our stated initial quarterly dividend rate. Please read below under “— Assumptions and Considerations” for further information as to the assumptions we have made for the preparation of the minimum estimated cash available for distribution set forth below.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the assumptions used in generating our minimum estimated cash available for distribution for the twelve months ending December 31, 2011 or to update those assumptions to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

TRC Minimum Estimated Cash Available for Distribution for the Twelve Month Period Ending December 31, 2011

	Twelve Months Ending
	December 31, 2011
	(In millions except per
	unit and per share
	amounts)
Targa Resources Partners LP Data
Revenues	$	6,098.1
Less: product purchases		(5,264.5	)
Gross margin(1)		833.6
Less: operating expenses		(289.3	)
Operating margin(2)		544.3
Less:
Depreciation and amortization expenses		(175.4	)
General and administrative expenses		(110.3	)
Income from operations		258.6
Plus (less) other income (expense)
Interest expense, net		(110.3	)
Equity in earnings of unconsolidated investment		11.5
Income before income taxes		159.8
Less: income tax expense		(2.5	)
Net income		157.3
Less: net income attributable to noncontrolling interest(3)		(31.2	)
Net income attributable to Targa Resources Partners LP	$	126.1
Plus:
Interest expense, net		110.3
Income tax expense		2.5
Depreciation and amortization expenses		175.4
Non-cash loss related to derivative instruments		0.4
Noncontrolling interest adjustment		(11.2	)
Estimated Adjusted EBITDA(4)	$	403.5
Less:
Interest expense, net		(110.3	)
Expansion capital expenditures, net		(129.0	)
Borrowings for expansion capital expenditures		129.0
Maintenance capital expenditures, net		(49.7	)
Amortization of debt issue costs		5.9
Cash reserve(5)		(58.8	)
Estimated minimum cash available for distribution(6)	$	190.6
Partnership debt covenant ratios(7)
Interest coverage ratio of not less than 2.25 to 1.0		3.7	x
Consolidated leverage ratio of not greater than 5.5 to 1.0		4.0	x
Consolidated senior leverage ratio of not greater than 4.0 to 1.0		2.2	x
Estimated minimum cash available for distribution to Partnership unitholders
Estimated minimum cash distributions to us:
2% general partner interest	$	3.8
Incentive distribution rights(8)		21.4
Common units		25.5
Total estimated minimum cash distributions to us		50.7
Estimated minimum cash distributions to public unitholders		139.9
Total estimated minimum cash distributions by the Partnership	$	190.6

	Twelve Months Ending
	December 31, 2011
	(In millions except
	per share amounts)
Targa Resources Corp. Data(9)(10)
Minimum estimated cash distributions to be received from the Partnership	$	50.7
Corporate general and administrative expenses(11)		(5.4	)
Partnership distributions less general and administrative expenses		45.3
Plus / (Less):
Interest Expense		(3.4	)
Interest Income		1.7
Cash taxes paid		(14.3	)
Cash taxes funded from cash on hand		14.3
Minimum estimated cash available for distribution	$	43.6
Expected dividend per share, on an annualized basis	$	1.03
Total estimated dividends paid to stockholders	$	43.6

(1)	Gross margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations.”
(2)	Operating margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations.”
(3)	Reflects net income attributable to Chevron’s 37% interest in Versado, Enterprise’s 12% interest in VESCO, ONEOK’s 11% interest in VESCO and BP’s 12% interest in CBF.
(4)	Adjusted EBITDA is presented because we believe it provides additional information with respect to both the performance of our fundamental business activities as well as our ability to meet future debt service, capital expenditures and working capital requirements. It is a non-GAAP financial measure and is not intended to be used in lieu of the GAAP presentation of net income.
(5)	Represents a discretionary cash reserve. See “—The Partnership’s Cash Distribution Policy.”
(6)	The Partnership’s estimated minimum cash available for distribution is presented because we believe it is used by investors to evaluate the ability of the Partnership to make quarterly cash distributions. It is a non-GAAP financial measure and is not intended to be used in lieu of the GAAP presentation of net income.
(7)	The Partnership’s credit agreement and indentures contain certain financial covenants. The Partnership’s revolving credit facility requires that, at the end of each fiscal quarter, the Partnership must maintain:

•  an interest coverage ratio, defined as the ratio of the Partnership’s consolidated adjusted EBITDA (as defined in the Amended and Restated Credit Agreement) for the four consecutive fiscal quarters most recently ended to the consolidated interest expense (as defined in the Amended and Restated Credit Agreement) for such period, of no less than 2.25 to 1.0;

•  a Consolidated Leverage Ratio, defined as the ratio of the Partnership’s consolidated funded indebtedness (as defined in the Amended and Restated Credit Agreement) to consolidated adjusted EBITDA, for the four fiscal quarters most recently ended, that is not greater than 5.5 to 1.0; and

•  a Consolidated Senior Leverage ratio, defined as the ratio of the Partnership’s consolidated funded indebtedness, excluding unsecured note indebtedness, to consolidated adjusted EBITDA, for the four fiscal quarters most recently ended, that is not greater than 4.0 to 1.0.

In addition, the indentures relating to the Partnership’s existing senior notes require that the Partnership have a fixed charge coverage ratio for the most recently ended four fiscal quarters of not less than 1.75 to 1.0 in order to make distributions, subject to certain exceptions. This ratio is approximately equal to the interest coverage ratio described above. As indicated by the table, we estimate that the Partnership’s pro forma EBITDA would be sufficient to permit cash distributions, under the terms of its credit agreement and indentures.

(8)

Based on the Partnership’s 75,545,409 outstanding common units as of November 1, 2010 and the Partnership’s fourth quarter 2010 quarterly distribution of $0.5475 per unit, or $2.19 per unit on an annualized basis, that management plans to recommend to the General Partner’s board of directors.

⁽⁹⁾ We expect that we will have no debt outstanding under TRI’s revolving credit facility, and accordingly, we have not presented credit ratios for this facility in the table. Pursuant to the terms of this facility at the end of each fiscal quarter, TRI must maintain:

•  an interest coverage ratio, defined as the ratio of our consolidated adjusted EBITDA (as defined in the revolving credit agreement) for the four consecutive fiscal quarters most recently ended to the consolidated interest expense (as defined in the revolving credit agreement) for such period, of no less than 1.5 to 1.0;

•  a Consolidated Leverage Ratio, defined as the ratio of our consolidated funded indebtedness (as defined in the revolving credit agreement) to consolidated adjusted EBITDA, for the four fiscal quarters most recently ended, that is not greater than 5.75 to 1.0 and becomes more restrictive over time.

⁽¹⁰⁾ The Holdco Loan agreement has no restrictive covenants which would impact our ability to pay dividends.

⁽¹¹⁾ General and administrative expenses include $3 million of public company expenses, including $1 million of estimated incremental public company expenses. TRI Resources Inc. was required to file reports under the Securities Exchange Act of 1934 until January 2010, and, accordingly, recognized costs associated with being a public company prior to that time.

Assumptions and Considerations

General

We estimate that our ownership interests in the Partnership will generate sufficient cash flow to enable us to pay our initial quarterly dividend of $0.2575 per share on all of our shares for the four quarters ending December 31, 2011. Our ability to make these dividend payments assumes that the Partnership will pay its current quarterly distribution of $0.5475 per common unit for each of the four quarters ending December 31, 2011, which means that the total amount of cash distributions we will receive from the Partnership for that period would be $50.7 million.

The primary determinant in the Partnership’s ability to pay a distribution of $0.5475 per common unit for each of the four quarters ending December 31, 2011, after giving effect to a $58.8 million cash reserve, is its ability to generate Adjusted EBITDA of at least $403.5 million during the period, which in turn is dependent on its ability to generate operating margin of $544.3 million. Our estimate of the Partnership’s ability to generate at least this amount of operating margin is based on a number of assumptions including those set forth below.

While we believe that these assumptions are generally consistent with the actual performance of the Partnership and are reasonable in light of our current beliefs concerning future events, the assumptions are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If these assumptions are not realized, the actual available cash that the Partnership generates, and thus the cash we would receive from our ownership interests in the Partnership, could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make our initial quarterly dividend on our shares for the forecasted period. In that event, the market price of our shares may decline materially. Consequently, the statement that we believe that we will have sufficient cash available to pay the initial dividend on our shares of common stock for each quarter through December 31, 2011, should not be regarded as a representation by us or the underwriters or any other person that we will make such a distribution. When reading this section, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” in this prospectus.

Commodity Price Assumptions.  As of October 29, 2010, the NYMEX 2011 calendar strip prices for natural gas and crude oil were $4.39 per MMBtu and $84.28 per Bbl. These prices are 13.9% and 0.9%

below the forecasted prices of $5.10 per MMBtu and $85.00 per Bbl used to calculate estimated Adjusted EBITDA.

	Twelve Months Ended
	December 31, 2009	September 30, 2010	December 31, 2011
Natural Gas	$3.99/MMBtu	$4.48/MMBtu	$5.10/MMBtu
Ethane	$0.48/gallon	$0.61/gallon	$0.47/gallon
Propane	$0.84/gallon	$1.12/gallon	$1.05/gallon
Isobutane	$1.19/gallon	$1.53/gallon	$1.46/gallon
Normal butane	$1.08/gallon	$1.44/gallon	$1.42/gallon
Natural gasoline	$1.31/gallon	$1.75/gallon	$1.80/gallon
Crude oil	$59.80/Bbl	$76.99/Bbl	$85.00/Bbl

In addition, the Partnership’s estimated Adjusted EBITDA reflects the effect of its commodity price hedging program under which it has hedged a portion of the commodity price risk related to the sale of its expected natural gas, NGL, and condensate equity volumes that result from itspercent-of-proceeds processing arrangements for our Field Gathering and Processing and the LOU portion of our Coastal Gathering and Processing operations. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors That Significantly Affect Our Results—Contract Terms and Contract Mix and the Impact of Commodity Prices.” The table below summarizes the Partnership’s hedged volumes for 2011 under derivative arrangements that are in place as of September 30, 2010. We estimate that these hedged volumes correspond to approximately 65% to 75% of the Partnership’s expected natural gas equity volumes and approximately 50% to 60% of Partnership’s expected NGLs and condensate equity volumes for 2011. The percentages hedged are derived by dividing the notional volumes hedged by a range of estimated equity volumes for 2011.

	Natural Gas	NGL	Condensate
Hedged volume — swaps	30,100 MMBtu/d	7,000 Bbls/d	750 Bbls/d
Weighted average price — swaps	$6.32 per MMBtu	$0.85 per gallon	$77.00 per Bbl
Hedged — volume floors		253 Bbls/d
Weighted average price — floors		$1.44 per gallon

The table below compares selected financial and volumetric data for the Partnership for the twelve months ending December 31, 2011 to the twelve months ended September 30, 2010 and December 31, 2009.

	Twelve Months Ended
							December 31, 2011
	December 31, 2009			September 30, 2010			(Estimated)
	(In millions, except for
	share amounts)
Targa Resources Partners LP Data
Revenues	$	4,503.7		$	5,321.4		$	6,098.1
Less: Product purchases		(3,792.9	)		(4,556.2	)		(5,264.5	)
Gross margin		710.8			765.2			833.6
Less: Operating expenses		(234.4	)		(242.4	)		(289.3	)
Operating margin		476.4			522.8			544.3
Adjusted EBITDA		397.1			397.0			403.5
Maintenance capital expenditures, net		35.3			40.4			49.7
Volume Statistics:
Inlet Volumes (MMcf/d)		2,139.8			2,288.5			2,470.2
Fractionation Volumes (MBbls/d)		217.2			221.4			291.6

Volume assumptions.  For the twelve months ended September 30, 2010, plant inlet volumes increased 7% over volumes for the twelve months ended December 31, 2009. For 2011, we expect a continued increase of 8% over the twelve months ended September 30, 2010. The volume increase is driven by additional volumes on the Partnership’s VESCO system (see “ —Coastal Gathering and Processing Segment Assumptions” for more detail), and expected new drilling and workover activity in our Field Gathering and Processing segment (see “ —Field Gathering and Processing Segment Assumptions” for more detail).

Fractionation volumes for 2011 are forecasted to increase 32% over the twelve months ended September 30, 2010 primarily due to the 78 MBbl/d CBF expansion, which is expected to be in service in the second quarter of 2011.

Revenue assumptions.  2011 revenue is forecasted to increase 15% over the twelve months ended September 30, 2010 and 35% over 2009. The increase in revenue is primarily due to higher plant inlet and fractionation volumes and higher commodity prices as presented in the table above.

Product purchase assumptions.  Product purchases are forecasted to increase 16% over the twelve months ended September 30, 2010 and 39% over 2009 primarily due to increased settlement costs associated with higher inlet volumes and increased commodity prices.

Operating expense assumptions.  Operating expenses are forecasted to increase 19% over the twelve months ended September 30, 2010 and 23% over 2009 mostly due to expanded operations in our Logistics segment resulting from the CBF expansion and partial year addition of the benzene treater. Also, expenses are forecasted to be higher for our Field Gathering and Processing Segment mostly due to increased connections resulting from new drilling activity.

Operating margin assumptions.  For the twelve months ended September 30, 2010, operating margin increased 10% over operating margin for the twelve months ended December 31, 2009 largely due to increases in the Field Gathering and Processing segment and the Coastal Gathering and Processing Segment. For full year 2011, we expect a continued increase of 4% over the twelve months ended September 30, 2010 largely due to increases in the Field Gathering and Processing segment and the Logistics Assets segment (see “ —Segment Operating Margin Assumptions” for more detail).

Maintenance Capital Expenditures assumptions, net.  The Partnership’s maintenance capital expenditures increased for the twelve months ended September 30, 2010 relative to 2009 because of a larger number of well connections associated with higher drilling activity levels for assets in our Field Gathering and Processing segment. We expect drilling activity to increase further, which will result in higher maintenance capital expenditures in 2011.

Segment Operating Margin Assumptions.  Based on the pricing and other assumptions outlined above and the segment information and other assumptions discussed below, we estimate forecasted operating margin for the Partnership���s segments for the twelve months ending December 31, 2011 as

shown in following table. Selected operating and historical financial data for the Partnership for the twelve months ended September 30, 2010 and the twelve months ended December 31, 2009 is also shown.

	Twelve Months Ending
					December 31, 2011
	December 31, 2009		September 30, 2010		(Estimated)
	(In millions)
Natural Gas Gathering and Processing
Field Gathering and Processing Segment	$	183.2	$	236.6	$	245.6
Coastal Gathering and Processing Segment		89.7		111.6		102.0
NGL Logistics and Marketing
Logistics Assets Segment		74.4		79.8		118.6
Marketing and Distribution Segment		82.9		78.1		65.6
Other		46.2		16.7		12.5
Total operating margin	$	476.4	$	522.8	$	544.3

Natural Gas Gathering and Processing.  The Partnership’s Natural Gas Gathering and Processing business 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 removing impurities and extracting a stream of combined NGLs or mixed NGLs. The Field Gathering and Processing segment assets are located in North Texas and in the Permian Basin of Texas and New Mexico. The Coastal Gathering and Processing segment assets are located in the onshore and near offshore regions of the Louisiana Gulf Coast accessing onshore and offshore gas supplies. The Partnership’s results of operations are impacted by changes in commodity prices as well as increases and decreases in the volume and thermal content of natural gas that the Partnership gathers and transports through its pipeline systems and processing plants.

Field Gathering and Processing Segment Assumptions.  The following table summarizes selected operating and financial data for the Partnership for the twelve months ending December 31, 2011 compared to historical data for the twelve months ended September 30, 2010 and the twelve months ended December 31, 2009.

	Twelve Months Ending
					December 31, 2011
	December 31, 2009		September 30, 2010		(Estimated)
Plant natural gas inlet,MMcf/d		581.9		579.2		660.3
Gross NGL Production, MBbl/d		69.8		69.9		80.2
Operating margin, $ in millions	$	183.2	$	236.6	$	245.6

We forecast plant inlet volumes will increase by 14.0% for the twelve months ending December 31, 2011 as compared to the twelve months ended September 30, 2010 based on expected producer drilling and workover activity. New drilling is expected to come from liquids rich hydrocarbons plays including the Wolfberry Trend and Canyon Sands plays, which can be accessed by SAOU, the Wolfberry and Bone Springs plays, which can be accessed by the Sand Hills system, and the Barnett Shale and Fort Worth Basin, including Montague, Cooke, Clay and Wise counties, which can be accessed by the North Texas system.

Operating margin increased 29% from 2009 to the twelve months ended September 30, 2010 primarily as a result of higher commodity prices. Operating margin is estimated to increase by 3.8% to $245.6 million for the twelve months ending December 31, 2011 as compared to $236.6 million for the twelve months ended September 30, 2010 due to increases in plant inlet volumes partially offset by increased operating expenses and lower NGL prices.

Coastal Gathering and Processing Segment Assumptions.  The following table summarizes selected operating and financial data for the Partnership for the twelve months ending December 31,

2011 compared to historical data for the twelve months ended September 30, 2010 and the twelve months ended December 31, 2009.

	Twelve Months Ending
					December 31, 2011
	December 31, 2009		September 30, 2010		(Estimated)
Plant natural gas inlet,MMcf/d		1,557.8		1,709.3		1,810.0
Gross NGL Production, MBbl/d		48.5		51.2		58.2
Operating margin, $ in millions	$	89.7	$	111.6	$	102.0

Plant inlet volumes increased by 10% for the twelve months ended September 30, 2010 as compared to full year 2009 as a result of the recovery from the impacts of hurricanes in 2008. Plant inlet volumes are forecasted to increase 6% for the twelve months ending December 31, 2011 as compared to the twelve months ended September 30, 2010 based on the addition of new supply to our VESCO system primarily from anticipated additional production from existing customers.

Operating margin is estimated to be $102.0 million for the twelve months ending December 31, 2011 as compared to $111.6 million for the twelve months ended September 30, 2010. The decrease in operating margin is primarily attributable to lower margins resulting from lower forecasted liquids prices and higher forecasted natural gas prices and leaner inlet gas partially offset by forecasted increases in VESCO volumes.

NGL Logistics and Marketing.  The Partnership’s NGL Logistics and Marketing segment includes all the activities necessary to fractionate mixed NGLs into finished NGL products—ethane, propane, normal butane, isobutane and natural gasoline—and provides certain value added services, such as the storage, terminalling, transportation, distribution and marketing of NGLs. The assets in this segment are generally connected indirectly to and supplied, in part, by the Partnership’s gathering and processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana. The Logistics Assets segment uses its platform of integrated assets to store, fractionate, treat and transport NGLs, typically under fee-based and margin-based arrangements. The Marketing and Distribution segment covers all activities required to distribute and market mixed NGLs and NGL products. It includes (1) marketing and purchasing NGLs in selected United States markets, (2) marketing and supplying NGLs for refinery customers, and (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users.

Logistics Assets Segment Assumptions.  The following table summarizes selected operating and financial data for the Partnership for the twelve months ending December 31, 2011 compared to pro forma historical data for the twelve months ended September 30, 2010 and the twelve months ended December 31, 2009.

	Twelve Months Ending
					December 31, 2011
	December 31, 2009		September 30, 2010		(Estimated)
Fractionation volumes, MBbl/d		217.2		221.4		291.6
Treating volumes, MBbl/d		21.9		21.4		27.5
Operating margin, $ in millions	$	74.4	$	79.8	$	118.6

Fractionation and treating volumes for 2011 are forecasted to increase approximately 31% relative to the twelve months ended September 30, 2010 primarily due to the 78 MBbl/d CBF expansion, which is expected to be in-service in the second quarter of 2011, and to the Mt. Belvieu Benzene treater, which is expected to be in-service in the fourth quarter of 2011.

Operating margin is estimated to increase approximately 49% to $118.6 million for 2011 as compared to $79.8 million for the twelve months ended September 30, 2010. This estimated increase is due to the higher fractionation and treating volumes; renewal of existing contracts at higher rates; the incremental price impact of the new contracts for the CBF expansion and the partial year impact of the Benzene treater described under “Business of Targa Resources Partners LP—Partnership Growth Drivers.”

Marketing and Distribution Segment Assumptions.  The following table summarizes selected operating and financial data for the Partnership for the twelve months ending December 31, 2011 compared to historical data for the twelve months ended September 30, 2010 and the twelve months ended December 31, 2009.

	Twelve Months Ending
					December 31, 2011
	December 31, 2009		September 30, 2010		(Estimated)
NGL Sales, MBbl/d		276.1		246.1		254.9
Operating margin, $ in millions	$	82.9	$	78.1	$	65.6

The decline in volumes from the year ended December 31, 2009 to the twelve months ended September 30, 2010 was the result of a contract renegotiation which resulted in lower volumes but higher per barrel margins. We expect volumes in 2011 to increase slightly over volumes for the twelve months ended September 30, 2010 primarily due to some refinery outages in 2010 that reduced our supply of NGLs.

Operating margin is estimated to be $65.6 million for the twelve months ending December 31, 2011 which represents a $12.5 million decline from the twelve months ended September 30, 2010. The decrease is primarily due to lower expected margins on the sales of inventories. The Marketing and Distribution segment benefitted from a generally rising pricing environment that produced gains from sales of inventory over the twelve month periods ended September 30, 2010 and December 31, 2009.

Other.  Other primarily reflects our hedge settlements which are the cash receipts or payments due to market prices settling above or below the prices of our hedging instruments. Contribution to operating margin from other decreased from $46.2 million for the twelve months ended December 31, 2009 to $16.7 million for the twelve months ended September 30, 2010 and is estimated to decrease further to $12.5 million for the twelve months ending December 31, 2011. The decrease from 2009 through the forecast period is primarily due to a trend of lower hedged volumes and higher commodity prices which result in lower cash settlements.

Other Assumptions

•  Depreciation and Amortization Expenses.  The Partnership’s depreciation and amortization expenses are estimated to be $175.4 million for the twelve months ending December 31, 2011, as compared to $170.1 million for the twelve months ended September 30, 2010. Depreciation and amortization is expected to increase as a result of the Partnership’s organic growth projects and maintenance capital expenditures.

•  General and Administrative Expenses.  The Partnership’s general and administrative expenses include its public company expenses and are estimated to be $110.3 million for the twelve months ending December 31, 2011, as compared to $116.6 million for the twelve months ended September 30, 2010. General and administrative expenses are expected to decrease as a result of lower estimated compensation expense and decreased professional services associated with 2010 transactions.

•  Interest Expense.  The Partnership’s interest expense is estimated to be $110.3 million for the twelve months ending December 31, 2011. This amount includes (i) $63.0 million of interest expense related to the $690 million of senior unsecured notes with a weighted average interest rate of approximately 9.1%, (ii) $39.0 million of interest expense, after giving effect to the impact of interest rate hedges, under the Partnership’s revolving credit facility, at an assumed interest rate of approximately 3.8% (based on a 1% LIBOR plus a spread of 2.75%) and (iii) $8.3 million of commitment fees, amortization of debt issuance costs and letter of credit fees. Pro forma as adjusted for the Versado acquisition, the VESCO acquisition and the Partnership’s debt and equity offerings in August 2010, the Partnership’s revolving credit facility had a balance of $753.3 million on September 30, 2010. The balance is estimated to be $778.3 million at December 31, 2010 with the increase attributable to expansion capital expenditures. During the twelve month period ending December 31, 2011, we estimate that the Partnership will borrow $129.0 million to fund

growth capital expenditures. After giving effect to LIBOR swaps for $300 million of the Partnership’s revolving credit facility, a 1.0% change in LIBOR would result in a change in interest for the forecast period of $5.4 million.

•  Equity in Earnings of Unconsolidated Investment.  The Partnership’s equity in earnings of unconsolidated investment is estimated to be $11.5 million for the twelve months ending December 31, 2011, compared to $5.6 million for the twelve months ended September 30, 2010. The Partnership’s equity in earnings of unconsolidated investment is related to its investment in GCF, and the increase is attributable to price increases for fractionation services.

•  Noncontrolling Interest Adjustment.  Net income attributable to noncontrolling interest is estimated to be $31.2 million for the twelve months ending December 31, 2011, compared to $25.5 million for the twelve months ended September 30, 2010. Net income attributable to noncontrolling interest is associated with minority ownership stakes in Versado, VESCO and CBF. In the reconciliation of Partnership net income to Partnership Adjusted EBITDA, the non-controlling interest adjustment reflects depreciation expense attributable to the minority ownership stake.

•  Expansion Capital Expenditures, net and investments.  The Partnership’s forecasted expansion capital expenditures for the twelve months ending December 31, 2011 are estimated to be approximately $129.0 million net of minority partnership share and primarily consist of the benzene treating project, the expansions of CBF and GCF and various gathering and processing system expansions. See “Business of Targa Resources Partners LP—Partnership Growth Drivers.” These forecasted capital expenditures are expected to be funded from borrowings under its revolving credit facility.

•  Maintenance Capital Expenditures, net.  The Partnership’s maintenance capital expenditures for the twelve months ending December 31, 2011 are estimated to be approximately $49.7 million, net of minority interest share, compared to $40.4 million on a pro forma basis for the twelve months ended September 30, 2010. These capital expenditures are expected to fund the development of additional gathering and processing capacity in areas in which producers have increased drilling activity. The estimated amount excludes approximately $8 million of capital expenditures associated with the Versado System that will be reimbursed to the Partnership by us. See “—Assumptions for Targa Resources Corp.—Capital Expenditure Reimbursement to the Partnership.”

•  Compliance with Debt Agreements.  We expect that we and the Partnership will remain in compliance with the financial covenants in our respective financing arrangements.

•  Regulatory and Other.  We have assumed that there will not be any new federal, state or local regulation of portions of the energy industry in which we and the Partnership operate, or a new interpretation of existing regulation, that will be materially adverse to our or the Partnership’s business and market, regulatory, insurance and overall economic conditions will not change substantially.

Assumptions for Targa Resources Corp.

•  Financing and Interest Expense.  We assume that our Holdco loan will have an average balance of approximately $85.0 million during 2011. Pursuant to the terms of such loan, we pay interest either in cash or in kind (PIK). We have assumed the cash pay option of LIBOR plus a margin of 3%.

•  Interest Income.  We estimate that we will invest in a combination of cash and equivalents, treasuries and liquid, investment grade securities until which time the cash is necessary to satisfy these obligations. For the twelve months ending December 31, 2011 we estimate such investments will earn an average return of 2%.

•  Cash Taxes.  We estimate that we will pay approximately $14.3 million in taxes for the twelve months ending December 31, 2011. This amount consists of $16.9 million from tax liabilities, which resulted from deferred gains for previous drop down transactions, partially offset by taxable losses that reduce taxes by $2.6 million. The $14.3 million of cash taxes due will be funded from our cash reserve, discussed further below.

•  Capital Expenditure Reimbursement to the Partnership.  In connection with the sale of our interests in Versado to the Partnership, we have agreed to reimburse the Partnership for an estimated $19 million of capital expenditures which are expected to be paid by the end of 2011 from our cash reserve, discussed further below.

•  Cash Reserve.  We estimate that at the closing of this offering we will have approximately $151.8 million of cash which will be sufficient to pay current payables as well as a $19 million capital expenditure reimbursement to be paid to the Partnership by the end of 2011 and $88 million of cash taxes which resulted from deferred gains from previous drop down transactions and which will be paid over the next ten years. We expect this cash balance, interest income earned on this balance over time, and any retained cash resulting from reserves established by our board of directors will be sufficient to satisfy these obligations.

TRC Minimum Estimated Cash Available for Distribution for the Three Month Period Ending December 31, 2010

Set forth below is a forecast of the “TRC Minimum Estimated Cash Available for Distribution” that supports our belief that we expect to generate sufficient cash flow to pay a quarterly dividend of $0.2575 per common share on all of our outstanding common shares for the three months ending December 31, 2010. We expect to pay a prorated dividend for the portion of the fourth quarter of 2010 that we are public. We believe our actual results of operations and cash flows for the three months ending December 31, 2010 will be sufficient to generate our minimum estimated cash available for distribution for such period; however, we can give you no assurance that such minimum estimated cash available for distribution will be achieved. There will likely be differences between our minimum estimated cash available for distribution for the three months ending December 31, 2010 and our actual results for such period and those differences could be material. If we fail to generate the minimum estimated cash available for distribution for the three months ending December 31, 2010, we may not be able to pay a prorated cash dividend on our common shares at the initial dividend rate stated in our cash dividend policy for such period.

This forward-looking financial information included in this prospectus has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has neither examined, compiled nor performed any procedures with respect to the accompanying forward-looking financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP reports included in this prospectus relate to our historical financial information. Such reports do not extend to this forward-looking financial information of the Partnership or us and should not be read to do so. Please see “TRC Minimum Estimated Cash Available for Distribution for the Twelve Month Period Ending December 31, 2011”

above for cautionary statements and a discussion of risks and uncertainties relating to the three month forecast set forth below.

TRC Minimum Estimated Cash Available for Distribution for the Three Month Period Ending December 31, 2010

	Three Months Ending
	December 31, 2010
	(In millions, except for
	share amounts)
Targa Resources Partners LP Data
Revenues	$	1,532.6
Less: Product purchases		(1,320.6	)
Gross margin(1)		212.0
Less: Operating expenses		(70.5	)
Operating margin(2)		141.5
Less:
Depreciation and amortization expenses		(43.3	)
General and administrative expenses		(32.6	)
Income from operations		65.6
Plus (less): other income (expense)
Interest expense, net		(25.7	)
Equity in earnings of unconsolidated investment		1.6
Income before income tax		41.5
Less: income tax expense		(1.3	)
Net income		40.2
Less: net income attributable to noncontrolling interest(3)		(6.5	)
Net income attributable to Targa Resources Partners LP	$	33.7
Plus:
Interest expense, net		25.7
Income tax expense		1.3
Depreciation and amortization expenses		43.3
Noncash loss related to derivative instruments		7.4
Noncontrolling interest adjustment		(2.7	)
Estimated Adjusted EBITDA(4)	$	108.7
Less:
Interest expense, net		(25.7	)
Expansion capital expenditures, net		(41.2	)
Borrowings for expansion capital expenditures		41.2
Maintenance capital expenditures, net		(20.0	)
Amortization of debt issue costs		1.5
Cash reserve(5)		(16.8	)
Estimated minimum cash available for distribution(6)	$	47.7
Partnership’s debt covenant ratios(7)
Interest coverage ratio of not less than 2.25 to 1.0		3.5	x
Consolidated leverage ratio of not greater than 5.5 to 1.0		3.8	x
Consolidated senior leverage ratio of not greater than 4.0 to 1.0		2.1	x

	Three Months Ending
	December 31, 2010
	(In millions, except for
	share amounts)
Estimated minimum cash available for distribution to Partnership unitholders
Estimated minimum cash distributions to us:
2% general partner interest	$	1.0
Incentive distribution rights(8)		5.3
Common units		6.4
Total estimated minimum cash distributions to us		12.7
Estimated minimum cash distributions to public unitholders		35.0
Total estimated minimum cash distributions by the Partnership	$	47.7

	Three Months Ending
	December 31, 2010
	(In millions, except for
	share amounts)
Targa Resources Corp. Data(9)(10)
Estimated minimum cash distributions to be received from the Partnership	$	12.7
Corporate general and administrative expenses		(1.4	)
Partnership distributions less general and administrative expenses		11.3
Plus / (Less):
Interest Expense		(0.8	)
Interest Income		0.4
Cash taxes paid		(3.2	)
Cash taxes funded from cash on hand		3.2
Minimum cash available for distribution		10.9
Expected dividend per share — Quarterly(11)	$	0.2575
Total dividends paid to stockholders (before proration)(11)	$	10.9

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

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

3. Reflects net income attributable to Chevron’s 37% interest in Versado, Enterprise’s 12% interest in VESCO, ONEOK’s 11% interest in VESCO and BP’s 12% interest in CBF.

4. Adjusted EBITDA is presented because we believe it provides additional information with respect to both the performance of our fundamental business activities as well as our ability to meet future debt service, capital expenditures and working capital requirements. It is a non-GAAP financial measure and is not intended to be used in lieu of the GAAP presentation of net income.

5. Represents a discretionary cash reserve. See “— The Partnership’s Cash Distribution Policy.”

6. The Partnership’s estimated minimum cash available for distribution is presented because we believe it is used by investors to evaluate the ability of the Partnership to make quarterly cash distributions. It is a non-GAAP financial measure and is not intended to be used in lieu of the GAAP presentation of net income.

7. The Partnership’s credit agreement and indentures contain certain financial covenants. The Partnership’s revolving credit facility requires that, at the end of each fiscal quarter, the Partnership must maintain:

•  an interest coverage ratio, defined as the ratio of the Partnership’s consolidated adjusted EBITDA (as defined in the Amended and Restated Credit Agreement) for the four consecutive fiscal quarters most recently ended to the consolidated interest expense (as defined in the Amended and Restated Credit Agreement) for such period, of no less than 2.25 to 1.0;

•  a Consolidated Leverage Ratio, defined as the ratio of the Partnership’s consolidated funded indebtedness (as defined in the Amended and Restated Credit Agreement) to consolidated adjusted EBITDA, for the four fiscal quarters most recently ended, that is not greater than 5.5 to 1.0; and

•  a Consolidated Senior Leverage ratio, defined as the ratio of the Partnership’s consolidated funded indebtedness, excluding unsecured note indebtedness, to consolidated adjusted EBITDA, for the four fiscal quarters most recently ended, that is not greater than 4.0 to 1.0.

In addition, the indentures relating to the Partnership’s existing senior notes require that the Partnership have a fixed charge coverage ratio for the most recently ended four fiscal quarters of not less than 1.75 to 1.0 in order to make distributions, subject to certain exceptions. This ratio is approximately equal to the interest coverage ratio described above. As indicated by the table, we estimate that the Partnership’s pro forma EBITDA would be sufficient to permit cash distributions, under the terms of its credit agreement and indentures.

8. Based on the Partnership’s 75,545,409 outstanding common units as of November 1, 2010 and the Partnership’s fourth quarter 2010 quarterly distribution of $0.5475 per unit, or $2.19 per unit on an annualized basis, that management plans to recommend to the General Partner’s board of directors.

9. We expect that we will have no debt outstanding under TRI’s revolving credit facility, and accordingly, we have not presented credit ratios for this facility in the table. Pursuant to the terms of this facility at the end of each fiscal quarter, TRI must maintain:

•  an interest coverage ratio, defined as the ratio of our consolidated adjusted EBITDA (as defined in the revolving credit agreement) for the four consecutive fiscal quarters most recently ended to the consolidated interest expense (as defined in the revolving credit agreement) for such period, of no less than 1.5 to 1.0;

•  a Consolidated Leverage Ratio, defined as the ratio of our consolidated funded indebtedness (as defined in the revolving credit agreement) to consolidated adjusted EBITDA, for the four fiscal quarters most recently ended, that is not greater than 5.75 to 1.0 and becomes more restrictive over time.

10. The Holdco Loan agreement has no restrictive covenants which would impact our ability to pay dividends.

11. We expect to pay a prorated divided for the portion of the fourth quarter of 2010 that we are public. We estimate that we will have sufficient cash available to pay the full amount of the dividend and, therefore, any prorated portion thereof.

Assumptions and Considerations

We estimate that our ownership interests in the Partnership will generate sufficient cash flow to enable us to pay our initial quarterly dividend of $0.2575 per share, which will be prorated for the post-offering period, on all of our shares for the quarter ending December 31, 2010. Our ability to make this dividend payment assumes that the Partnership will pay its quarterly distribution of $0.5475 per common unit that management plans to recommend to the General Partner’s board of directors for the fourth quarter ending December 31, 2010, which means that the total amount of cash distributions we will receive from the Partnership for that period would be $12.7 million.

The primary determinant in the Partnership’s ability to pay a distribution of $0.5475 per common unit for the fourth quarter ending December 31, 2010, after giving effect to a $16.8 million cash reserve, is its ability to generate Adjusted EBITDA of at least $108.7 million during the period, which in turn is dependent on its ability to generate operating margin of $141.5 million.

The estimates of the Adjusted EBITDA and operating margin to be generated by the Partnership for the fourth quarter ending December 31, 2010 assumes the following volume and commodity price information:

	Three Months Ended
	December 31, 2010
	(Estimated)
Field Plant Natural Gas Inlet,MMcf/d		596.7
Coastal Plant Natural Gas Inlet,MMcf/d		1,633.6
Logistics Fractionation, MBbl/d		250.1

	Three Months Ended
	December 31, 2010
	(Estimated)
Natural Gas	$	3.67/MMBtu
Ethane	$	0.64/gallon
Propane	$	1.26/gallon
Isobutane	$	1.61/gallon
Normal Butane	$	1.57/gallon
Natural Gasoline	$	1.96/gallon
Crude Oil	$	80.34/Bbl

Other Assumptions

Volume assumptions.  Field Gathering and Processing volumes reflect the impact of continued growth from increased drilling activity. Coastal Gathering and Processing daily volumes decline slightly as compared to the twelve months ended September 30, 2010 due primarily to temporary pipeline interruptions. Fractionation volumes reflect the stable demand for fractionating services. The volumes for each of these segments is set forth in the table above.

Commodity price assumptions.  Commodity prices are based on actual prices for October 2010 and market prices as of November 4, 2010 for the remainder of the quarter.

General and Administrative Expenses.  The Partnership’s general and administrative expenses include its public company expenses and are estimated to be $32.6 million for the three months ending December 31, 2010. The general and administrative expense for the three months ending December 31, 2010 is higher than the quarterly average for the twelve months ended September 30, 2010 due to increased compensation costs and drop down transaction costs.

Interest Expense.  The Partnership’s interest expense is estimated to be $25.7 million for the three months ending December 31, 2010. This amount is based on the Partnership’s outstanding senior unsecured notes and September 30, 2010 balance on the Partnership’s revolving credit facility and gives effect to expansion capital expenditures funded during the three months ending December 31, 2010.

Expansion Capital Expenditures, net.  The Partnership’s forecasted expansion capital expenditures for the three months ending December 31, 2010 are estimated to be approximately $41.2 million, net of minority partnership share, and primarily consist of expenditures on previously announced expansion projects.

Maintenance Capital Expenditures, net.  The Partnership’s maintenance capital expenditures for the three months ending December 31, 2010 are estimated to be approximately $20.0 million, net of minority interest share. These capital expenditures are expected to fund the development of additional gathering and processing capacity in areas in which producers have increased drilling activity.

TRC Assumptions

General and Administrative Expense.  We have assumed one quarter of the $5.4 million of the general and administrative expense estimated for the twelve months ending December 31, 2011.

Interest Expense.  We assume that our Holdco loan will have an average balance of approximately $85 million for the three months ending December 31, 2010. Pursuant to the terms of such loan, we can pay interest either in cash or in kind (PIK). We have assumed the cash pay option of LIBOR plus a margin of 3%.

Interest Income.  We estimate that we will invest in a combination of cash and cash equivalents, treasuries and liquid, investment grade securities. For the three months ending December 31, 2010 we estimate such investments will earn an average return of 2%.

Cash Taxes.  We estimate that we will pay approximately $3.2 million in taxes for the three months ending December 31, 2010. This amount consists of $3.7 million of tax liabilities, resulting from deferred gains for previous drop down transactions, partially offset by taxable losses that reduce taxes by $0.5 million. The $3.2 million of cash taxes due will be funded from our cash reserve.

Cash Reserve.  We estimate that at the closing of this offering we will have approximately $151.8 million of cash on hand which will be sufficient to pay $3.2 million of taxes for the three months ending December 31, 2010.

     The information furnished pursuant to this Item 7.01 shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.

SIGNATURES

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

	TARGA RESOURCES PARTNERS LP
	By:	Targa Resources GP LLC,
		its general partner
Dated: November 17, 2010	By:	/s/ John Robert Sparger
		John Robert Sparger
		Senior Vice President and Chief Accounting Officer