As filed with the Securities and Exchange Commission on October 17, 2007

Registration No. 333-146436

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

Amendment No. 2

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 OCTOBER 17, 2007

PROSPECTUS

 

Targa Resources Partners LP

12,500,000 Common Units

Representing Limited Partner Interests

 

Targa Resources Partners LP is offering 12,500,000 common units representing limited partner interests. Our common units are traded on The NASDAQ Stock Market LLC under the symbol “NGLS.” On October 10, 2007, the last reported sale price of our common units on The NASDAQ Stock Market LLC was $27.53 per common unit.

 

Investing in our common units involves risks. Please see “Risk Factors” beginning on page 16.

 

These risks assume completion of the acquisition of certain businesses described herein and include the following:

 

 

 

We have granted the underwriters a 30-day option to purchase up to an additional 1,875,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 12,500,000 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 our common units through the facilities of The Depository Trust Company on or about          , 2007.

 

Citi       Lehman Brothers       Goldman, Sachs & Co.       Merrill Lynch & Co.

 

          , 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.

	•	The San Angelo Operating Unit System (the “SAOU System”) — the SAOU System consists of the approximately 1,350 mile San Angelo natural gas gathering system, which is located in the Permian Basin of west Texas, and the Mertzon, Sterling and Conger processing plants with aggregate processing capacity of approximately 135 MMcf/d; and
	•	The Louisiana Operating Unit System (the “LOU System”) — the LOU System consists of an approximately 700-mile natural gas gathering system, which is located in southwest Louisiana, the Gillis and Acadia processing plants with aggregate processing capacity of approximately 260 MMcf/d and an integrated fractionation facility at the Gillis processing plant with processing capacity of approximately 13 thousand barrels per day, or MBbls/d.

	•	we will issue 12,500,000 common units to the public, representing a 28.2% limited partner interest in us;

	•	we will borrow approximately $397.1 million under our amended credit facility;

	•	we will issue to our general partner 255,103 general partner units as partial consideration for the Acquired Businesses, enabling it to maintain its 2% general partner interest in us;

	•	we will use the net proceeds from this offering and borrowings under our amended credit facility to pay expenses associated with this offering and our amended credit facility and to pay consideration of approximately $698.0 million to Targa to purchase the Acquired Businesses; and

	•	we will use the remaining net proceeds to pay $24.2 million to Targa for certain hedge transactions associated with the Acquired Businesses effected on September 25 and 26, 2007, which is an adjustment to the purchase price for the Acquired Businesses.

	•	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 minimum quarterly distribution rate under our cash distribution policy.
	•	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. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our equity commodity volumes that are hedged decreases substantially over time.
	•	We will use the proceeds of this offering together with borrowings to purchase the Acquired Businesses. If the acquired businesses or future acquisitions do not perform as expected, our future financial performance may be negatively impacted.

	•	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.
	•	Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

	•	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 (the “IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

	•	If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted, and the costs of any IRS 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.
	•	Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Public Common Units			71.9	%
Subordinated Units			26.1	%
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.

Common units offered to the public		12,500,000 common units or 14,375,000 common units if the underwriters exercise in full their option to purchase additional common units.
Units outstanding after this offering		31,836,000 common units and 11,528,231 subordinated units, representing a 71.9% and 26.1% limited partner interest in us, respectively (33,711,000 common units and 11,528,231 subordinated units, representing a 73.0% and 25.0% limited partner interest in us, respectively, if the underwriters exercise in full their option to purchase additional common units).

Use of proceeds		The net proceeds from this offering of common units will be approximately $330.3 million after deducting underwriting discounts but before estimated offering expenses (based on the closing price for our common units on October 10, 2007 of $27.53 per unit). We will use the net proceeds of this offering of common units and borrowings of approximately $397.1 million under our amended credit facility to pay approximately:

		• $698.0 million of the $705.0 million aggregate consideration, subject to certain adjustments, to Targa to acquire the Acquired Businesses;

		• $24.2 million to Targa for certain hedge transactions associated with the Acquired Businesses effected on September 25 and 26, 2007, which is an adjustment to the purchase price for the Acquired Businesses; and
		• $5.3 million of estimated expenses associated with our acquisition of the Acquired Businesses and the related financing transactions, including this offering.
		In addition, we will issue to our general partner 255,103 general partner units as partial consideration for the Acquired Businesses, enabling it to maintain its 2% general partner interest in us.
		If the underwriters exercise their option to purchase additional common units, we will use the net proceeds to reduce outstanding borrowings under our amended credit facility. Please read “Use of Proceeds.”
Cash distributions		We paid a prorated quarterly cash distribution of $0.16875 per unit for the first quarter of 2007, or $1.35 per unit on an annualized basis, on May 15, 2007 to unitholders of record as of May 3, 2007. This distribution was for the period from February 14, 2007, the date of the closing of our initial public offering, through the end of the first quarter.
		We paid a quarterly cash distribution of $0.3375 per common unit for the second quarter of 2007, or $1.35 per unit on an annualized basis, on August 14, 2007 to unitholders of record as of August 2, 2007.
		Within 45 days after the end of each quarter, we distribute our available cash to unitholders of record on the applicable record date.

		In general, we will pay any cash distributions we make each quarter 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 “Our Cash Distribution Policy.”
Subordinated units		Targa owns 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 our 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 March 31, 2010. 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 our 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 “Our Cash Distribution Policy — 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 “Our Cash Distribution Policy — 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 manages and operates 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 completion of this offering, our general partner and its affiliates will own an aggregate of 26.6% of our common and subordinated units. 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 our 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, 2010, 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.”
Trading		Our common units are traded on The NASDAQ Stock Market LLC under the symbol “NGLS.”

		Predecessor Business																					Targa Resources				Targa Resources Partners LP
		Dynegy									Targa North Texas LP												Partners LP				Pro Forma
		Year				Ten Months					Two Months				Year				Six Months				Six Months				Period from
		Ended				Ended					Ended				Ended				Ended				Ended				March 12, 2004				Year Ended								Six Months Ended
		December 31,				October 31,					December 31,				December 31,				June 30,				June 30,				to December 31,				December 31,								June 30,
		2004				2005					2005				2006				2006				2007				2004				2005				2006				2006				2007
		(Audited)				(Audited)					(Audited)				(Audited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)
		(In millions of dollars, except per unit, operating and price data)
Statement of Operations Data:
Total operating revenues		$	258.6			$	293.3				$	75.1			$	384.8			$	188.9			$	200.0			$	603.9			$	1,160.4			$	1,755.3			$	986.0			$	761.4
Product purchases		$	182.6			$	210.8				$	54.9			$	269.3			$	132.8			$	138.3			$	544.9			$	1,061.6			$	1,517.6			$	866.5			$	666.2
Operating expense			17.7				18.0					3.5				24.1				11.5				12.0				15.3				24.4				49.1				23.8				23.9
Depreciation and amortization expense			12.2				11.3					9.2				56.0				27.4				28.5				10.4				23.1				70.0				34.1				35.7
General and administrative expense			7.2				7.3					1.1				6.9				3.2				3.5				11.1				16.8				16.1				5.3				8.0
Interest expense allocated from parent			—				—					11.5				72.9				35.7				—				6.1				9.6				—				43.1				—
Interest expense, net			—				—					—				—				—				17.7				—				—				49.9				—				24.9
Loss on debt extinguishment			—				—					—				—				—				—				—				15.2				—				—				—
Deferred income taxes(1)			—				—					—				2.5				1.5				0.7				—				—				2.9				1.9				0.7
Other, net			0.3				—					—				—				—				—				—				—				—				—				(0.3	)
Net income (loss)		$	38.6			$	45.9				$	(5.1	)			(46.9	)		$	(23.2	)		$	(0.7	)		$	16.1				9.7			$	49.7			$	11.3			$	2.3
Pro forma net income per limited partner unit																																			$	1.12							$	0.05

		Predecessor Business																					Targa Resources				Targa Resources Partners LP
		Dynegy									Targa North Texas LP												Partners LP				Pro Forma
		Year				Ten Months					Two Months				Year				Six Months				Six Months				Period from
		Ended				Ended					Ended				Ended				Ended				Ended				March 12, 2004				Year Ended								Six Months Ended
		December 31,				October 31,					December 31,				December 31,				June 30,				June 30,				to December 31,				December 31,								June 30,
		2004				2005					2005				2006				2006				2007				2004				2005				2006				2006				2007
		(Audited)				(Audited)					(Audited)				(Audited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)
		(In millions of dollars, except per unit, operating and price data)
Financial and Operating Data:
Financial data:
Operating margin(2)		$	58.3			$	64.5				$	16.7			$	91.4			$	44.6			$	49.7			$	43.7			$	74.4			$	188.6			$	95.7			$	71.3
Adjusted EBITDA(3)			50.8				57.2					15.6				84.5				41.4				46.2				31.3				54.4				155.8				82.0				84.6
Operating data:
Gathering throughput, MMcf/d(4)			152.0				161.2					168.8				168.3				167.3				166.3
Plant Natural Gas Inlet, MMcf/d(5)			145.4				156.2					161.9				161.8				160.4				160.0
Gross NGL production, MBbl/d			17.2				18.5					19.8				18.9				18.7				17.3
Natural gas sales, BBtu/d			59.2				68.9					72.3				74.9				74.4				75.9
NGL sales, MBbl/d			13.2				14.3					15.4				15.2				13.9				13.0
Condensate sales, MBbl/d			0.7				0.5					0.5				0.5				1.6				1.9
Average Realized Prices:
Natural gas, $/MMBtu		$	5.43			$	6.79				$	8.61			$	6.09			$	6.28			$	6.84
NGL, $/gal			0.64				0.78					0.90				0.88				0.84				0.87
Condensate, $/Bbl			40.56				53.42					57.54				65.31				51.87				52.97
Balance Sheet Data (at period end):
Property, plant, and equipment, net		$	191.2			$	196.4				$	1,097.0			$	1,064.1			$	1,080.8			$	1,046.1																			$	1,276.3
Total assets			193.5				198.5					1,122.8				1,115.8				1,116.8				1,123.8																				1,421.0
Long-term debt including current portion			—				—					868.9				864.0				866.4				294.5																				691.6
Partners’ capital /Net parent investment			168.8				158.5					219.5				215.6				220.4				767.7																				552.9
Cash Flow Data:
Net cash provided by (used in):
Operating activities		$	58.0			$	72.7				$	(1.5	)		$	16.2			$	3.4			$	23.5
Investing activities			(23.4	)			(16.4	)				(2.1	)			(23.1	)			(11.2	)			(10.5	)
Financing activities			(34.6	)			(56.3	)				3.6				6.9				7.8				(3.6	)

(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)		Adjusted EBITDA is net income before interest, income tax, depreciation and amortization, and non-cash income or loss related to derivative instruments. 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.

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

		Predecessor Business																					Targa
											Targa North Texas LP												Resources				Targa Resources Partners LP
		Dynegy																	Six				Partners LP				Pro Forma
		Year				Ten Months					Two Months				Year				Months				Six Months				Period from
		Ended				Ended					Ended				Ended				Ended				Ended				March 12, 2004				Year Ended								Six Months
		December 31,				October 31,					December 31,				December 31,				June 30,				June 30,				to December 31,				December 31,								Ended June 30,
		2004				2005					2005				2006				2006				2007				2004				2005				2006				2006				2007
		(Audited)				(Audited)					(Audited)				(Audited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)				(Unaudited)
		(In millions)
Reconciliation of “Adjusted EBITDA” to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities		$	58.0			$	72.7				$	(1.5	)		$	16.2			$	3.4			$	23.5
Allocated interest expense from parent(1)			—				—					10.7				67.8				33.1				—
Interest expense, net(1)			—				—					—				—				—				17.4
Changes in operating working capital which provided (used) cash:
Accounts receivable			(0.7	)			0.3					0.1				(0.2	)			(0.4	)			11.7
Accounts payable			(2.7	)			1.3					0.8				(0.6	)			6.8				(6.6	)
Other, including changes in noncurrent assets and liabilities			(3.8	)			(17.1	)				5.5				1.3				(1.5	)			0.2
Non-cash mark-to-market loss (gain)			—				—					—				—				—				—
Adjusted EBITDA		$	50.8			$	57.2				$	15.6			$	84.5			$	41.4			$	46.2
Reconciliation of “Adjusted EBITDA” to net income:
Net income (loss)		$	38.6			$	45.9				$	(5.1	)		$	(46.9	)		$	(23.2	)		$	(0.7	)		$	16.1			$	9.7			$	49.7			$	11.3			$	2.3
Add:
Allocated interest expense from parent			—				—					11.5				72.9				35.7				—				6.1				9.6				—				43.1				—
Interest expense, net			—				—					—				—				—				17.7				—				—				49.9				—				24.9
Deferred tax expense			—				—					—				2.5				1.5				0.7				—				—				2.9				1.9				0.7
Depreciation and amortization expense			12.2				11.3					9.2				56.0				27.4				28.5				10.4				23.1				70.0				34.1				35.7
Non-cash mark-to-market loss (gain)			—				—					—				—				—				—				(1.3	)			12.0				(16.7	)			(8.4	)			21.0
Adjusted EBITDA		$	50.8			$	57.2				$	15.6			$	84.5			$	41.4			$	46.2			$	31.3			$	54.4			$	155.8			$	82.0			$	84.6
Reconciliation of “operating margin” to net income:
Net income (loss)		$	38.6			$	45.9				$	(5.1	)		$	(46.9	)		$	(23.2	)		$	(0.7	)		$	16.1			$	9.7			$	49.7			$	11.3			$	2.3
Add:
Depreciation and amortization expense			12.2				11.3					9.2				56.0				27.4				28.5				10.4				23.1				70.0				34.1				35.7
Deferred income tax			—				—					—				2.5				1.5				0.7				—				—				2.9				1.9				0.7
Other, net			0.3				—					—				—				—				—				—				—				—				—				(0.3	)
Loss on debt extinguishment			—				—					—				—				—				—				—				15.2				—				—				—
Allocated interest expense from parent			—				—					11.5				72.9				35.7				—				6.1				9.6				—				43.1				—
Interest expense, net			—				—					—				—				—				17.7				—				—				49.9				—				24.9
General and administrative expense			7.2				7.3					1.1				6.9				3.2				3.5				11.1				16.8				16.1				5.3				8.0
Operating margin		$	58.3			$	64.5				$	16.7			$	91.4			$	44.6			$	49.7			$	43.7			$	74.4			$	188.6			$	95.7			$	71.3

(1)		Excludes non-cash amortization of debt issue costs of $0.8 million for the two months ended December 31, 2005, $5.1 million for the year ended December 31, 2006, $2.6 million for the six months ended June 30, 2006 and $0.3 million for the six months ended June 30, 2007.

 

RISK FACTORS

 

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are consistent with 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.

 

The following risks are presented as if we have completed the acquisition of the Acquired Businesses.

 

Risks Related to Our Business

 

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 minimum quarterly distribution rate under our cash distribution policy.

 

In order to make our cash distributions at our minimum quarterly 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 $14.9 million per quarter, or $59.7 million per year, based on our common units and subordinated units outstanding immediately upon completion of this offering ($15.6 million or $62.3 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 minimum quarterly 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.”

 

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 prompt month contract in the year ended December 31, 2005 ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu and for the year ended December 31, 2006 ranged from a high of $10.63 per MMBtu to a low of $4.20 per MMBtu. From the beginning of 2007 through June 30, 2007 the NYMEX daily settlement price for natural gas has ranged from a high of $9.07 per MMBtu to a low of $5.40 per MMBtu. NGL prices exhibit similar volatility. Based on monthly index prices, the average price for our NGL composition in the year ended December 31, 2005 ranged from a high of $1.12 per gallon to a low of $0.73 per gallon and for the year ended December 31, 2006 ranged from a high of $1.18 per gallon to a low of $0.92 per gallon in 2006. From the beginning of 2007 through June 30, 2007 the average price for our NGL composition ranged from a high of $1.13 per gallon to a low of $0.93 per gallon.

 

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 six month period ended June 30, 2007, our percent-of-proceeds arrangements accounted for approximately 82% of our gathered natural gas volume. Under percent-of-proceeds arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. 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.

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 areas in which we operate has been and will continue to be a limiting factor on the number of wells drilled in these areas. 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. In the past, the prices of natural gas have been extremely volatile, and we expect this volatility to continue. Natural gas prices reached historic highs in 2005 and early 2006, but declined substantially in the second half of 2006 and have continued to decline in 2007. 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. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our equity commodity volumes that are hedged decreases substantially over time.

 

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 percentages of our expected equity volumes that are covered by our hedges decrease over time. 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. These pricing differentials may be substantial and materially impact the prices we ultimately realize. 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. 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.”

 

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 years ended December 31, 2006 and 2005 was ConocoPhillips, who accounted for approximately 12.5% and 13.3%, 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 processing 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 processing facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner 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, or if the gas quality specifications for their pipelines or facilities change so as to restrict our ability to transport gas on those pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

 

We depend on our Chico system for a substantial portion 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. To a similar but lesser degree, we are dependent on the Acquired Businesses, especially the Mertzon, Sterling and Gillis plants and their respective gathering systems.

 

Any significant curtailment of gathering, compressing, treating, processing or fractionation of natural gas on our Chico system or at our other plants and systems could result in our realizing materially lower levels of revenues and cash flow for the duration of such curtailment. For the year ended December 31, 2006, our Chico plant inlet volume accounted for over 31% of our revenues. Operations at our Chico system or our other plants or systems 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 or the Mertzon, Sterling and Gillis plants and their respective gathering systems that is not fully insured, it could adversely affect our operations and financial condition.

We will use the proceeds of this offering together with borrowings to purchase the Acquired Businesses. If the Acquired Businesses or future acquisitions do not perform as expected, our future financial performance may be negatively impacted.

 

Our acquisition of the Acquired Businesses will significantly increase the size of our company and diversify the geographic areas in which we operate. We cannot assure you that we will achieve the desired profitability from the Acquired Businesses or any other acquisitions we may complete in the future. In addition, failure to successfully assimilate future acquisitions could adversely affect our financial condition and results of operations.

 

Our acquisitions involve numerous risks, including:

 

 

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

 

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.

 

We have entered into purchase agreements with Targa pursuant to which Targa will purchase (i) all of the North Texas System’s natural gas, NGLs and high-pressure condensate for a term of 15 years and (ii) substantially all of the Acquired Businesses’ natural gas for a term of 15 years and NGLs for a term of one year. Targa also manages the Acquired Businesses’ natural gas sales to third parties under contracts that remain in the name of the Acquired Businesses. We are also party to an amended and restated omnibus agreement with Targa which addresses, among other things, the provision of general and administrative and operating services to us. As of September 6, 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.

 

Weather may limit our ability to operate our business and could adversely affect our operating results.

 

The weather in the areas in which we operate can cause delays in our operations and, in some cases, work stoppages. For example, natural gas sales volumes for the six months ended June 30, 2007 were negatively impacted by unseasonably wet weather, which limited our ability to complete connections to new wells. Any similar delays or work stoppages caused by the weather could adversely affect our operating results for the affected periods.

 

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. For example, Hurricanes Katrina and Rita damaged gathering systems, processing facilities, NGL fractionators and pipelines along the Gulf Coast, including, in the case of Hurricane Rita, certain of our facilities. These hurricanes disrupted the operations of our customers in August and September 2005, which curtailed or suspended the operations of various energy companies with assets in the region. 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. For example, following Hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms generally are less favorable than terms that could be obtained prior to such hurricanes. 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.

 

Upon completion of this offering, we expect to have approximately $691.6 million of debt outstanding under our amended 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 have significant exposure to increases in interest rates. Upon completion of this offering, we expect to have approximately $691.6 million of debt outstanding under our amended credit facility at variable interest rates. An increase of 1 percentage point in the interest rates will result in an increase in annual interest expense of $6.9 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 amended 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. Our amended credit facility contains covenants limiting our ability to make distributions, incur indebtedness, grant liens, and engage in transactions with affiliates. Furthermore, our amended credit facility contains 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 amended 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 natural gas gathering, treating, fractionating and processing operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws include, for example, (1) the federal Clean Air Act and comparable state laws 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 disposal of solid and hazardous waste from our facilities, (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 at locations to which our wastes have been transported for disposal, and (4) the Federal Water Pollution Control Act, also know as the Clean Water Act, and comparable state laws that regulate discharges of wastewater from our facilities to state and federal waters. 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 laws, including CERCLA and analogous state laws, 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 incurring environmental costs and liabilities in connection with our operations due to our handling of natural gas and other petroleum products, air emissions and water discharges 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 all or any of these costs from insurance. Please see “Business — Environmental Matters” for more information.

 

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 and transportation 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 those businesses and the markets for products derived from those businesses. FERC has recently proposed to require intrastate pipelines, possibly including natural gas gathering pipelines, to comply with certain Internet posting requirements, with the goal of promoting transparency in the interstate natural gas market. FERC has not yet issued a final rule on that proposed rulemaking. We may experience an increase in costs if the rule is adopted as proposed.

 

Other FERC regulations may indirectly impact our 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, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. 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 transportation capacity.

 

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress. Accordingly, in such a circumstance, the classification and regulation of some of our natural gas gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress.

 

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, or EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation.

 

State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser 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 states we operate in have adopted regulations that generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering and intrastate transportation pipeline access and rate discrimination. Our gathering and intrastate transportation operations could be adversely affected in the future should they become subject to the application of state or federal regulation of rates and services. These operations may also be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from natural gas wells. 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. For more information regarding regulation of Targa’s operations, please read “Business — Regulation of Operations.”

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 sells our processed natural gas to third parties and other Targa affiliates at our plant tailgates or at pipeline pooling points. Targa also manages the Acquired Businesses’ natural gas sales to third parties under contracts that remain in the name of the Acquired Businesses. 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 transmission pipelines located where a leak or rupture could do the most harm in “high consequence areas,” including high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators of covered pipelines to:

 

 

We currently estimate that we will incur an aggregate cost of approximately $1 million between 2007 and 2010 to implement pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines. This estimate 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. At this time, we cannot predict the ultimate cost of compliance with this regulation, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. Following this initial round of testing and repairs, we will continue our pipeline integrity testing programs to assess and maintain the integrity or our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of our pipelines.

 

Our historical and pro forma financial information may not be representative of our results as a combined company.

 

The historical and pro forma financial information included in this prospectus is derived from our separate financial statements, the separate financial statements of Targa for periods prior to our initial public offering, the separate financial statements of Dynegy Midstream Services, Limited Partnership (“DMS”) for periods prior to the consummation of Targa’s acquisition of DMS and the separate financial statements of Targa’s predecessor for periods prior to the consummation of Targa’s acquisition of the Acquired Businesses. The audited historical financial statements of the Predecessor Business and the Acquired Businesses were prepared in accordance with GAAP, on a going-concern basis, as if the Predecessor Business and the Acquired

Businesses had existed as separate entities during the periods presented. Expenses included in the financial statements of the Predecessor business and the Acquired Businesses may not be indicative of the level of expenses that might have been incurred had such businesses been operating as separate stand-alone companies. In addition, the unaudited pro forma financial information presented in this prospectus is based, in part, on certain assumptions regarding our acquisition of the Acquired Businesses that we believe are reasonable. To the extent financial statements are prepared for our business in the future, such information will differ from the information contained herein, and such differences may be material.

 

Accordingly, the historical, pro forma and other financial information included in this prospectus may not reflect what our results of operations and financial condition would have been had we been a combined entity during the periods presented, or what our results of operations and financial condition will be in the future.

 

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:

 

 

 

If these risks materialize, the acquired assets may inhibit our growth or fail to deliver expected benefits.

 

Our acquisition strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.

 

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

 

We do not own most of the land on which our pipelines and facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or leases or if such rights of way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere, reduce our revenue and impair our ability to make distributions to our unitholders.

 

We do not have any officers or employees and rely solely on officers of our general partner and employees of Targa.

 

None of the officers of our general partner are employees of our general partner. We have entered into an omnibus agreement with Targa, pursuant to which Targa operates our assets and performs other administrative services for us such as accounting, legal, regulatory, corporate development, finance, land and engineering. Affiliates of Targa conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to Targa. As a result, there could be material competition for the time and effort of the officers and employees who provide services to our general partner and Targa. If the officers of our general partner and the employees of Targa do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

 

If our general partner fails to develop or maintain an effective system of internal controls, then we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

 

Targa Resources GP LLC, our general partner, has sole responsibility for conducting our business and for managing our operations. Effective internal controls are necessary for our general partner, on our behalf, to provide reliable financial reports, prevent fraud and operate us successfully as a public company. If our general partner’s efforts to develop and maintain its internal controls are not successful, it is unable to maintain adequate controls over our financial processes and reporting in the future or it is unable to assist us in complying with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

The amount of cash we have available for distribution to holders of our common units and subordinated units depends primarily on our cash flow and not solely on profitability. Consequently, even if we are profitable, we may not be able to make cash distributions to holders of our common units and subordinated units.

 

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

 

Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

 

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry in general, and on us in particular, is not known at this time.

 

Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

 

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

 

Risks Inherent in an Investment in Us

 

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.

 

Targa owns and controls our general partner. Some of our general partner’s directors, and some of its executive officers, are directors or officers of Targa. Therefore, conflicts of interest may arise between Targa, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

 

 

Please see “Conflicts of Interest and Fiduciary Duties.”

The credit and business risk profile of our general partner and its owners could adversely affect our credit ratings and profile.

 

The credit and business risk profiles of the general partner and its owners may be factors in credit evaluations of a master limited partnership. This is because the general partner can exercise significant influence over the business activities of the partnership, including its cash distribution and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of the general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.

 

Targa, the owner of our general partner, has significant indebtedness outstanding and is partially dependent on the cash distributions from their indirect general partner and limited partner equity interests in us to service such indebtedness. Any distributions by us to such entities will be made only after satisfying our then current obligations to our creditors. Our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of the entities that control our general partner were viewed as substantially lower or more risky than ours.

 

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.

 

The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, Targa. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

 

 

If you purchase any common units, you will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please see “Conflicts of Interests and Fiduciary Duties — Fiduciary Duties.”

 

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

 

Neither our partnership agreement nor the omnibus agreement between us and Targa prohibit Targa from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Targa may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Targa is a large, established participant in the midstream energy business, and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with Targa with respect to commercial activities as well as for acquisition candidates. As a result, competition from Targa could adversely impact our results of operations and cash available for distribution. Please see “Conflicts of Interest and Fiduciary Duties.”

 

Cost reimbursements due our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to you.

 

Pursuant to the omnibus agreement we entered into with Targa Resources GP LLC, our general partner and others, Targa receives reimbursement for the payment of operating expenses related to our operations and for the provision of various general and administrative services for our benefit. Payments for these services are substantial and reduce the amount of cash available for distribution to unitholders. Please see “Certain Relationships and Related Transactions — Omnibus Agreement.” In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify our general partner. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

 

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or our general partner’s board of directors, and have no right to elect our general partner or our general partner’s board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by Targa. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which our common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

Removal of our general partner without its consent will dilute and adversely affect our common unitholders.

 

If our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our

general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

 

We may issue additional units without your approval, which would dilute your existing ownership interests.

 

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

 

Affiliates of our general partner may sell common units in the public markets, which sales could have an adverse impact on the trading price of our common units.

 

Management of our general partner and Targa beneficially hold 85,700 common units and 11,528,231 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier. The sale of these units in the public markets could have an adverse impact on the price of our common units or on any trading market that may develop.

 

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units. This ability may result in lower distributions to holders of our common units in certain situations.

 

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 percentage increases above the reset minimum quarterly distribution amount.

 

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. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its

incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please see “Our Cash Distribution Policy — General Partner Interest and Incentive Distribution Rights.”

 

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, for expansion capital expenditures or for other purposes.

 

As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, for expansion capital expenditures or for other purposes.

 

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

 

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

Control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.

 

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

 

If at any time our general partner and its affiliates own more than 80% of our common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of our common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 26.6% of our aggregate outstanding common units. For additional information about this right, please see “The Partnership Agreement — Limited Call Right.”

 

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in Louisiana and

Texas. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if: