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As filed with the Securities and Exchange Commission on July 15, 2011

Registration No. 333-173191

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 8
to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

American Midstream Partners, LP

(Exact Name of Registrant as Specified in its Charter)


Delaware	4922	27-0855785
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1614 15th Street
Suite 300
Denver, Colorado 80202
(720) 457-6060

(Address, including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

Brian F. Bierbach
President and Chief Executive Officer
1614 15th Street
Suite 300
Denver, Colorado 80202
(720) 457-6060

(Name, Address, including Zip Code, and Telephone Number, including Area Code, of Agent for Service)

Copies to:


G. Michael O’Leary Timothy C. Langenkamp Andrews Kurth LLP 600 Travis, Suite 4200 Houston, Texas 77002 (713) 220-4200		William N. Finnegan IV Brett E. Braden Latham & Watkins LLP 717 Texas Avenue, Suite 1600 Houston, Texas 77002 (713) 546-5400

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

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

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

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, 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):


Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
		(Do not check if a smaller reporting company)

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 JULY 15, 2011

PRELIMINARY PROSPECTUS

3,750,000 Common Units

Representing Limited Partner Interests

American Midstream Partners, LP

This is the initial public offering of our common units representing limited partner interests. We are offering 3,750,000 common units in this offering. We currently expect that the initial public offering price will be between $19.00 and $21.00 per common unit. Prior to this offering, there has been no public market for our common units.

We have granted the underwriters an option to purchase up to an additional 562,500 common units to cover over-allotments.

We have been approved to list our common units on the New York Stock Exchange under the symbol “AMID” subject to official notice of issuance.

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 14.

These risks include the following:


	•	We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution or any distribution to holders of our common units and subordinated units.

	•	Because of the natural decline in production from existing wells in our areas of operation, our success depends on our ability to obtain new sources of natural gas, which is dependent on factors beyond our control. Any decrease in the volumes of natural gas that we gather, process or transport could adversely affect our business and operating results.

	•	Natural gas, NGL and other commodity prices are volatile, and a reduction in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our gross margin and cash flow and our ability to make distributions to our unitholders.

	•	We are a relatively small enterprise, and our management has limited history with our assets and no experience in managing our business as a publicly traded partnership. As a result, operational, financial and other events in the ordinary course of business could disproportionately affect us, and our ability to grow our business could be significantly limited.

	•	If third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash available for distribution could be adversely affected.

	•	AIM Midstream Holdings, LLC directly owns and controls American Midstream GP, LLC, our general partner, which has sole responsibility for conducting our business and managing our operations, each of which have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our other unitholders.

	•	There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

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

	•	Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

	•	You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.


	Per Common Unit	Total

Public Offering Price	$	$
Underwriting Discount(1)	$	$
Proceeds to American Midstream Partners, LP (before expenses)	$	$


(1)		Excludes an aggregate structuring fee payable to Citigroup Global Markets Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated that is equal to 0.75% of the gross proceeds of this offering. Please see “Underwriting.”

The underwriters expect to deliver the common units to purchasers on or about , 2011, through the book-entry facilities of The Depository Trust Company.

Joint Book-Running Managers


Citi	BofA Merrill Lynch

Co-Managers


Barclays Capital		Raymond James		Wells Fargo Securities

, 2011

SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical consolidated financial statements and related notes of American Midstream Partners, LP and the historical combined financial statements and related notes of American Midstream Partners Predecessor, which we refer to as our Predecessor. The information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus), (2) unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised, and (3) that the reverse unit split referred to in “Recapitalization Transactions and Partnership Structure” has occurred. You should read “Risk Factors” beginning on page 14 for more information about important risks that you should consider carefully before investing in our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.

Unless the context otherwise requires, references in this prospectus to (i) “American Midstream Partners, LP,” “we,” “our,” “us” or like terms for periods from and after the acquisition of our assets on November 1, 2009 refer to American Midstream Partners, LP and its subsidiaries; (ii) “American Midstream Partners, LP,” “we,” “our,” “us” or like terms for periods prior to November 1, 2009 refer to our Predecessor and its subsidiaries; (iii) “American Midstream GP” or our “general partner” refer to American Midstream GP, LLC; (iv)“AIM Midstream Holdings” refers to AIM Midstream Holdings, LLC and its subsidiaries and affiliates, other than American Midstream Partners, LP and its subsidiaries and American Midstream GP, as of the closing date of this offering; and (v) “AIM” refers to American Infrastructure MLP Fund, L.P. and its subsidiaries and affiliates, other than American Midstream Partners, LP, American Midstream GP, AIM Midstream Holdings and their respective subsidiaries.

American Midstream Partners, LP

Overview

We are a growth-oriented Delaware limited partnership that was formed by AIM in August 2009 to own, operate, develop and acquire a diversified portfolio of natural gas midstream energy assets. We are engaged in the business of gathering, treating, processing and transporting natural gas through our ownership and operation of nine gathering systems, three processing facilities, two interstate pipelines and six intrastate pipelines. Our primary assets, which are strategically located in Alabama, Louisiana, Mississippi, Tennessee and Texas, provide critical infrastructure that links producers and suppliers of natural gas to diverse natural gas markets, including various interstate and intrastate pipelines, as well as utility, industrial and other commercial customers. We currently operate approximately 1,400 miles of pipelines that gather and transport over 500 MMcf/d of natural gas. We acquired our existing portfolio of assets from a subsidiary of Enbridge Energy Partners, L.P., or Enbridge, in November 2009.

Our operations are organized into two segments: (i) Gathering and Processing and (ii) Transmission. In our Gathering and Processing segment, we receive fee-based and fixed-margin compensation for gathering, transporting and treating natural gas. Where we provide processing services at the plants that we own, or obtain processing services for our own account in connection with our elective processing arrangements, we typically retain and sell a percentage of the residue natural gas and resulting natural gas liquids, or NGLs, under percent-of-proceeds, or POP, arrangements. We also receive fee-based and fixed-margin compensation in our Transmission segment primarily related to capacity reservation charges under our firm transportation contracts and the transportation of natural gas pursuant to our interruptible transportation and fixed-margin contracts.

For the year ended December 31, 2010 and the quarter ended March 31, 2011, we generated $38.1 million and $12.3 million of gross margin, respectively, of which $24.6 million and $8.2 million, respectively, represented segment gross margin generated in our Gathering and Processing segment and $13.5 million and $4.1 million, respectively, represented segment gross margin generated in our Transmission segment. For the year ended December 31, 2010 and the quarter ended March 31, 2011, $24.9 million, or 65.4%, and $7.3 million, or 59.5%, respectively, of our gross margin was generated from fee-based, fixed-margin and firm and interruptible transportation contracts with respect to which we have little or no direct commodity price exposure. For a definition of gross margin and a reconciliation of gross margin to its most directly comparable financial measure calculated in accordance with GAAP, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.”

Business Strategies

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. We expect to achieve this objective by executing the following strategies:


	•	Capitalize on Organic Growth Opportunities Associated with Our Existing Assets. We continually seek to identify and evaluate economically attractive organic expansion and asset enhancement opportunities that leverage our existing asset footprint and strategic relationships with our customers.

	•	Attract Additional Volumes to Our Systems. We intend to attract new volumes of natural gas to our systems from existing and new customers by continuing to provide superior customer service and reestablishing relationships with customers that were potentially underserved by the previous owner of our assets.

	•	Pursue Strategic and Accretive Acquisitions. We plan to pursue accretive acquisitions of energy infrastructure assets that are complementary to our existing asset base or that provide attractive potential returns in new operating regions or business lines.

	•	Manage Exposure to Commodity Price Risk. We will manage our commodity price exposure by targeting a contract portfolio that is weighted towards fee-based and fixed-margin contracts while mitigating direct commodity price exposure by employing a prudent hedging strategy.

	•	Maintain Financial Flexibility and Conservative Leverage. We plan to pursue a disciplined financial policy and seek to maintain a conservative capital structure that we believe will allow us to consider attractive growth projects and acquisitions even in periods of challenging market environments.

	•	Continue Our Commitment to Safe and Environmentally Sound Operations. The safety of our employees and the communities in which we operate is one of our highest priorities. We believe it is critical to handle natural gas and NGLs for our customers safely, while striving to minimize the environmental impact of our operations.

Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:


	•	Well Positioned to Pursue Opportunities Overlooked by Larger Competitors. Our size and flexibility, in conjunction with our geographically diverse asset base, position us to pursue economically attractive growth projects and acquisitions that may not be large enough to be attractive to many of our larger competitors.

	•	Diversified Asset Base. Our assets are diversified geographically and by business line, which contributes to the stability of our cash flows and creates a number of potential growth opportunities for our business.

	•	Strategically Located Assets. Our assets are located in areas where we believe there will be opportunities to access new natural gas supplies and to capture new customers that are underserved by our competitors. We continue to see drilling activity on and around our systems, and we believe that our assets are strategically positioned to capitalize on such activity.

	•	Focus on Delivering Excellent Customer Service. We view our strong customer relationships as one of our key assets and believe it is critical to maintain operational excellence and ensure best-in-class customer service and reliability.

	•	Experienced and Incentivized Management and Operating Teams. Our executive management team has an average of over 25 years of experience in the midstream energy industry. The team possesses a comprehensive skill set to support our business and enhance unitholder value through asset optimization, accretive development projects and acquisitions.

Our Sponsor

American Infrastructure MLP Fund, L.P., or AIM, is a private investment firm specializing in investments in energy, natural resources, infrastructure and real property. AIM, along with certain of the funds that AIM advises, currently indirectly owns 84.4% of the ownership interests in AIM Midstream Holdings, which owns 100.0% of our general partner. Robert B. Hellman, Jr., Matthew P. Carbone and Edward O. Diffendal serve on the board of directors of our general partner and are principals of and have ownership interests in AIM. After the closing of this offering, AIM Midstream Holdings will continue to hold 100.0% of the ownership interests in our general partner and will hold 16.0% of our common units and 100.0% of our subordinated units, or an aggregate of 58.0% of our total limited partner interests.

Risk Factors

An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. Please read carefully the risks under the caption “Risk Factors” immediately following this Summary, beginning on page 14.

Recapitalization Transactions and Partnership Structure

We are a growth-oriented Delaware limited partnership that was formed by AIM to own, operate, develop and acquire a diversified portfolio of midstream energy assets.

Immediately prior to the closing of this offering, the following transactions, which we refer to as the recapitalization transactions, will occur:


	•	each general partner unit held by our general partner will automatically reverse split into 0.485 general partner units, resulting in the ownership by our general partner of an aggregate of 108,718 general partner units, representing a 2.0% general partner interest in us;

	•	each common unit held by participants in our Long-Term Incentive Plan, or LTIP, will automatically reverse split into 0.485 common units, resulting in their ownership of an aggregate of 50,946 common units, representing an aggregate 0.9% limited partner interest in us;

	•	each outstanding phantom unit granted to participants in our LTIP will automatically reverse split into 0.485 phantom units, resulting in their holding an aggregate of 209,824 phantom units;

	•	each common unit held by AIM Midstream Holdings will automatically reverse split into 0.485 common units, resulting in the ownership by AIM Midstream Holdings of an aggregate of 5,327,205 common units, representing an aggregate 97.1% limited partner interest in us; and

	•	the common units held by AIM Midstream Holdings will automatically convert into 801,139 common units and 4,526,066 subordinated units.

In connection with the closing of this offering and immediately following the recapitalization transactions, the following transactions will occur:


	•	we will issue 3,750,000 common units to the public in this offering;

	•	AIM Midstream Holdings will contribute 76,019 common units to our general partner as a capital contribution;

	•	our general partner will contribute the common units contributed to it by AIM Midstream Holdings to us in exchange for 76,019 general partner units in order to maintain its 2.0% general partner interest in us;

	•	we will use the net proceeds from this offering for the purposes set forth in “Use of Proceeds;”

	•	we will enter into a new credit facility; and

	•	we will use the net proceeds from borrowings under our new credit facility for the purposes set forth in “Use of Proceeds.”

Our Management

We are managed and operated by the board of directors and executive officers of our general partner, American Midstream GP. Currently, and upon the closing of this offering, AIM Midstream Holdings will own all of the ownership interests in our general partner. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. AIM holds an aggregate 84.4% indirect interest in AIM Midstream Holdings. Robert B. Hellman, Jr., Matthew P. Carbone and Edward O. Diffendal serve on the board of directors of our general partner and are principals of and have ownership interests in AIM. In addition, the executive officers of our general partner and certain members of our general partner’s board of directors hold an aggregate 1.1% interest in AIM Midstream Holdings. After the closing of this offering, AIM Midstream Holdings will continue to hold 100.0% of the ownership interests in our general partner and will hold 16.0% of our common units and 100.0% of our subordinated units, or an aggregate of 58.0% of our total limited partner interests. For information about the executive officers and directors of our general partner, please read “Management.” Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it.

In order to maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, American Midstream, LLC and its subsidiaries. However, we, American Midstream, LLC and its subsidiaries do not have any employees. Although all of the employees that conduct our business are employed by our general partner, we sometimes refer to these individuals in this prospectus as our employees.

Following the closing of this offering, our general partner and its affiliates will not receive any management fee or other compensation in connection with our general partner’s management of our business, but will be reimbursed for expenses incurred on our behalf. These expenses include the costs of employee and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate for the conduct of our business and allocable to us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

Following the closing of this offering, our general partner will own 184,737 general partner units representing a 2.0% general partner interest in us, which will entitle it to receive 2.0% of all the distributions we make. Our general partner also owns all of our incentive distribution rights, which will entitle it to increasing percentages, up to a maximum of 48.0%, of the cash we distribute in excess of $0.47438 per unit per quarter, after the closing of our initial public offering. Please read “Certain Relationships and Related Party Transactions.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 1614 15th Street, Suite 300, Denver, CO 80202, and our telephone number is (720) 457-6060. Our website is located at www.americanmidstream.com. We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties

General

Our general partner has a legal duty to manage us in a manner beneficial to the holders of our common and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, the officers and directors of our general partner also have a fiduciary duty to manage the business of our general partner in a manner beneficial to its owner, AIM Midstream Holdings.

Certain of the officers and directors of our general partner are also officers of AIM Midstream Holdings. As a result of these relationships, conflicts of interest may arise in the future between us and holders of our common units, on the one hand, and AIM Midstream Holdings and our general partner, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions as discussed above.

Partnership Agreement Modifications to Fiduciary Duties

Our partnership agreement limits the liability of, and reduces the fiduciary duties owed by, our general partner to holders of our common and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common and subordinated units for actions that might otherwise constitute a breach of our general partner’s fiduciary duties. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

AIM Midstream Holdings May Engage in Competition with Us

Our partnership agreement does not prohibit AIM, AIM Midstream Holdings or their respective affiliates other than our general partner from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, AIM Midstream Holdings may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to acquire or construct any of those assets.

For a more detailed description of the conflicts of interest and the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

The Offering


Common units offered to the public		3,750,000 common units.

		4,312,500 common units, if the underwriters exercise in full their option to purchase additional common units.

Units outstanding after this offering		4,526,066 common units and 4,526,066 subordinated units, each representing a 49.0% limited partner interest in us. Our general partner will own 184,737 general partner units, representing a 2.0% general partner interest in us.

Use of proceeds		We intend to use the net proceeds from this offering of approximately $69.8 million, after deducting underwriting discounts, commissions and structuring fees, but before paying offering expenses, to:


		• repay in full the outstanding balance under our existing credit facility of approximately $59.8 million;


		• pay offering expenses of approximately $3.3 million;

		• terminate, in exchange for a payment of $2.5 million, the advisory services agreement between our subsidiary, American Midstream, LLC, and AIM;

		• establish a cash reserve of $2.2 million related to our non-recurring deferred maintenance capital expenditures for the twelve months ending June 30, 2012; and


		• make an aggregate distribution of approximately $2.0 million, on a pro rata basis, to LTIP participants holding common units, AIM Midstream Holdings and our general partner. The distribution to AIM Midstream Holdings and our general partner is a reimbursement for certain capital expenditures incurred with respect to assets contributed to us.


		We will use the proceeds from borrowings of approximately $30.0 million under our new credit facility to (i) make an aggregate distribution of approximately $28.0 million, on a pro rata basis, to LTIP participants holding common units, AIM Midstream Holdings and our general partner and (ii) pay fees and expenses relating to our new credit facility of approximately $2.0 million. The distribution made to AIM Midstream Holdings and our general partner will be a reimbursement for certain capital expenditures incurred with respect to assets contributed to us.


		If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from AIM Midstream Holdings a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit in this offering before expenses but after deducting underwriting discounts, commissions and structuring fees.

		Please read “Use of Proceeds.”

Cash distributions		We intend to pay a minimum quarterly distribution of $0.4125 per unit ($1.65 per unit on an annualized basis) to the extent we have


		sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash.” Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.” We will adjust the minimum quarterly distribution payable for the period from the closing of this offering through September 30, 2011, based on the length of that period.

		Our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:

		• first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.4125 plus any arrearages from prior quarters;

		• second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $0.4125; and

		• third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.47438.

		If cash distributions to our unitholders exceed $0.47438 per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

		The amount of as adjusted cash available for distribution generated during the year ended December 31, 2010 and the twelve months ended March 31, 2011 would have been insufficient to allow us to pay the full minimum quarterly distribution ($0.4125 per unit per quarter, or $1.65 on an annualized basis) on all of our common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for such period. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

		We believe that, based on the Statement of Estimated Adjusted EBITDA included under the caption “Our Cash Distribution Policy and Restrictions on Distributions,” we will have sufficient cash available for distribution to pay the annualized minimum quarterly distribution of $0.4125 per unit on all common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2012.

Subordinated units		AIM Midstream Holdings will initially indirectly own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution


		plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

Conversion of subordinated units		The subordination period will end on the first business day after we have earned and paid at least (i) $1.65 (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit, as well as the corresponding distribution on our 2.0% general partner interest, for each of three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2014 or (ii) $2.475 (150% of the annualized minimum quarterly distribution) on each outstanding common and subordinated unit, as well as the corresponding distribution on our 2.0% general partner interest, in addition to any distribution made in respect of the incentive distribution rights, for any four consecutive quarter period ending on or after September 30, 2012; provided that we have paid at least the minimum quarterly distribution from operating surplus on each outstanding common unit and subordinated unit, as well as the corresponding distribution on our 2.0% general partner interest, for each quarter in that four-quarter period.

		In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.

		When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.

Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding limited partner units voting together as a single class, including any limited partner units owned by our general partner and its affiliates, including AIM Midstream Holdings. Upon the closing of this offering, AIM Midstream Holdings will own an aggregate of 58.0% of our common and subordinated units. This will give AIM Midstream Holdings the ability to prevent the involuntary removal of our general partner. Please read “The Partnership Agreement — Voting Rights.”

Limited call right		If at any time our general partner and its affiliates own more than 80.0% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price that is not less than the then-current market price of the common units.

Eligible holders and redemption		If our general partner determines that a holder of our common units is not an eligible holder, it may elect not to make distributions or allocate income or loss to such holder. Eligible holders are:


		• U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us; or

		• U.S. entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are domestic individuals or entities subject to such taxation.

		We have the right, which we may assign to any of our affiliates, but not the obligation, to redeem all of the common units of any holder that is not an eligible holder or that has failed to certify or has falsely certified that such holder is an eligible holder. The purchase price for such redemption would be equal to the lesser of the holder’s purchase price and the then-current market price of the common units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

		Please read “The Partnership Agreement — Non-Citizen Assignees; Redemption” and “The Partnership Agreement — Non-Taxpaying Assignees; Redemption.”

Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2013, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.65 per unit, we estimate that your average allocable federal taxable income per year will be no more than $0.33 per unit. Please read “Material Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions” and “Material Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Limitations on Deductibility of Losses.”

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


Exchange listing		We have been approved to list our common units on the New York Stock Exchange under the symbol ‘‘AMID” subject to official notice of issuance.

Summary Historical Financial and Operating Data

The following table presents our summary historical consolidated financial and operating data, as well as the summary historical combined financial and operating data of our Predecessor, which was comprised of 12 indirectly wholly owned subsidiaries of Enbridge, as of the dates and for the periods indicated.

The summary historical combined financial data presented as of and for the year ended December 31, 2008, and as of and for the 10 months ended October 31, 2009 are derived from the audited historical combined financial statements of our Predecessor that are included elsewhere in this prospectus. The summary historical consolidated financial data presented as of December 31, 2009, for the period from August 20, 2009 (date of inception) to December 31, 2009, as of and for the year ended December 31, 2010, as of and for the quarter ended March 31, 2010 and as of and for the quarter ended March 31, 2011 are derived from our audited and unaudited historical consolidated financial statements included elsewhere in this prospectus. We acquired our assets effective November 1, 2009. During the period from our inception on August 20, 2009 to October 31, 2009, we had no operations although we incurred certain fees and expenses associated with our formation and the acquisition of our assets from Enbridge.

For a detailed discussion of the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with our historical audited and unaudited consolidated financial statements and related notes and our Predecessor’s audited combined financial statements and related notes included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

The following table presents the non-GAAP financial measures adjusted EBITDA and gross margin that we use in our business and view as important supplemental measures of our performance. These measures are not calculated or presented in accordance with GAAP. We explain these measures under “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures” and reconcile them to net income (loss), their most directly comparable financial measure calculated and presented in accordance with GAAP.


	American Midstream Partners Predecessor						American Midstream Partners, LP and Subsidiaries (Successor)
							Period from
				10 Months			August 20, 2009
	Year Ended			Ended			(Inception Date)			Year Ended			Quarter Ended			Quarter Ended
	December 31,			October 31,			to December 31,			December 31,			March 31,			March 31,
	2008			2009			2009			2010			2010			2011
	(in thousands, except per unit and operating data)
Statement of Operations Data:
Revenue	$	366,348		$	143,132		$	32,833		$	211,940		$	54,712		$	67,265
Unrealized gain (loss) on commodity derivatives		—			—			—			—			—			(3,500	)
Total revenue		366,348			143,132			32,833			211,940			54,712			63,765

Operating expenses:
Purchases of natural gas, NGLs and condensate		323,205			113,227			26,593			173,821			44,964			54,953
Direct operating expenses		13,423			10,331			1,594			12,187			2,692			3,058
Selling, general and administrative expenses(1)		8,618			8,577			1,346			8,854			2,113			2,675
One-time transaction costs		—			—			6,404			303			74			288
Depreciation expense		13,481			12,630			2,978			20,013			4,966			5,037

Total operating expenses		358,727			144,765			38,915			215,178			54,809			66,011

Operating income (loss)		7,621			(1,633	)		(6,082	)		(3,238	)		(97	)		(2,246	)
Other (income) expenses:
Interest expense		5,747			3,728			910			5,406			1,357			1,264
Income tax expense		—			—			—			—			—			—
Other (income) expenses		(854	)		(24	)		—			—			—			—

Net income (loss)	$	2,728		$	(5,337	)	$	(6,992	)	$	(8,644	)	$	(1,454	)	$	(3,510	)
General partner’s interest in net income (loss)								(140	)		(173	)		(29	)		(70	)

Limited partners’ interest in net income (loss)								(6,852	)		(8,471	)		(1,425	)		(3,440	)

Limited partners’ net income (loss) per unit							$	(1.52	)	$	(0.81	)	$	(0.14	)	$	(0.30	)
Pro forma earnings per common unit(2)										$	(1.63	)				$	(0.61	)
Pro forma weighted average common units outstanding(2)											5,199						5,668
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	18,155		$	14,589		$	(6,531	)	$	13,791		$	2,323		$	5,067
Investing activities		(10,486	)		(853	)		(151,976	)		(10,268	)		(494	)		(1,291	)
Financing activities		(7,929	)		(14,008	)		159,656			(4,609	)		(2,888	)		(3,686	)
Other Financial Data:
Adjusted EBITDA(3)	$	21,956		$	11,021		$	3,450		$	18,263		$	5,197		$	6,914
Gross margin(4)		43,143			29,905			6,240			38,119			9,748			12,312
Segment gross margin:
Gathering and Processing		27,354			20,024			3,698			24,595			6,098			8,167
Transmission		15,789			9,881			2,542			13,524			3,650			4,145
Balance Sheet Data (At Period End):
Cash and cash equivalents	$	421		$	149		$	1,149		$	63		$	90		$	153
Accounts receivable, net and unbilled revenue		9,532			8,756			19,776			22,850			17,446			22,248
Property, plant and equipment, net		216,903			205,126			149,266			146,808			151,167			143,394
Total assets		277,242			250,162			174,470			173,229			173,217			169,693
Total debt (current and long-term)(5)		60,000			—			61,000			56,370			58,380			56,500
Operating Data:
*Gathering and Processing segment*:
Throughput (MMcf/d)		179.2			211.8			169.7			175.6			164.3			242.8
Plant inlet volume (MMcf/d)(6)		12.5			11.7			11.4			9.9			11.1			15.2
Gross NGL production (Mgal/d)(6)		40.2			39.3			38.2			34.1			35.2			55.1
*Transmission segment*:
Throughput (MMcf/d)		336.2			357.6			381.3			350.2			360.6			446.0
Firm transportation — capacity reservation (MMcf/d)		627.3			613.2			701.0			677.6			702.8			762.1
Interruptible transportation — throughput (MMcf/d)		141.6			121.0			118.0			80.9			80.2			76.5


(1)		Includes LTIP expenses for the period from August 20, 2009 to December 31, 2009, for the year ended December 31, 2010, for the quarter ended March 31, 2010 and for the quarter ended March 31, 2011 of $0.2 million, $1.7 million, $0.3 million and $0.5 million, respectively. Of these amounts, $0.2 million, $1.2 million, $0.3 million and $0.3 million, respectively, represent non-cash expenses.


(2)		The pro forma earnings per common unit gives effect to the recapitalization transactions as of December 31, 2010 and March 31, 2011 and the additional number of common units issued in this offering (at an assumed offering price of $20.00 per unit) necessary to pay the portion of the distribution to AIM Midstream Holdings, LTIP Participants holding common units and our general partner described in “Use of Proceeds” that will be funded from the proceeds of this offering that exceeds net income for the year ended December 31, 2010 and the three months ended March 31, 2011. For a description of the calculation of pro forma earnings attributable to common and subordinated units, please read Note 1 to our audited consolidated financial statements and Note 1 to our unaudited consolidated financial statements included elsewhere in this prospectus. For a reconciliation of historical weighted average common units used in the computation of limited partners’ net income (loss) per common unit and pro forma weighted average common and subordinated units outstanding, please read Note 1 to our audited consolidated financial statements and Note 1 to our unaudited consolidated financial statements included elsewhere in this prospectus.


(3)		For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical Financial and Operating Data — How We Evaluate Our Operations,” and for a discussion of how we use adjusted EBITDA to evaluate our operating performance, please read “— How We Evaluate Our Operations.”

(4)		For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 12 to our unaudited consolidated financial statements and Note 18 to our audited consolidated financial statements included elsewhere in this prospectus and for a discussion of how we use gross margin to evaluate our operating performance, please read “— How We Evaluate Our Operations.”

(5)		Excludes Predecessor Note payable to Enbridge Midcoast Limited Holdings, L.L.C. of $39.3 million as of December 31, 2008.

(6)		Excludes volumes and gross production under our elective processing arrangements. For a description of our elective processing arrangements, please read “Business — Gathering and Processing Segment — Gloria System.”

RISK FACTORS

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

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

Risks Related to our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.

In order to pay the minimum quarterly distribution of $0.4125 per unit, or $1.65 per unit on an annualized basis, we will require available cash of approximately $3.8 million per quarter, or $15.2 million per year, based on the number of common and subordinated units and the 2.0% general partner interest to be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:


	•	the volume of natural gas we gather, process and transport;

	•	the level of production of oil and natural gas and the resultant market prices of oil and natural gas and NGLs;

	•	realized pricing impacts on our revenue and expenses that are directly subject to commodity price exposure;

	•	the market prices of natural gas and NGLs relative to one another, which affects our processing margins;

	•	capacity charges and volumetric fees associated with our transportation services;

	•	the level of competition from other midstream energy companies in our geographic markets;

	•	the level of our operating, maintenance and general and administrative costs; and

	•	regulatory action affecting the supply of, or demand for, natural gas, the transportation rates we can charge on our regulated pipelines, how we contract for services, our existing contracts, our operating costs or our operating flexibility.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:


	•	the level of capital expenditures we make;

	•	the cost of acquisitions, if any;

	•	our debt service requirements and other liabilities;

	•	fluctuations in our working capital needs;


	•	our ability to borrow funds and access capital markets;

	•	restrictions contained in our debt agreements;

	•	the amount of cash reserves established by our general partner; and

	•	other business risks affecting our cash levels.

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

On a historical as adjusted basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2010 and for the twelve months ended March 31, 2011.

We must generate approximately $15.2 million of available cash to pay the minimum quarterly distribution for four quarters on all of our common and subordinated units that will be outstanding immediately following this offering, as well as the corresponding distribution on our 2.0% general partner interest. The amount of historical as adjusted available cash generated during the year ended December 31, 2010 and for the twelve months ended March 31, 2011 would not have been sufficient to allow us to pay the full minimum quarterly distribution on our common and subordinated units as well as the corresponding distribution on our 2.0% general partner interest, during those periods. Specifically, the amount of historical as adjusted available cash generated during the year ended December 31, 2010 would have been sufficient to pay the minimum quarterly distribution on all of our common units, but only 29.0% of the minimum quarterly distribution on our subordinated units. Likewise, the amount of historical as adjusted available cash generated during the twelve months ended March 31, 2011 would have been sufficient to pay the minimum quarterly distribution on all of our common units, but only 43.1% of the minimum quarterly distribution on our subordinated units. For a calculation of our ability to make cash distributions to our unitholders based on our historical as adjusted results, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

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

The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, adjusted EBITDA and cash available for distribution for the twelve months ending June 30, 2012. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including risks that expansion projects do not result in an increase in gathered and transported volumes, and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.

Because of the natural decline in production from existing wells in our areas of operation, our success depends on our ability to obtain new sources of natural gas, which is dependent on factors beyond our control. Any decrease in the volumes of natural gas that we gather, process or transport could adversely affect our business and operating results.

The natural gas volumes that support our business are dependent on the level of production from natural gas and oil wells connected to our systems, the production of which will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas. The primary factors affecting

our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for volumes from successful new wells.

We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things:


	•	the availability and cost of capital;

	•	prevailing and projected oil and natural gas and NGL prices;

	•	demand for oil, natural gas and NGLs;

	•	levels of reserves;

	•	geological considerations;

	•	environmental or other governmental regulations, including the availability of drilling permits; and

	•	the availability of drilling rigs and other production and development costs.

Fluctuations in energy prices can also greatly affect the development of new oil and natural gas reserves. Further declines in natural gas prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our assets.

Because of these and other factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

Natural gas, NGL and other commodity prices are volatile, and a reduction in these prices in absolute terms, or an adverse change in the prices of natural gas and NGLs relative to one another, could adversely affect our gross margin and cash flow and our ability to make distributions to our unitholders.

We are subject to risks due to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The NYMEX daily settlement price for natural gas for the forward month contract in 2010 ranged from a high of $6.01 per MMBtu to a low of $3.29 per MMBtu. Natural gas prices reached relatively high levels in 2005 and early 2006 and have exhibited significant volatility since then, including a sustained decline beginning in 2008, with the forward month gas futures contracts closing at a seven-year low of $2.51 per MMBtu in September 2009. NGL prices are generally positively correlated to the price of WTI crude oil, which has also exhibited frequent and substantial fluctuations. The NYMEX daily settlement price for WTI crude oil for the forward month contract in 2010 ranged from a high of $91.51 per Bbl to a low of $66.88 per Bbl. Crude oil prices reached historically high levels in July 2008, hitting a peak of $145.63 per Bbl, and have demonstrated substantial volatility since then, with the forward month crude oil futures contracts ranging from $30.81 per Bbl in December 2008 to above $100.00 per Bbl in March 2011.

The markets for and prices of natural gas, NGLs and other hydrocarbon commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:


	•	worldwide economic conditions;

	•	worldwide political events, including actions taken by foreign oil and gas producing nations;

	•	worldwide weather events and conditions, including natural disasters and seasonal changes;

	•	the levels of domestic production and consumer demand;


	•	the availability of imported liquefied natural gas, or LNG;

	•	the availability of transportation systems with adequate capacity;

	•	the volatility and uncertainty of regional pricing differentials;

	•	the price and availability of alternative fuels;

	•	the effect of energy conservation measures;

	•	the nature and extent of governmental regulation and taxation; and

	•	the anticipated future prices of oil, natural gas, NGLs and other commodities.

In our Gathering and Processing segment, we have exposure to direct commodity price risk under percent-of-proceeds processing contracts as well as under our elective processing arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers and retain an agreed percentage of the proceeds (in cash or in-kind) from the sale at market prices of pipeline-quality natural gas and NGLs resulting from our processing activities. We also purchase natural gas at various receipt points, process the gas at a third-party owned natural gas processing facility and sell our portion of the residue gas and NGLs. Under percent-of-proceeds arrangements, our revenue and our cash flows increase or decrease as the prices of natural gas and NGLs fluctuate. When we process natural gas that we purchase for our own account, the relationship between natural gas prices and NGL prices also affects our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for us to process the natural gas that we purchase and process for our own account. When natural gas prices are high relative to NGL prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and because of the increased cost (principally that of natural gas shrink that occurs during processing and use of natural gas as a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed pursuant to our elective processing arrangements. For the year ended December 31, 2010 and for the quarter ended March 31, 2011, percent-of-proceeds arrangements accounted for approximately 34.6% and 40.5%, respectively, of our gross margin, or 53.6% and 61.0%, respectively, of the segment gross margin in our Gathering and Processing segment. For a discussion of these arrangements, please read “Industry Overview — Typical Midstream Contractual Arrangements.”

A decrease in demand for natural gas, NGLs or condensate by the petrochemical, refining or heating industries, could adversely affect the profitability of our midstream business.

A decrease in demand for natural gas, NGLs or condensate by the petrochemical, refining or heating industries, could adversely affect the profitability of our midstream business. Various factors impact the demand for natural gas, NGLs and condensate, including general economic conditions, extended periods of ethane rejection, increased competition from petroleum-based products due to pricing differences, adverse weather conditions, availability of natural gas processing and transportation capacity and government regulations affecting prices and production levels of natural gas, NGLs and condensate.

Our hedging activities may not be effective in reducing our direct exposure to commodity price risk and the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows.

We have entered into derivative transactions related to only a portion of the equity volumes of NGLs to which we take title. As a result, we will continue to have direct commodity price risk to the unhedged portion of our NGL equity volumes. We currently have no hedges in place beyond December 2012. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our

liquidity. The derivative instruments we utilize for these hedges are based on posted market prices, which may be lower than the actual NGL prices that we realize in our operations. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certain circumstances may actually increase the variability of our cash flows. To the extent we hedge our commodity price risk, we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. We do not enter into derivative transactions with respect to the volumes of natural gas or condensate that we purchase and sell.

We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.

We purchase from producers and other suppliers a substantial amount of the natural gas that flows through our pipelines and processing facilities for sale to third parties, including natural gas marketers and other purchasers. We are exposed to fluctuations in the price of natural gas through volumes sold pursuant to percent-of-proceeds arrangements as well as through volumes sold pursuant to our fixed-margin contracts.

In order to mitigate our direct commodity price exposure, we do not enter into natural gas hedge contracts, but rather attempt to balance our natural gas sales with our natural gas purchases on an aggregate basis across all of our systems. We may not be successful in balancing our purchases and sales, and as such may become exposed to fluctuations in the price of natural gas. For example, we are currently net purchasers of natural gas on certain of our systems and net sellers of natural gas on certain of our other systems. Our overall net position with respect to natural gas can change over time and our exposure to fluctuations in natural gas prices could materially increase, which in turn could result in increased volatility in our revenue, gross margin and cash flows.

Although we enter into back-to-back purchases and sales of natural gas in our fixed-margin contracts in which we purchase natural gas from producers or suppliers at receipt points on our systems and simultaneously sell an identical volume of natural gas at delivery points on our systems, we may still be exposed to commodity price risks. For example, the volumes or timing of our purchases and sales may not correspond. In addition, a producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to become unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks, which in turn could result in increased volatility in our revenue, gross margin and cash flows.

We are a relatively small enterprise, and our management has limited history with our assets and no experience in managing our business as a publicly traded partnership. As a result, operational, financial and other events in the ordinary course of business could disproportionately affect us, and our ability to grow our business could be significantly limited.

We will be smaller than many of the other companies in our industry for the foreseeable future, not only in terms of market capitalization but also in terms of managerial, operational and financial resources. Consequently, an operational incident, customer loss or other event that would not significantly impact the business and operations of the larger companies in our industry may have a material adverse impact on our business and results of operations. In addition, our executive management team is relatively small with no experience in managing our business as a publicly traded partnership and has managed our business and assets for less than two years. As a result, we may not be able to anticipate or respond to material changes or other events in our business as effectively as if our executive management team had such experience and had managed our business and assets for many years. Furthermore, acquisitions and other growth projects may place a significant strain on our management resources. As a result, our ability to execute our growth strategy and to integrate acquisitions and expansion projects successfully into our existing operations could be significantly limited.

We currently have a limited accounting staff, and if we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 for our fiscal year ending December 31, 2012. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations.

Prior to this offering, we have been a private company and have not been required to file reports with the SEC. We currently have limited accounting personnel, and while we have begun the process of evaluating the adequacy of our accounting personnel staffing level and other matters related to our internal controls over financial reporting, we cannot predict the outcome of our review at this time.

Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our, or our independent registered public accounting firm’s, future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

We depend on a relatively small number of customers for a significant portion of our gross margin. The loss of any one or more of these customers could adversely affect our ability to make distributions to you.

A significant percentage of the gross margin in each of our segments is attributable to a relatively small number of customers. Additionally, a number of customers upon which our business depends are small companies that may in the future have limited access to capital or that may, as a result of operational incidents or other events, be disproportionately affected as a compared to larger, better capitalized companies. In our Gathering and Processing segment, Contango Operators Inc. and Venture Oil & Gas Co. accounted for approximately 19% and 13%, respectively, of our segment gross margin for the year ended December 31, 2010 and approximately 15% and 23%, respectively, of our segment gross margin for the quarter ended March 31, 2011. In our Transmission segment, Calpine Corporation accounted for approximately 38% of our segment gross margin for the year ended December 31, 2010 and approximately 30% of our segment gross margin for the quarter ended March 31, 2011. Although we have gathering, processing or transmission contracts with each of these customers of varying duration and commercial terms, if one or more of these customers were to default on their contract or if we were unable to renew our contract with one or more of these customers on favorable terms, we may not be able to replace any of these customers in a timely fashion, on favorable terms or at all. In any of these situations, our gross margin and cash flows and our ability to make cash distributions to our unitholders may be adversely affected. We expect our exposure to concentrated risk of non-payment or non-performance to continue as long as we remain substantially dependent on a relatively small number of customers for a substantial portion of our gross margin.

If third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash available for distribution could be adversely affected.

Our natural gas gathering and processing and transportation systems connect to other pipelines or facilities, the majority of which, such as the Southern Natural Gas Company, or Sonat, pipeline, the Toca plant, oil gathering lines on Quivira and the Burns Point processing plant, as well as the Destin, Tennessee Gas and Transco pipelines, are owned and operated by third parties. For example, our elective processing arrangements are entirely dependent on the Toca plant for processing services and the Sonat pipeline for natural gas takeaway capacity and are substantially dependent on the Tennessee Gas Pipeline, or TGP, for natural gas supply volumes. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from hurricanes or other operational hazards. If any of these pipelines or other midstream facilities becomes unable to receive or transport natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenue and cash available for distribution could be adversely affected.

Our reliance on our key customers exposes us to their credit risks, and any material nonpayment or nonperformance by our key customers or purchasers could have a material adverse effect on our revenue, gross margin and cash flows.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers to which we provide services and sell commodities. Our three largest purchasers of natural gas in our Gathering and Processing segment are ConocoPhillips, Enbridge Marketing (U.S.) L.P., or EMUS, and Dow Hydrocarbons and Resources, which accounted for approximately 34%, 29% and 10%, respectively, of our segment revenue for the year ended December 31, 2010 and approximately 59%, 16% and 8%, respectively, of our segment revenue for the quarter ended March 31, 2011. Additionally, ExxonMobil and Calpine Corporation are the two largest purchasers of natural gas and transmission capacity, respectively, in our Transmission segment and accounted for approximately 43% and 10%, respectively, of our segment revenue for the year ended December 31, 2010 and approximately 50% and 7%, respectively, of our segment revenue for the quarter ended March 31, 2011.

Some of our customers may be highly leveraged or under-capitalized and subject to their own operating and regulatory risks, which could increase the risk that they may default on their obligations to us. In addition, some of our customers, such as Calpine Corporation, which emerged from bankruptcy in 2008, may have a history of bankruptcy or other material financial and liquidity issues. Any material nonpayment or nonperformance by any of our key customers could have a material adverse effect on our revenue, gross margin and cash flows and our ability to make cash distributions to our unitholders.

Our gathering, processing and transportation contracts subject us to renewal risks.

We gather, purchase, process, transport and sell most of the natural gas and NGLs on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. For example, depending on prevailing market conditions at the time of a contract renewal, gathering and processing customers with percent-of-proceeds contracts may choose to switch to fee-based gathering and transportation contracts, or a producer with whom we have a natural gas purchase contract may choose to enter into a transportation contract with us and retain title to its natural gas. To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenue, gross margin and cash flows could decline and our ability to make distributions to our unitholders could be materially and adversely affected.

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

We compete with other midstream companies in our areas of operation. In addition, some of our competitors are large companies that have greater financial, managerial and other resources than we do. Our competitors may expand or construct gathering, compression, treating, processing or transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, compression, treating, processing or transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Significant portions of our pipeline systems have been in service for several decades and we have a limited ownership history with respect to all of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.

We purchased our assets from Enbridge in November 2009. Significant portions of the pipeline systems that we purchased have been in service for many decades. In addition, our executive management team was hired shortly before that purchase and, consequently, has a limited history of operating our assets. There may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our pipeline systems could adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing 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 U.S. Department of Transportation, or DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could harm “high consequence areas,” including high population areas, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators, including us, to:


	•	perform ongoing assessments of pipeline integrity;

	•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

	•	maintain processes for data collection, integration and analysis;

	•	repair and remediate pipelines as necessary; and

	•	implement preventive and mitigating actions.

Upon reviewing the integrity maintenance plan we inherited, we determined that we have an additional sixteen high consequence areas that we identified after we acquired our assets.

In addition, many states have adopted regulations similar to existing DOT regulations for intrastate gathering and transmission lines. Although many of our natural gas facilities fall within a class that is not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our non-exempt pipelines, particularly our AlaTenn and Midla pipelines. We currently estimate that we will incur future costs of approximately $2.1 million during 2012

to complete the testing required by existing DOT regulations. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT regulations, we could be subject to penalties and fines.

We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our distributions to our unitholders.

If we are unable to make accretive acquisitions from third parties, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors or for any other reason, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

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


	•	mistaken assumptions about volumes, revenue and costs, including synergies;

	•	an inability to secure adequate customer commitments to use the acquired systems or facilities;

	•	an inability to integrate successfully the assets or businesses we acquire, particularly given the relatively small size of our management team and its limited history with our assets;

	•	the assumption of unknown liabilities;

	•	limitations on rights to indemnity from the seller;

	•	mistaken assumptions about the overall costs of equity or debt;

	•	the diversion of management’s and employees’ attention from other business concerns;

	•	unforeseen difficulties operating in new geographic areas and business lines; and

	•	customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

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

One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be

completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.

For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenue until the project is completed and placed into service. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize or only materializes over a period materially longer than expected. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases materially, our cash flows could be adversely affected.

We do not intend to obtain independent evaluations of natural gas reserves connected to our gathering and transportation systems on a regular or ongoing basis; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.

We do not intend to obtain independent evaluations of natural gas reserves connected to our systems on a regular or ongoing basis. Accordingly, we may not have independent estimates of total reserves dedicated to some or all of our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering and transportation systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Recent incidents and their aftermath could lead to additional governmental regulation of the offshore exploration and production industry, which may result in substantial cost increases or delays in offshore drilling as well as our offshore natural gas gathering activities.

In April 2010, a deepwater exploration well located in the Gulf of Mexico, owned and operated by companies unrelated to us, sustained a blowout and subsequent explosion leading to the leaking of hydrocarbons. In response to this event, certain federal agencies and governmental officials ordered additional inspections of deepwater operations in the Gulf of Mexico. On May 28, 2010, a six-month federal moratorium was implemented on all offshore deepwater drilling projects. On October 12, 2010, the Department of the Interior announced it was lifting the deepwater drilling moratorium. Despite the fact that the drilling moratorium was lifted, this spill and its aftermath has led to additional governmental regulation of the offshore exploration and production industry and delays in the issuance of drilling permits, which may result in volume impacts, cost increases or delays in our offshore natural gas gathering activities, which could materially impact our business, financial condition and results of operations. Although none of our offshore gathering systems currently depend on deepwater production, we cannot predict with any certainty what form any additional regulation or limitations would take or what impact they may have on offshore drilling activity in general or the producers to which we provide offshore gathering services.

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

Our operations are subject to all of the risks and hazards inherent in the gathering, compressing, treating, processing and transportation of natural gas, including:


	•	damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

	•	inadvertent damage from construction, vehicles, farm and utility equipment;

	•	leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;

	•	ruptures, fires and explosions; and

	•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

For example, in April 2010, there was a rupture in our Bazor Ridge gathering pipeline which gathers natural gas high in hydrogen sulfide content which resulted in an extended shut-down of a significant portion of that system until the pipeline could be inspected and repaired. The affected portion of the line is the one that gathers the most significant volumes of gas on this system and delivers it to our Bazor Ridge plant, and we were required to curtail a portion of this flow volume until we built a new bypass pipeline, the Winchester Lateral, connecting this production, as well as potential new production, to the Bazor Ridge plant. The affected section of line was fully shut down for approximately 25 days and, until our Winchester Lateral was completed approximately 177 days later, we were able to gather only approximately 70% of pre-rupture flow volume. The Winchester Lateral cost $3.9 million to construct and the repairs to, and testing of, the affected sections of pipe cost approximately $0.5 million.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example, we do not have any casualty insurance on our underground pipeline systems that would cover damage to the pipelines. Additionally, we do not have business interruption/loss of income insurance that would provide coverage in the event of damage to any of our underground facilities. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.

Our interstate natural gas pipelines are subject to regulation by the FERC, which could adversely affect our ability to make distributions to our unitholders.

Our AlaTenn and Midla interstate natural gas transportation systems are subject to regulation by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA. Under the NGA, the rates for and terms of conditions of service on these interstate facilities must be just and reasonable and not unduly discriminatory. The rates and terms and conditions for our interstate pipeline services are set forth in tariffs that must be filed with and approved by the FERC. Pursuant to the FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by

protest. Any successful complaint or protest against our rates could have an adverse impact on our revenue associated with providing transportation service.

Under the NGA, the FERC has the authority to regulate companies that provide natural gas pipeline transportation services in interstate commerce. The FERC’s authority over such companies includes such matters as:


	•	rates and terms and conditions of service;

	•	the types of services interstate pipelines may offer to their customers;

	•	the certification and construction of new facilities;

	•	the acquisition, extension, disposition or abandonment of facilities;

	•	the maintenance of accounts and records;

	•	relationships between affiliated companies involved in certain aspects of the natural gas business;

	•	the initiation and discontinuation of services;

	•	market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and

	•	participation by interstate pipelines in cash management arrangements.

The Energy Policy Act of 2005 amended the NGA to add an anti-manipulation provision. Pursuant to the amended NGA, the FERC established rules prohibiting energy market manipulation. Also, the FERC’s rules require interstate pipelines and their affiliates to adhere to Standards of Conduct that, among other things, require that transportation employees function independently of marketing employees. The FERC also requires interstate pipelines to adhere to its rules regarding the filing and approval of transportation agreements that include provisions which differ from the transportation agreements included in their FERC gas tariff. We are conducting a review of the transportation agreements entered into by our predecessor to determine whether, and to what extent, any of our transportation agreements include such provisions. We are subject to audit by the FERC of our compliance in general, including adherence to all its rules and regulations. A violation of these rules, or any other rules, regulations or orders issued or administered by the FERC, may subject us to civil penalties, disgorgement of unjust profits, or appropriate non-monetary remedies imposed by the FERC. In addition, the Energy Policy Act of 2005 amended the NGA and the Natural Gas Policy Act of 1978, or NGPA, to increase civil and criminal penalties for any violation of the NGA, NGPA and any rules, regulations or orders of the FERC up to $1.0 million per day per violation.

Additionally, existing rates may not reflect our current costs of operations, which may have risen since the last time our rates were approved by the FERC. Because proposed rate increases are procedurally complicated, we may have a significant period of time during which our gross margin from such FERC-regulated systems may be materially less than we have historically obtained.

The application of certain FERC policy statements could affect the rate of return on our equity we are allowed to recover through rates and the amount of any allowance (if any) our interstate systems can include for income taxes in establishing their rates for service, which would in turn impact our revenue and/or equity earnings.

In setting authorized rates of return for interstate natural gas pipelines, the FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. The FERC allows master limited partnerships, or MLPs, to be included in the proxy group to determine return on equity. However, as to such MLPs, the FERC will generally adjust the long-term growth rate used to calculate the equity cost of capital. The FERC stated that the long-term growth projection for natural gas pipeline MLPs will be equal to fifty percent of gross domestic product, or GDP, as compared to the unadjusted GDP used for

corporations. Therefore, to the extent that MLPs are included in a proxy group, the FERC’s policy lowers the return on equity that might otherwise be allowed if there were no adjustment to the MLP growth projection used for the discounted cash flow model. This could lower the return on equity that we would otherwise be able to obtain.

The FERC currently allows partnerships, including MLPs, to include in their cost-of-service an income tax allowance if the partnership’s owners have actual or potential income tax liability, a matter that will be reviewed by the FERC on a case-by-case basis. Any changes to the FERC’s treatment of income tax allowances in cost-of-service rates or an adverse determination with respect to the inclusion of an income tax allowance in our interstate pipelines’ rates could result in an adjustment in a future rate case of our interstate pipelines’ respective equity rates of return that underlie their recourse rates and may cause their recourse rates to be set at a level that is different, and in some instances lower, than the level otherwise in effect.

A change in the jurisdictional characterization or regulation of our assets by federal, state or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets which could materially and adversely affect our financial condition, results of operations and cash flows.

Intrastate transportation facilities that do not provide interstate transmission services are exempt from the jurisdiction of the FERC under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that our intrastate natural gas pipelines and related facilities that are not engaged in providing interstate transmission services are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to FERC jurisdiction. We believe that our natural gas gathering pipelines meet the traditional tests that the FERC has used to determine if a pipeline is a gathering pipeline and is therefore not subject to the FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial ongoing litigation and, over time, the FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and intrastate transportation and gathering facilities, on the other, is a fact-based determination made by the FERC on a case by case basis. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

Moreover, FERC regulation affects our gathering, transportation and compression business generally. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, directly and indirectly affect our gathering business. In addition, the classification and regulation of our gathering and intrastate transportation facilities also are subject to change based on future determinations by the FERC, the courts or Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, the FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of these companies transferring gathering facilities to federally unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels.

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

Our natural gas gathering, compression, treating and transportation operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:


	•	the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;

	•	the federal Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;

	•	the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;

	•	the federal Oil Pollution Act, also known as OPA, and analogous state laws that establish strict liability for releases of oil into waters of the United States;

	•	the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities;

	•	the Endangered Species Act, also known as the ESA; and

	•	the Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations.

There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbon wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering or transportation systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance. Please read “Business — Environmental Matters” for more information.

We recently discovered that our Bazor Ridge processing plant exceeded its air emissions permit and potentially violated other related environmental regulations in 2009 and 2010, the effects of which could be materially adverse to us.

We recently determined that, with respect to our Bazor Ridge processing plant, (i) emissions during 2009 and 2010 exceeded the sulfur dioxide, or SO₂, emission limits under our Title V Air Permit issued pursuant to the federal Clean Air Act, (ii) our emission levels may have required a Prevention of Significant Deterioration, or PSD, permit in 2009 under the federal Clean Air Act, and (iii) our SO₂ emission levels required reporting under the federal Emergency Planning and Community Right-to-Know Act, or EPCRA, in 2009 and 2010 that was not made. As a result of these exceedances and violations, we could be subject to monetary sanctions and our Bazor Ridge plant could become subject to restrictions or limitations (including the possibility of installing additional emission controls) on its operations or be required to obtain a PSD permit or to amend its current Title V Air Permit, the consequences of which (either individually or in the aggregate) could be material. In addition, we may experience a delay in obtaining or be unable to obtain the required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. Please read “Business — Environmental Matters — Air Emissions” for more information about these matters.

We are currently evaluating SO₂ emissions at the Bazor Ridge plant prior to our November 2009 acquisition of the plant. Based on our preliminary analysis, we have recently determined that such SO₂ emissions may have exceeded permitted levels during at least some portion of the statutory five-year limitations period under the federal Clean Air Act, which exceedances may have been significant. We have not yet determined whether the prior owner may have been required to obtain a PSD permit or report SO₂ emissions under EPCRA.

If emission levels for our Bazor Ridge plant were not properly reported by the prior owner or if a PSD permit was required for periods before our acquisition, it is possible that one or both of the Mississippi Department of Environmental Quality, or MDEQ, and the EPA may institute enforcement actions against us and/or the prior owner. If one or both of the MDEQ and the EPA pursue enforcement actions or other sanctions against the prior owner, we may have an obligation under our purchase agreement with the prior owner to indemnify it for any losses (as defined in the purchase agreement) that may result.

Our operations may impact the environment or cause environmental contamination, which could result in material liabilities to us.

Our operations use hazardous materials, generate limited quantities of hazardous wastes and may affect runoff or drainage water. In the event of environmental contamination or a release of hazardous materials, we could become subject to claims for toxic torts, natural resource damages and other damages and for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. These and other impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could have a material adverse effect on us. Please read “Business — Environmental Matters.”

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.

In recent years, the U.S. Congress has been considering legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane, that are understood to contribute to global warming. The American Clean Energy and Security Act of 2009, passed by the House of Representatives, would, if enacted by the full Congress, have required greenhouse gas, or GHG, emissions reductions by covered sources of as much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although

energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either 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 until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that smaller sources such as our gas-fired compressors could become subject to GHG-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

Independent of Congress, the EPA is beginning to adopt regulations controlling GHG emissions under its existing Clean Air Act authority. For example, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human 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. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. Our Bazor Ridge facility is currently required to report under this rule beginning in 2011. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of greenhouse gas emissions by regulated facilities to EPA by March 2012 for emissions during 2011 and annually thereafter. Three of our onshore compression facilities will likely be required to report under this rule, with the first report due to the EPA on March 31, 2012. In 2010, EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the Clean Air Act. Several of EPA’s greenhouse gas rules are being challenged in pending court proceedings and, depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather, treat or otherwise handle in connection with our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of greenhouse gases could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Our pipelines may become subject to more stringent safety regulation.

Proposed pipeline safety legislation requiring more stringent spill reporting and disclosure obligations was introduced in the U.S. Congress and passed by the U.S. House of Representatives in 2010, but was not voted

on in the U.S. Senate. Similar legislation has been proposed in the current session of Congress, either independently or in conjunction with the reauthorization of the Pipeline Safety Act. The Department of Transportation, or DOT, has also recently proposed legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules, which is in addition to the Pipeline and Hazardous Materials Safety Administration’s announced intention to strengthen its rules. The Pipeline and Hazardous Materials Safety Administration, or the PHMSA, which is part of DOT, recently issued a final rule, effective October 1, 2011, applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. We believe that this rule does not apply to any of our pipelines. While we cannot predict the outcome of other proposed legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations particularly by extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines not previously subject to such requirements. Additionally, legislative and regulatory changes may also result in higher penalties for the violation of federal pipeline safety regulations. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations. We cannot predict with any certainty at this time the terms of any new laws or rules or the costs of compliance associated with such requirements.

The adoption and implementation of new statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010 federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted. The Dodd-Frank Act provides new statutory requirements for swap transactions, including oil and gas hedging transactions. These statutory requirements must be implemented through, regulation primarily through rules to be adopted by the Commodities Futures Trading Commission, or the CFTC. The Dodd-Frank Act provisions are intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which most swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. Many market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that may impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants will be subject to new reporting and recordkeeping requirements.

The impact of the Dodd-Frank Act on our hedging activities is uncertain at this time, and the CFTC has not yet promulgated final regulations implementing the key provisions. Although we do not believe we will need to register as a swap dealer or major swap participant, and do not believe we will be subject to the new requirements to trade on an exchange or swap execution facility or to clear swaps through a central counterparty, we may have new regulatory burdens. Moreover, the changes to the swap market as a result of Dodd-Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps.

Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

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

We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use

if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Restrictions in our new credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

We expect to enter into a new credit facility concurrently with the closing of the offering. Our new credit facility is likely to limit our ability to, among other things:


	•	incur additional debt;

	•	make distributions on or redeem or repurchase units;

	•	make certain investments and acquisitions;

	•	incur certain liens or permit them to exist;

	•	enter into certain types of transactions with affiliates;

	•	merge or consolidate with another company; and

	•	transfer or otherwise dispose of assets.

Our new credit facility also will likely contain covenants requiring us to maintain certain financial ratios.

The provisions of our new credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our new credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our future level of debt could have important consequences to us, including the following:


	•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

	•	our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

	•	we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

	•	our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

As our common units will be yield-oriented securities, increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

We currently have a small management team, and our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel.

We currently have a small management team, and our ability to operate our business and implement our strategies depends on the continued contributions of certain executive officers and key employees of our general partner. Our general partner has a smaller managerial, operational and financial staff than many of the companies in our industry. Given the small size of our management team, the loss of any one member of our management team could have a material adverse effect on our business. In addition, certain of our field operating managers are approaching retirement age. We believe that our future success will depend on our continued ability to attract and retain highly skilled management personnel with midstream natural gas industry experience and competition for these persons in the midstream natural gas industry is intense. Given our small size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

A shortage of skilled labor in the midstream natural gas industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.

The gathering, treating, processing and transporting of natural gas requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our general partner’s employees, our results of operations could be materially and adversely affected.

Our work force could become unionized in the future, which could adversely affect the stability of our production and materially reduce our profitability.

All of our systems are operated by non-union employees of our general partner. Our employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. If our employees choose to form or affiliate with a union and the terms of a union collective bargaining agreement are significantly different from our current compensation and job assignment arrangements with our employees, these arrangements could adversely affect the stability of our operations and materially reduce our profitability.

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions

during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Risks Inherent in an Investment in Us

AIM Midstream Holdings directly owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. AIM Midstream Holdings and our general partner have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.

Following this offering, AIM Midstream Holdings will own and control our general partner, as well as appoint all of the officers and directors of our general partner, some of whom will also be officers of AIM Midstream Holdings. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, AIM Midstream Holdings. Conflicts of interest may arise between AIM Midstream Holdings and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of AIM Midstream Holdings over our interests and the interests of our unitholders. These conflicts include the following situations, among others:


	•	Neither our partnership agreement nor any other agreement requires AIM Midstream Holdings to pursue a business strategy that favors us.

	•	Our general partner is allowed to take into account the interests of parties other than us, such as AIM Midstream Holdings, in resolving conflicts of interest.

	•	Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

	•	Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

	•	Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

	•	Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.

	•	Our general partner determines which costs incurred by it are reimbursable by us.

	•	Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

	•	Our partnership agreement permits us to classify up to $11.5 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.

	•	Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

	•	Our general partner intends to limit its liability regarding our contractual and other obligations.


	•	Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

	•	Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

	•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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

Please read “Conflicts of Interest and Fiduciary Duties.”

AIM Midstream Holdings is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.

AIM Midstream Holdings is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, AIM Midstream Holdings may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while AIM Midstream Holdings may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only 3,750,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional common units. In addition, AIM Midstream Holdings will own 725,120 common units and 4,526,066 subordinated units, representing an aggregate of approximately 56.8% limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Furthermore, this offering is smaller than initial public offerings for midstream companies in recent years, which may lead to an even greater lack of liquidity than normal. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:


	•	our quarterly distributions;

	•	our quarterly or annual earnings or those of other companies in our industry;

	•	the loss of a large customer;

	•	announcements by us or our competitors of significant contracts or acquisitions;

	•	changes in accounting standards, policies, guidance, interpretations or principles;

	•	general economic conditions;


	•	the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

	•	future sales of our common units; and

	•	other factors described in these “Risk Factors.”

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We have been approved to list our common units on the NYSE subject to official notice of issuance. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management.”

If you are not an eligible holder, you may not receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.

We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are U.S. individuals or entities subject to such taxation. If you are not an eligible holder, our general partner may elect not to make distributions or allocate income or loss on your units, and you run the risk of having your units redeemed by us at the lower of your purchase price cost and the then-current market price. The redemption price may be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “The Partnership Agreement — Non-Citizen Assignees; Redemption.”

Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.

Our partnership agreement gives our general partner the power to amend the agreement to avoid any adverse effect on the maximum applicable rates chargeable to customers by us under FERC regulations, or in order to reverse an adverse determination that has occurred regarding such maximum rate. If our general partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. Please read “The Partnership Agreement — Non-Taxpaying Assignees; Redemption.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our

general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitation in our new credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.

Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner or otherwise, free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:


	•	how to allocate corporate opportunities among us and its affiliates;

	•	whether to exercise its limited call right;

	•	how to exercise its voting rights with respect to the units it owns;

	•	whether to elect to reset target distribution levels; and

	•	whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:


	•	provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any


		other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;


	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in, or not opposed to, the best interest of our partnership;

	•	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

	•	provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

(a) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

(b) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

(c) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

(d) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such

situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”

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

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by AIM Midstream Holdings. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the closing of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding limited partner units voting together as a single class is required to remove our general partner. Following the closing of this offering, AIM Midstream Holdings will own 58.0% of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

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

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of AIM Midstream Holdings to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

You will experience immediate and substantial dilution in net tangible book value of $8.13 per common unit.

The estimated initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus) exceeds our pro forma net tangible book value of $11.87 per unit. Based on the estimated initial public offering price of $20.00 per common unit, you will incur immediate and substantial dilution of $8.13 per common unit. Please read “Dilution.”

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

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


	•	our existing unitholders’ proportionate ownership interest in us will decrease;

	•	the amount of cash available for distribution on each unit may decrease;

	•	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

	•	the ratio of taxable income to distributions may increase;

	•	the relative voting strength of each previously outstanding unit may be diminished; and

	•	the market price of the common units may decline.

AIM Midstream Holdings may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, AIM Midstream Holdings will hold an aggregate of 725,120 common units and 4,526,066 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the closing of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, AIM Midstream Holdings will own approximately 16.0% of our outstanding common units. At the end of the

subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), AIM Midstream Holdings will own approximately 58.0% of our outstanding common units. For additional information about this right, please read “The Partnership Agreement — Limited Call Right.”

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

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:


	•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

	•	your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement — Limited Liability.”

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the New York Stock Exchange, or the NYSE, have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We have included $2.3 million of estimated annual incremental costs associated with being a publicly traded

partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. If we were taxed as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units. For a discussion of the federal income tax implications that would result from our treatment as a corporation in any taxable year, please read “Material Federal Income Tax Consequences — Partnership Status.”

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate distributions (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

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

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. 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. Imposition of such a tax on us by Texas, and if applicable by any other state, will reduce the cash available for distribution to you. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly

distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Recently, members of the U.S. Congress have considered substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships, which, if enacted, may or may not be applied retroactively. Although we are unable to predict whether any of these changes or any other proposals will ultimately be enacted, any such changes could negatively impact the value of an investment in our common units.

Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Federal Income Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Andrews Kurth LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Allocations Between Transferors and Transferees.”

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common

units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We will initially own property or conduct business in a number of states, most of which currently impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax laws and regulations, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

USE OF PROCEEDS

We expect to receive net proceeds of approximately $69.8 million (based upon the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, commissions and structuring fees, but before paying offering expenses, from the issuance and sale of common units offered by this prospectus. We will use the net proceeds from this offering to:


	•	repay in full the outstanding balance under our existing credit facility;

	•	pay offering expenses of approximately $3.3 million;

	•	terminate, in exchange for a payment of $2.5 million, the advisory services agreement between American Midstream, LLC and AIM;

	•	establish a cash reserve of $2.2 million related to non-recurring deferred maintenance capital expenditures for the twelve months ending June 30, 2012; and

	•	make an aggregate distribution of approximately $2.0 million, on a pro rata basis, to LTIP participants holding common units, AIM Midstream Holdings and our general partner. The distribution to AIM Midstream Holdings and our general partner will be a reimbursement for certain capital expenditures incurred with respect to assets contributed to us.

Immediately following the repayment of the outstanding balance under our existing credit facility with the net proceeds of this offering, we will terminate our existing credit facility and enter into a new credit facility and borrow approximately $30.0 million under that credit facility. We will use the proceeds from our borrowings to (i) make an aggregate distribution of approximately $28.0 million, on a pro rata basis, to LTIP participants holding common units, AIM Midstream Holdings and our general partner and (ii) pay fees and expenses of approximately $2.0 million relating to our new credit facility. The distribution made to AIM Midstream Holdings and our general partner will be a reimbursement for certain capital expenditures incurred with respect to assets contributed to us.

The following table illustrates our use of the net proceeds from this offering and our borrowings under our new credit facility.


Sources of Cash (in millions)	Uses of Cash (in millions)


Net proceeds from this offering	$	69.8	Repayment of outstanding balance under existing credit facility	$	59.8

Borrowings under new credit facility	$	30.0	Termination of advisory services agreement	$	2.5

			Establishment of cash reserve related to non-recurring deferred maintenance capital expenditures for the twelve months ending June 30, 2012	$	2.2

			Distribution to AIM Midstream Holdings, the LTIP participants holding common units and our general partner	$	30.0

			Offering and credit facility expenses payable by us	$	5.3


Total	$	99.8	Total	$	99.8

A portion of the amounts to be repaid under our existing credit facility with the net proceeds of this offering were used to finance our acquisition of our assets in November 2009. As of June 6, 2011, we had approximately $59.8 million of indebtedness outstanding under our existing credit facility. This indebtedness had a weighted average interest rate of 7.3% as of June 6, 2011. At March 31, 2011, we had $56.5 million of borrowings outstanding under our existing credit facility. Our existing credit facility matures in November 2012.

Our estimates assume an initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus) and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, to increase or decrease by $3.5 million. Any increase or decrease in the initial public offering price will result in a corresponding adjustment to the distribution to the LTIP participants holding common units, AIM Midstream Holdings and our general partner from the net proceeds of this offering.

Our estimates assume an outstanding balance under our existing credit facility of $59.8 million, which was our balance as of June 6, 2011. An increase or decrease in the outstanding balance under our existing credit facility of $1.0 million would result in a corresponding $1.0 million decrease or increase, respectively, in the distribution to the LTIP participants holding common units, AIM Midstream Holdings and our general partner from the net proceeds of this offering.

If the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from AIM Midstream Holdings a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit in this offering before expenses but after deducting underwriting discounts, commissions and structuring fees.

The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Please read “Underwriting.”

CAPITALIZATION

The following table shows:


	•	our historical capitalization, as of March 31, 2011; and

	•	our pro forma as adjusted capitalization, as of March 31, 2011, giving effect to:


	•	our receipt and use of net proceeds of $69.8 million from the issuance and sale of 3,750,000 common units to the public at an assumed initial offering price of $20.00 per unit (the mid-point of the price range set forth on the cover of this prospectus) in the manner described in “Use of Proceeds,’’ including the repayment of all outstanding indebtedness under our existing credit facility;


	•	the entry into and borrowings of $30.0 million under the new credit facility; and

	•	the other transactions described in “Summary — Recapitalization Transactions and Partnership Structure.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This table assumes that the underwriters’ option to purchase additional common units is not exercised.


	As of March 31, 2011
			Pro Forma,
	Historical		As Adjusted
	(in thousands)

Cash and cash equivalents(1)	$	153	$	2,353

Long-Term Debt:
Existing credit facility(2)	$	56,500	$	—
New credit facility(3)(4)		—		30,000

Total long-term debt (including current maturities)	$	56,500	$	30,000

Partners’ Capital:
Limited partners
Common unitholders — public(5)	$	—	$	64,000
Common unitholders — AIM Midstream Holdings(5)		76,911		5,502
Subordinated unitholders — AIM Midstream Holdings(5)		—		37,248
General partner(5)		1,998		2,859

Total partners’ capital(6)	$	78,909	$	109,609

Total capitalization	$	135,409	$	139,609


(1)		The pro forma, as adjusted amount includes $2.2 million of cash reserved for our non-recurring deferred maintenance capital expenditures.

(2)		As of June 6, 2011, we had $59.8 million of borrowings outstanding under our existing credit facility (excluding $0.6 million in outstanding letters of credit). As a result, the distribution to AIM Midstream holdings, LTIP participants holding common units and our general partner implied from the table above on a pro forma basis is $3.3 million higher than the distribution described in “Use of Proceeds.”

(3)		Does not include $0.6 million in currently outstanding letters of credit that will be issued under our new credit facility.

(4)		We expect the initial interest rate under our new credit facility to be 3.0%.

(5)		As of March 31, 2011, we had 11,080,967 common units, no subordinated units and 224,000 general partner units issued and outstanding. On a pro forma, as adjusted basis, giving effect to the transactions described in “Summary — Recapitalization Transactions and Partnership Structure” and the issuance of 3,750,000 common units in this offering, we had 4,526,066 common units, 4,526,066 subordinated units and 184,737 general partner units issued and outstanding as of March 31, 2011.

(6)		Total partners’ capital does not include $0.1 million of accumulated other comprehensive income.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of March 31, 2011, after giving effect to the recapitalization transactions and the offering of common units at an initial public offering price of $20.00 (the mid-point of the price range set forth on the cover of this prospectus) and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $109.7 million, or $11.87 per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:


Assumed initial public offering price per common unit				$	20.00
Net tangible book value per unit before the offering(1)	$	14.39
Decrease in net tangible book value per unit attributable to purchasers in the offering		(2.52	)

Less: Pro forma net tangible book value per unit after the offering(2)					11.87

Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)				$	8.13


(1)		Determined by dividing the number of units (852,085 common units, 4,526,066 subordinated units and 108,718 general partner units) held by our general partner and its affiliates, including AIM Midstream Holdings, and LTIP participants holding common units into the net tangible book value of our assets.

(2)		Determined by dividing the total number of units to be outstanding after this offering (4,526,066 common units, 4,526,066 subordinated units and 184,737 general partner units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of this offering.

(3)		If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $9.13 and $7.13, respectively. Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the option.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering upon the closing of the transactions contemplated by this prospectus:


	Units Acquired					Total Consideration
	Number		Percent			Amount		Percent
	($ in thousands)

General partner and affiliates(1)(2)		5,486,869		59.4	%	$	78,965		53.1	%
Purchasers in the offering		3,750,000		40.6			69,750		46.9

Total		9,236,869		100.0	%	$	148,715		100.0	%


(1)		The units acquired by our general partner and its affiliates, including AIM Midstream Holdings, and LTIP participants holding common units consist of 776,066 common units, 4,526,066 subordinated units and 184,737 general partner units.

(2)		Assumes the underwriters’ option to purchase additional common units is not exercised.

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “— Assumptions and Considerations” below. In addition, please read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical operating results, you should refer to our historical consolidated financial statements and related notes and our Predecessor’s historical combined financial statements and related notes included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects our belief that our unitholders will be better served if we distribute rather than retain our available cash. Generally, our available cash is the sum of our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:


	•	Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement provides that in order for a determination by our general partner to be considered to have been made in good faith, our general partner must believe that the determination is in our best interests.

	•	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain limited circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by AIM Midstream Holdings) after the subordination period has ended. At the closing of this offering, assuming no exercise of the underwriters’ option to purchase additional common units, AIM Midstream Holdings will own our general partner and approximately 16.0% of our outstanding common units and all of our outstanding subordinated units, or 58.0% of our limited partner interests.

	•	Even if our cash distribution policy is not modified or revoked, the amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

	•	Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

	•	We may lack sufficient cash to pay distributions to our unitholders for a number of reasons, including as a result of increases in our operating or general and administrative expenses, principal and interest


		payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our general partner will not receive a management fee or other compensation for its management of us. However, under our partnership agreement, we are obligated to reimburse our general partner and its affiliates for all expenses incurred on our behalf. Our partnership agreement provides that our general partner will determine the amount of these reimbursed expenses.

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

Because we will distribute all of our available cash to our unitholders, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitations in our new credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution

Upon the closing of this offering, the board of directors of our general partner intends to adopt an initial distribution rate of $0.4125 per unit per quarter, or $1.65 per unit on an annualized basis, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending September 30, 2011. This equates to an aggregate cash distribution of $3.8 million per quarter, or $15.2 million on an annualized basis, based on the number of common and subordinated units anticipated to be outstanding immediately after the closing of this offering, as well as our 2.0% general partner interest. We refer to our initial quarterly distribution rate as our minimum quarterly distribution. We will adjust our first distribution for the period from the closing of this offering through September 30, 2011 based on the length of that period.

To the extent the underwriters exercise their option to purchase additional common units, we will use the net proceeds from that exercise to redeem from AIM Midstream Holdings a number of common units equal to the number of common units issued upon such exercise, at a price per common unit equal to the proceeds per common unit before expenses but after deducting underwriting discounts, commissions and structuring fees. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units or subordinated units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Use of Proceeds.”

Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner’s initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest.

The table below sets forth the number of common, subordinated and general partner units that we anticipate will be outstanding immediately following the closing of this offering, assuming the underwriters do not exercise their option to purchase additional common units and the aggregate distribution amounts payable on those units during the year following the closing of this offering at our minimum quarterly distribution rate of $0.4125 per unit per quarter ($1.65 per unit on an annualized basis).


	Number of
	Units		Minimum Quarterly Distributions
			One Quarter		Annualized

Public Common Units		3,750,000	$	1,546,875	$	6,187,500
AIM Midstream Holdings Units:
Common Units		725,120		299,112		1,196,449
Subordinated Units		4,526,066		1,867,002		7,468,009
LTIP Participants Common Units		50,946		21,015		84,061
General Partner Interest		184,737		76,204		304,816

Total		9,236,869	$	3,810,208	$	15,240,834

The subordination period generally will end and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $1.65 on each outstanding common and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2014. The subordination period will automatically terminate and all of the subordinated units will convert into an equal number of common units if we have earned and paid at least $2.475 (150% of the annualized minimum quarterly distribution) on each outstanding common and subordinated unit and the corresponding distributions on our general partner’s 2.0% interest and incentive distribution rights for any four consecutive quarter period ending on or after September 30, 2012; provided that we have paid at least the minimum quarterly distribution from operating surplus on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each quarter in that four-quarter period. Please read the “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”

If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except in some circumstances during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units and the corresponding distributions on our general partner’s 2.0% interest, we will use this excess available cash to pay any distribution arrearages on the common units related to prior quarters before any cash distribution is made to holders of the subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $1.65 per unit for the twelve months ending June 30, 2012. In those sections, we present two tables, consisting of:


	•	“Unaudited Historical As Adjusted Available Cash,” in which we present the amount of cash we would have had available for distribution on a historical as adjusted basis for our fiscal year ended December 31, 2010 and for the twelve months ended March 31, 2011, derived from our audited historical consolidated financial statements that are included in this prospectus, as adjusted to give


		effect to the incremental general and administrative expenses associated with being a publicly traded partnership; and


	•	“Statement of Estimated Adjusted EBITDA,” which supports our belief that we will be able to generate the sufficient estimated adjusted EBITDA to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2012.

Unaudited Historical As Adjusted Available Cash for the Year Ended December 31, 2010 and for the Twelve Months Ended March 31, 2011

If we had completed this offering on January 1, 2010, our historical as adjusted available cash generated would have been approximately $10.0 million for the year ended December 31, 2010. This amount would have been insufficient to pay the minimum quarterly distribution on all of our common and subordinated units for such period.

If we had completed this offering on April 1, 2010, our historical as adjusted available cash generated would have been approximately $10.9 million for the twelve months ended March 31, 2011. This amount would have been insufficient to pay the minimum quarterly distribution on all of our common and subordinated units for such period.

Our unaudited historical as adjusted available cash for the year ended December 31, 2010 and for the twelve months ended March 31, 2011 includes $2.3 million of incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. This amount is an estimate, and our general partner will ultimately determine the actual amount of these incremental general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. Incremental general and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees and director and officer insurance expenses. These expenses are not reflected in our or our Predecessor’s historical financial statements.

Our estimate of incremental general and administrative expenses is based upon currently available information. The adjusted amounts below do not purport to present our results of operations had this offering been completed as of the date indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our historical consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of historical as adjusted available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we completed this offering on the dates indicated.

The following table illustrates, on a historical as adjusted basis, for the year ended December 31, 2010 and for the twelve months ended March 31, 2011, the amount of cash that would have been available for distribution to our unitholders, assuming that this offering had been completed at the beginning of such periods. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.

Unaudited Historical As Adjusted Available Cash


	Year Ended			Twelve Months Ended
	December 31, 2010			March 31, 2011
	(in thousands, except per unit data)

Net Loss	$	(8,644	)	$	(10,700	)
Adjustments to reconcile net loss to adjusted EBITDA:
Add:
Other non-cash items(1)		1,488			5,282
Depreciation expense		20,013			20,084
Interest expense		5,406			5,313

Adjusted EBITDA(2)	$	18,263		$	19,979
Adjustments to reconcile adjusted EBITDA to Historical as Adjusted Available Cash:
Less:
Incremental general and administrative expenses of being a publicly traded partnership(3)		2,250			2,250
Net cash interest expense		4,523			4,379
Maintenance capital expenditures(4)		1,659			2,442
Expansion capital expenditures(4)		8,609			8,665
Add:
Capital contributed to fund expansion capital expenditures(5)		8,609			8,665

Historical as Adjusted Available Cash	$	9,831		$	10,908

Cash Distributions
Distributions per unit(6)		1.65			1.65
Distributions to public common unitholders(6)		6,188			6,188
Distributions to AIM Midstream Holdings, our general partner and LTIP participants(6)(7)		9,053			9,053

Total Distributions	$	15,241		$	15,241

Excess (Shortfall)	$	(5,410	)	$	(4,333	)

Percent of minimum quarterly distributions payable to common unitholders		100.0	%		100.0	%
Percent of minimum quarterly distributions payable to subordinated unitholders		29.0	%		43.1	%


(1)		Includes non-cash compensation expense related to our LTIP, an unrealized loss on our commodity derivatives and certain transaction expenses related to our formation, entry into our new credit facility and acquisition of assets.

(2)		For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.”

(3)		Represents estimated cash expenses associated with being a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees and director and officer insurance expenses.


(4)		Our capital expenditures totaled $10.3 million and $11.1 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. For these periods, capital expenditures included maintenance capital expenditures and expansion capital expenditures. For the year ended December 31, 2010, we estimate that 16.2% of our capital expenditures, or $1.7 million, were maintenance capital expenditures and that 83.8% of our capital expenditures, or $8.6 million, were expansion capital expenditures. For the twelve months ended March 31, 2011, we estimate that 22.0% of our capital expenditures, or $2.4 million, were maintenance capital expenditures and that 78.0% of our capital expenditures, or $8.7 million, were expansion capital expenditures. Although we classified our capital expenditures as maintenance capital expenditures and expansion capital expenditures, we believe those classifications approximate, but do not necessarily correspond to, the definitions of estimated maintenance capital expenditures and expansion capital expenditures under our partnership agreement. While we expect that, in the future, expansion capital expenditures will primarily be funded through borrowings or the sale of debt or equity securities, we funded our expansion capital expenditures during the year ended December 31, 2010 and the twelve months ended March 31, 2011 through a capital contribution made to us by AIM Midstream Holdings and our general partner.


(5)		Consists of an aggregate of $8.6 million in capital contributed to us by AIM Midstream Holdings and our general partner in September and November of 2010 that was used to fund our expansion capital expenditures during these periods.


(6)		The table above is based on the following assumptions: (i) the recapitalization transactions have been consummated and our general partner has maintained its 2.0% general partner interest, (ii) we have issued 3,750,000 common units in this offering, and (iii) the underwriters’ option to purchase additional common units has not been exercised. Please read “Summary — Recapitalization Transactions and Partnership Structure.” The table reflects the number of common and subordinated units that we anticipate will be outstanding immediately following the closing of this offering, as well as our 2.0% general partner interest, and the aggregate distribution amounts payable on those units during the year following the closing of this offering at our minimum quarterly distribution rate of $0.4125 per unit per quarter ($1.65 per unit on an annualized basis), as well as the corresponding distribution on our 2.0% general partner interest.


(7)		Does not include common units issuable pursuant to unvested phantom units that have been granted under our LTIP. As of June 27, 2011, on a pro forma basis after giving effect to the recapitalization transactions, we had 209,824 unvested phantom units outstanding under our LTIP, none of which are subject to vesting within 60 days of the date of this prospectus.

Estimated Adjusted EBITDA for the Twelve Months Ending June 30, 2012

Set forth below is a Statement of Estimated Adjusted EBITDA that supports our belief that we will be able to generate sufficient cash available for distribution to pay the annualized minimum quarterly distribution on all of our outstanding units for the twelve months ending June 30, 2012. The financial forecast presents, to the best of our knowledge and belief, the expected results of operations, adjusted EBITDA and cash available for distribution for the forecast period. We define adjusted EBITDA as net income, plus interest expense, income tax expense, depreciation expense, certain non-cash charges such as non-cash equity compensation, unrealized losses on commodity derivative contracts and selected charges that are unusual or non-recurring, less interest income, income tax benefit, unrealized gains on commodity derivative contracts and selected gains that are unusual or non-recurring.

For a reconciliation of adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.”

Our Statement of Estimated Adjusted EBITDA reflects our judgment, as of the date of this prospectus, of conditions we expect to exist and the course of action we expect to take in order to be able to pay the annualized minimum quarterly distribution on all of our outstanding units and the corresponding distributions on our general partner’s 2.0% interest for the twelve months ending June 30, 2012. The assumptions discussed below under “— Assumptions and Considerations” are those that we believe are significant to our ability to generate our estimated adjusted EBITDA. We believe our actual results of operations and cash flows will be sufficient to generate the minimum adjusted EBITDA necessary to pay the annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution

on our 2.0% general partner interest, for the twelve months ending June 30, 2012; however, we can give you no assurance that we will generate this amount. There will likely be differences between our estimated adjusted EBITDA and our actual results and those differences could be material. If we fail to generate our estimated adjusted EBITDA, we may not be able to pay the annualized minimum quarterly distribution on all of our outstanding limited partner units and the corresponding distribution on our 2.0% general partner interest. In order to fund distributions on all of our outstanding common, subordinated and general partner units at our initial rate of $1.65 per unit on an annualized basis, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2012, our adjusted EBITDA for the twelve months ending June 30, 2012 must be at least $19.5 million.

We do not, as a matter of course, make public projections as to future operations, earnings or other results. However, management has prepared the Statement of Estimated Adjusted EBITDA and related assumptions and considerations set forth below to substantiate our belief that we will have sufficient available cash to pay the annualized minimum quarterly distribution to all our unitholders for the twelve months ending June 30, 2012. This forecast is a forward-looking statement and should be read together with our historical consolidated financial statements and the accompanying notes, and our Predecessor’s historical combined financial statements and the accompanying notes included elsewhere in this prospectus, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, is substantially consistent with those guidelines and was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate the minimum adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the aggregate annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2012. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has not examined, compiled or performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The reports of PricewaterhouseCoopers LLP included in this prospectus relate to our and our Predecessor’s historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate the minimum adjusted EBITDA necessary to pay the annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2012.

We are providing the Statement of Estimated Adjusted EBITDA to supplement our historical consolidated financial statements and our Predecessor’s historical combined financial statements in support of our belief that we will have sufficient available cash to pay the annualized minimum quarterly distribution on all of our outstanding common and subordinated units, as well as the corresponding distribution on our 2.0% general partner interest, for the twelve months ending June 30, 2012. Please read below under “— Assumptions and Considerations” for further information as to the assumptions we have made for the financial forecast.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

Statement of Estimated Adjusted EBITDA


	Twelve Months
	Ending
	June 30, 2012
	(in thousands, except
	per unit data)

Total Revenue	$	279,915
Purchases of natural gas, NGLs and condensate		233,776

Gross margin(1)	$	46,139
Operating expenses:
Direct operating expenses		14,404
Selling, general and administrative expenses(2)		10,837
Depreciation expense		20,181

Total operating expenses	$	45,422

Operating income (loss)		717
Interest expense		1,803

Net income (loss)	$	(1,086	)
Adjustments to reconcile net income to estimated adjusted EBITDA:
Add:
Interest expense		1,803
Non-cash compensation expense related to our LTIP		1,600
Depreciation expense		20,181

Estimated adjusted EBITDA(1)	$	22,498
Adjustments to reconcile estimated adjusted EBITDA to estimated cash available for distribution:
Less:
Cash interest expense		1,214
Estimated maintenance capital expenditures(3)		3,000
Non-recurring deferred maintenance capital expenditures during forecast period		2,200
Expansion capital expenditures		3,755
Add:
Non-cash items(4)		5
Borrowings to fund expansion capital expenditures		3,755
Cash from offering proceeds reserved to fund non-recurring deferred maintenance capital expenditures		2,200

Estimated Cash Available for Distribution	$	18,289

Estimated Annual Cash Distributions
Distributions per unit(5)		1.65
Distributions on public common units(5)		6,188
Distributions on common units held by AIM Midstream Holdings(5)		1,196
Distributions on subordinated units held by AIM Midstream Holdings(5)		7,468
Distributions to our general partner(5)		305
Distributions on common units held by LTIP participants(5)(6)		84
Total Estimated Annual Distributions	$	15,241

Excess Cash Available for Distributions	$	3,048

Minimum Estimated Adjusted EBITDA	$	19,450

Percent of minimum quarterly distributions payable to common unitholders		100	%
Percent of minimum quarterly distributions payable to subordinated unitholders		100	%


(1)		For definitions of adjusted EBITDA and gross margin, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures.”


(2)		Includes $2.3 million of estimated cash expenses associated with being a publicly traded partnership, such as expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution, Sarbanes-Oxley compliance, expenses associated with listing on the NYSE, independent auditor fees, legal fees, investor relations expenses, registrar and transfer agent fees and director and officer insurance expenses.

(3)		The 3.0 million of estimated maintenance capital expenditures for the forecast period does not include $1.5 million of forecasted integrity management expenditures for that period, which amount is included in direct operating expenses as required by GAAP.

(4)		Represents estimated non-cash costs associated with our commodity price hedging program and non-cash revenue from our construction, operating and maintenance agreements.

(5)		The table above is based on the assumption that the underwriters’ option to purchase additional common units has not been exercised and reflects the number of common and subordinated units that we anticipate will be outstanding immediately following the closing of this offering, as well as our 2.0% general partner interest, and the aggregate distribution amounts payable on those units during the forecast period at our minimum quarterly distribution rate of $1.65 per unit on an annualized basis, as well as the corresponding distribution on our 2.0% general partner interest.


(6)		Does not include common units issuable pursuant to unvested phantom units that have been granted under our LTIP. As of June 27, 2011, on a pro forma basis after giving effect to the recapitalization transactions we had 209,824 unvested phantom units outstanding under our LTIP, none of which are subject to vesting within 60 days of the date of this prospectus.

Assumptions and Considerations

Set forth below are the material assumptions that we have made in order to demonstrate our ability to generate our estimated adjusted EBITDA for the twelve months ending June 30, 2012.

General Considerations and Sensitivity Analysis


	•	Revenue and operating expenses are net of intercompany transactions.

	•	We estimate that the price of natural gas, NGLs and condensate for the twelve months ending June 30, 2012 will average $4.72 per Mcf, $1.51 per gallon and $2.41 per gallon, respectively. These estimates for the price of natural gas, NGLs and condensate were prepared using forward NYMEX natural gas, OPIS NGL and NYMEX crude oil strip prices, respectively, as of May 25, 2011. The prices we expect to realize reflect various discounts or premiums to these NYMEX- and OPIS-based prices due to transportation, quality and regional price adjustments as well as the effect of the hedging program described below.

	•	Our estimated revenue, gross margin and adjusted EBITDA include the effect of our commodity price hedging program under which we have hedged a portion of the commodity price risk related to our expected NGL sales with swaps and puts, primarily on individual NGL components. Our hedging program for the twelve months ending June 30, 2012 covers approximately 89% of our expected NGL equity volumes for that period. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.”

	•	System throughput volumes and realized natural gas and NGL prices are the key factors that will influence whether the amount of cash available for distribution for the twelve months ending June 30, 2012 is above or below our forecast. For example, if all other assumptions are held constant, a 5.0% increase or decrease in volumes across all of our assets above or below forecasted levels would result in a $1.6 million increase or decrease, respectively, in cash available for distribution. A 5.0% increase or decrease in the price of natural gas above or below forecasted levels would result in a $0.2 million decrease or increase, respectively, in cash available for distribution. A 5.0% decrease in the price of NGLs below forecasted levels, including the effect of our existing hedges, would result in a $0.4 million decrease in cash available for distribution. A 5.0% increase in the price of NGLs above forecasted levels, including the effect of our existing hedges, would result in a $0.4 million increase in cash available for distribution. A decrease in forecasted cash flow of greater than $3.0 million would result in our generating less than the minimum cash required to pay distributions during the forecast period.

Total Revenue

We estimate that we will generate total revenue of $279.9 million for the twelve months ending June 30, 2012, compared to $211.9 million and $221.0 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. This increase primarily relates to higher expected volumes and higher NGL and condensate prices on our systems as described below. Please read “— Gathering and Processing Segment Gross Margin” and “— Transmission Segment Gross Margin.”

Purchases of Natural Gas, NGLs and Condensate

We estimate that total purchases of natural gas, NGLs and condensate for the twelve months ending June 30, 2012 will be $233.8 million, compared to $173.8 million and $183.8 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. The expected increase in purchases of natural gas, NGLs and condensate for the twelve months ending June 30, 2012 compared to each of the year ended December 31, 2010 and the twelve months ended March 31, 2011 is primarily due to expected higher volumes on

our systems and higher NGL and condensate prices, as further described below. We purchase natural gas and NGLs at market prices adjusted for transportation, quality and regional price differentials. As further discussed below, $152.0 million of our estimated purchases of natural gas relate to fixed-margin contracts in our two segments.

Gathering and Processing Segment Gross Margin

We estimate that we will generate segment gross margin for our Gathering and Processing segment of $32.9 million for the twelve months ending June 30, 2012, as compared to $24.6 million and $26.7 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. The table below outlines the composition of our estimated and actual segment gross margin for our Gathering and Processing segment for the twelve months ending June 30, 2012, the year ended December 31, 2010 and the twelve months ended March 31, 2011.


	Historical				Projected
			Twelve Months		Twelve Months
	Year Ended		Ended		Ending
	December 31, 2010		March 31, 2011		June 30, 2012

Gathering and Processing Segment Gross Margin:
Fee-based	$	6.5	$	7.1	$	10.0
Fixed-margin		4.9		4.8		3.0
Percent-of-proceeds — fee-based		0.9		1.7		2.9
Percent-of-proceeds — equity		12.3		13.1		17.0	(1)

Total	$	24.6	$	26.7	$	32.9


(1)		Includes a net realized loss of $1.1 million due to our hedging program.

With respect to the fee-based and fixed-margin portions of our estimated segment gross margin, the increase is primarily attributable to higher estimated volumes on our systems, as further described below. The increase in segment gross margin related to the sale of our equity volumes under our percent-of-proceeds arrangements is attributable to increased estimated volumes on our Gloria and Bazor Ridge systems as well as increased estimated NGL prices.

Throughput and Processing Volumes. We estimate that we will transport an average of 252.6 MMcf/d of natural gas and process an average of 48.6 MMcf/d of natural gas for the twelve months ending June 30, 2012, compared to an average of approximately 175.6 MMcf/d and 36.8 MMcf/d, respectively, for the year ended December 31, 2010 and an average of approximately 195.1 MMcf/d and 42.7 MMcf/d, respectively, for the twelve months ended March 31, 2011. The table below outlines the composition of our estimated and actual volumes for our Gathering and Processing segment for the twelve months ending June 30, 2012, the year ended December 31, 2010 and the twelve months ended March 31, 2011.


	Historical				Projected
			Twelve Months		Twelve Months
	Year Ended		Ended		Ending June 30,
	December 31, 2010		March 31, 2011		2012

Throughput Volumes (MMcf/d):
Fee-based		98.7		113.9		165.8
Fixed-margin		65.2		63.4		47.0
Percent-of-proceeds — owned plants		9.9		10.9		15.6
Incremental interconnect volumes(1)		1.8		6.9		24.2

Total throughput volumes		175.6		195.1		252.6

Processing Plant Inlet Volumes (MMcf/d):
Owned plants		9.9		10.9		15.6
Elective processing arrangements(2)		26.9		31.8		33.0

Total processing inlet volumes		36.8		42.7		48.6


(1)		Represents volumes of natural gas that we purchase at market-based prices at the Lafitte/TGP interconnect to be processed under our elective processing arrangements. We do not receive a gathering or treating fee for such volumes.

(2)		Volumes processed pursuant to our elective processing arrangements include certain volumes that are also gathered on our systems pursuant to fixed-margin arrangements. The amount of volumes gathered and processed in this manner is estimated to be 8.9 MMcf/d for the twelve months ending June 30, 2012 and was 25.2 MMcf/d and 25.0 MMcf/d for the year ended December 31, 2010 and the twelve months ended March 31, 2011. This decrease was primarily the result of the conversion of two contracts from fixed-margin to fee-based.

The increased throughput volumes estimated for the twelve months ending June 30, 2012 are primarily due to increased estimated shipments on the Gloria and Bazor Ridge systems as a result of the completion of an interconnect between TGP and our Lafitte system and the Winchester lateral, respectively, as well as new production on the Quivira system resulting from wells that were connected in late 2010. The increased processing volumes estimated for the twelve months ending June 30, 2012 are primarily due to the full-year impact of the Lafitte/TGP interconnect, the full-year impact of the Winchester lateral that relieved pipeline constraints on our Bazor Ridge system, new production connected to our Bazor Ridge system and planned growth projects.

Gathering Fees. For the twelve months ending June 30, 2012, we estimate that we will realize an average gathering fee of $0.16/Mcf and $0.18/Mcf for our fee-based and fixed-margin gathering activities, respectively, and an average fee of $0.51/Mcf related to the fee-based portion of our percent-of-proceeds arrangements at our owned plants (we do not receive a gathering or treating fee with respect to our incremental interconnect volumes). This compares to $0.18/Mcf, $0.21/Mcf and $0.26/Mcf, respectively, for the year ended December 31, 2010 and $0.17/Mcf, $0.21/Mcf and $0.42/Mcf, respectively, for the twelve months ended March 31, 2011. Our estimated gathering and fixed-margin fees are generally consistent with those realized on a historical basis. Our estimated fees under the fee-based portion of our percent-of-proceeds arrangements are expected to increase primarily due to an additional fee we collect on volumes associated with the Winchester lateral.

Gathering and Processing Product Sales and Purchases. The table below outlines the amount and composition of our estimated natural gas, NGL and condensate sales volumes, revenue and associated product purchase costs for the twelve months ending June 30, 2012 without giving effect to our hedging program.


	Sales Volume		Revenue		Purchase Cost
			(in millions)

Gathering and Processing Product Sales:
Natural gas fixed-margin (MMcf/d)		47.0	$	86.3	$	83.2
Percent-of-proceeds arrangements at owned plants(1):
Natural gas (MMcf/d)		7.5		12.9		10.0
NGLs (Mgal/d)		59.2		29.6		22.7
Condensate (Mgal/d)		6.8		5.8		4.6
Elective processing arrangements(2):
Natural gas (MMcf/d, net)		21.0		38.4		44.4
NGLs (Mgal/d, net)		24.1		12.4		—
Condensate (Mgal/d, net)		0.7		0.7		—


(1)		Represents gross sales volumes, for which we are entitled to retain a percentage of the sales proceeds and remit back the remainder to the producer.

(2)		Represents net equity sales volumes pursuant to our elective processing arrangements.

For the year ended December 31, 2010, we sold an average of 72.9 MMcf/d of natural gas at an average realized price of $4.61/Mcf, an average of 62.2 Mgal/d of NGLs at an average realized price of $1.08/gal and

an average of 5.9 Mgal/d of condensate at an average realized price of $1.82/gal. For the twelve months ended March 31, 2011, we sold an average of 76.3 MMcf/d of natural gas at an average realized price of $4.22/Mcf, an average of 70.8 Mgal/d of NGLs at an average realized price of $1.12/gal and an average of 6.8 Mgal/d of condensate at an average realized price of $1.91/gal. Additionally, total purchases of natural gas, NGLs and condensate in our Gathering and Processing segment were $133.9 million and $133.3 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively.

Transmission Segment Gross Margin

We estimate that we will generate segment gross margin for our Transmission segment of $13.2 million for the twelve months ending June 30, 2012, as compared to $13.5 million and $14.0 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. The table below outlines the composition of our estimated and actual segment gross margin for our Transmission segment for the twelve months ending June 30, 2012, the year ended December 31, 2010 and the twelve months ended March 31, 2011.


	Historical				Projected
			Twelve Months		Twelve Months
	Year Ended		Ended		Ending
	December 31, 2010		March 31, 2011		June 30, 2012
	(in millions)

Transmission Segment Gross Margin:
Firm transportation contracts	$	10.8	$	10.8	$	11.0
Interruptible transportation contracts		2.0		2.3		1.7
Fixed-margin		0.7		0.9		0.5

Total	$	13.5	$	14.0	$	13.2

Transportation Volumes. We estimate that we will transport 328.6 MMcf/d of natural gas for the twelve months ending June 30, 2012, compared to an average of approximately 350.2 MMcf/d and 372.4 MMcf/d for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. Additionally, we estimate that we will have 702.7 MMcf/d of reserved capacity pursuant to firm transportation contracts during the twelve months ending June 30, 2012, compared to approximately 677.6 MMcf/d and 692.4 MMcf/d for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. We estimate that transportation volumes will consist of 251.8 MMcf/d and 38.1 MMcf/d of volumes pursuant to firm and interruptible transportation contracts, respectively, and 38.7 MMcf/d of volumes pursuant to fixed-margin contracts during the twelve months ending June 30, 2012, compared to 269.3 MMcf/d, 53.5 MMcf/d and 27.4 MMcf/d, respectively, for the year ended December 31, 2010 and 292.4 MMcf/d, 46.9 MMcf/d and 33.1 MMcf/d, respectively, for the twelve months ended March 31, 2011.

Transportation Fees. We estimate that we will realize an aggregate average fee of $0.04/Mcf for capacity reservation and variable use fees pursuant to firm transportation contracts, an average fee of $0.12/Mcf for transportation pursuant to interruptible contracts and an average fee of $0.04/Mcf for transportation pursuant fixed-margin activities for the twelve months ending June 30, 2012, compared to an average of $0.04/Mcf, $0.10/Mcf and $0.07/Mcf, respectively, for the year ended December 31, 2010 and an average of $0.04/Mcf, $0.13/Mcf and $0.08/Mcf, respectively, for the twelve months ended March 31, 2011 due primarily to the full-year impact of a new fixed-margin contract with a lower transportation fee that we entered into in June 2010.

Transmission Product Sales and Purchases. We estimate that our fixed-margin activities will generate $69.4 million of revenue related to natural gas sales and $68.8 million of expense related to natural gas product purchases for the forecast period.

Direct Operating Expense

We estimate that direct operating expense for the twelve months ending June 30, 2012 will be $14.4 million compared to $12.2 million and $12.6 million for the year ended December 31, 2010 and the

twelve months ended March 31, 2011, respectively. Direct operating expense is comprised primarily of direct labor costs, insurance costs, ad valorem and property taxes, repair and maintenance costs, integrity management costs, utilities, lost and unaccounted for gas and contract services. As such costs are almost entirely of a fixed nature, direct operating expense will not vary significantly with increases or decreases in revenue and gross margin. The expected increase is primarily due to $1.5 million in costs associated with our integrity management program during the forecast period that were not required to be incurred during these historical periods pursuant to the program.

Selling, General and Administrative Expense

We estimate that SG&A expense for the twelve months ending June 30, 2012 will be $10.8 million, compared to $8.9 million and $9.4 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. These amounts include $1.6 million, $1.7 million and $2.0 million of cash and non-cash expenses, respectively, associated with grants pursuant to our LTIP program. This increase is attributable to the estimated $2.3 million of incremental SG&A expense that we expect to incur as a result of being a publicly traded partnership. SG&A expense is comprised primarily of fixed costs and will not vary significantly with increases or decreases in revenue or gross margin.

Depreciation Expense

We estimate that depreciation expense for the twelve months ending June 30, 2012 will be $20.2 million compared to $20.0 million and $20.1 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. Estimated depreciation expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation expense is primarily attributable to additional depreciation associated with capital projects that we expect to be placed in service during the forecast period. Depreciation expenses are derived from asset value and useful life, and therefore will not vary with increases or decreases in revenue and gross margin.

Capital Expenditures

We estimate that total capital expenditures for the twelve months ending June 30, 2012 will be $8.9 million compared to $10.3 million and $11.1 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. Total capital expenditures for the twelve months ending June 30, 2012 includes $2.2 million of estimated non-recurring deferred maintenance capital expenditures for which we have reserved $2.2 million of net proceeds from this offering. Our estimate is based on the following assumptions:


	•	We estimate that maintenance capital expenditures for the twelve months ending June 30, 2012 will total $5.2 million. These expenditures include planned maintenance on our systems. This compares to $1.7 million and $2.4 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. The $5.2 million in estimated maintenance capital expenditures includes the $3.0 million in average estimated annual maintenance capital expenditures that we expect to be required to maintain our assets over the long-term. In addition, we have included $2.2 million of estimated maintenance capital expenditures required for deferred maintenance items on certain of our assets that we identified based upon a thorough review and evaluation of our assets following the closing of our November 2009 acquisition from Enbridge. In order to fund the $2.2 million of incremental costs, we intend to establish at the closing of this offering a cash reserve with a portion of the net proceeds from this offering.


	•	We estimate that expansion capital expenditures for the twelve months ending June 30, 2012 will be $3.8 million. These expenditures are comprised of three expansion capital projects that we believe we will pursue during the forecast period. We expect that these projects will add over $1.5 million in gross margin, which is reflected in this forecast. Our expansion capital expenditures were $8.6 million and


		$8.7 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. The capital projects that we expect to undertake in our forecast period include:


	•	a cylinder upgrade on the existing Gloria compressor that we expect will increase throughput capacity on the Gloria system by approximately 7 MMcf/d and that we expect to be completed in the third quarter of 2011 at a cost of approximately $0.2 million;

	•	the construction of an interconnect and the installation of a skid-mounted treating facility along Midla, which is expected to cost approximately $0.3 million and be completed in the third quarter of 2011; and

	•	the addition of field compression capacity to the Bazor Ridge gathering system, which would provide us with the opportunity to treat new natural gas production, at an expected cost of approximately $3.4 million that we expect to complete in the first quarter of 2012.

Financing

We estimate that interest expense will be approximately $1.8 million for the twelve months ending June 30, 2012, compared to approximately $5.4 million and $5.3 million for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively. Our estimate of interest expense for the forecast period is based on the following assumptions:


	•	We will repay in full the outstanding borrowings of $59.8 million under our existing credit facility with a portion of the proceeds from this offering.

	•	We will have debt outstanding as of the closing of this offering of $30.0 million.

	•	We will have average outstanding borrowings of $31.8 million, including borrowings to finance our estimated expansion capital expenditures of $3.8 million, with an assumed weighted average interest rate of 3.5% under our new credit facility, which is lower than the weighted average interest rate under our existing credit facility of 7.5% and 7.6% for the year ended December 31, 2010 and the twelve months ended March 31, 2011, respectively.

	•	We will maintain a low cash balance and therefore do not forecast any interest income.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending June 30, 2012 is based on the following significant assumptions related to regulatory, industry and economic factors:


	•	There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.

	•	There will not be any major adverse change in the midstream energy sector, commodity prices, capital or insurance markets or general economic conditions.

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2009, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through September 30, 2011 based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:


	•	less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:


	•	provide for the proper conduct of our business (including reserves for our future capital expenditures, anticipated future credit needs and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);

	•	comply with applicable law, any of our debt instruments or other agreements; or

	•	provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for common and subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter and the next four quarters);


	•	plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners, and with the intent of the borrower to repay such borrowings within 12 months with funds other than from additional working capital borrowings. The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the 12-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Intent to Distribute the Minimum Quarterly Distribution

We intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.4125 per unit, or $1.65 on an annualized basis, to the extent we have sufficient cash

from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Our Credit Facility” for a discussion of the restrictions to be included in our new credit facility that may restrict our ability to make distributions.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

We define operating surplus as:


	•	$11.5 million (as described below); plus

	•	all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below); plus

	•	working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus

	•	cash distributions paid on equity issued to finance all or a portion of the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset (such as equipment or facilities) in respect of the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition, development or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service and the date that it is abandoned or disposed of; plus

	•	cash distributions paid on equity issued to pay the construction-period interest on debt incurred, or to pay construction-period distributions on equity issued, to finance the capital improvements or capital assets referred to above; less

	•	all of our operating expenditures (as defined below) after the closing of this offering; less

	•	the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

	•	all working capital borrowings not repaid within 12 months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings; less

	•	any cash loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $11.5 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus.

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other

dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements, (iv) the termination of commodity hedge contracts or interest rate hedge contracts prior to the termination date specified therein (provided that cash receipts from any such termination will be included in operating surplus in equal quarterly installments over the remaining scheduled life of the contract), (v) capital contributions received and (vi) corporate reorganizations or restructurings.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, interest payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), estimated maintenance capital expenditures (as discussed in further detail below), director and officer compensation, repayment of working capital borrowings and non-pro rata repurchases of our units; provided, however, that operating expenditures will not include:


	•	repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

	•	payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;

	•	expansion capital expenditures;

	•	actual maintenance capital expenditures;

	•	investment capital expenditures;

	•	payment of transaction expenses (including, but not limited to, taxes) relating to interim capital transactions;

	•	distributions to our partners;

	•	non-pro rata purchases of any class of our units made with the proceeds of an interim capital transaction; or

	•	any other payments made in connection with this offering that are described in “Use of Proceeds.”

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:


	•	borrowings other than working capital borrowings;

	•	sales of our equity and debt securities; and

	•	sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets.

Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets, for the acquisition of existing, or the construction or development of new, capital assets or for any integrity management program) made to maintain our long-term operating income or operating capacity. We expect that a primary component of maintenance capital expenditures will include expenditures for routine equipment and pipeline maintenance or replacement due to obsolescence. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction or development of a replacement asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that any such replacement asset commences commercial service and the date that it is abandoned or disposed of.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus.

Our partnership agreement requires that an estimate of the average quarterly maintenance capital expenditures be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus for those periods will be determined by the board of directors of our general partner at least once a year, subject to approval by the Conflicts Committee. The estimate will be made annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures on a long-term basis. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures and other maintenance capital expenditures for the forecast period ending June 30, 2012, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:


	•	it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for the quarter and subsequent quarters;

	•	it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;

	•	it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner; and

	•	it will reduce the likelihood that a large actual maintenance capital expenditure in a period will prevent our general partner’s affiliates from being able to convert some or all of their subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, investment capital expenditures and actual maintenance capital expenditures do not.

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. Expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance the construction, acquisition or development of an improvement to our capital assets and paid in respect of the period beginning on the date that we enter into a binding obligation to commence construction, acquisition or development of the capital improvement and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or

disposed of. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or treating capacity or new compression capacity.

Capital expenditures that are made in part for expansion capital purposes and in part for other purposes will be allocated between expansion capital expenditures and expenditures for other purposes by our general partner (with the concurrence of the Conflicts Committee).

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but that are not expected to expand, for more than the short term, our operating capacity or operating income.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4125 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day of any quarter beginning after September 30, 2014, that each of the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common and subordinated units equaled or exceeded $1.65 (the annualized minimum quarterly distribution) and the corresponding distributions on our 2.0% general partner interest and were made, in each case for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded (i) the sum of $1.65 (the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units during those periods on a fully diluted basis and (ii) the corresponding distribution on our 2.0% general partner interest; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

For purposes of determining whether sufficient adjusted operating surplus has been generated under the above conversion test, the Conflicts Committee may adjust operating surplus upwards or downwards if it determines in good faith that the amount of estimated maintenance capital expenditures used in the determination of adjusted operating surplus was materially incorrect, based on the circumstances prevailing at the time of the original estimate, for any one or more of the preceding two four-quarter periods.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day of any quarter beginning after September 30, 2012, that each of the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $2.475 (150.0% of the annualized minimum quarterly distribution), and the corresponding distribution on our general partner’s 2.0% interest and the incentive distribution rights were made, in each case, for the four-quarter period immediately preceding that date;

	•	the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $2.475 per unit (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted basis and (ii) the distributions made on our 2.0% general partner interest and the incentive distribution rights;

	•	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution of $0.4125, and we made the corresponding distribution on our 2.0% general partner interest, for each quarter during the four-quarter period immediately preceding that date; and

	•	there are no arrearages in payment of the minimum quarterly distributions on the common units.

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:


	•	the subordination period will end and each subordinated unit will immediately and automatically convert into one common unit;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:


	•	operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under the caption “— Operating Surplus and Capital Surplus — Operating Surplus” above); less

	•	any net increase in working capital borrowings with respect to that period; less

	•	any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net decrease in working capital borrowings with respect to that period; plus

	•	any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus


	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus during the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:


	•	first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

	•	second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

	•	third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter, in the manner described in “— General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:


	•	first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter, in the manner described in “— General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled from such 2.0% interest, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. It may instead fund its capital contribution by the contribution to us of common units or other property.

Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:


	•	we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

	•	we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:


	•	first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $0.47438 per unit for that quarter (the “first target distribution”);

	•	second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $0.51563 per unit for that quarter (the “second target distribution”);

	•	third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $0.61875 per unit for that quarter (the “third target distribution”); and

	•	thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.


					Marginal Percentage Interest
					in Distributions
	Total Quarterly Distribution							General
	per Unit Target Amount				Unitholders			Partner

Minimum Quarterly Distribution			$	0.41250		98.0	%		2.0	%
First Target Distribution			up to $	0.47438		98.0	%		2.0	%
Second Target Distribution	above $	0.47438	up to $	0.51563		85.0	%		15.0	%
Third Target Distribution	above $	0.51563	up to $	0.61875		75.0	%		25.0	%
Thereafter			above $	0.61875		50.0	%		50.0	%

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of our incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the Conflicts Committee, at any time when there are no

subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units and general partner units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:


	•	first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;

	•	second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

	•	third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

	•	thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.65.


					Marginal Percentage
					Interest in Distributions
								2.0%						Quarterly
								General			Incentive			Distributions
	Quarterly Distribution							Partner			Distribution			per Unit Following
	per Unit Prior to Reset				Unitholders			Interest			Rights			Hypothetical Reset

Minimum Quarterly Distribution			$	0.41250		98.0	%		2.0	%		—		$	0.6500
First Target Distribution			up to $	0.47438		98.0	%		2.0	%		—			0.7475
Second Target Distribution	above $	0.47438	up to $	0.51563		85.0	%		2.0	%		13.0	%		0.8125
Third Target Distribution	above $	0.51563	up to $	0.61875		75.0	%		2.0	%		23.0	%		0.9750
Thereafter			above $	0.61875		50.0	%		2.0	%		48.0	%		0.9750


(1)		This amount is 115.0% of the hypothetical reset minimum quarterly distribution.

(2)		This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

(3)		This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed each quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be 9,052,132 common units outstanding, our general partner has maintained its 2.0% general partner interest and the average distribution to each common unit would be $0.65 for the two quarters prior to the reset.


					Cash		Cash Distribution to General Partner Prior to Reset
					Distributions to		2.0%
	Quarterly				Common		General		Incentive
	Distribution per				Unitholders		Partner		Distribution				Total
	Unit Prior to Reset				Prior to Reset		Interest		Rights		Total		Distributions

Minimum Quarterly Distribution			$	0.41250	$	3,734,004	$	76,204	$	—	$	76,204	$	3,810,209
First Target Distribution			up to $	0.47438		560,101		11,431		—		11,431		571,531
Second Target Distribution	above $	0.47438	up to $	0.51563		373,400		8,786		57,108		65,894		439,295
Third Target Distribution	above $	0.51563	up to $	0.61875		933,501		24,893		286,274		311,167		1,244,668
Thereafter			above $	0.61875		282,879		11,315		271,564		282,879		565,758

					$	5,883,886	$	132,629	$	614,946	$	747,575	$	6,631,461

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, with respect to the quarter in which the reset occurs. The table reflects that, as a result of the reset, there would be 9,998,203 common units outstanding, our general partner’s 2.0% interest has been maintained, and the average distribution to each common unit would be $0.65. The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above, or $614,946, by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $0.65.


							Cash Distribution to General Partner
							After Reset
					Cash		Common
					Distributions to		Units Issued in		2.0%
	Quarterly				Common		Connection		General		Incentive
	Distribution per				Unitholders		With		Partner		Distribution				Total
	Unit After Reset				After Reset		Reset		Interest		Rights		Total		Distributions

Minimum Quarterly Distribution			$	0.6500	$	5,883,886	$	614,946	$	132,629	$	—	$	747,575	$	6,631,461
First Target Distribution			up to $	0.7475		—		—		—		—		—		—
Second Target Distribution	above $	0.7475	up to $	0.8125		—		—		—		—		—		—
Third Target Distribution	above $	0.8125	up to $	0.9750		—		—		—		—		—		—

Thereafter			above $	0.9750	$	5,883,886	$	614,946	$	132,629	$	—	$	747,575	$	6,631,461

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:


	•	first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;

	•	second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

	•	thereafter, as if they were from operating surplus.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume that our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:


	•	the minimum quarterly distribution;

	•	the number of common units into which a subordinated unit is convertible;

	•	target distribution levels;

	•	the unrecovered initial unit price; and

	•	the number of general partner units comprising the general partner interest.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be convertible into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:


	•	first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

	•	second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

	•	third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

	•	fourth, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;

	•	fifth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;

	•	sixth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence;

	•	thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:


	•	first, 98.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;


	•	second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

	•	thereafter, 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the partners’ capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The following table presents our selected historical consolidated financial and operating data, as well as the selected historical combined financial and operating data of our Predecessor, which was comprised of 12 indirectly wholly owned subsidiaries of Enbridge, as of the dates and for the periods indicated.

The selected financial data as of and for the year ended December 31, 2006 are derived from the unaudited historical combined financial data of our Predecessor that are not included in this prospectus. The selected historical combined financial data presented as of and for the year ended December 31, 2007 are derived from the audited historical combined financial statements of our Predecessor that are not included in this prospectus. The selected historical combined financial data presented as of and for the year ended December 31, 2008, and as of and for the 10 months ended October 31, 2009 are derived from the audited historical combined financial statements of our Predecessor that are included elsewhere in this prospectus. The selected historical consolidated financial data presented as of December 31, 2009, for the period from August 20, 2009 (date of inception) to December 31, 2009, as of and for the year ended December 31, 2010, as of and for the quarter ended March 31, 2010 and as of and for the quarter ended March 31, 2011 are derived from our audited and unaudited historical consolidated financial statements included elsewhere in this prospectus. We acquired our assets effective November 1, 2009. During the period from our inception, on August 20, 2009, to October 31, 2009, we had no operations although we incurred certain fees and expenses of approximately $6.4 million associated with our formation and the acquisition of our assets from Enbridge, which are reflected in the “One-time transaction costs” line item of our consolidated financial data for the period from August 20, 2009 through December 31, 2009.

For a detailed discussion of the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with the historical audited and unaudited consolidated financial statements of American Midstream Partners, LP and related notes and our Predecessor’s audited combined financial statements and related notes included elsewhere in this prospectus. Among other things, those historical financial statements include more detailed information regarding the basis of presentation for the information in the following table.

The following table presents the non-GAAP financial measures adjusted EBITDA and gross margin that we use in our business and view as important supplemental measures of our performance. For a definition of these measures and a reconciliation of them to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “ — Non-GAAP Financial Measures.”


	American Midstream Partners Predecessor												American Midstream Partners, LP and Subsidiaries (Successor)
													Period from
													August 20,
	Year			Year			Year			10 Months			2009 (Inception			Year			Quarter			Quarter
	Ended			Ended			Ended			Ended			Date) to			Ended			Ended			Ended
	December 31,			December 31,			December 31,			October 31,			December 31,			December 31,			March 31,			March 31,
	2006			2007			2008			2009			2009			2010			2010			2011
	(in thousands, except per unit and operating data)

Statement of Operations Data:
Revenue	$	314,278		$	290,777		$	366,348		$	143,132		$	32,833		$	211,940		$	54,712		$	67,265
Unrealized gain (loss) on commodity derivatives		—			—			—			—			—			—			—			(3,500	)

Total revenue		314,278			290,777			366,348			143,132			32,833			211,940			54,712			63,765

Operating expenses:
Purchases of natural gas, NGLs and condensate		278,590			251,959			323,205			113,227			26,593			173,821			44,964			54,953
Direct operating expenses		14,295			15,334			13,423			10,331			1,594			12,187			2,692			3,058
Selling, general and administrative expenses(1)		7,407			10,294			8,618			8,577			1,346			8,854			2,113			2,675
One-time transaction costs		—			—			—			—			6,404			303			74			288
Depreciation expense		9,917			12,500			13,481			12,630			2,978			20,013			4,966			5,037

Total operating expenses		310,209			290,087			358,727			144,765			38,915			215,178			54,809			66,011

Operating income (loss)		4,069			690			7,621			(1,633	)		(6,082	)		(3,238	)		(97	)		(2,246	)
Other (income) expenses:
Interest expense		8,469			8,527			5,747			3,728			910			5,406			1,357			1,264
Income tax expense		102			—			—			—			—			—			—			—
Other (income) expenses		(996	)		1,209			(854	)		(24	)		—			—			—			—

Net income (loss)	$	(3,506	)	$	(9,046	)	$	2,728		$	(5,337	)	$	(6,992	)	$	(8,644	)	$	(1,454	)	$	(3,510	)

General partner’s interest in net income (loss)														(140	)		(173	)		(29	)		(70	)

Limited partners’ interest in net income (loss)														(6,852	)		(8,471	)		(1,425	)		(3,440	)

Limited partners’ net income (loss) per unit													$	(1.52	)	$	(0.81	)	$	(0.14	)	$	(0.30	)

Pro forma earnings per common unit(2)																$	(1.63	)				$	(0.61	)
Pro forma weighted average common units outstanding(2)																	5,199						5,668
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	2,486		$	(447	)	$	18,155		$	14,589		$	(6,531	)	$	13,791		$	2,323		$	5,067
Investing activities		(7,587	)		745			(10,486	)		(853	)		(151,976	)		(10,268	)		(494	)		(1,291	)
Financing activities		5,132			322			(7,929	)		(14,088	)		159,656			(4,609	)		(2,888	)		(3,686	)
Other Financial Data:
Adjusted EBITDA(3)	$	14,880		$	11,981		$	21,956		$	11,021		$	3,450		$	18,263		$	5,197		$	6,914
Gross margin(4)		35,688			38,818			43,143			29,905			6,240			38,119			9,748			12,312
Segment gross margin:
Gathering and Processing		19,215			22,108			27,354			20,024			3,698			24,595			6,098			8,167
Transmission		16,476			16,710			15,789			9,881			2,542			13,524			3,650			4,145
Balance Sheet Data (At Period End):
Cash and cash equivalents	$	61		$	681		$	421		$	149		$	1,149		$	63		$	90		$	153
Accounts receivable, net and unbilled revenue		16,357			13,643			9,532			8,756			19,776			22,850			17,446			22,248
Property, plant and equipment, net		233,143			219,898			216,903			205,126			149,226			146,808			151,167			143,394
Total assets		298,161			287,290			277,242			250,162			174,470			173,229			173,217			169,693
Total debt (current and long-term)(5)		65,000			60,000			60,000			—			61,000			56,370			58,380			56,500
Operating Data:
*Gathering and Processing segment*:
Throughput (MMcf/d)								179.2			211.8			169.7			175.6			164.3			242.8
Plant inlet volume (MMcf/d)(6)								12.5			11.7			11.4			9.9			11.1			15.2
Gross NGL production (Mgal/d)(6)								40.2			39.3			38.2			34.1			35.2			55.1
*Transmission segment*:
Throughput (MMcf/d)								336.2			357.6			381.3			350.2			360.6			446.0
Firm transportation — capacity reservation (MMcf/d)								627.3			613.2			701.0			677.6			702.8			762.1
Interruptible transportation — throughput (MMcf/d)								141.6			121.0			118.0			80.9			80.2			76.5


(1)		Includes LTIP expenses for the period from August 20, 2009 to December 31, 2009, the year ended December 31, 2010, the quarter ended March 31, 2010 and the quarter ended March 31, 2011 of $0.2 million, $1.7 million, $0.3 million and $0.5 million, respectively. Of these amounts, $0.2 million, $1.2 million, $0.3 million and $0.3 million, respectively, represent non-cash expenses.


(2)		The pro forma earnings per common unit gives effect to the recapitalization transactions as of December 31, 2010 and March 31, 2011 and the additional number of common units issued in this offering (at an assumed offering price of $20.00) necessary to pay the portion of the distribution to AIM Midstream Holdings, LTIP participants holding common units and our general partner described in “Use of Proceeds” that will be funded from the proceeds of this offering that exceeds net income for the year ended December 31, 2010 and the three months ended March 31, 2011. For a description of the calculation of pro forma earnings attributable to common and subordinated units, please read Note 1 to our audited consolidated financial statements and Note 1 to our unaudited consolidated financial statements included elsewhere in this prospectus. For a reconciliation of historical weighted average common units used in the computation of limited partners’ net income (loss) per common unit and pro forma weighted average common and subordinated units outstanding, please read Note 1 to our audited consolidated financial statements and Note 1 to our unaudited consolidated financial statements included elsewhere in this prospectus.


(3)		For a definition of adjusted EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Selected Historical Financial and Operating Data — Non-GAAP Financial Measures,” and for a discussion of how we use adjusted EBITDA to evaluate our operating performance, please read “— How We Evaluate Our Operations.”

(4)		For a definition of gross margin and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Note 12 to our unaudited consolidated financial statements and Note 18 to our audited consolidated financial statements included elsewhere in this prospectus and for a discussion of how we use gross margin to evaluate our operating performance, please read “— How We Evaluate Our Operations.”

(5)		Excludes Predecessor Note payable to Enbridge Midcoast Limited Holdings, L.L.C. of $39.3 million as of December 31, 2008.

(6)		Excludes volumes and gross production under our elective processing arrangements. For a description of our elective processing arrangements, please read “Business — Gathering and Processing Segment — Gloria System.”

Non-GAAP Financial Measures

We include in this prospectus the non-GAAP financial measures of adjusted EBITDA and gross margin. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

Adjusted EBITDA

We define adjusted EBITDA as net income:


	Page

Cash Distributions		181
Capital Contributions		181
Voting Rights		182
Limited Liability		183
Issuance of Additional Securities		184
Amendment of Our Partnership Agreement		184
Merger, Sale or Other Disposition of Assets		186
Termination and Dissolution		187
Liquidation and Distribution of Proceeds		187
Withdrawal or Removal of Our General Partner		187
Transfer of General Partner Interest		188
Transfer of Ownership Interests in Our General Partner		189
Transfer of Subordinated Units and Incentive Distribution Rights		189
Change of Management Provisions		189
Limited Call Right		190
Meetings; Voting		190
Status as Limited Partner		191
Non-Citizen Assignees; Redemption		191
Non-Taxpaying Assignees; Redemption		191
Indemnification		192
Reimbursement of Expenses		192
Books and Reports		192
Right to Inspect Our Books and Records		193
Registration Rights		193
Units Eligible for Future Sale		194
Material Federal Income Tax Consequences		195
Partnership Status		195
Limited Partner Status		197
Tax Consequences of Unit Ownership		197
Tax Treatment of Operations		203
Disposition of Common Units		204
Uniformity of Units		206
Tax-Exempt Organizations and Other Investors		207
Administrative Matters		208
Recent Legislative Developments		210
State, Local, Foreign and Other Tax Considerations		210
Investment in American Midstream Partners, LP by Employee Benefit Plans		211
Underwriting		213
Offering Price Determination		215
Notice to Prospective Investors in the European Economic Area		215
Notice to Prospective Investors in the Dubai International Financial Centre		216
Notice to Prospective Investors in the United Kingdom		216
Notice to Prospective Investors in Germany		216
Notice to Prospective Investors in the Netherlands		217
Notice to Prospective Investors in Switzerland		217
Validity of the Common Units		218
Experts		218
Where You Can Find More Information		218
Forward-Looking Statements		218
Index to Financial Statements		F-1
Appendix A — Amended and Restated Agreement of Limited Partnership of American Midstream Partners, LP		A-1
Appendix B — Glossary of Terms		B-1
EX-10.9
EX-23.1
EX-23.2


	Page

Summary		1
American Midstream Partners, LP		1
Overview		1
Business Strategies		2
Competitive Strengths		2
Our Sponsor		3
Risk Factors		3
Recapitalization Transactions and Partnership Structure		3
Ownership of American Midstream Partners, LP		4
Our Management		5
Principal Executive Offices and Internet Address		5
Summary of Conflicts of Interest and Fiduciary Duties		5
General		5
Partnership Agreement Modifications to Fiduciary Duties		6
AIM Midstream Holdings May Engage in Competition with Us		6
The Offering		7
Summary Historical Financial and Operating Data		11
Risk Factors		14
Risks Related to our Business		14
Risks Inherent in an Investment in Us		33
Tax Risks to Common Unitholders		41
Use of Proceeds		46
Capitalization		48
Dilution		49
Our Cash Distribution Policy and Restrictions on Distributions		50
General		50
Our Minimum Quarterly Distribution		51
Unaudited Historical As Adjusted Available Cash for the Year Ended December 31, 2010 and the Twelve Months Ended March 31, 2011		53
Estimated Adjusted EBITDA for the Twelve Months Ending June 30, 2012		55
Statement of Estimated Adjusted EBITDA		57
Assumptions and Considerations		59
Provisions of our Partnership Agreement Relating to Cash Distributions		65
Distributions of Available Cash		65
Operating Surplus and Capital Surplus		66
Capital Expenditures		68
Subordination Period		69
Distributions of Available Cash from Operating Surplus during the Subordination Period		71
Distributions of Available Cash from Operating Surplus after the Subordination Period		71
General Partner Interest and Incentive Distribution Rights		71
Percentage Allocations of Available Cash from Operating Surplus		72
General Partner’s Right to Reset Incentive Distribution Levels		72
Distributions from Capital Surplus		75
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		76
Distributions of Cash Upon Liquidation		76
Selected Historical Financial and Operating Data		79
Non-GAAP Financial Measures		81
Management’s Discussion and Analysis of Financial Condition and Results of Operations		84
Overview		84
Our Operations		84
How We Evaluate Our Operations		86
Items Affecting the Comparability of Our Financial Results		88


	Page

General Trends and Outlook		89
Results of Operations — Combined Overview		91
Segment Results		95
Liquidity and Capital Resources		100
Quantitative and Qualitative Disclosures about Market Risk		106
Impact of Seasonality		108
Critical Accounting Policies and Estimates		108
Industry Overview		111
General		111
Midstream Services		111
Typical Midstream Contractual Arrangements		112
U.S. Natural Gas Fundamentals		113
Business		115
Overview		115
Business Strategies		116
Competitive Strengths		117
Our Sponsor		118
Our Assets		119
Gathering and Processing Segment		120
Transmission Segment		127
Competition		132
Safety and Maintenance		132
Regulation of Operations		133
Environmental Matters		138
Title to Properties and Rights-of-Way		143
Employees		144
Legal Proceedings		144
Management		145
Compensation Discussion and Analysis		148
Summary Compensation Table for 2010		156
Grants of Plan-Based Awards for 2010		156
Outstanding Equity-Based Awards at December 31, 2010		158
Units Vested in 2010		158
Long-Term Incentive Plan		159
Potential Payments Upon Termination or Change in Control		159
Compensation of Directors		163
Director Compensation Table for 2010		164
Compensation Practices as they Relate to Risk Management		165
Security Ownership of Certain Beneficial Owners and Management		166
Certain Relationships and Related Party Transactions		168
Distributions and Payments to our General Partner and its Affiliates		168
Ownership Interests of Certain Executive Officers and Directors of Our General Partner		169
Agreements with Affiliates		169
Procedures for Review, Approval and Ratification of Related-Person Transactions		170
Conflicts Of Interest and Fiduciary Duties		171
Conflicts of Interest		171
Fiduciary Duties		176
Description of the Common Units		179
The Units		179
Transfer Agent and Registrar		179
Transfer of Common Units		179
The Partnership Agreement		181
Organization and Duration		181
Purpose		181