As filed with the Securities and Exchange Commission on February 1, 2007

Registration No. 333-138747

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

Amendment No. 4

to

 

Form S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

 

 

 

 

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

 

 

 

 

1000 Louisiana, Suite 4300

Houston, Texas 77002

(713) 584-1000

(Address, including zip code and telephone number, including area code, of registrant’s principal executive offices)

 

Rene R. Joyce

Chief Executive Officer

1000 Louisiana, Suite 4300

Houston, Texas 77002

(713) 584-1000

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

 

 

Copies to:

 

 

 

Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.

 

 

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  o

 

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

 

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

 

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

Subject to Completion, dated February 1, 2007

PROSPECTUS

 

TARGA RESOURCES PARTNERS LP

 

16,800,000 Common Units

Representing Limited Partner Interests

 

Targa Resources Partners LP is a limited partnership recently formed by Targa Resources, Inc. This is the initial public offering of our common units. All of the common units are being sold by us. Prior to this offering, there has been no public market for our common units. We expect the initial public offering price to be between $19.00 and $21.00 per unit. Our common units have been approved for listing on The NASDAQ Global Market under the symbol “NGLS.”

 

Investing in our common units involves risks. Please see “Risk Factors” beginning on page 17.

 

These risks include the following:

 

 

 

 

 

 

We have granted the underwriters a 30-day option to purchase up to an additional 2,520,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 16,800,000 common units in this offering.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

 

The underwriters expect to deliver the common units through the facilities of The Depository Trust Company on or about          , 2007.

 

 

 

          , 2007

TABLE OF CONTENTS

 

          

 

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

 

Until          , 2007 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

 

SUMMARY

 

Targa Resources Partners LP

 

Non-GAAP Financial Measures

	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure;
	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

		Predecessor Business																									Targa Resources Partners LP
		Dynegy																	Targa								Pro Forma
										Nine Months				Ten Months					Two Months				Nine Months								Nine Months
		Years Ended								Ended				Ended					Ended				Ended				Year Ended				Ended
		December 31,								September 30,				October 31,					December 31,				September 30,				December 31,				September 30,
		2003				2004				2005				2005					2005				2006				2005				2006
		(Audited)				(Audited)				(Unaudited)				(Audited)					(Audited)				(Unaudited)				(Unaudited)				(Unaudited)
		(in millions of dollars)
Reconciliation of “EBITDA” to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities		$	31.3			$	58.0			$	59.2			$	72.7				$	(1.5	)		$	11.1
Allocated interest expense from parent(1)			—				—				—				—					10.7				50.5
Changes in operating working capital which provided (used) cash:
Accounts receivable			0.7				(0.7	)			0.5				0.3					0.1				(0.4	)
Accounts payable			(1.0	)			(2.7	)			1.1				1.3					0.8				—
Other, including changes in noncurrent assets and liabilities			(4.9	)			(3.8	)			(12.6	)			(17.1	)				5.5				1.5
EBITDA		$	26.1			$	50.8			$	48.2			$	57.2				$	15.6			$	62.7
Reconciliation of “EBITDA” to net income:
Net income (loss)		$	14.1			$	38.6			$	38.1			$	45.9				$	(5.1	)		$	(35.4	)		$	(6.8	)		$	0.4
Add:
Interest expense, net			—				—				—				—					11.5				54.4				24.8				18.6
Deferred tax expense			—				—				—				—					—				2.0				—				2.0
Depreciation and amortization expense			12.0				12.2				10.1				11.3					9.2				41.7				54.8				41.7
EBITDA		$	26.1			$	50.8			$	48.2			$	57.2				$	15.6			$	62.7			$	72.8			$	62.7
Reconciliation of “operating margin” to net income:
Net income (loss)		$	14.1			$	38.6			$	38.1			$	45.9				$	(5.1	)		$	(35.4	)		$	(6.8	)		$	0.4
Add:
Depreciation and amortization expense			12.0				12.2				10.1				11.3					9.2				41.7				54.8				41.7
Deferred income tax			—				—				—				—					—				2.0				—				2.0
Other, net			0.6				0.3				—				—					—				—				—				—
Interest expense, net			—				—				—				—					11.5				54.4				24.8				18.6
General and administrative expense			7.7				7.2				6.7				7.3					1.1				5.1				8.4				5.1
Operating margin		$	34.4			$	58.3			$	54.9			$	64.5				$	16.7			$	67.8			$	81.2			$	67.8

(1)	Excludes non-cash amortization of debt issue costs of $0.8 million for the two months ended December 31, 2005 and $3.9 million for the nine months ended September 30, 2006.

 

Our Relationship with Targa Resources, Inc.

 

Our Relationship with Warburg Pincus LLC

 

Summary of Risk Factors

	•	We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.
	•	On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2005 or for the twelve months ended September 30, 2006.

	•	Our cash flow is affected by natural gas and NGL prices, and decreases in these prices could adversely affect our ability to make distributions to holders of our common units and subordinated units.
	•	Because of the natural decline in production from existing wells in our operating regions, our success depends on our ability to obtain new sources of supplies of natural gas and NGLs, which depends on certain factors beyond our control. Any decrease in supplies of natural gas or NGLs could adversely affect our business and operating results.
	•	Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. In addition, the significant contribution to our results of operations that we are currently receiving from our hedge positions will decrease substantially through 2010.

	•	Targa controls our general partner, which has sole responsibility for conducting our business and managing our operations. Targa has conflicts of interest with us and may favor its own interests to your detriment.
	•	The credit and business risk profile of our general partner and its owners could adversely affect our credit ratings and profile.

	•	Our partnership agreement limits our general partner’s fiduciary duties to holders of our units and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

	•	Targa is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.

	•	Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.
	•	If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the cost of any contest will reduce our cash available for distribution to you.
	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

 

Formation Transactions and Partnership Structure

 

General

	•	Targa will contribute the North Texas System to us;
	•	we will issue to Targa 11,528,231 subordinated units, representing a 39.9% limited partner interest in us;
	•	we will issue to our general partner, Targa Resources GP LLC, 578,127 general partner units representing its initial 2% general partner interest in us, and all of our incentive distribution rights,

		which incentive distribution rights will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.3881 per unit per quarter;

	•	we will issue 16,800,000 common units to the public in this offering, representing a 58.1% limited partner interest in us, and will use the proceeds to pay expenses associated with this offering, the Formation Transactions and our new credit facility and to pay approximately $307.1 million to Targa to retire a portion of our affiliate indebtedness;

	•	we will borrow approximately $342.5 million under our new $500 million credit facility, the proceeds of which will be paid to Targa to retire an additional portion of our affiliate indebtedness;
	•	the remaining affiliate indebtedness will be retired and treated as a capital contribution to us;
	•	we will enter into an omnibus agreement with Targa and our general partner, which will address, among other things, the provision of and the reimbursement for general and administrative and operating services;
	•	we will enter into a natural gas purchase agreement, pursuant to which we will sell all of our residue natural gas to Targa at market-based prices for a term of 15 years; and
	•	we will enter into NGL and condensate purchase agreements, pursuant to which we will sell all of our NGLs and high-pressure condensate to Targa at market-based prices for a term of 15 years.

 

Management of Targa Resources Partners LP

 

Simplified Organizational Structure and Ownership of Targa Resources Partners LP
after the Formation Transactions

Public Common Units			58.1	%
Targa Subordinated Units			39.9	%
General Partner Units			2.0	%
Total			100.0	%

(1)		Ownership percentages are presented on a fully-diluted basis.
(2)		Targa Resources, Inc. is an indirect wholly-owned subsidiary of Targa Resources Investments Inc. Warburg Pincus LLC controls us through its ownership of securities in Targa Resources Investments Inc. and a stockholders agreement among Targa Resources Investments Inc. and its owners.

Principal Executive Offices and Internet Address

 

Summary of Conflicts of Interest and Fiduciary Duties

 

The Offering

Common units offered to the public		16,800,000 common units or 19,320,000 common units if the underwriters exercise in full their option to purchase additional common units.
Units outstanding after this offering		16,800,000 common units and 11,528,231 subordinated units, representing 58.1% and 39.9% limited partner interests in us (19,320,000 common units and 11,528,231 subordinated units, representing 61.4% and 36.6% limited partner interests in us if the underwriters exercise in full their option to purchase additional common units). The general partner will own 578,127 general partner units, or 629,555 general partner units if the underwriters exercise in full their option to purchase additional common units, in each case representing a 2% general partner interest in us.
Use of proceeds		We intend to use the net proceeds of approximately $315.3 million from this offering (at an assumed offering price of $20.00 per common unit), after deducting underwriting discounts and deducting a structuring fee of approximately $1.3 million but before paying offering expenses, to:
		• pay approximately $4.0 million in expenses associated with this offering and the Formation Transactions;

		• pay approximately $4.2 million in fees and expenses related to our new credit facility; and

		• use the remaining proceeds to pay approximately $307.1 million to Targa to retire a portion of our affiliate indebtedness.

