As filed with the Securities and Exchange Commission on April 13, 2011

Registration No. 333-173262      

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

 

 

Amendment No. 1 to

 

Form S-1

 

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

 

 

TARGA RESOURCES CORP.

(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, 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, 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(c) 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(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

 

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

 

 

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 April 13, 2011

 

PROSPECTUS

5,650,000 Shares

 

Targa Resources Corp.

Common Stock

 

The selling stockholders identified in this prospectus are offering 5,650,000 shares of our common stock. We will not receive any proceeds from the sale of shares by the selling stockholders.

 

An affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated, an underwriter in this offering, is a selling stockholder. See “Underwriting (Conflicts of Interest)—Conflicts of Interest.”

 

Our common stock trades on the New York Stock Exchange under the symbol “TRGP.” The last reported trading price of our common stock on the New York Stock Exchange on April 12, 2011 was $32.78 per share of common stock.

 

Investing in our common stock involves risks. See “Risk Factors” beginning on page 20 of this prospectus.

 

 

Certain of the selling stockholders have granted the underwriters a 30-day option to purchase up to an additional 847,500 shares of common stock on the same terms and conditions as set forth above if the underwriters sell more than 5,650,000 shares of common stock in this offering.

 

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

 

Barclays Capital, on behalf of the underwriters, expects to deliver the shares on or about          , 2011.

 

 

 

 

 

 

 

 

 

 

 

Prospectus dated          , 2011

 

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.

 

SUMMARY

	•	a 2% general partner interest, which we hold through our 100% ownership interest in the general partner of the Partnership;
	•	all of the outstanding IDRs; and
	•	11,645,659 of the 84,756,009 outstanding common units of the Partnership, representing 13.7% of the limited partnership interest in the Partnership.

	•	2% of all cash distributed in respect for that quarter;

	•	13% of all cash distributed in a quarter after $0.3881 has been distributed in respect of each common unit of the Partnership for that quarter;
	•	23% of all cash distributed in a quarter after $0.4219 has been distributed in respect of each common unit of the Partnership for that quarter; and
	•	48% of all cash distributed in a quarter after $0.50625 has been distributed in respect of each common unit of the Partnership for that quarter.

	•	Cedar Bayou Fractionator expansion project:  The Partnership is currently starting up the approximately 78 MBbl/d of additional fractionation capacity at the Partnership’s 88% owned Cedar Bayou Fractionator (“CBF”) in Mont Belvieu. The capital cost is expected to be less than the original estimated gross cost of $78 million.
	•	Benzene treating project:  A new treater is under construction which will operate in conjunction with the Partnership’s existing low sulfur natural gasoline (“LSNG”) facility at Mont Belvieu and is designed to reduce benzene content of natural gasoline to meet new, more stringent environmental standards. The treater has an estimated gross cost of approximately $33 million and is expected to be completed and operating by the end of the year.
	•	Gulf Coast Fractionators expansion project:  The Partnership has announced plans by Gulf Coast Fractionators (“GCF”), a partnership with ConocoPhillips and Devon Energy Corporation in

		which the Partnership owns a 38.8% interest, to expand the capacity of its NGL fractionation facility in Mont Belvieu by 43 MBbl/d for an estimated gross cost of $75 million.

	•	SAOU Expansion Program:  The Partnership has announced a $30 million capital expenditure program including new compression facilities and pipelines as well as expenditures to restart the 25 MMcf/d Conger processing plant in response to strong volume growth and new well connects. The Partnership expects the Conger plant to restart in April 2011. Additionally, two 15 MMcf/d processing trains from the Garden City plant are being refurbished for future use at another SAOU location.
	•	North Texas Expansion Program:  The board of directors of the General Partner has approved approximately $40 million of capital expenditures to expand the gathering and processing capability of the Partnership’s North Texas System with certain provisions of the approved expenditures subject to finalization of ongoing customer commercial agreements. The expansion program is a response to strong volume growth and new well connects associated with producer activity in “oilier” portions of the Barnett Shale natural gas play. Management expects that additional investment will be required to keep pace with producer activity.

	•	The Partnership is one of the largest and best positioned/interconnected fractionators of NGLs in the Gulf Coast.
	•	The Partnership’s gathering and processing businesses are predominantly located in active and growth oriented oil and gas producing basins.
	•	The Partnership provides a comprehensive package of services to natural gas producers.
	•	The Partnership maintains gathering and processing positions in strategic oil and gas producing areas across multiple basins and provides services under attractive contract terms to a diverse mix of customers.
	•	The Partnership’s gathering and processing systems and logistics assets consist of high-quality, well maintained facilities, resulting in low cost, efficient operations.
	•	Maintaining appropriate leverage and distribution coverage levels and mitigating commodity price volatility allow the Partnership to be flexible in its growth strategy and enable it to pursue strategic acquisitions and large growth projects.
	•	The executive management team which formed TRI in 2004 and continues to manage Targa today possesses over 200 years of combined experience working in the midstream natural gas and energy business.

	•	The Partnership has a substantial amount of indebtedness which may adversely affect its financial position.
	•	The Partnership’s cash flow is affected by supply and demand for oil, natural gas and NGL products and by natural gas and NGL prices, and decreases in these prices could adversely affect its results of operations and financial condition.

	•	The Partnership’s long-term success depends on its ability to obtain new sources of supplies of natural gas and NGLs, which depends on certain factors beyond its control. Any decrease in supplies of natural gas or NGLs could adversely affect the Partnership’s business and operating results.

	•	If the Partnership does not make investments in new assets or acquisitions on economically acceptable terms or efficiently and effectively integrate new assets, its results of operations and financial condition could be adversely affected.

	•	The Partnership is subject to regulatory, environmental, political, legal, credit and economic risks, which could adversely affect its results of operations and financial condition.
	•	The Partnership’s growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair its ability to grow.
	•	The Partnership’s hedging activities may not be effective in reducing the variability of its cash flows and may, in certain circumstances, increase the variability of its cash flows.
	•	The Partnership’s industry is highly competitive, and increased competitive pressure could adversely affect the Partnership’s business and operating results.

(1)		Please see “Security Ownership of Management and Selling Stockholders” for information regarding the beneficial ownership of our common stock for our executive officers and directors.

Common stock offered by the selling stockholders		5,650,000 shares (6,497,500 shares if the underwriters’ over-allotment is exercised in full)

Common stock outstanding as of April 12, 2011		42,349,738 shares

Over-allotment option		Certain of the selling stockholders have granted the underwriters a 30-day option to purchase up to an aggregate of 847,500 additional shares of our common stock to cover over-allotments.

Use of proceeds		We will not receive any proceeds from the sale of shares by the selling stockholders. See “Use of Proceeds.”
Dividend Policy		We intend to pay to our stockholders, on a quarterly basis, dividends equal to the cash we receive from our Partnership distributions, less reserves for expenses, future dividends and other uses of cash, including:
		• federal income taxes, which we are required to pay because we are taxed as a corporation;
		• the expenses of being a public company;
		• other general and administrative expenses;
		• reserves our board of directors believes prudent to maintain; and
		• capital contributions to the Partnership upon the issuance by it of additional partnership securities if we choose to maintain the General Partner’s 2% interest.

Dividends		We announced a dividend of $0.2725 per share of common stock for the first quarter of 2011 on April 11, 2011 to be paid on May 17, 2011 to stockholders of record on April 21, 2011. The dividend corresponds to $1.09 per share on an annualized basis. If we close this offering on or prior to the record date on April 21, 2011, the shares of common stock sold in this offering will receive the declared dividend of $0.2725 per share of common stock for the first quarter of 2011. If we do not close this offering on or prior to the record date on April 21, 2011, then the shares of common stock sold in this offering will not receive the declared dividend. We cannot assure you that any dividends will be declared or paid by us. Please read “Our Dividend Policy.”

Tax		For a discussion of the material tax consequences that may be relevant to prospective stockholders who are non-U.S. holders (as defined below), please read “Material U.S. Federal Income Tax Consequences to Non-U.S. Holders.”

Risk factors		You should carefully read and consider the information beginning on page 20 of this prospectus set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.
New York Stock Exchange symbol		TRGP

Conflicts of interest		An affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated, an underwriter in this offering, will receive more than 5% of the net proceeds of the offering as a selling stockholder. Because an affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated will receive more than 5% of the net proceeds, this offering is being conducted in accordance with FINRA Rule 5121. This rule requires, among other things, that a qualified independent underwriter has participated in the preparation of, and has exercised the usual standards of due diligence with respect to, this prospectus and the registration statement of which this prospectus is a part. Barclays Capital Inc. is acting as the qualified independent underwriter. See “Underwriting (Conflicts of Interest)—Conflicts of Interest.”

	•	common unitholders of the Partnership have a priority over the IDRs with respect to the Partnership distributions;
	•	we participate in the General Partner’s distributions and IDRs and the common unitholders do not;
	•	we and our stockholders are taxed differently from the Partnership and its common unitholders; and
	•	we may enter into other businesses separate and apart from the Partnership or any of its affiliates.

		Partnership’s Common Units		Our Shares
Distributions and Dividends		The Partnership pays its limited partners and the General Partner quarterly distributions equal to all of the available cash from operating surplus. The General Partner has a 2% general partner interest. Common unitholders do not participate in the distributions to the General Partner or in the IDRs.		We intend to pay our stockholders, on a quarterly basis, dividends equal to the cash the Partnership distributes to us based on our ownership of Partnership interests, less federal income taxes, which we are required to pay because we are taxed as a corporation, the expenses of being a public company, other general and administrative expenses, capital contributions to the Partnership upon the issuance by it of additional Partnership securities if we choose to maintain the General Partner’s 2% interest and reserves established by our board of directors.
				We receive distributions from the Partnership with respect to our 11,645,659 common units.

		Partnership’s Common Units		Our Shares
				In addition, through our ownership of the Partnership’s general partner, we participate in the distributions to the General Partner pursuant to the 2% general partner interest and the IDRs. If the Partnership is successful in implementing its strategy to increase distributable cash flow, our income from these rights may increase in the future. However, no distributions may be made on the IDRs until the minimum quarterly distribution has been paid on all outstanding common units. Therefore, distributions with respect to the IDRs are even more uncertain than distributions on the common units.
Taxation of Entity and Equity Owners		The Partnership is a flow-through entity that is not subject to an entity level federal income tax. The Partnership expects that holders of units in the Partnership other than us will benefit for a period of time from tax basis adjustments and remedial allocations of deductions so that they will be allocated a relatively small amount of federal taxable income compared to the cash distributed to them.		Our taxable income is subject to U.S. federal income tax at the corporate tax rate, which is currently a maximum of 35%. In addition, we will be allocated more taxable income relative to our Partnership distributions than the other common unitholders and the relative amount thereof may increase if the Partnership issues additional units or distributes a higher percentage of cash to the holder of the IDRs.

		Partnership’s Common Units		Our Shares
		Common unitholders will receive Forms K-1 from the Partnership reflecting the unitholders’ share of the Partnership’s items of income, gain, loss, and deduction. Tax-exempt organizations, including employee benefit plans, will have unrelated business taxable income as a result of the allocation of the Partnership’s items of income, gain, loss, and deduction to them. Regulated investment companies or mutual funds will be allocated items of income, which may not constitute qualifying income, as a result of the ownership of common units.		Because we are not a flow-through entity, our stockholders do not report our items of income, gain, loss and deduction on their federal income tax returns. Distributions to our stockholders will constitute dividends for U.S. tax purposes to the extent of our current or accumulated earnings and profits. To the extent those distributions are not treated as dividends, they will be treated as gain from the sale of the common stock to the extent the distribution exceeds a stockholder’s adjusted basis in the common stock sold. Our stockholders will generally recognize capital gain or loss on the sale of our common stock equal to the difference between a stockholder’s adjusted tax basis in the shares of common stock sold and the proceeds received by such holder. This gain or loss will generally be long-term gain or loss if a holder sells shares of common stock held for more than one year. Under current law, long-term capital gains of individuals generally are subject to a reduced rate of U.S. federal income tax. Tax-exempt organizations, including employee benefit plans, will not have unrelated business taxable income upon the receipt of dividends from us. Regulated investment companies or mutual funds will have qualifying income as a result of dividends received from us.

		Partnership’s Common Units		Our Shares
Voting		Certain significant decisions require approval by a “unit majority” of the common units. These significant decisions include, among other things: •   merger of the Partnership or the sale of all or substantially all of its assets in certain circumstances; and •   certain amendments to the Partnership’s partnership agreement. For more information, please read “Material Provisions of the Partnership’s Partnership Agreement—Voting Rights.”		Under our amended and restated bylaws, each stockholder is entitled to cast one vote, either in person or by proxy, for each share standing in his or her name on the books of the corporation as of the record date. Our amended and restated certificate of incorporation and amended and restated bylaws contain supermajority voting requirements for certain matters. See “Description of Our Capital Stock—Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law—Certificate of Incorporation and Bylaws.”
Election, Appointment and Removal of General Partner and Directors		Common unitholders do not elect the directors of Targa Resources GP LLC. Instead, these directors are elected annually by us, as the sole equity owner of Targa Resources GP LLC. The Partnership’s general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of the outstanding units, voting together as a single class, including units held by the general partner and its affiliates, and the Partnership receives an opinion of counsel regarding limited liability and tax matters.		We have a staggered board of three classes with each class being elected every three years and only one class elected each year. Also, each director shall hold office until the director’s successor shall have been duly elected and shall qualify or until the director shall resign or shall have been removed. Directors serving on our board may only be removed from office for cause and only by the affirmative vote of a supermajority of our stockholders. See “Description of Our Capital Stock—Anti-Takeover Effects of Provisions of our Amended and Restated Certificate of Incorporation, our Amended and Restated Bylaws and Delaware Law—Certificate of Incorporation and Bylaws.”
Preemptive Rights to Acquire Securities		Common unitholders do not have preemptive rights. Whenever the Partnership issues equity securities to any person other than the General Partner and its affiliates, the General Partner has a preemptive right to purchase additional limited partnership interests on the same terms in order to maintain its percentage interest.		Our stockholders do not have preemptive rights.

		Partnership’s Common Units		Our Shares
Liquidation		The Partnership will dissolve upon any of the following •   the election of the general partner to dissolve the Partnership, if approved by the holders of units representing a unit majority; •   there being no limited partners, unless the Partnership is continued without dissolution in accordance with applicable Delaware law;		We will dissolve upon any of the upon any of the following: •   the entry of a decree of judicial dissolution of us; or •   the approval of at least 67% of our outstanding common stock.
		•   the entry of a decree of judicial dissolution of the Partnership pursuant to applicable Delaware law; or
		•   the withdrawal or removal of the General Partner or any other event that results in its ceasing to be the general partner other than by reason of a transfer of its general partner interest in accordance with the Partnership’s partnership agreement or withdrawal or removal following approval and admission of a successor.

		For the Years Ended December 31,
		2008				2009				2010
		(In millions, except operating, per common share and price data)
Revenues(1)		$	7,998.9			$	4,536.0			$	5,469.2
Product purchases			7,218.5				3,791.1				4,687.7
Gross margin(2)			780.4				744.9				781.5
Operating expenses			275.2				235.0				260.2
Operating margin(3)			505.2				509.9				521.3
Depreciation and amortization expenses			160.9				170.3				185.5
General and administrative expenses			96.4				120.4				144.4
Other			13.4				2.0				(4.7	)
Income from operations			234.5				217.2				196.1
Interest expense, net			(141.2	)			(132.1	)			(110.9	)
Gain on insurance claims			18.5				—				—
Equity in earnings of unconsolidated investments			14.0				5.0				5.4
Gain (loss) on debt repurchases			25.6				(1.5	)			(17.4	)
Gain on early debt extinguishment			3.6				9.7				12.5
Gain (loss) on mark-to-market derivative instruments			(1.3	)			0.3				(0.4	)
Other			—				1.2				0.5
Income tax expense:			(19.3	)			(20.7	)			(22.5	)
Net income			134.4				79.1				63.3
Less: Net income attributable to non controlling interest			97.1				49.8				78.3
Net income (loss) attributable to Targa Resources Corp.			37.3				29.3				(15.0	)
Dividends on Series B preferred stock			(16.8	)			(17.8	)			(9.5	)
Less:
Undistributed earnings attributable to preferred shareholders			(20.5	)			(11.5	)			—
Dividends to common equivalents			—				—				(177.8	)
Net income (loss) available to common shareholders		$	—			$	—			$	(202.3	)
Net income (loss) available per common share—basic and diluted		$	—			$	—			$	(30.94	)
Operating data:
Plant natural gas inlet, MMcf/d(4),(5)			1,846.4				2,139.8				2,268.0
Gross NGL production, MBbl/d			101.9				118.3				121.2
Natural gas sales, BBtu/d(5)			532.1				598.4				685.1
NGL sales, MBbl/d			286.9				279.7				251.5
Condensate sales, MBbl/d			3.8				4.7				3.5
Average realized prices(6):
Natural gas, $/MMBtu		$	8.20			$	3.96			$	4.43
NGL, $/gal			1.38				0.79				1.06
Condensate, $/Bbl			91.28				56.32				73.68

		For the Years Ended December 31,
		2008				2009				2010
		(In millions, except operating, per common share and price data)
Balance Sheet Data (at period end):
Property plant and equipment, net		$	2,617.4			$	2,548.1			$	2,509.0
Total assets			3,641.8				3,367.5				3,393.8
Long-term debt, less current maturities			1,976.5				1,593.5				1,534.7
Convertible cumulative participating Series B preferred stock			290.6				308.4				—
Total owners’ equity			822.0				754.9				1,036.1
Cash Flow Data:
Net cash provided by (used in):
Operating activities		$	390.7			$	335.8			$	208.5
Investing activities			(206.7	)			(59.3	)			(134.6	)
Financing activities			0.9				(386.9	)			(137.9	)

(1)		Includes business interruption insurance revenues of $32.9 million, $21.5 million and $6.0 million for the years ended December 31, 2008, 2009 and 2010.
(2)		Gross margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations” and “—How We Evaluate the Partnership’s Operations.”
(3)		Operating margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations” and “—How We Evaluate the Partnership’s Operations.”
(4)		Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.
(5)		Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.
(6)		Average realized prices include the impact of hedging activities.

 

The nature of our business activities subjects us to certain hazards and risks. You should carefully consider the risks described below, in addition to the other information contained in this prospectus, before making an investment decision. Realization of any of these risks or events could have a material adverse effect on our business, financial condition, cash flows and results of operations, which could result in a decline in the trading price of our common stock, and you may lose all or part of your investment.

 

Risks Inherent in an Investment in Us

 

Our cash flow is dependent upon the ability of the Partnership to make cash distributions to us.

 

Our cash flow consists of cash distributions from the Partnership. The amount of cash that the Partnership will be able to distribute to its partners, including us, each quarter principally depends upon the amount of cash it generates from its business. For a description of certain factors that can cause fluctuations in the amount of cash that the Partnership generates from its business, please read “—Risks Inherent in the Partnership’s Business” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors That Significantly Affect Our Results.” The Partnership may not have sufficient available cash each quarter to continue paying distributions at their current level or at all. If the Partnership reduces its per unit distribution, because of reduced operating cash flow, higher expenses, capital requirements or otherwise, we will have less cash available to pay dividends to our stockholders and would probably be required to reduce the dividend per share of common stock. The amount of cash the Partnership has available for distribution depends primarily upon the Partnership’s cash flow, including cash flow from the release of reserves as well as borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, the Partnership may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records profits.

 

Once we receive cash from the Partnership and the General Partner, our ability to distribute the cash received to our stockholders is limited by a number of factors, including:

 

 

The actual amount of cash that is available for dividends to our stockholders will depend on numerous factors, many of which are beyond our control. For additional information, please read “Our Dividend Policy.”

A reduction in the Partnership’s distributions will disproportionately affect the amount of cash distributions to which we are entitled.

 

Our ownership of the IDRs in the Partnership entitles us to receive specified percentages of the amount of cash distributions made by the Partnership to its limited partners only in the event that the Partnership distributes more than $0.3881 per unit for such quarter. As a result, the holders of the Partnership’s common units have a priority over our IDRs to the extent of cash distributions by the Partnership up to and including $0.3881 per unit for any quarter.

 

Our IDRs entitle us to receive increasing percentages, up to 48%, of all cash distributed by the Partnership. Because the Partnership’s distribution rate is currently above the maximum target cash distribution level on the IDRs, future growth in distributions we receive from the Partnership will not result from an increase in the target cash distribution level associated with the IDRs. Furthermore, a decrease in the amount of distributions by the Partnership to less than $0.50625 per unit per quarter would reduce the General Partner’s percentage of the incremental cash distributions above $0.3881 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from the Partnership would have the effect of disproportionately reducing the distributions that we receive from the Partnership based on our IDRs as compared to distributions we receive from the Partnership with respect to our 2% general partner interest and our common units.

 

If the Partnership’s unitholders remove the General Partner, we would lose our general partner interest and IDRs in the Partnership and the ability to manage the Partnership.

 

We currently manage our investment in the Partnership through our ownership interest in the General Partner. The Partnership’s partnership agreement, however, gives unitholders of the Partnership the right to remove the General Partner upon the affirmative vote of holders of 662/3% of the Partnership’s outstanding units. If the General Partner were removed as general partner of the Partnership, it would receive cash or common units in exchange for its 2% general partner interest and the IDRs and would also lose its ability to manage the Partnership. While the cash or common units the General Partner would receive are intended under the terms of the Partnership’s partnership agreement to fully compensate us in the event such an exchange is required, the value of the investments we make with the cash or the common units may not over time be equivalent to the value of the general partner interest and the IDRs had the General Partner retained them. Please read “Material Provisions of the Partnership’s Partnership Agreement—Withdrawal or Removal of the General Partner.”

 

In addition, if the General Partner is removed as general partner of the Partnership, we would face an increased risk of being deemed an investment company. Please read “—If in the future we cease to manage and control the Partnership, we may be deemed to be an investment company under the Investment Company Act of 1940.”

 

The Partnership, without our stockholders’ consent, may issue additional common units or other equity securities, which may increase the risk that the Partnership will not have sufficient available cash to maintain or increase its cash distribution level per common unit.

 

Because the Partnership distributes to its partners most of the cash generated by its operations, it relies primarily upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion capital expenditures. Accordingly, the Partnership has wide latitude to issue additional common units on the terms and conditions established by its general partner. We receive cash distributions from the Partnership on the general partner interest, IDRs and common units that we own. Because a significant portion of the cash we receive from the Partnership is attributable to our ownership of the IDRs, payment of distributions on additional Partnership common units may increase the risk that the Partnership will be unable to maintain or increase its quarterly cash distribution per unit, which in turn may reduce the amount of distributions we receive attributable to our common units, general partner interest and IDRs and the available cash that we have to pay as dividends to our stockholders.

The General Partner, with our consent but without the consent of our stockholders, may limit or modify the incentive distributions we are entitled to receive, which may reduce cash dividends to you.

 

We own the General Partner, which owns the IDRs in the Partnership that entitle us to receive increasing percentages, up to a maximum of 48% of any cash distributed by the Partnership as certain target distribution levels are reached in excess of $0.3881 per common unit in any quarter. A substantial portion of the cash flow we receive from the Partnership is provided by these IDRs. Because of the high percentage of the Partnership’s incremental cash flow that is distributed to the IDRs, certain potential acquisitions might not increase cash available for distribution per Partnership unit. In order to facilitate acquisitions by the Partnership or for other reasons, the board of directors of the General Partner may elect to reduce the IDRs payable to us with our consent. These reductions may be permanent reductions in the IDRs or may be reductions with respect to cash flows from the potential acquisition. If distributions on the IDRs were reduced for the benefit of the Partnership units, the total amount of cash distributions we would receive from the Partnership, and therefore the amount of cash dividends we could pay to our stockholders, would be reduced.

 

In the future, we may not have sufficient cash to pay estimated dividends.

 

Because our only source of operating cash flow consists of cash distributions from the Partnership, the amount of dividends we are able to pay to our stockholders may fluctuate based on the level of distributions the Partnership makes to its partners, including us. The Partnership may not continue to make quarterly distributions at the 2010 fourth quarter distribution level of $0.5475 per common unit, or may not distribute any other amount, or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease dividends to our stockholders if the Partnership increases or decreases distributions to us, the timing and amount of such changes in distributions, if any, will not necessarily be comparable to the timing and amount of any changes in dividends made by us. Factors such as reserves established by our board of directors for our estimated general and administrative expenses of being a public company as well as other operating expenses, reserves to satisfy our debt service requirements, if any, and reserves for future dividends by us may affect the dividends we make to our stockholders. The actual amount of cash that is available for dividends to our stockholders will depend on numerous factors, many of which are beyond our control.

 

Our cash dividend policy limits our ability to grow.

 

Because we plan on distributing a substantial amount of our cash flow, our growth may not be as fast as the growth of businesses that reinvest their available cash to expand ongoing operations. In fact, because our only cash-generating assets are direct and indirect partnership interests in the Partnership, our growth will be substantially dependent upon the Partnership. If we issue additional shares of common stock or we were to incur debt, the payment of dividends on those additional shares or interest on that debt could increase the risk that we will be unable to maintain or increase our cash dividend levels.

 

Our rate of growth may be reduced to the extent we purchase additional units from the Partnership, which will reduce the relative percentage of the cash we receive from the IDRs.

 

Our business strategy includes, where appropriate, supporting the growth of the Partnership by purchasing the Partnership’s units or lending funds or providing other forms of financial support to the Partnership to provide funding for the acquisition of a business or asset or for a growth project. To the extent we purchase common units or securities not entitled to a current distribution from the Partnership, the rate of our distribution growth may be reduced, at least in the short term, as less of our cash distributions will come from our ownership of IDRs, whose distributions increase at a faster rate than those of our other securities.

We have a credit facility that contains various restrictions on our ability to pay dividends to our stockholders, borrow additional funds or capitalize on business opportunities.

 

We have a credit facility that contains various operating and financial restrictions and covenants. Our ability to comply with these restrictions and covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If we are unable to comply with these restrictions and covenants, any future indebtedness under this credit facility may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.

 

Our credit facility limits our ability to pay dividends to our stockholders during an event of default or if an event of default would result from such dividend.

 

In addition, any future borrowings may:

 

 

Our payment of any principal and interest will reduce our cash available for dividends to holders of common stock. In addition, we are able to incur substantial additional indebtedness in the future. If we incur additional debt, the risks associated with our leverage would increase. For more information regarding our credit facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

 

If dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.

 

Dividends to our stockholders will not be cumulative. Consequently, if dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’s payments in the future.

 

The Partnership’s practice of distributing all of its available cash may limit its ability to grow, which could impact distributions to us and the available cash that we have to dividend to our stockholders.

 

Because our only cash-generating assets are common units and general partner interests in the Partnership, including the IDRs, our growth will be dependent upon the Partnership’s ability to increase its quarterly cash distributions. The Partnership has historically distributed to its partners most of the cash generated by its operations. As a result, it relies primarily upon external financing sources, including debt and equity issuances, to fund its acquisitions and expansion capital expenditures. Accordingly, to the extent the Partnership is unable to finance growth externally, its ability to grow will be impaired because it distributes substantially all of its available cash. Also, if the Partnership incurs additional indebtedness to finance its growth, the increased interest expense associated with such indebtedness may reduce the amount of available cash that we can distribute to you. In addition, to the extent the Partnership issues additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that the Partnership will be unable to maintain or increase its per unit distribution level, which in turn may impact the cash available for dividends to our stockholders.

Restrictions in the Partnership’s senior secured credit facility and indentures could limit its ability to make distributions to us.

 

The Partnership’s senior secured credit facility and indentures contain covenants limiting its ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions. The Partnership’s senior secured credit facility also contains covenants requiring the Partnership to maintain certain financial ratios. The Partnership is prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under its senior secured credit facility or the indentures.

 

If in the future we cease to manage and control the Partnership, we may be deemed to be an investment company under the Investment Company Act of 1940.

 

If we cease to manage and control the Partnership and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contractual rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us and our affiliates, and adversely affect the price of our common stock.

 

Our historical financial information may not be representative of our future performance.

 

The historical financial information included in this prospectus is derived from our historical financial statements, including for periods prior to our initial public offering in December 2010. Our audited historical financial statements were prepared in accordance with GAAP. Accordingly, the historical financial information included in this prospectus does not reflect what our results of operations and financial condition would have been had we been a public entity during the periods presented, or what our results of operations and financial condition will be in the future.

 

If we lose any of our named executive officers, our business may be adversely affected.

 

Our success is dependent upon the efforts of the named executive officers. Our named executive officers are responsible for executing the Partnership’s business strategy and, when appropriate to our primary business objective, facilitating the Partnership’s growth through various forms of financial support provided by us, including, but not limited to, modifying the Partnership’s IDRs, exercising the Partnership’s IDR reset provision contained in its partnership agreement, making loans, making capital contributions in exchange for yielding or non-yielding equity interests or providing other financial support to the Partnership. There is substantial competition for qualified personnel in the midstream natural gas industry. We may not be able to retain our existing named executive officers or fill new positions or vacancies created by expansion or turnover. We have not entered into employment agreements with any of our named executive officers. In addition, we do not maintain “key man” life insurance on the lives of any of our named executive officers. A loss of one or more of our named executive officers could harm our and the Partnership’s business and prevent us from implementing our and the Partnership’s business strategy.

 

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.

 

Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely and reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and

financial reporting capabilities. These enhancements require a significant commitment of resources, personnel and the maintenance of formalized internal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective controls, or difficulties encountered in the effective improvement of our internal controls could prevent us from timely and reliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we or the Partnership are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material effect on our business, results of operations, financial condition and ability to service our and our subsidiaries’ debt obligations.

 

Our shares of common stock and the Partnership’s common units may not trade in relation or proportion to one another.

 

The shares of our common stock and the Partnership’s common units may not trade, either by volume or price, in correlation or proportion to one another. Instead, while the trading prices of our common stock and the Partnership’s common units may follow generally similar broad trends, the trading prices may diverge because, among other things:

 

 

An increase in interest rates may cause the market price of our common stock to decline.

 

Like all equity investments, an investment in our common stock is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments. Reduced demand for our common stock resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common stock to decline.

 

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

 

As a public company with listed equity securities, we must comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange, or NYSE, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements occupies a significant amount of time of our board of directors and management and has significantly increased our costs and expenses. These laws and regulations require us to:

 

 

In addition, being a public company requires us to either accept less director and officer liability insurance coverage than we desire or to incur additional costs to maintain coverage. These factors could make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our Audit Committee, and qualified executive officers.

 

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

 

We or our stockholders may sell shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have 42,349,738 outstanding shares of common stock, 14,691,076 of which will be owned by our directors and executive officers and affiliates of Warburg Pincus LLC (“Warburg Pincus”). A substantial portion of these shares may be sold into the market in the future. Certain of our existing stockholders, including our executive officers, certain of our directors and affiliates of Warburg Pincus, are party to a registration rights agreement with us which requires us to effect the registration of their shares in certain circumstances.

 

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

 

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

 

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

 

 

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors. We have opted out of this provision of Delaware law until such time as Warburg Pincus and certain transferees do not beneficially own at least 15% of our common stock. Please read “Description of Our Capital Stock—Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law.”

 

Merrill Lynch, Pierce, Fenner & Smith Incorporated may have a conflict of interest with respect to this offering.

 

Merrill Lynch Ventures L.P. 2001 (“ML Ventures”), an affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated (“BofA Merrill Lynch”), an underwriter in this offering, will receive more than 5% of the net proceeds of the offering as a selling stockholder. Accordingly, BofA Merrill Lynch’s interest may go beyond receiving customary underwriting discounts and commissions. In particular, there may be a conflict of interest between BofA Merrill Lynch’s own interests as underwriter and the interests of its affiliate, ML Ventures, as a selling stockholder. Because an affiliate of BofA Merrill Lynch will receive more than 5% of the net proceeds, this offering is being conducted in accordance with FINRA Rule 5121. This rule requires, among other things, that a qualified independent underwriter has participated in the preparation of, and has exercised the usual standards of due diligence with respect to, this prospectus and the registration statement of which this prospectus is a part. Accordingly, Barclays Capital Inc. (“Barclays Capital”) is assuming the responsibilities of acting as the qualified independent underwriter in this offering. Although the qualified independent underwriter has participated in the preparation of the registration statement and prospectus and conducted due diligence, we cannot assure you that this will adequately address any potential conflicts of interest related to BofA Merrill Lynch and ML Ventures. We have agreed to indemnify Barclays Capital for acting as qualified independent underwriter against certain liabilities, including liabilities under the Securities Act of 1933 (the “Securities Act”) and to contribute to payments that Barclays Capital may be required to make for these liabilities.

 

We have a significant stockholder, which will limit your ability to influence corporate matters and may give rise to conflicts of interest.

 

Upon completion of this offering, affiliates of Warburg Pincus will beneficially own approximately     % of our outstanding common stock. See “Security Ownership of Management and Selling Stockholders.” Accordingly, Warburg Pincus exerts influence over us and any action requiring the approval of the holders of our stock, including the election of directors and approval of significant corporate transactions. Warburg’s concentrated ownership makes it less likely that any other holder or group of holders of common stock will be able to affect the way we are managed or the direction of our business. These factors also may delay or prevent a change in our management or voting control.

 

Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Warburg Pincus and its affiliates, on the other hand, concerning among other things, potential competitive business activities, business opportunities, the issuance of additional securities, the payment of dividends by us and other matters. Warburg Pincus is a private equity firm that has invested, among other things, in companies in the energy industry. As a result, Warburg Pincus’ existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.

In our amended and restated certificate of incorporation, we have renounced business opportunities that may be pursued by the Partnership or by affiliated stockholders that currently hold a significant amount of our common stock.

 

In our restated charter and in accordance with Delaware law, we have renounced any interest or expectancy we may have in, or being offered an opportunity to participate in, any business opportunities, including any opportunities within those classes of opportunity currently pursued by the Partnership, presented to Warburg Pincus or any private fund that it manages or advises, their affiliates (other than us and our subsidiaries), their officers, directors, partners, employees or other agents who serve as one of our directors, Merrill Lynch Ventures L.P. 2001, its affiliates (other than us and our subsidiaries), and any portfolio company in which such entities or persons has an equity investment (other than us and our subsidiaries) participates or desires or seeks to participate in and that involves any aspect of the energy business or industry. Please read “Description of Our Capital Stock—Corporate Opportunity.”

 

The duties of our officers and directors may conflict with those owed to the Partnership and these officers and directors may face conflicts of interest in the allocation of administrative time among our business and the Partnership’s business.

 

Substantially all of our officers and certain members of our board of directors are officers or directors of the General Partner and, as a result, have separate duties that govern their management of the Partnership’s business. These officers and directors may encounter situations in which their obligations to us, on the one hand, and the Partnership, on the other hand, are in conflict. For a description of how these conflicts will be resolved, please read “Certain Relationships and Related Transactions—Conflicts of Interest.” The resolution of these conflicts may not always be in our best interest or that of our stockholders.

 

In addition, our officers who also serve as officers of the General Partner may face conflicts in allocating their time spent on our behalf and on behalf of the Partnership. These time allocations may adversely affect our or the Partnership’s results of operations, cash flows, and financial condition. For a discussion of our officers and directors that will serve in the same capacity for the General Partner and the amount of time we expect them to devote to our business, please read “Management.”

 

The U.S. federal income tax rate on dividend income is scheduled to increase in 2013.

 

Our distributions to our stockholders will constitute dividends for U.S. federal income tax purposes to the extent such distributions are paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Dividends received by certain non-corporate U.S. stockholders, including individuals, are subject to a reduced maximum federal tax rate of 15% for taxable years beginning on or before December 31, 2012. However, for taxable years beginning after December 31, 2012, dividends received by such non-corporate U.S. stockholders will be taxed at the rate applicable to ordinary income of individuals, which is scheduled to increase to a maximum of 39.6%.

 

Risks Inherent in the Partnership’s Business

 

Because we are directly dependent on the distributions we receive from the Partnership, risks to the Partnership’s operations are also risks to us. We have set forth below risks to the Partnership’s business and operations, the occurrence of which could negatively impact the Partnership’s financial performance and decrease the amount of cash it is able to distribute to us.

 

The Partnership has a substantial amount of indebtedness which may adversely affect its financial position.

 

The Partnership has a substantial amount of indebtedness. As of December 31, 2010, the Partnership had approximately $765.3 million of borrowings outstanding under its senior secured credit facility, approximately $101.3 million of letters of credit outstanding and approximately $233.4 million of additional borrowing capacity under its senior secured credit facility. The Partnership’s $1.1 billion senior secured revolving credit facility allows it to request increases in commitments up to an additional

$300 million. For the years ended December 31, 2008, 2009 and 2010, the Partnership’s consolidated interest expense was $156.1 million, $159.8 million and $110.8 million.

 

This substantial level of indebtedness increases the possibility that the Partnership may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of indebtedness. This substantial indebtedness, combined with the Partnership’s lease and other financial obligations and contractual commitments, could have other important consequences to us, including the following:

 

 

The Partnership’s ability to service its debt will depend upon, among other things, its 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 its control. If the Partnership’s operating results are not sufficient to service its current or future indebtedness, it will be forced to take actions such as reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital and may adversely affect the Partnership’s ability to make cash distributions. The Partnership may not be able to effect any of these actions on satisfactory terms, or at all.

 

Increases in interest rates could adversely affect the Partnership’s business.

 

The Partnership has significant exposure to increases in interest rates. As of December 31, 2010, its total indebtedness was $1,445.4 million, of which $680.1 million was at fixed interest rates and $765.3 million was at variable interest rates. After giving effect to interest rate swaps with a notional amount of $300 million, a one percentage point increase in the interest rate on the Partnership’s variable interest rate debt would have increased its consolidated annual interest expense by approximately $4.7 million. As a result of this significant amount of variable interest rate debt, the Partnership’s financial condition could be adversely affected by significant increases in interest rates.

 

Despite current indebtedness levels, the Partnership may still be able to incur substantially more debt. This could increase the risks associated with its substantial leverage.

 

The Partnership may be able to incur substantial additional indebtedness in the future. As of December 31, 2010, the Partnership had approximately $765.3 million of borrowings outstanding under its senior secured credit facility, approximately, $101.3 million of letters of credit outstanding and approximately $233.4 million of additional borrowing capacity under its senior secured credit facility. The Partnership may be able to incur an additional $300 million of debt under its senior secured credit facility if it requests and is able to obtain commitments for the additional $300 million available under its senior secured credit facility. Although the Partnership’s senior secured credit facility contains restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be

substantial. If the Partnership incurs additional debt, the risks associated with its substantial leverage would increase.

 

The terms of the Partnership’s senior secured credit facility and indentures may restrict its current and future operations, particularly its ability to respond to changes in business or to take certain actions.

 

The credit agreement governing the Partnership’s senior secured credit facility and the indentures governing the Partnership’s senior notes (other than its 111/4% senior notes due 2017) contain, and any future indebtedness the Partnership incurs will likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on its ability to engage in acts that may be in its best long-term interests. These agreements include covenants that, among other things, restrict the Partnership’s ability to:

 

 

In addition, the Partnership’s senior secured credit facility requires it to satisfy and maintain specified financial ratios and other financial condition tests. The Partnership’s ability to meet those financial ratios and tests can be affected by events beyond its control, and we cannot assure you that the Partnership will meet those ratios and tests.

 

A breach of any of these covenants could result in an event of default under the Partnership’s senior secured credit facility and indentures, as applicable. Upon the occurrence of such an event of default, all amounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further credit could be terminated. If the Partnership is unable to repay the accelerated debt under its senior secured credit facility, the lenders under senior secured credit facility could proceed against the collateral granted to them to secure that indebtedness. The Partnership has pledged substantially all of its assets as collateral under its senior secured credit facility. If the Partnership indebtedness under its senior secured credit facility or indentures is accelerated, we cannot assure you that the Partnership will have sufficient assets to repay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may

adversely affect the Partnership’s ability to finance future operations or capital needs or to engage in other business activities.

 

The Partnership’s cash flow is affected by supply and demand for natural gas and NGL products and by natural gas and NGL prices, and decreases in these prices could adversely affect its results of operations and financial condition.

 

The Partnership’s operations can be affected by the level of natural gas and NGL prices and the relationship between these prices. The prices of oil, natural gas and NGLs have been volatile and we expect this volatility to continue. The Partnership’s future cash flow may be materially adversely affected if it experiences significant, prolonged pricing deterioration. The markets and prices for natural gas and NGLs depend upon factors beyond the Partnership’s control. These factors include demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

 

 

The Partnership’s primary natural gas gathering and processing arrangements that expose it to commodity price risk are its percent-of-proceeds arrangements. For the year ended December 31, 2010 and 2009, its percent-of-proceeds arrangements accounted for approximately 38% and 48% of its gathered natural gas volume. Under these arrangements, the Partnership generally processes natural gas from producers and remits 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 its processing facilities. In some percent-of-proceeds arrangements, the Partnership remits to the producer a percentage of an index-based 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, the Partnership’s revenues and its cash flows increase or decrease, whichever is applicable, as the price of natural gas, NGLs and crude oil fluctuates. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.”

 

Because of the natural decline in production in the Partnership’s operating regions and in other regions from which it sources NGL supplies, the Partnership’s long-term success depends on its ability to obtain new sources of supplies of natural gas and NGLs, which depends on certain factors beyond its control. Any decrease in supplies of natural gas or NGLs could adversely affect the Partnership’s business and operating results.

 

The Partnership’s gathering systems are connected to oil and natural gas wells from which production will naturally decline over time, which means that its cash flows associated with these sources of natural gas will likely also decline over time. The Partnership’s logistics assets are similarly

impacted by declines in NGL supplies in the regions in which the Partnership operates as well as other regions from which it sources NGLs. To maintain or increase throughput levels on its gathering systems and the utilization rate at its processing plants and its treating and fractionation facilities, the Partnership must continually obtain new natural gas and NGL supplies. A material decrease in natural gas production from producing areas on which the Partnership relies, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of natural gas that it processes and NGL products delivered to its fractionation facilities. The Partnership’s ability to obtain additional sources of natural gas and NGLs depends, in part, on the level of successful drilling and production activity near its gathering systems and, in part, on the level of successful drilling and production in other areas from which it sources NGL supplies. The Partnership has no control over the level of such activity in the areas of its operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, the Partnership has 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, other production and development costs and the availability and cost of capital.

 

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 and production activity generally decreases as oil and natural gas prices decrease. Prices of oil and natural gas have been historically volatile, and the Partnership expects this volatility to continue. Consequently, even if new natural gas reserves are discovered in areas served by the Partnership’s assets, producers may choose not to develop those reserves. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas in which the Partnership operates may prevent it from obtaining supplies of natural gas to replace the natural decline in volumes from existing wells, which could result in reduced volumes through its facilities, and reduced utilization of its gathering, treating, processing and fractionation assets.

 

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

 

The Partnership’s ability to grow depends, in part, on its ability to make acquisitions that result in an increase in cash generated from operations per unit. The Partnership is unable to acquire businesses from us in order to grow because our only assets are the interests in the Partnership that we own. As a result, it will need to focus on third-party acquisitions and organic growth. If the Partnership is unable to make these accretive acquisitions either because the Partnership is (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 its 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 the Partnership’s growth, fail to deliver expected benefits and add further unexpected costs. Challenges may arise whenever businesses with different operations or management are combined and the Partnership may experience unanticipated delays in realizing the benefits of an acquisition. If the Partnership consummates any future acquisition, its capitalization and results of operations may change significantly and you may not have the opportunity to evaluate the economic, financial and other relevant information that the Partnership will consider in evaluating future acquisitions.

 

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

 

Acquisitions may significantly increase the Partnership’s size and diversify the geographic areas in which it operates. The Partnership may not achieve the desired affect from any future acquisitions.

 

The Partnership’s 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 its results of operations and financial condition.

 

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

 

The Partnership’s acquisition strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair its ability to grow through acquisitions.

 

The Partnership continuously considers and enters into discussions regarding potential acquisitions. Any limitations on its access to capital will impair its ability to execute this strategy. If the

cost of such capital becomes too expensive, its ability to develop or acquire strategic and accretive assets will be limited. The Partnership may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence the Partnership’s initial cost of equity include market conditions, fees it pays to underwriters and other offering costs, which include amounts it pays for legal and accounting services. The primary factors influencing the Partnership’s cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges it pays to lenders.

 

Weak economic conditions and the volatility and disruption in the financial markets could increase the cost of raising money in the debt and equity capital markets substantially while diminishing the availability of funds from those markets. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers. These factors may impair the Partnership’s ability to execute its acquisition strategy.

 

In addition, the Partnership is experiencing increased competition for the types of assets it contemplates purchasing. Weak economic conditions and competition for asset purchases could limit the Partnership’s ability to fully execute its growth strategy.

 

Demand for propane is seasonal and requires increases in the Partnership’s inventory to meet seasonal demand.

 

Weather conditions have a significant impact on the demand for propane because end-users depend on propane principally for heating purposes. Warmer-than-normal temperatures in one or more regions in which the Partnership operates can significantly decrease the total volume of propane it sells. Lack of consumer demand for propane may also adversely affect the retailers with which the Partnership transacts in its wholesale propane marketing operations, exposing it to their inability to satisfy their contractual obligations to the Partnership.

 

If the Partnership fails to balance its purchases of natural gas and its sales of residue gas and NGLs, its exposure to commodity price risk will increase.

 

The Partnership may not be successful in balancing its purchases of natural gas and its sales of residue gas and NGLs. In addition, a producer could fail to deliver promised volumes to the Partnership or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance between the Partnership’s purchases and sales. If the Partnership’s purchases and sales are not balanced, it will face increased exposure to commodity price risks and could have increased volatility in its operating income.

 

The Partnership’s hedging activities may not be effective in reducing the variability of its cash flows and may, in certain circumstances, increase the variability of its cash flows. Moreover, the Partnership’s hedges may not fully protect it against volatility in basis differentials. Finally, the percentage of the Partnership’s expected equity commodity volumes that are hedged decreases substantially over time.

 

The Partnership has entered into derivative transactions related to only a portion of its equity volumes. As a result, it will continue to have direct commodity price risk to the unhedged portion. The Partnership’s actual future volumes may be significantly higher or lower than it estimated at the time it entered into the derivative transactions for that period. If the actual amount is higher than it estimated, it will have greater commodity price risk than it intended. If the actual amount is lower than the amount that is subject to its derivative financial instruments, it might be forced to satisfy all or a portion of its derivative transactions without the benefit of the cash flow from its sale of the underlying physical commodity. The percentages of the Partnership’s expected equity volumes that are covered by its hedges decrease over time. To the extent the Partnership hedges its commodity price risk, it may forego the benefits it would

otherwise experience if commodity prices were to change in its favor. The derivative instruments the Partnership utilizes for these hedges are based on posted market prices, which may be higher or lower than the actual natural gas, NGLs and condensate prices that it realizes in its operations. These pricing differentials may be substantial and could materially impact the prices the Partnership ultimately realizes. In addition, current market and economic conditions may adversely affect the Partnership’s hedge counterparties’ ability to meet their obligations. Given the current volatility in the financial and commodity markets, the Partnership may experience defaults by its hedge counterparties in the future. As a result of these and other factors, the Partnership’s hedging activities may not be as effective as it intends in reducing the variability of its cash flows, and in certain circumstances may actually increase the variability of its cash flows. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.”

 

If third-party pipelines and other facilities interconnected to the Partnership’s natural gas pipelines and processing facilities become partially or fully unavailable to transport natural gas and NGLs, the Partnership’s revenues could be adversely affected.

 

The Partnership depends upon third-party pipelines, storage and other facilities that provide delivery options to and from its pipelines and processing facilities. Since it does not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within the Partnership’s control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict the Partnership’s ability to utilize them, its revenues could be adversely affected.

 

The Partnership’s industry is highly competitive, and increased competitive pressure could adversely affect the Partnership’s business and operating results.

 

The Partnership competes with similar enterprises in its respective areas of operation. Some of its competitors are large oil, natural gas and natural gas liquid companies that have greater financial resources and access to supplies of natural gas and NGLs than it does. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services the Partnership provides to its customers. In addition, its customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using the Partnership’s. The Partnership’s ability to renew or replace existing contracts with its customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of its competitors and its customers. All of these competitive pressures could have a material adverse effect on the Partnership’s business, results of operations, and financial condition.

 

The Partnership typically does not obtain independent evaluations of natural gas reserves dedicated to its gathering pipeline systems; therefore, volumes of natural gas on the Partnership’s systems in the future could be less than it anticipates.

 

The Partnership typically does not obtain independent evaluations of natural gas reserves connected to its gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, the Partnership does not have independent estimates of total reserves dedicated to its gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to its gathering systems is less than it anticipates and the Partnership is unable to secure additional sources of natural gas, then the volumes of natural gas transported on its gathering systems in the future could be less than it anticipates. A decline in the volumes of natural gas on the Partnership’s systems could have a material adverse effect on its business, results of operations, and financial condition.

A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel markets, or a significant increase in NGL product supply relative to this demand, could materially adversely affect the Partnership’s business, results of operations and financial condition.

 

The NGL products the Partnership produces have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general or industry specific economic conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction industries), increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a decline in the volume of NGL products the Partnership handles or reduce the fees it charges for its services. Also, increased supply of NGL products could reduce the value of NGLs handled by the Partnership and reduce the margins realized. The Partnership’s NGL products and their demand are affected as follows:

 

Ethane.  Ethane is typically supplied as purity ethane and as part of ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream thereby reducing the volume of NGLs delivered for fractionation and marketing.

 

Propane.  Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for the Partnership’s propane may be reduced during periods of warmer-than-normal weather.

 

Normal Butane.  Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, either alone or in a mixture with propane, and in the production of ethylene and propylene. Changes in the composition of refined products resulting from governmental regulation, changes in feedstocks, products and economics, demand for heating fuel and for ethylene and propylene could adversely affect demand for normal butane.

 

Isobutane.  Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.

 

Natural Gasoline.  Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation and in demand for ethylene and propylene could adversely affect demand for natural gasoline.

 

NGLs and products produced from NGLs also compete with products from global markets. Any reduced demand or increased supply for ethane, propane, normal butane, isobutane or natural gasoline in the markets the Partnership’s accesses for any of the reasons stated above could adversely affect demand for the services it provides as well as NGL prices, which would negatively impact the Partnership’s results of operations and financial condition.

The Partnership has significant relationships with Chevron Phillips Chemical Company LLC as a customer for its marketing and refinery services. In some cases, these agreements are subject to renegotiation and termination rights.

 

For the years ended December 31, 2010 and 2009, approximately 10% and 15% of the Partnership’s consolidated revenues were derived from transactions with Chevron Phillips Chemical Company LLC (“CPC”). Under many of the Partnership’s CPC contracts where it purchases or markets NGLs on CPC’s behalf, CPC may elect to terminate the contracts or renegotiate the price terms. To the extent CPC reduces the volumes of NGLs that it purchases from the Partnership or reduces the volumes of NGLs that the Partnership markets on its behalf, or to the extent the economic terms of such contracts are changed, the Partnership’s revenues and cash available for debt service could decline.

 

The tax treatment of the Partnership depends on its status as a partnership for federal income tax purposes as well as its not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat the Partnership as a corporation for federal income tax purposes or the Partnership becomes subject to a material amount of entity-level taxation for state tax purposes, then its cash available for distribution to its unitholders, including us, would be substantially reduced.

 

We currently own an approximate 13.5% limited partner interest, a 2% general partner interest and the IDRs in the Partnership. The anticipated after-tax economic benefit of our investment in the Partnership depends largely on its being treated as a partnership for federal income tax purposes. In order to maintain its status as a partnership for United States federal income tax purposes, 90 percent or more of the gross income of the Partnership for every taxable year must be “qualifying income” under section 7704 of the Internal Revenue Code of 1986, as amended. The Partnership has not requested and does not plan to request a ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes.

 

Despite the fact that the Partnership is a limited partnership under Delaware law, it is possible, under certain circumstances for an entity such as the Partnership to be treated as a corporation for federal income tax purposes. Although the Partnership does not believe based upon its current operations that it is so treated, a change in the Partnership’s business could cause it to be treated as a corporation for federal income tax purposes or otherwise subject it to federal income taxation as an entity.

 

If the Partnership were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to the Partnership’s unitholders, including us, would generally be taxed again as corporate distributions and no income, gains, losses or deductions would flow through to the Partnership’s unitholders, including us. If such tax was imposed upon the Partnership as a corporation, its cash available for distribution would be substantially reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Partnership’s unitholders, including us, and would likely cause a substantial reduction in the value of our investment in the Partnership.

 

In addition, current law may change so as to cause the Partnership to be treated as a corporation for federal income tax purposes or otherwise subject the Partnership to entity-level taxation for state or local income tax purposes. At the federal level, members of Congress have recently considered legislative changes that would affect the tax treatment of certain publicly traded partnerships. Although the considered legislation would not appear to have affected the Partnership’s treatment as a partnership, we are unable to predict whether any of these changes, or other proposals will be reintroduced or will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in the Partnership’s common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, the Partnership is required to pay Texas franchise tax at a maximum effective rate of 0.7% of its gross income apportioned

to Texas in the prior year. Imposition of any similar tax on the Partnership by additional states would reduce the cash available for distribution to Partnership unitholders, including us.

 

The Partnership’s partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects it to taxation as a corporation or otherwise subjects it to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution and the target distribution amounts may be adjusted to reflect the impact of that law on the Partnership.

 

The Partnership does not own most of the land on which its pipelines and compression facilities are located, which could disrupt its operations.

 

The Partnership does not own most of the land on which its pipelines and compression facilities are located, and the Partnership is therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if it does not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. The Partnership sometimes obtains the rights to land owned by third parties and governmental agencies for a specific period of time. The Partnership’s loss of these rights, through its inability to renew right-of-way contracts, leases or otherwise, could cause it to cease operations on the affected land, increase costs related to continuing operations elsewhere, and reduce its revenue.

 

The Partnership may be unable to cause its majority-owned joint ventures to take or not to take certain actions unless some or all of its joint venture participants agree.

 

The Partnership participates in several majority-owned joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business, among others. Without the concurrence of joint venture participants with enough voting interests, the Partnership may be unable to cause any of its joint ventures to take or not take certain actions, even though taking or preventing those actions may be in the best interest of the Partnership or the particular joint venture.

 

In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners. Any such transaction could result in the Partnership partnering with different or additional parties.

 

Weather may limit the Partnership’s ability to operate its business and could adversely affect its operating results.

 

The weather in the areas in which the Partnership operates can cause disruptions and in some cases suspension of its operations. For example, unseasonably wet weather, extended periods of below-freezing weather and hurricanes may cause disruptions or suspensions of the Partnership’s operations, which could adversely affect its operating results.

The Partnership’s business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or event occurs that is not fully insured, if the Partnership fails to recover all anticipated insurance proceeds for significant accidents or events for which it is insured, or if it fails to rebuild facilities damaged by such accidents or events, its operations and financial results could be adversely affected.

 

The Partnership’s operations are subject to many hazards inherent in gathering, compressing, treating, processing and selling natural gas and storing, fractionating, treating, transporting and selling NGLs, including:

 

 

These risks could result in substantial losses due to personal injury, 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 the Partnership’s related operations. A natural disaster or other hazard affecting the areas in which the Partnership operates could have a material adverse effect on its operations. For example, Hurricanes Katrina and Rita damaged gathering systems, processing facilities, NGL fractionators and pipelines along the Gulf Coast, including certain of the Partnership’s facilities. These hurricanes disrupted the operations of the Partnership’s customers in August and September 2005, which curtailed or suspended the operations of various energy companies with assets in the region. The Louisiana and Texas Gulf Coast was similarly impacted in September 2008 as a result of Hurricanes Gustav and Ike. The Partnership is not fully insured against all risks inherent to its business. The Partnership is not insured against all environmental accidents that might occur which may include toxic tort claims, other than incidents considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, if the Partnership fails to recover all anticipated insurance proceeds for significant accidents or events for which it is insured, or if it fails to rebuild facilities damaged by such accidents or events, its operations and financial condition could be adversely affected. In addition, the Partnership may not be able to maintain or obtain insurance of the type and amount it desires at reasonable rates. As a result of market conditions, premiums and deductibles for certain of the Partnership’s 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 were generally less favorable than terms that could be obtained prior to such hurricanes. Insurance market conditions worsened as a result of the losses sustained from Hurricanes Gustav and Ike in September 2008. As a result, the Partnership experienced further increases in deductibles and premiums, and further reductions in coverage and limits, with some coverages unavailable at any cost.

 

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

 

Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the DOT, through the PHMSA, 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:

 

 

In addition, states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. The Partnership currently estimates that it will incur an aggregate cost of approximately $6.6 million between 2011 and 2013 to implement pipeline integrity management program testing along certain segments of its 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, the Partnership cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, 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. The Partnership will continue its pipeline integrity testing programs to assess and maintain the integrity of its pipelines. The results of these tests could cause the Partnership to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of its pipelines.

 

Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase the Partnership’s exposure to commodity price movements.

 

The Partnership sells processed natural gas to third parties at plant tailgates or at pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. The Partnership attempts to balance sales with volumes supplied from processing operations, but unexpected volume variations due to production variability or to gathering, plant or pipeline system disruptions may expose the Partnership to volume imbalances which, in conjunction with movements in commodity prices, could materially impact the Partnership’s income from operations and cash flow.

 

The Partnership requires a significant amount of cash to service its indebtedness. The Partnership’s ability to generate cash depends on many factors beyond its control.

 

The Partnership’s ability to make payments on and to refinance its indebtedness and to fund planned capital expenditures depends on its ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond its control. We cannot assure you that the Partnership will generate sufficient cash flow from operations or that future borrowings will be available to it under its credit agreement or otherwise in an amount sufficient to enable it to pay its indebtedness or to fund its other liquidity needs. The Partnership may need to refinance all or a portion of its indebtedness at or before maturity. The Partnership cannot assure you that it will be able to refinance any of its indebtedness on commercially reasonable terms or at all.

 

Failure to comply with existing or new environmental laws or regulations or an accidental release of hazardous substances, hydrocarbons or wastes into the environment may cause the Partnership to incur significant costs and liabilities.

 

The Partnership’s 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, as amended, (“RCRA”) and comparable state laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from the Partnership’s facilities, (3) the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, (“CERCLA” or the “Superfund” law) 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 the Partnership’s hazardous substances have been transported for recycling or disposal and (4) the Clean Water Act and comparable state laws that regulate discharges of wastewater from the Partnership’s 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 or other sanctions, the imposition of remedial obligations 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, hydrocarbons or waste products 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 noise, odor or the release of hazardous substances, hydrocarbons or waste products into the environment.

 

There is inherent risk of incurring environmental costs and liabilities in connection with the Partnership’s operations due to its handling of natural gas, NGLs and other petroleum products, because of air emissions and water discharges related to its operations, and as a result of historical industry operations and waste disposal practices. For example, an accidental release from one of the Partnership’s facilities could subject it to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages and fines or penalties for related violations of environmental laws or regulations.

 

Moreover, stricter laws, regulations or enforcement policies could significantly increase the Partnership’s operational or compliance costs and the cost of any remediation that may become necessary. For instance, since August 2009, the Texas Commission on Environmental Quality (“TCEQ”) has conducted a comprehensive analysis of air emissions in the Barnett Shale area in response to reported concerns about high concentrations of benzene in the air near drilling sites and natural gas processing facilities. Partially in response to its investigation, on January 26, 2011, the TCEQ adopted new air permitting requirements for oil and gas facilities in the state, which first became applicable to facilities located in the Barnett Shale area as of February 1, 2011. These new requirements may require the Partnership to incur increased capital or operating costs. Moreover, the agency’s investigations could lead to additional, more stringent air permitting requirements, increased regulation, and possible enforcement actions against producers and midstream operators in the Barnett Shale area. The Partnership is also conducting its own evaluation of air emissions at certain of its facilities in the Barnett Shale area and, as necessary, plans to conduct corrective actions at such facilities. Additionally, environmental groups have advocated increased regulation and a moratorium on the issuance of drilling permits for new natural gas wells in the Barnett Shale area. The adoption of any laws, regulations or other legally enforceable mandates that result in more stringent air emission limitations or that restrict or prohibit the drilling of new natural gas wells for any extended period of time could increase the Partnership’s operating and compliance costs as well as reduce the rate of production of natural gas operators with whom the Partnership has a business relationship, which could have a material adverse effect on the Partnership’s results of operations and cash flows.

Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the Partnership’s revenues by decreasing the volumes of natural gas that the Partnership gathers, processes and fractionates.

 

Hydraulic fracturing is a process used by oil and gas exploration and production operators in the completion of certain oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and, to a lesser extent, oil production. The process is typically regulated by state oil and gas commissions. However, the U.S. Environmental Protection Agency (“EPA”) recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (“SDWA”) Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential adverse impact of hydraulic fracturing activities, with the initial results of the study expected to be available in late 2012 with completion of this study in 2014. Also, legislation that was introduced in the 111^th session of Congress has been re-introduced in the 112^th Congress that would amend the SDWA to subject hydraulic fracturing operations to regulation under the SDWA and require both pre-fracturing and post-fracturing disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Moreover, some states have adopted, and other states, including Texas, are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. Adoption of legislation or of any implementing regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect the Partnership’s revenues and results of operations by decreasing the volumes of natural gas that it gathers, processes and fractionates. Moreover, required disclosure without protection for trade secret or proprietary products could discourage service companies from using such products and as a result impact the degree to which some oil and natural gas wells may be efficiently and economically completed or brought into production.

 

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

 

Venice Gathering System, L.L.C. (“VGS”) is a wholly owned subsidiary of Venice Energy Services Company, L.L.C. (“VESCO”) engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (“NGA”). VGS owns and operates a natural gas gathering system extending from South Timbalier Block 135 to an onshore interconnection to a natural gas processing plant owned by VESCO. With the exception of our interest in VGS, our operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses. The NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. The Partnership believes that the natural gas pipelines in its 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 the Partnership’s gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. In addition, the courts have determined that certain pipelines that would otherwise be subject to the Interstate Commerce Act (“ICA”) are exempt from such regulation by FERC under the ICA as proprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. At this time, the Partnership does not have any such proprietary lines. The classification and regulation of some of the Partnership’s gathering facilities and transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress.

While the Partnerships’ natural gas gathering operations are generally exempt from FERC regulation under the NGA, its gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. FERC has issued a final rule (as amended by orders on rehearing and clarification), Order 704, requiring certain participants in the natural gas market, including intrastate pipelines, natural gas gatherers, natural gas marketers and natural gas processors, that engage in a minimum level of natural gas sales or purchases to submit annual reports regarding those transactions to FERC. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.

 

In addition, FERC has issued a final rule, (as amended by orders on rehearing and clarification), Order 720, requiring major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtus of gas over the previous three calendar years, to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has design capacity equal to or greater than 15,000 MMBtu/d and requiring interstate pipelines to post information regarding the provision of no-notice service. The Partnership takes the position that at this time it and its subsidiaries are exempt from this rule as currently written. A petition for review of Order 720 is currently pending before the Court of Appeals for the Fifth Circuit, and the Partnership has no way to predict with certainty whether and to what extent Order 720 will be modified in response to the petition for review.

 

In addition, FERC recently issued an order extending certain of the open-access requirements including the prohibition on buy/sell arrangements and shipper-must-have-title provisions to include Hinshaw pipelines to the extent such pipelines provide interstate service. However, FERC issued a Notice of Inquiry on October 21, 2010, effectively suspending the recent ruling and requesting comments on whether and how holders of firm capacity on Section 311 and Hinshaw pipelines should be permitted to allow others to make use of their firm interstate capacity, including to what extent buy/sell transactions should be permitted.

 

Other FERC regulations may indirectly impact the Partnership’s 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. For more information regarding the regulation of our and the Partnership’s operations, see “Business of Targa Resources Partners LP—Regulation of Operations.”

 

Should the Partnership fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines.

 

Under the Domenici-Barton Energy Policy Act of 2005 (“EP Act 2005”), which is applicable to VGS, 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. While the Partnership’s systems have not been regulated by FERC as a natural gas companies under the NGA, FERC has adopted regulations that may subject certain of its otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject the Partnership to civil penalty liability. For more information regarding the regulation of our and the Partnership’s operations, see “Business of Targa Resources Partners LP—Regulation of Operations.”

The adoption of climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the products and services we provide.

 

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has already adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources effective January 2, 2011. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing or requiring state environmental agencies to implement the rules. The EPA has also adopted rules requiring the annual reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring after January 1, 2010, as well as emissions from certain onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities on an annual basis, beginning in 2012 for emissions occurring in 2011.

 

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require the Partnership to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the natural gas and NGLs the Partnership processes or fractionates. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Partnership’s business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Partnership’s financial condition and results of operations.

 

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Partnership’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.

 

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010, and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets, and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require the Partnership to comply with margin requirements and with certain clearing and trade-execution requirements in connection with its derivative activities, although

the application of those provisions to the Partnership is uncertain at this time. The financial reform legislation may also require counterparties to the Partnership’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect the Partnership’s available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Partnership encounters, reduce the Partnership’s ability to monetize or restructure its existing derivative contracts, and increase the Partnership’s exposure to less creditworthy counterparties. If the Partnership reduces its use of derivatives as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Partnership’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Partnership, its financial condition, and its results of operations.

 

The Partnership’s interstate common carrier liquids pipeline is regulated by the Federal Energy Regulatory Commission.

 

Targa NGL Pipeline Company LLC (“Targa NGL”), one of the Partnership’s subsidiaries, is an interstate NGL common carrier subject to regulation by FERC under the ICA. Targa NGL owns a twelve inch diameter pipeline that runs between Lake Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move mixed NGL and purity NGL products. Targa NGL also owns an eight inch diameter pipeline and a 20 inch diameter pipeline each of which run between Mont Belvieu, Texas and Galena Park, Texas. The eight inch and the 20 inch pipelines are part of an extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides services to domestic and foreign import and export customers. The ICA requires that the Partnership maintain tariffs on file with FERC for each of these pipelines. Those tariffs set forth the rates the Partnership charges for providing transportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and non-discriminatory. All shippers on these pipelines are the Partnership’s subsidiaries.

 

Recent events in the Gulf of Mexico may adversely affect the operations of the Partnership.

 

In April 2010, the Transocean Deepwater Horizon drilling rig exploded and subsequently sank 130 miles south of New Orleans, Louisiana, in the ultra deep water of the Gulf of Mexico, and the resulting release of crude oil into the Gulf of Mexico was declared a Spill of National Significance by the United States Department of Homeland Security. Response actions to the release are continuing in the Gulf of Mexico. Moreover, the federal Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) has developed and adopted a series of changes to its regulations to impose a variety of new safety and operating measures intended to help prevent a similar disaster in the future. Consequently, before being allowed to resume drilling in deepwater, outer continental shelf operators must now comply with strict new safety and operating requirements and also must demonstrate the availability of adequate spill response and blowout preventer containment resources. The Partnership cannot predict with any certainty the impact of this oil spill, the extent of cleanup activities associated with this spill, or the affects of changes in regulations adopted by BOEMRE or possible changes in laws or regulations that still may be enacted in response to this spill, but this event and its aftermath could adversely affect the Partnership’s operations. It is possible that the direct results of the spill and clean-up efforts could interrupt certain offshore production processed by our facilities as offshore exploration and productions operators work to comply with new legal requirements. Furthermore, additional governmental regulation of, or delays in issuance of permits for, the offshore exploration and production industry may negatively impact current or future volumes being gathered or processed by the Partnership’s facilities, and may potentially reduce volumes in its Downstream logistics and marketing business.

Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to the Partnership’s business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact the Partnership’s 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 the Partnership’s industry in general and on it in particular is not known at this time. However, resulting regulatory requirements and/or related business decisions associated with security are likely to increase the Partnership’s costs.

 

Increased security measures taken by the Partnership as a precaution against possible terrorist attacks have resulted in increased costs to its business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect the Partnership’s operations in unpredictable ways, including disruptions of crude oil supplies and markets for its products, and the possibility that infrastructure facilities could be direct targets, 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 the Partnership to obtain. Moreover, the insurance that may be available to the Partnership may be significantly more expensive than its existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect the Partnership’s ability to raise capital.

 

We will not receive any of the net proceeds from any sale of shares of common stock by any selling stockholder. We expect to incur approximately $0.75 million of expenses in connection with this offering, including all expenses of the selling stockholders which we have agreed to pay.

 

Our common stock has been listed on the New York Stock Exchange since December 7, 2010 under the symbol “TRGP.” The following table sets forth the high and low sales prices of the common stock, as reported by the NYSE through April 12, 2011.

 

 

 

 

 

 

The last reported sales price of our common stock on the NYSE on April 12, 2011 was $32.78. As of April 12, 2011, there were approximately 219 stockholders of record of our common stock. This number does not include stockholders whose shares are held in trust by other entities. The actual number of stockholders is greater than the number of holders of record.

 

General

 

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

 

 

On April 11, 2011, we announced that our board of directors declared a quarterly cash dividend of $0.2725 per share of common stock, or $1.09 per share on an annualized basis for the first quarter of 2011. This cash dividend will be paid on May 17, 2011 on all outstanding shares of common stock to holders of record as of the close of business on April 21, 2011. If we close this offering on or prior to the record date on April 21, 2011, the shares of common stock sold in this offering will receive the declared dividend of $0.2725 per share of common stock for the first quarter of 2011. If we do not close this offering on or prior to the record date on April 21, 2011, then the shares of common stock sold in this offering will not receive the declared dividend. If the Partnership is successful in implementing its business strategy and increasing distributions to its partners, we would generally expect to increase dividends to our stockholders, although the timing and amount of any such increased dividends will not necessarily be comparable to the increased Partnership distributions. We cannot assure you that any dividends will be declared or paid in the future.

 

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

 

Overview of Dividends

 

During the past three fiscal years, our stockholders have received dividends from us on a pro rata basis. Holders of our previously outstanding preferred stock received their pro rata share of (i) an $18 million dividend paid on November 22, 2010; (ii) a $220 million extraordinary dividend paid in April 2010; (iii) a $200 million extraordinary dividend paid on the common stock (treating the preferred stock on a common stock equivalent basis) in April 2010; and (iv) a $445 million dividend paid in 2007. Holders of our common stock received their pro rata share of the $200 million extraordinary dividend paid in April 2010 (treating the preferred stock on a common stock equivalent basis).

The Partnership’s Cash Distribution Policy

 

Under the Partnership’s partnership agreement, available cash is defined to generally mean, for each fiscal quarter, all cash on hand at the date of determination of available cash for that quarter less the amount of cash reserves established by the General Partner to provide for the proper conduct of the Partnership’s business, to comply with applicable law or any agreement binding on the Partnership and its subsidiaries and to provide for future distributions to the Partnership’s unitholders for any one or more of the upcoming four quarters. The determination of available cash takes into account the possibility of establishing cash reserves in some quarterly periods that the Partnership may use to pay cash distributions in other quarterly periods, thereby enabling it to maintain relatively consistent cash distribution levels even if the Partnership’s business experiences fluctuations in its cash from operations due to seasonal and cyclical factors. The General Partner’s determination of available cash also allows the Partnership to maintain reserves to provide funding for its growth opportunities. The Partnership makes its quarterly distributions from cash generated from its operations, and those distributions have grown over time as its business has grown, primarily as a result of numerous acquisitions and organic expansion projects that have been funded through external financing sources and cash from operations.

 

The actual cash distributions paid by the Partnership to its partners occur within 45 days after the end of each quarter. Since second quarter 2007, the Partnership has increased its quarterly cash distribution 8 times. During that time period, the Partnership has increased its quarterly distribution by 65% from $0.3375 per common unit, or $1.35 on an annualized basis, to $0.5575 per common unit, or $2.23 on an annualized basis. Please see “The Partnership’s Cash Distribution Policy.”

 

The following table presents selected historical consolidated financial and operating data of Targa Resources Corp. for the periods and as of the dates indicated. The selected historical consolidated statement of operations and cash flow data for the years ended December 31, 2008, 2009 and 2010 and selected historical consolidated balance sheet data as of December 31, 2009 and 2010 have been derived from our audited financial statements, and that information should be read together with and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes beginning on page F-1 of this prospectus.

 

The selected historical consolidated statement of operations and cash flow data for the years ended December 31, 2006 and 2007 and the selected historical consolidated balance sheet data as of December 31, 2006, 2007 and 2008 have been derived from audited financial statements that are not included in this prospectus.

 

 

 

 

You should read the following discussion of our financial condition and results of operations in conjunction with the historical consolidated financial statements and notes thereto included elsewhere in this prospectus. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the historical financial statements included elsewhere in this prospectus. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding certain risks inherent in our and the Partnership’s business.

 

Overview

 

Financial Presentation

 

An indirect subsidiary of ours is the sole member of the General Partner. Because we control the General Partner, under generally accepted accounting principles we must reflect our ownership interest in the Partnership on a consolidated basis. Accordingly, our financial results are combined with the Partnership’s financial results in our consolidated financial statements even though the distribution or transfer of Partnership assets are limited by the terms of the partnership agreement, as well as restrictive covenants in the Partnership’s lending agreements. The limited partner interests in the Partnership not owned by us are reflected in our results of operations as net income attributable to non-controlling interests. Therefore, throughout this discussion, we make a distinction where relevant between financial results of the Partnership versus those of us as a standalone parent including our non-Partnership subsidiaries.

 

General

 

The Partnership is a leading provider of midstream natural gas and NGL services in the United States. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas, storing, fractionating, treating, transporting and selling NGLs and NGL products and storing and terminaling refined petroleum products and crude oil. It operates through two divisions: the Natural Gas Gathering and Processing division and the Logistics and Marketing division.

 

As a result of the conveyance of all of our remaining operating assets to the Partnership in September 2010, we currently have no separate, direct operating activities apart from those conducted by the Partnership. As such, our cash inflows will primarily consist of cash distributions from our interests in the Partnership. The Partnership is required to distribute all available cash at the end of each quarter after establishing reserves to provide for the proper conduct of its business or to provide for future distributions.

 

The results of operations included in our consolidated financial statements will differ from the results of operations of the Partnership primarily due to the financial effects of: non-controlling interests in the Partnership, our separate debt obligations, certain general and administrative costs applicable to us as a separate public company, and certain non-operating assets and liabilities that we retained and were not included in the asset conveyances to the Partnership.

 

Factors That Significantly Affect Our Results

 

Our cash flow and resulting ability to pay dividends depends upon the Partnership’s ability to make distributions to its partners, including us. The actual amount of cash that the Partnership has available for distributions depends primarily on the amount of cash that it generates from its operations.

 

As of April 12, 2011, our interests in the Partnership consist of the following:

 

 

 

Cash Distributions

 

The following table sets forth the historical distributions that the Partnership has paid in respect of our 2% general partner interest, the associated IDRs and actual common units that we held during the periods indicated. The amount of these Partnership distributions available for distribution to us and the Partnership’s shareholders will be after reserves are established for the Partnership’s capital contributions, debt service requirements, general, administrative and other expenses, future distributions and other miscellaneous uses of cash. We will not distribute all of the cash that we receive from the Partnership to our shareholders, as we will establish reserves for capital contributions, debt service requirements, general, administrative and other expenses, future distributions and other miscellaneous uses of cash.

 

 

 

 

Factors That Significantly Affect the Partnership’s Results

 

The Partnership’s results of operations are substantially impacted by the volumes that move through its gathering and processing and logistics assets, its contract terms and changes in commodity prices.

 

Volumes.  In the Partnership’s gathering and processing operations, plant inlet volumes and capacity utilization rates generally are driven by wellhead production, its competitive and contractual position on a regional basis and more broadly by the impact of prices for oil, natural gas and NGLs on exploration and production activity in the areas of its operations. The factors that impact the gathering and processing volumes also impact the total volumes that flow to the Partnership’s Downstream Business. In addition, fractionation volumes are also affected by the location of the resulting mixed NGLs, available

pipeline capacity to transport NGLs to the Partnership’s fractionators, and the Partnership’s competitive and contractual position relative to other fractionators.

 

Contract Terms and Contract Mix and the Impact of Commodity Prices.  Because of the significant volatility of natural gas and NGL prices, the contract mix of the Partnership’s natural gas gathering and processing segment can also have a significant impact on its profitability, especially those that create exposure to changes in energy prices.

 

Set forth below is a table summarizing the contract mix of the Partnership’s natural gas gathering and processing division for 2010 and the potential impacts of commodity prices on operating margins:

 

 

 

 

The Partnership generally prefers to enter into contracts with less commodity price sensitivity including fee-based and percent-of-proceeds arrangements. However, negotiated contract terms are based upon a variety of factors, including natural gas quality, geographic location, the competitive commodity and pricing environment at the time the contract is executed, and customer requirements. The gathering and processing contract mix and, accordingly, the exposure to natural gas and NGL prices, may change as a result of producer preferences, competition, and changes in production as wells decline at different rates or are added, the Partnership’s expansion into regions where different types of contracts are more common as well as other market factors.

 

The contract terms and contract mix of the Downstream Business can also have a significant impact on its results of operations. During periods of low relative demand for available fractionation capacity, rates were low and take -or -pay contracts were not readily available. Currently, demand for fractionation services is relatively high, rates have increased, contract terms or lengths have increased and reservation fees are required. These fractionation contracts in the logistics assets segment are primarily fee-based arrangements while the marketing and distribution segment includes both fee-based and margin-based contracts.

 

Impact of the Partnership’s Commodity Price Hedging Activities.  In an effort to reduce the variability of its cash flows, the Partnership has hedged the commodity price associated with a portion of its expected natural gas, NGL and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, the Partnership has attempted to mitigate its exposure to commodity price movements with respect to its forecasted volumes for these periods. The Partnership actively manages the Downstream Business product inventory and other working capital levels to reduce exposure to changing NGL prices. For additional information regarding the Partnership’s hedging activities, see “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.”

General Trends and Outlook

 

We expect the midstream energy business environment to continue to be affected by the following key trends: demand for our services, significant relationships, commodity prices, volatile capital markets and increased regulation. These expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

 

Demand for Services.  Fluctuations in energy prices can affect production rates and investments by third parties in the development of oil and natural gas reserves. Generally, drilling and production activity will increase as energy prices increase. We believe that the current strength of oil, condensate and NGL prices compared to natural gas prices has caused producers in and around the Partnership’s natural gas gathering and processing areas of operation to focus their drilling programs on regions rich in liquid forms of hydrocarbons. This focus is reflected in increased drilling permits and higher rig counts in these areas, and we expect these activities to lead to higher inlet volumes in the Field Gathering and Processing segment over the next several years. Producer activity in areas rich in oil, condensate and NGLs is currently generating increased demand for the Partnership’s fractionation services and for related fee-based services provided by its Downstream Business. While we expect development activity to remain robust with respect to oil and liquids rich gas development and production, currently depressed natural gas prices have resulted in reduced activity levels surrounding comparatively dry natural gas reserves, whether conventional or unconventional.

 

Significant Relationships.  The following table lists the counterparties that account for more than 10% of the Partnership’s consolidated sales and consolidated product purchases.

 

 

No other third party customer accounted for more than 10% of our consolidated revenues or consolidated product purchases during these periods.

 

Commodity Prices.  Current forward commodity prices for the January 2011 through December 2011 period show natural gas and crude oil prices strengthening while NGL prices weaken on an absolute price basis and as a percentage of crude oil. Various industry commodity price forecasts based on fundamental analysis may differ significantly from forward market prices. Both are subject to change due to multiple factors. There has been and we believe there will continue to be significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. In addition, the volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers and ultimately supply to the Partnership’s systems.

 

The Partnership’s operating income generally improves in an environment of higher natural gas, NGL and condensate prices, primarily as a result of its percent-of-proceeds contracts. The Partnership’s processing profitability is largely dependent upon pricing, the supply of and market demand for natural gas, NGLs and condensate, which are beyond its control and have been volatile. Recent weak economic conditions have negatively affected the pricing and market demand for natural gas, NGLs and condensate, which caused a reduction in profitability of the Partnership’s processing operations. In a declining commodity price environment, without taking into account the Partnership’s hedges, it will realize a reduction in cash flows under its percent-of-proceeds contracts proportionate to average price declines. The Partnership has attempted to mitigate its exposure to commodity price movements by entering into hedging arrangements. For additional information regarding hedging activities, see “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”

 

Volatile Capital Markets.  We and the Partnership are dependent on our abilities to access equity and debt capital markets in order to fund acquisitions and expansion expenditures. Global financial markets

have been, and are expected to continue to be, volatile and disrupted and weak economic conditions may cause a significant decline in commodity prices. As a result, we and the Partnership may be unable to raise equity or debt capital on satisfactory terms, or at all, which may negatively impact the timing and extent to which we and the Partnership execute growth plans. Prolonged periods of low commodity prices or volatile capital markets may impact our and the Partnership’s ability or willingness to enter into new hedges, fund organic growth, connect to new supplies of natural gas, execute acquisitions or implement expansion capital expenditures.

 

Increased Regulation.  Additional regulation in various areas has the potential to materially impact the Partnership’s operations and financial condition. For example, increased regulation of hydraulic fracturing used by producers may cause reductions in supplies of natural gas and of NGLs from producers. Please read “Risk Factors—Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the Partnership’s revenues by decreasing the volumes of natural gas that the Partnership gathers, processes and fractionates.” Similarly, the forthcoming rules and regulations of the CFTC may limit the Partnership’s ability or increase the cost to use derivatives, which could create more volatility and less predictability in its results of operations. Please read “Risk Factors—The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Partnership’s ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.”

 

How We Evaluate Our Operations

 

Our consolidated operations include the operations of the Partnership due to our ownership and control of the General Partner. As a result of our conveyances of all of our remaining operating assets to the Partnership we have no separate, direct operating activities from those conducted by the Partnership. Our financial results differ from the Partnership’s due to the financial effects of non-controlling interests in the Partnership, our separate debt obligations, certain non-operating costs associated with assets and liabilities that we retained and were not included in the asset conveyances to the Partnership, and certain general and administrative costs applicable to us as a separate public company.

 

How We Evaluate the Partnership’s Operations

 

The Partnership’s profitability is a function of the difference between the revenues it receives from our operations, including revenues from the natural gas, NGLs and condensate it sells, and the costs associated with conducting its operations, including the costs of wellhead natural gas and mixed NGLs that it purchases as well as operating and general and administrative costs, and the impact of the Partnership’s commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in the Partnership’s revenues alone are not necessarily indicative of increases or decreases in its profitability. The Partnership’s contract portfolio, the prevailing pricing environment for natural gas and NGLs, and the volume of natural gas and NGL throughput on its systems are important factors in determining its profitability. The Partnership’s profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for its products and services and changes in its customer mix.

 

Management uses a variety of financial and operational measurements to analyze the Partnership’s performance. These measurements include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses and (3) the following non-GAAP measures—gross margin, operating margin and adjusted EBITDA.

 

Throughput Volumes, Facility Efficiencies and Fuel Consumption.  The Partnership’s profitability is impacted by its ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to its gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production as well as by capturing natural gas supplies currently gathered by third parties. Similarly, the Partnership’s profitability is impacted

by its ability to add new sources of mixed NGL supply, typically connected by third -party transportation, to its Downstream Business’ fractionation facilities. The Partnership fractionates NGLs generated by its gathering and processing plants as well as by contracting for mixed NGL supply from third -party gathering or fractionation facilities.

 

In addition, the Partnership seeks to increase operating margins by limiting volume losses and reducing fuel consumption by increasing compression efficiency. With its gathering systems’ extensive use of remote monitoring capabilities, the Partnership monitors the volumes of natural gas received at the wellhead or central delivery points along its gathering systems, the volume of natural gas received at its processing plant inlets and the volumes of NGLs and residue natural gas recovered by its processing plants. The Partnership also monitors the volumes of NGLs received, stored, fractionated, and delivered across its logistics assets. This information is tracked through its processing plants and Downstream Business facilities to determine customer settlements for sales and volume -related fees for service, which helps the Partnership increase efficiency and reduce fuel consumption.

 

As part of monitoring the efficiency of its operations, the Partnership measures the difference between the volume of natural gas received at the wellhead or central delivery points on its gathering systems and the volume received at the inlet of its processing plants as an indicator of fuel consumption and line loss. The Partnership also tracks the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of the facilities. Similar tracking is performed for its logistics assets. These volume, recovery and fuel consumption measurements are an important part of the Partnership’s operational efficiency analysis.

 

Operating Expenses.  Operating expenses are costs associated with the operation of a specific asset. Labor, ad valorem taxes, repair and maintenance, utilities and contract services comprise the most significant portion of the Partnership’s operating expenses. These expenses generally remain relatively stable and independent of the volumes through its systems but fluctuate depending on the scope of the activities performed during a specific period.

 

Gross Margin.  Gross margin is defined as revenue less purchases. It is impacted by volumes and commodity prices as well as the Partnership’s contract mix and hedging programs. We define Natural Gas Gathering and Processing division gross margin as total operating revenues from the sales of natural gas and NGLs plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. Logistics Assets gross margin consists primarily of service fee revenue. Marketing and Distribution gross margin equals total revenue from service fees and NGL sales, less cost of sales, which consists primarily of NGL purchases, transportation costs and changes in inventory valuation. The gross margin impacts of cash flow hedge settlements are reported in Other.

 

Operating Margin.  Operating margin is an important performance measure of the core profitability of the Partnership’s operations. We define operating margin as gross margin less operating expenses. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges.

 

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. You should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

 

Targa senior management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Gross Margin and Operating Margin provide useful information to investors because they are used as supplemental financial

measures by us and by external users of our financial statements, including such investors, commercial banks and others, to assess:

 

 

The Partnership’s management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision-making processes.

 

 

Adjusted EBITDA.  The Partnership defines Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and non-cash income or loss related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by the Partnership and by external users of our financial statements such as investors, commercial banks and others.

 

The economic substance behind the Partnership’s use of Adjusted EBITDA is to measure the ability of its assets to generate cash sufficient to pay interest costs, support its indebtedness and make distributions to its investors.

 

The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by

operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

 

The Partnership compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.