		We also expect to borrow approximately $342.5 million under our new credit facility upon the closing of this offering and to pay that amount to Targa to retire an additional portion of our affiliate indebtedness. The remaining balance of our affiliate indebtedness will be retired and treated as a capital contribution to us. Please see “Certain Relationships and Related Party Transactions — Distributions and Payments to our General Partner and its Affiliates.”
		We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to reduce outstanding borrowings under our new credit facility.
Cash distributions		We will make an initial quarterly distribution of $0.3375 per common unit ($1.35 per common unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Our ability to pay cash distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”
		Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement. Our

		partnership agreement also requires that we distribute all of our available cash from operating surplus each quarter during the subordination period in the following manner:
		• first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.3375 plus any arrearages from prior quarters;
		• second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.3375; and
		• third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received an aggregate distribution of $0.3881.
		If cash distributions to our unitholders exceed $0.3881 per common unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 48%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please see “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

		We will adjust the quarterly distribution for the period from the closing of this offering through March 31, 2007 based on the actual length of the period. We expect to pay this cash distribution on or about May 15, 2007.

		The amount of our pro forma available cash generated during the year ended December 31, 2005 and the twelve months ended September 30, 2006 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units but only approximately 29% and 98%, respectively, of the minimum quarterly distribution on our subordinated units during these periods (28% and 97%, respectively, assuming the underwriters exercise in full their option to purchase additional common units). For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2006, please see “Our Cash Distribution Policy and Restrictions on Distributions.”
		We believe that, based on the minimum estimated EBITDA for the twelve months ending December 31, 2007 included under the caption “Our Cash Distribution Policy and Restrictions on Distributions,” we will have sufficient cash available for distribution to make cash distributions for the four quarters ending December 31, 2007 at the initial quarterly distribution rate of $0.3375 per unit on all common units, subordinated units and general partner units.
Subordinated units		Targa will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.3375 per unit only after the common units have received the minimum quarterly distribution plus any

		arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. The subordination period generally will end if we have earned and paid at least $0.3375 on each outstanding unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2009. The subordination period will also end if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal.
		When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.
Early conversion of subordinated units		If we have earned and paid at least $2.025 (150% of the annualized minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for any four-quarter period, the subordination period will terminate automatically and all of the subordinated units will convert into an equal number of common units. Please see “Provisions of Our Partnership Agreement Related to Cash Distributions — Subordination Period.”
General Partner’s right to reset the target distribution levels		Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution amount as in our current target distribution levels.
		In connection with resetting these target distribution levels, our general partner will be entitled to receive Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. For a more detailed description of our general partner’s right to reset the target distribution levels upon which the incentive distribution payments are based and the concurrent right of our general partner to receive Class B units in connection with this reset, please see “Provisions of Our

		Partnership Agreement Related to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”
Issuance of additional units		We can issue an unlimited number of units without the consent of our unitholders. Please see “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”
Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of 40.7% of our common and subordinated units. This will give our general partner the ability to prevent its involuntary removal. Please see “The Partnership Agreement — Voting Rights.”
Limited call right		If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units.

Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.35 per unit, we estimate that your average allocable federal taxable income per year will be no more than $0.27 per unit. Please see “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions.”

Material tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please see “Material Tax Consequences.”

Exchange listing		Our common units have been approved for listing on The NASDAQ Global Market under the symbol “NGLS.”

 

Summary Historical and Pro Forma Financial and Operating Data

	•	we will issue to Targa 11,528,231 subordinated units, representing a 39.9% limited partner interest in us;
	•	we will issue to our general partner, Targa Resources GP LLC, 578,127 general partner units representing its initial 2% general partner interest in us, and all of our incentive distribution rights, which incentive distribution rights will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.3881 per unit per quarter;

	•	we will issue 16,800,000 common units to the public in this offering, representing a 58.1% limited partner interest in us, and will use the proceeds to pay expenses associated with this offering, the Formation Transactions and our new credit facility and to pay approximately $307.1 million to Targa to retire a portion of our affiliate indebtedness;

	•	we will borrow approximately $342.5 million under our new $500 million credit facility the proceeds of which will be paid to Targa to retire an additional portion of our affiliate indebtedness; and
	•	the remaining affiliate indebtedness will be retired and treated as a capital contribution to us.

		Predecessor Business																									Targa Resources Partners LP
		Dynegy																	Targa								Pro Forma
										Nine Months				Ten Months					Two Months				Nine Months								Nine Months
		Years Ended								Ended				Ended					Ended				Ended				Year Ended				Ended
		December 31,								September 30,				October 31,					December 31,				September 30,				December 31,				September 30,
		2003				2004				2005				2005					2005				2006				2005				2006
		(Audited)				(Audited)				(Unaudited)				(Audited)					(Audited)				(Unaudited)				(Unaudited)				(Unaudited)
		(in millions of dollars, except per unit and operating data)
Statement of Operations Data:
Total operating revenues		$	196.8			$	258.6			$	249.7			$	293.3				$	75.1			$	290.9			$	368.4			$	290.9
Product purchases			147.3				182.6				179.0				210.8					54.9				205.2				265.7				205.2
Operating expense			15.1				17.7				15.8				18.0					3.5				17.9				21.5				17.9
Depreciation and amortization expense			12.0				12.2				10.1				11.3					9.2				41.7				54.8				41.7
General and administrative expense			7.7				7.2				6.7				7.3					1.1				5.1				8.4				5.1
Interest expense, net			—				—				—				—					11.5				54.4				24.8				18.6
Deferred income tax(1)			—				—				—				—					—				2.0				—				2.0
Other, net			0.6				0.3				—				—					—				—				—				—
Net income (loss)		$	14.1			$	38.6			$	38.1			$	45.9				$	(5.1	)		$	(35.4	)		$	(6.8	)		$	0.4
Pro forma net income (loss) per limited partner unit																											$	(0.24	)		$	0.01
Financial and Operating Data:
Financial data:
Operating margin(2)		$	34.4			$	58.3			$	54.9			$	64.5				$	16.7			$	67.8			$	81.2			$	67.8
EBITDA(3)			26.1				50.8				48.2				57.2					15.6				62.7				72.8				62.7
Operating data:
Gathering throughput, MMcf/d(4)			134.3				152.0				160.4				161.2					168.8				168.2
Plant natural gas inlet, MMcf/d(5)			128.6				145.4				155.4				156.2					161.9				161.6
Gross NGL production, MBbl/d			15.9				17.2				18.4				18.5					19.8				18.8
Natural gas sales, BBtu/d			42.0				59.2				68.4				68.9					72.3				75.2
NGL sales, MBbl/d			15.3				13.2				14.2				14.3					15.4				15.1
Condensate sales, MBbl/d			0.6				0.7				0.5				0.5					0.5				0.5
Balance Sheet Data (at period end):
Property, plant, and equipment, net		$	180.4			$	191.2				195.4			$	196.4				$	1,097.0			$	1,073.0							$	1,073.0
Total assets			182.9				193.5				197.6				198.5					1,122.8				1,126.3								1,110.9
Long-term debt (including current portion)			—				—				—				—					868.9				865.2								342.5
Partners’ capital / Net parent equity			164.8				168.8				161.9				158.5					219.5				227.2								734.5
Cash Flow Data:
Net cash provided by (used in):
Operating activities		$	31.3			$	58.0			$	59.2			$	72.7				$	(1.5	)		$	11.1
Investing activities			(14.6	)			(23.4	)			(14.2	)			(16.4	)				(2.1	)			(17.7	)
Financing activities			(16.7	)			(34.6	)			(45.0	)			(56.3	)				3.6				6.6

(1)	In May 2006, Texas adopted a margin tax consisting of a 1% tax on the amount by which total revenue exceeds cost of goods sold. The amount presented represents our estimated liability for this tax.
(2)	Operating margin is total operating revenues less product purchases and operating expense. Please see “— Non-GAAP Financial Measures.”
(3)	EBITDA is net income before interest, income taxes, depreciation and amortization. Please see “— Non-GAAP Financial Measures.”
(4)	Gathering throughput represents the volume of natural gas gathered and passed through natural gas gathering pipelines from connections to producing wells and central delivery points.
(5)	Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet point of a natural gas processing plant.

 

Non-GAAP Financial Measures

	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure;
	•	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

		Predecessor Business																									Targa Resources Partners LP
		Dynegy																	Targa								Pro Forma
										Nine Months				Ten Months					Two Months				Nine Months								Nine Months
		Years Ended								Ended				Ended					Ended				Ended				Year Ended				Ended
		December 31,								September 30,				October 31,					December 31,				September 30,				December 31,				September 30,
		2003				2004				2005				2005					2005				2006				2005				2006
		(Audited)				(Audited)				(Unaudited)				(Audited)					(Audited)				(Unaudited)				(Unaudited)				(Unaudited)
		(in millions of dollars)
Reconciliation of “EBITDA” to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities		$	31.3			$	58.0			$	59.2			$	72.7				$	(1.5	)		$	11.1
Allocated interest expense from parent(1)			—				—				—				—					10.7				50.5
Changes in operating working capital which provided (used) cash:
Accounts receivable			0.7				(0.7	)			0.5				0.3					0.1				(0.4	)
Accounts payable			(1.0	)			(2.7	)			1.1				1.3					0.8				—
Other, including changes in noncurrent assets and liabilities			(4.9	)			(3.8	)			(12.6	)			(17.1	)				5.5				1.5
EBITDA		$	26.1			$	50.8			$	48.2			$	57.2				$	15.6			$	62.7
Reconciliation of “EBITDA” to net income:
Net income (loss)		$	14.1			$	38.6			$	38.1			$	45.9				$	(5.1	)		$	(35.4	)		$	(6.8	)		$	0.4
Add:
Interest expense, net			—				—				—				—					11.5				54.4				24.8				18.6
Deferred tax expense			—				—				—				—					—				2.0				—				2.0
Depreciation and amortization expense			12.0				12.2				10.1				11.3					9.2				41.7				54.8				41.7
EBITDA		$	26.1			$	50.8			$	48.2			$	57.2				$	15.6			$	62.7			$	72.8			$	62.7
Reconciliation of “operating margin” to net income:
Net income (loss)		$	14.1			$	38.6			$	38.1			$	45.9				$	(5.1	)		$	(35.4	)		$	(6.8	)		$	0.4
Add:
Depreciation and amortization expense			12.0				12.2				10.1				11.3					9.2				41.7				54.8				41.7
Deferred income tax			—				—				—				—					—				2.0				—				2.0
Other, net			0.6				0.3				—				—					—				—				—				—
Interest expense, net			—				—				—				—					11.5				54.4				24.8				18.6
General and administrative expense			7.7				7.2				6.7				7.3					1.1				5.1				8.4				5.1
Operating margin		$	34.4			$	58.3			$	54.9			$	64.5				$	16.7			$	67.8			$	81.2			$	67.8

(1)	Excludes non-cash amortization of debt issue costs of $0.8 million for the two months ended December 31, 2005 and $3.9 million for the nine months ended September 30, 2006.

 

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

 

If any of the following risks were actually to occur, then our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

 

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.

 

In order to make our cash distributions at our initial distribution rate of $0.3375 per common unit and subordinated unit per complete quarter, or $1.35 per unit per year, we will require available cash of approximately $9.8 million per quarter, or $39.0 million per year, based on the common units and subordinated units outstanding immediately after completion of this offering ($10.6 million or $42.5 million, respectively, if the underwriters exercise in full their option to purchase additional common units). We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

 

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

 

 

 

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please see “Our Cash Distribution Policy and Restrictions on Distributions.”

 

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2005 or for the twelve months ended September 30, 2006.

 

The amount of available cash we need to pay the minimum quarterly distribution for four quarters on all of our units to be outstanding immediately after this offering is approximately $39.0 million. The amount of our pro forma available cash generated during the year ended December 31, 2005 and the twelve months ended September 30, 2006 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units but only approximately 29% and 98%, respectively, of the minimum quarterly distribution on our subordinated units during these periods (28% and 97% respectively, assuming the underwriters exercise in full their option to purchase additional common units). For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2006, please see “Our Cash Distribution Policy and Restrictions on Distributions.”

 

Our cash flow is affected by natural gas and NGL prices, and decreases in these prices could adversely affect our ability to make distributions to holders of our common units and subordinated units.

 

Our operations can be affected by the level of natural gas and NGL prices and the relationship between these prices. The prices of natural gas and NGLs have been volatile and we expect this volatility to continue. The NYMEX daily settlement price for natural gas for the forward month contract in 2005 ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu. In the first nine months of 2006, NYMEX pricing ranged from a high of $10.63 per MMBtu to a low of $4.20 per MMBtu. Natural gas prices reached relatively high levels in 2005 and early 2006 but have declined substantially through the first three quarters of 2006, with the forward month gas futures contracts closing at a four-year low in September of 2006. NGL prices exhibit similar volatility. Based on monthly index prices, the average price for our NGL composition ranged from a high of $1.12 per gallon to a low $0.73 per gallon in 2005, and from a high of $1.14 per gallon to a low of $0.88 per gallon for the first nine months of 2006.

 

Our future cash flow will be materially adversely affected if we experience significant, prolonged pricing deterioration below general price levels experienced over the past few years in our industry.

 

The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

 

 

Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. For the nine month period ended September 30, 2006, our percent-of-proceeds arrangements accounted for approximately 96% of our gathered natural gas volume. Under percent-of-proceeds arrangements, we generally process natural gas from producers for an agreed percentage of the proceeds from the sale of residue gas and NGLs resulting from our processing activities, selling the resulting residue gas and NGLs at market prices. Under these types of arrangements, our revenues and our cash flows increase or decrease, whichever is applicable, as the price of natural gas, NGLs and crude oil fluctuates. For additional information regarding our hedging activities, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

 

Because of the natural decline in production from existing wells in our operating regions, our success depends on our ability to obtain new sources of supplies of natural gas and NGLs, which depends on certain factors beyond our control. Any decrease in supplies of natural gas or NGLs could adversely affect our business and operating results.

 

Our gathering systems are connected to natural gas wells, from which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas supplies. Our ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near our gathering systems.

 

We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, availability of drilling rigs and other production and development costs and the availability and cost of capital. We believe that rig availability in the Fort Worth Basin has been and will continue to be a limiting factor on the number of wells drilled in that area. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. Natural gas prices reached relatively high levels in 2005 and early 2006 but have declined substantially through the first three quarters of 2006, with gas futures contracts closing at a four-year low in September of 2006. These recent declines in natural gas prices are beginning to have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Reductions in exploration or production activity or shut-ins by producers in the areas in which we operate as a result of a sustained decline in natural gas prices would lead to reduced utilization of our gathering and processing assets.

 

Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. If, due to reductions in drilling activity or competition, we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on our pipelines and the utilization rates of our treating, processing and fractionation facilities would decline, which could reduce our revenue and impair our ability to make distributions to our unitholders.

 

Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. In addition, the significant contribution to our results of operations that we are currently receiving from our hedge positions will decrease substantially through 2010.

 

We have entered into derivative transactions related to only a portion of our equity volumes. As a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative

transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our liquidity. The derivative instruments we utilize for these hedges are based on posted market prices, which may be lower than the actual natural gas, NGL and condensate prices that we realize in our operations. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certain circumstances may actually increase the variability of our cash flows. To the extent we hedge our commodity price risk, we may forego the benefits we would otherwise experience if commodity prices were to change in our favor.

 

Our results of operations are currently realizing a significant benefit from hedge positions entered into in April and May of 2006. We estimate that our hedges will generate approximately $15 million in operating income for the twelve months ending December 31, 2007. If future prices remain comparable to current prices, we expect that this benefit will decline materially over the life of the hedges, which cover decreasing volumes at declining prices through 2010. For additional information regarding our hedging activities, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Quantitative and Qualitative Disclosures about Market Risk.”

 

The assumptions underlying the minimum estimated EBITDA we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

 

The minimum estimated EBITDA set forth in “Our Cash Distribution Policy and Restrictions on Distributions” presents our ability to make the minimum quarterly distribution for the twelve months ending December 31, 2007. Our minimum estimated EBITDA and related assumptions have been prepared by, and are the responsibility of, management and our independent auditor has neither compiled nor examined our minimum estimated EBITDA and provides no assurance nor any report on it. The assumptions underlying our minimum estimated EBITDA are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve our anticipated results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

 

We depend on one natural gas producer for a significant portion of our supply of natural gas. The loss of this customer or replacement of its contracts on less favorable terms could result in a decline in our volumes, revenues and cash available for distribution.

 

Our largest natural gas supplier for the year ended December 31, 2005 and the nine months ended September 30, 2006 was ConocoPhillips, who accounted for approximately 36% and 34%, respectively, of our supply. The loss of all or even a portion of the natural gas volumes supplied by this customer or the extension or replacement of these contracts on less favorable terms, if at all, as a result of competition or otherwise, could reduce our revenue or increase our cost for product purchases, impairing our ability to make distributions to our unitholders.

 

If third-party pipelines and other facilities interconnected to our natural gas pipelines and facilities become partially or fully unavailable to transport natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.

 

We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities become partially or fully unavailable to transport natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.

We depend on our Chico system for a substantial majority of our revenues and if those revenues were reduced, there would be a material adverse effect on our results of operations and ability to make distributions to unitholders.

 

Any significant curtailment of gathering, compressing, treating, processing or fractionation of natural gas on our Chico system could result in our realizing materially lower levels of revenues and cash flow for the duration of such curtailment. For the nine months ended September 30, 2006, our Chico plant inlet volume accounted for over 90% of our revenues. Operations at our Chico system could be partially curtailed or completely shut down, temporarily or permanently, as a result of:

 

 

The magnitude of the effect on us of any curtailment of operations will depend on the length of the curtailment and the extent of the operations affected by such curtailment. We have no control over many of the factors that may lead to a curtailment of operations.

 

In addition, our business interruption insurance is subject to limitations and deductions. If a significant accident or event occurs at our Chico system that is not fully insured, it could adversely affect our operations and financial condition.

 

We are exposed to the credit risk of Targa and any material nonperformance by Targa could reduce our ability to make distributions to our unitholders.

 

At the closing of this offering, we will enter into purchase agreements with Targa pursuant to which Targa will purchase all of our natural gas, NGLs and high-pressure condensate for a term of 15 years. We will also enter into an omnibus agreement with Targa which will address, among other things, the provision of general and administrative and operating services to us. As of January 31, 2007, Moody’s and Standard & Poor’s assigned Targa corporate credit ratings of B1 and B+, respectively, which are speculative ratings. These speculative ratings signify a higher risk that Targa will default on its obligations, including its obligations to us, than does an investment grade credit rating. Any material nonperformance under the omnibus and purchase agreements by Targa could materially and adversely impact our ability to operate and make distributions to our unitholders.

 

Our general partner is an obligor under, and subject to a pledge related to, Targa’s credit facility; in the event Targa is unable to meet its obligations under that facility, or is declared bankrupt, Targa’s lenders may gain control of our general partner or, in the case of bankruptcy, our partnership may be dissolved.

 

Our general partner is an obligor under, and all of its assets and Targa’s ownership interest in it are subject to a lien related to, Targa’s credit facility. In the event Targa is unable to satisfy its obligations under the credit facility and the lenders foreclose on their collateral, the lenders will own our general partner and all of its assets, which include the general partner interest in us and our incentive distribution rights. In such event, the lenders would control our management and operation. Moreover, in the event Targa becomes insolvent or is declared bankrupt, our general partner may be deemed insolvent or declared bankrupt as well. Under the terms of our partnership agreement, the bankruptcy or insolvency of our general partner will cause a dissolution of our partnership.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

 

We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas and NGLs than we do. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

 

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations and financial results could be adversely affected.

 

Our operations are subject to many hazards inherent in the gathering, compressing, treating, processing and transporting of natural gas and NGLs, including:

 

 

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. Our insurance is provided under Targa’s insurance programs. We are not fully insured against all risks inherent to our business. We are not insured against all environmental accidents that might occur which may include toxic tort claims, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, Targa may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Moreover, significant claims by Targa may limit or eliminate the amount of insurance proceeds available to us. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.

 

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

 

At the closing of this offering, we will borrow approximately $342.5 million under our new credit facility. Our level of debt could have important consequences for us, including the following:

 

 

 

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Requirements.”

 

Increases in interest rates could adversely affect our business.

 

In addition to our exposure to commodity prices, we will have significant exposure to increases in interest rates. After this offering, we expect to have approximately $342.5 million of debt on a pro forma basis at variable interest rates. An increase of 1 percentage point in the interest rates will result in an increase in annual interest expense of $3.4 million. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.

 

Restrictions in our credit facility may interrupt distributions to us from our subsidiaries, which may limit our ability to make distributions to you, satisfy our obligations and capitalize on business opportunities.

 

We are a holding company with no business operations. As such, we depend upon the earnings and cash flow of our subsidiaries and the distribution of that cash to us in order to meet our obligations and to allow us to make distributions to our unitholders. In connection with this offering, we expect to enter into a new credit facility which will contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, and engage in transactions with affiliates. Furthermore, our credit facility will contain covenants requiring us to maintain a ratio of consolidated indebtedness to consolidated EBITDA initially of not more than 5.75 to 1.00 and a ratio of consolidated EBITDA to consolidated interest expense of not less than 2.25 to 1.00. If we fail to meet these tests or otherwise breach the terms of our credit facility our operating subsidiary will be prohibited from making any distribution to us and, ultimately, to you. Any interruption of distributions to us from our subsidiaries may limit our ability to satisfy our obligations and to make distributions to you.

 

We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances or hydrocarbons into the environment.

 

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (1) the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling, storage, treatment or discharge of waste from our facilities and (3) the federal Comprehensive Environmental Response, Compensation, and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental regulations,

including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

 

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. In particular, we may incur expenditures in order to maintain compliance with legal requirements governing emissions of air pollutants from our facilities. We may not be able to recover these costs from insurance. Please see “Business — Environmental Matters.”

 

We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering pipeline systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.

 

We typically do not obtain independent evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas on our gathering systems in the future could be less than we anticipate. A decline in the volumes of natural gas on our systems could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.

 

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

 

Our natural gas gathering operations are generally exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation; accordingly, the classification and regulation of some of our intrastate pipelines may be subject to change based on future determinations by FERC, the courts or Congress.

 

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and as a number of such companies have transferred gathering facilities to unregulated affiliates. The Railroad Commission of Texas, or TRRC, has adopted regulations that generally allow natural gas producers and shippers to file complaints with the TRRC in an effort to resolve grievances relating to intrastate pipeline access and rate discrimination. Our natural gas gathering operations could be

adversely affected in the future should they become subject to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect our business. See “Business — Regulation of Operations.”

 

Our costs may increase because our credit obligations under hedging and other contractual arrangements will not be guaranteed by Targa.

 

Prior to the completion of this offering, Targa maintains credit support for our obligations related to derivative financial instruments, such as commodity price hedging contracts. Beginning with the closing of this offering, Targa will no longer provide credit support for our obligations under derivative financial instruments and other commercial contracts governing our business or operations. Consequently, we will need to provide our own credit support arrangements for commercial contracts, which may increase our costs. For example, it could be more costly for us to manage our commodity price risk through certain types of financial hedging arrangements unless we are able to achieve creditworthiness similar to the current creditworthiness of Targa.

 

All of our operations are based in the Fort Worth Basin and we are dependent on drilling activities and our ability to attract and maintain customers in such region.

 

All of our operations are located in the Fort Worth Basin in north Texas. Due to our lack of diversification in industry type and location, an adverse development in the oil and gas production from this area would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

 

Under the terms of our gas sales agreement, Targa will manage the sales of our natural gas and will pay us the amount it realizes for gas sales less certain costs; however, unexpected volume changes due to production variability or to gathering, plant, or pipeline system disruptions may increase our exposure to commodity price movements.

 

Targa will sell our processed natural gas to third parties and other Targa affiliates at our plant tailgate or at interstate pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. Targa will attempt to balance sales with volumes supplied from our processing operations, but unexpected volume variations due to production variability or to gathering, plant, or pipeline system disruptions may expose us to volume imbalances which, in conjunction with movements in commodity prices, could materially impact our income from operations, and cash flow.

 

We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.

 

Pursuant to the Pipeline Safety Improvement Act of 2002, the United States Department of Transportation, or DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

 

 

 

We currently estimate that we will incur an aggregate cost of approximately $1 million between 2006 and 2010 to implement pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial.

 

Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

 

One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a new pipeline, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we do not possess reserve expertise and we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

 

If we do not make acquisitions on economically acceptable terms, or efficiently and effectively integrate the acquired assets with our asset base, our future growth will be limited.

 

Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited.

 

Any acquisition involves potential risks, including, among other things: